CORPORATE PRESENTATION

February 2017 FORWARD-LOOKING INFORMATION: Certain statements contained in this presentation constitute forward-looking statements and information (collectively referred to as “forward-looking information”) within the meaning of applicable Canadian securities laws. Such forward-looking information relates to future events or Birchcliff’s future performance. All information other than historical fact may be forward-looking information. Such forward-looking information is often, but not always, identified by the use of words such as “seek”, “plan”, “expect”, “project”, “intend”, “believe”, “anticipate”, “estimate”, “estimated”, “forecast”, “potential”, “proposed”, “predict”, “budget”, “continue”, “targeting”, “may”, “will”, “could”, “might”, “should” and other similar words and expressions. This information involves known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking information. Birchcliff believes that the expectations reflected in the forward-looking information are reasonable in the current circumstances but no assurance can be given that these expectations will prove to be correct and such forward-looking information included in this presentation should not be unduly relied upon. In particular, this presentation contains forward-looking information relating to the following: Birchcliff’s plans and other aspects of its anticipated future operations, focus, objectives, strategies, opportunities, priorities and goals, including the Five Year Plan, including the production forecast by the plan, the focus of, objectives of and anticipated results of the plan, the number of wells estimated to be drilled by the plan; Birchcliff’s belief that it has the people, the assets, the forecast cash flow and the balance sheet to execute on its growth plan; the 2017 Capital Program, including estimated net capital expenditures, planned capital expenditures and capital allocation, Birchcliff’s plan to drill a total of 46 (46.0 net) wells, Birchcliff’s expectation that it will fund the 2017 Capital Program using internally generated cash flow and that the 2017 Capital Program will be less than expected cash flow for 2017, and the focus of, the objectives of and the anticipated results from the 2017 Capital Program; Birchcliff’s production guidance, including its estimates of its annual average production, production growth, exit production and commodity mix in 2017; estimates of reserves and the net present values of future net revenue associated with Birchcliff’s reserves; price forecasts; FDC; reserves life index; decline rates; the performance characteristics of Birchcliff’s oil and natural gas properties and expected results from its assets; estimates of future drilling locations and opportunities; Birchcliff’s proposed exploration and development activities and the timing thereof, including wells to be drilled and brought on production; proposed expansions of the PC Gas Plant, including the anticipated processing capacities of the PC Gas Plant after such expansions and the anticipated timing and costs of such expansions; Birchcliff’s hedging strategy and the use of risk-management techniques; Birchcliff’s future growth plans for the Elmworth area, including Birchcliff’s intention to construct and operate the Elmworth Gas Plant and the anticipated processing capacity and timing thereof; Birchcliff’s dividend policy and the payment of dividends, including the amount of and timing of the payment of future dividends and statements regarding the sustainability of dividends; reference to the potential for LNG export in the future; proposed completion techniques for Pouce Coupe core area Montney D1 horizontal wells in 2017; the benefits to be obtained as a result of the Gordondale Acquisition. Information relating to reserves is forward-looking as it involves the implied assessment, based on certain estimates and assumptions, that the reserves exist in the quantities predicted or estimated and that the reserves can profitably be produced in the future. With respect to forward-looking information contained in this presentation, assumptions have been made regarding, among other things: Birchcliff’s ability to continue to develop the Gordondale Assets and obtain the anticipated benefits therefrom; prevailing and future commodity prices and differentials, currency exchange rates, interest rates, inflation rates, royalty rates and tax rates; expected cash flow from operations; Birchcliff’s future debt levels; the state of the economy and the exploration and production business; the economic and political environment in which Birchcliff operates; the regulatory framework regarding royalties, taxes and environmental laws; the sources of funding for Birchcliff’s capital expenditure programs and other activities; anticipated timing and results of capital expenditures; the sufficiency of budgeted capital expenditures to carry out planned operations; Birchcliff’s ability to find opportunities to reduce costs and defer certain capital expenditures; results of future operations; future operating, transportation, marketing and general and administrative costs; the performance of existing and future wells, well production rates and well decline rates; well drainage areas; success rates for future drilling; reserves and resource volumes and Birchcliff’s ability to replace and expand oil and gas reserves through acquisition, development or exploration; the impact of competition on Birchcliff; the availability of, demand for and cost of labour, services and materials; Birchcliff’s ability to access capital; the ability to obtain financing on acceptable terms; the ability to obtain any necessary regulatory approvals in a timely manner; the ability of Birchcliff to secure adequate transportation for its products; Birchcliff’s ability to market oil and gas; and the availability of hedges on terms acceptable to Birchcliff. In addition to the foregoing assumptions, Birchcliff has made the following assumptions with respect to certain forward-looking information contained in this presentation: • With respect to the Five Year Plan: o The plan is based on the following commodity price and exchange rate assumptions over the five year period: an average forecast WTI price of approximately US$55.00 per bbl of oil; an average forecast AECO price of approximately CDN$3.00 per GJ of natural gas; and an exchange rate of CDN$/US$ of 1.29. o The forecast production contained in the plan is subject to similar assumptions as Birchcliff’s other production guidance as set forth herein, as well as assumptions regarding future commodity prices and exchange rates, the number of wells drilled over the five year period and the processing capacity and timing of the construction and commissioning of future facilities of Birchcliff. o The plan forecasts that approximately 375 wells are drilled over the five year period. The number of wells forecast to be drilled under the plan is subject to similar assumptions regarding the drilling of future wells as set forth herein. The actual number of wells drilled may fluctuate significantly depending on, among other things, the production performance of wells drilled. o The plan assumes that the Phase V expansion of the PCS Gas Plant (for a total combined processing capacity of 260 MMcf) is operational in October 2017, that the Phase VI expansion of the PCS Gas Plant (for a total combined processing capacity of 340 MMcf/d) is operational in October 2018, that the Phase VII expansion of the PCS Gas Plant (for a total combined processing capacity of 420 MMcf/d) is operational in the fall of 2020 and that the Elmworth Gas Plant (with a processing capacity of 40 MMcf/d) is operational in the fall of 2021. o With respect to statements that the production growth and capital expenditures contemplated by the plan are expected to be funded out of internally generated cash flow and that Birchcliff is expected to generate significant free cash flow over the five year period, such statements assume that the production targets and commodity price assumptions set forth herein are achieved. These statements also assume that the commodity mix of natural gas, oil and NGLs forecast by Birchcliff is achieved. Statements that Birchcliff expects to fund its 2017 capital expenditures and dividends out of internally generated cash flow are based on the same assumptions. • With respect to statements regarding the 2017 Capital Program, such program is based on the following commodity price and exchange rate assumptions during 2017: an annual average WTI price of US$55.00 per barrel of oil; an AECO price of CDN$3.00 per GJ of natural gas; and an exchange rate of CDN$/US$ of 1.29. o With respect to statements that the 2017 Capital Program is expected to be fully funded out of internally generated cash flow and that the 2017 Capital Program will be less than expected cash flow for 2017, such statements assume that: the 2017 Capital Program will be carried out as currently contemplated; the production targets and commodity price assumptions set forth herein are achieved; and Birchcliff’s forecast commodity mix is achieved. o With respect to the estimate of net capital expenditures during 2017, such estimate assumes that: the 2017 Capital Program will be carried out as currently contemplated; and the cost of labour, services and materials stays relatively consistent with current levels. o Actual spending may vary due to a variety of factors, including commodity prices, economic conditions, results of operations and cots of labour, services and materials. Birchcliff will monitor economic conditions and commodity prices and, where deemed prudent, will adjust the 2017 Capital Program to respond to changes in commodity prices and other material changes in the assumptions underlying the 2017 Capital Program. • With respect to Birchcliff’s 2017 production guidance, the key assumptions are that: the 2017 Capital Program will be carried out as currently contemplated; no unexpected outages occur in the infrastructure that Birchcliff relies on to produce its wells and that any transportation service curtailments or unplanned outages that occur will be short in duration or otherwise insignificant; the construction of new infrastructure meets timing and operational expectations; existing wells continue to meet production expectations; and future wells scheduled to come on production meet timing, production and capital expenditure expectations. • With respect to estimates of reserves volumes and the net present values of future net revenue associated with Birchcliff’s reserves, the key assumption is the validity of the data used by Deloitte and McDaniel in their independent reserves evaluations. • With respect to statements of future wells to be drilled and brought on production and estimates of potential future drilling locations and opportunities, the key assumptions are: the continuing validity of the geological and other technical interpretations performed by Birchcliff’s technical staff, which indicate that commercially economic volumes can be recovered from Birchcliff’s lands as a result of drilling future wells; and that commodity prices and general economic conditions will warrant proceeding with the drilling of such wells. • With respect to statements regarding proposed expansions of the PC Gas Plant, including the anticipated processing capacities of the PC Gas Plant after such expansions and the anticipated timing of such expansions, the key assumptions are that: future drilling is successful; there is sufficient labour, services and equipment available; Birchcliff will have access to sufficient capital to fund those projects; the key components of the plant will operate as designed; and commodity prices and general economic conditions will warrant proceeding with the construction of such facilities and the drilling of associated wells. • With respect to statements regarding Birchcliff’s intention to construct and operate the Elmworth Gas Plant, including the anticipated processing capacity of such plant and the anticipated timing thereof, the key assumptions are that: future drilling in the Elmworth area is successful; the acid gas disposal well drilled by Birchcliff is capable of handling the volumes of acid gas to be produced at the plant and complies with all regulatory requirements; there is sufficient labour, services and equipment available; Birchcliff will have access to sufficient capital to fund the Elmworth Gas Plant; and commodity prices and general economic conditions warrant proceeding with the construction of the Elmworth Gas Plant and the drilling of associated wells. Birchcliff’s actual results, performance or achievements could differ materially from those anticipated in the forward-looking information as a result of both known and unknown risks and uncertainties including, but not limited to: the failure to realize the anticipated benefits of acquisitions and dispositions, including the Gordondale Acquisition; unforeseen difficulties in integrating the Gordondale Assets into Birchcliff’s operations; variances in Birchcliff’s actual capital costs, operating costs and economic returns from those anticipated; general economic, market and business conditions which will, among other things, impact the demand for and market prices of Birchcliff’s products and Birchcliff’s access to capital; volatility of crude oil and natural gas prices; fluctuations in currency and interest rates; operational risks and liabilities inherent in oil and natural gas operations; uncertainties associated with estimating oil and natural gas reserves and resources; the accuracy of oil and natural gas reserves estimates and estimated production levels as they are affected by exploration and development drilling and estimated decline rates; geological, technical, drilling, construction and processing problems; uncertainty of geological and technical data; uncertainties related to Birchcliff’s future potential drilling locations; fluctuations in the costs of borrowing; changes in tax laws, crown royalty rates, environmental laws and incentive programs relating to the oil and natural gas industry and other actions by government authorities, including changes to the royalty and carbon tax regimes and the imposition or reassessment of taxes; the cost of compliance with current and future environmental laws; political uncertainty and uncertainty associated with government policy changes; uncertainties and risks associated with pipeline restrictions and outages to third‐party infrastructure that could cause disruptions to production; the ability to satisfy obligations under Birchcliff’s firm marketing and transportation arrangements; the inability to secure adequate production transportation for Birchcliff’s products; the occurrence of unexpected events such as fires, equipment failures and other similar events affecting Birchcliff or other parties whose operations or assets directly or indirectly affect Birchcliff; potential delays or changes in plans with respect to exploration or development projects or capital expenditures; stock market volatility; loss of market demand; environmental risks, claims and liabilities; incorrect assessments of the value of acquisitions and exploration and development programs; shortages in equipment and skilled personnel; the absence or loss of key employees; uncertainties associated with the outcome of litigation or other proceedings involving Birchcliff; uncertainty that development activities in connection with its assets will be economical; competition for, among other things, capital, acquisitions of reserves, undeveloped lands, equipment and skilled personnel; uncertainties associated with credit facilities; counterparty credit risk; risks associated with Birchcliff’s hedging program and the risk that hedges on terms acceptable to Birchcliff may not be available; and risks associated with the declaration and payment of dividends, including the discretion of Birchcliff’s board of directors to declare dividends. Readers are cautioned that the foregoing lists of factors are not exhaustive. Additional information on these and other risk factors that could affect results of operations, financial performance or financial results are included in Birchcliff’s most recent Annual Information Form and in other reports filed with Canadian securities regulatory authorities. Any future-orientated financial information and financial outlook information (collectively, “FOFI”) contained in this presentation, as such terms are defined by applicable securities laws, is provided for the purpose of providing information about management’s current expectations and plans relating to the future and is subject to the same assumptions, risk factors, limitations and qualifications as set forth in the above paragraphs. FOFI contained in this presentation was made as of the date of this presentation and Birchcliff disclaims any intention or obligation to update or revise any FOFI contained in this presentation, whether as a result of new information, future events or otherwise, unless required by applicable law. Readers are cautioned that any FOFI contained herein should not be used for purposes other than those for which it has been disclosed herein. Management has included the above summary of assumptions and risks related to forward-looking information provided in this presentation in order to provide readers with a more complete perspective on Birchcliff’s future operations. Readers are cautioned that this information may not be appropriate for other purposes. The forward-looking information contained in this presentation is expressly qualified by the foregoing cautionary statements. The forward-looking information contained in this presentation is made as of the date of this presentation. Birchcliff is not under any duty to update or revise any of the forward-looking information except as expressly required by applicable securities laws. SELECTED DEFINITIONS: “2016 Deloitte Reserves Report” means the evaluation by Deloitte LLP effective December 31, 2016 as contained in the report of Deloitte dated February 3, 2017. “2016 McDaniel Reserves Report” means evaluation by McDaniel with an effective date of December 31, 2016 as contained in the report of McDaniel dated February 8, 2017. “2016 Consolidated Reserves Report” means the consolidated report of Deloitte with an effective date of December 31, 2016 prepared by consolidating the properties evaluated by Deloitte in the 2016 Deloitte Reserves Report with the properties evaluated by McDaniel in the 2016 McDaniel Reserves Report, in each case using Deloitte’s forecast price and cost assumptions effective December 31, 2016 “Deloitte” means Deloitte LLP, independent qualified reserves evaluator to the Corporation. “Five Year Plan” refers to Birchcliff’s 2021 Five Year Plan as outlined in the Corporations November 9, 2016 press release. “Gordondale Acquisition” refers to the previously announced acquisition of certain petroleum and natural gas properties, interests and related assets primarily located in the Gordondale area of Alberta from Encana Corporation. “Gordondale Assets” means the petroleum and natural gas properties, interests and related assets primarily located in the Gordondale area in the Province of Alberta acquired in the previously announced Gordondale Acquisition. “McDaniel” means McDaniel & Associates Consultants Ltd., independent qualified reserves evaluator to the Corporation. “PC Gas Plant” refers to Birchcliff’s 100% owned and operated natural gas plant located in the Pouce Coupe area of Alberta.

2 PEOPLE, FOCUS & EXECUTION

3 Corporate Snapshot & Select Guidance

Q4 2016 average production 60,750 boe/d

% oil and NGL 21%

Current production as at February 8, 2017 62,000 boe/d

Estimated 2017 annual average production 70,000 – 74,000 boe/d

% oil and NGL 23%

Estimated 2017 net capital expenditures (millions) $355

Total debt as at December 31, 2016 (millions) $600

Credit facilities limit as at December 31, 2016 (millions) $950

Common shares (basic) as at December 31, 2016 264,041,902

Market capitalization as at December 31, 2016 (billions) $2.5

Enterprise value as at December 31, 2016 (billions)(1) $3.2

Montney/Doig land position as at December 31, 2016 (gross sections) 441.2

Montney/Doig potential net future horizontal drilling locations as at December 31, 2016(2) 5,703.1

Gross proved developed producing reserves(3) 165,507 Mboe

Gross proved plus probable reserves(3) 880,464 Mboe

(1) Enterprise value is calculated by multiplying the closing price of the common shares on the TSX as at December 31, 2016 by the total number of common shares outstanding as at December 31, 2016 and adding estimated total debt as at December 31, 2016, including the face value of the Series A Preferred Shares and Series C Preferred Shares. (2) See “Advisories – Drilling Locations”. (3) See appendix at the end of this presentation for disclosures on oil & gas reserves and related metrics.

4 INVESTMENT HIGHLIGHTS

• Record quarterly average production of 60,750 boe/d, an 11% increase from 54,538 boe/d in the Q3 2016 and a 50% increase from 40,445 boe/d in Q4 2015 • Q4 2016 cash flow was $71.8 million or $0.27 per basic common share, a 72% increase from $41.7 million ($0.18 per basic common share) in Q3 2016 and a 113% increase from $33.7 million ($0.22 per basic common share) in Q4 2015 • Q4 2016 net income to common shareholders of $11.1 million ($0.04 per basic common share), as compared to the net loss to common shareholders of $2.1 million ($0.01 per basic common share) in Q3 2016 and the net loss to common shareholders of $10.3 million ($0.07 per basic common share) in Q4 2015 • Q4 2016 operating costs of $4.54/boe, a 2% decrease from $4.65/boe in Q3 2016 and a 9% increase from $4.16/boe in Q4 2015 • Birchcliff’s intends to pay a sustainable annual dividend to common shareholders of $0.10 per basic common share, with the initial dividend expected to be paid in respect of the quarter ending March 31, 2017 in the amount of $0.025 per common share

5 INVESTMENT HIGHLIGHTS

• Focused assets in the Peace River Arch Area of Alberta (the Montney/Doig Resource Play and the Charlie Lake Light Oil Resource Play) • Essentially 100% working interest; 99% of production is operated • Large, contiguous undeveloped land base with an average 93% W.I. • Significant control of infrastructure including the 100% owned and operated 180 MMcf/d Pouce Coupe Gas Plant (“PC Gas Plant”) • Top tier cost structure driving peer leading profitability • 2P reserve life index (RLI)(1)(2) of approximately 33.5 as at December 31, 2016 • 295 (289.7 net) Montney/Doig horizontal wells drilled as at December 31, 2016 • 5,703.1 net future potential Montney/Doig horizontal drilling locations as at December 31, 2016(3)

(1) See appendix at the end of this presentation for disclosures on oil & gas reserves and related metrics. (2) Reserves life index is calculated by dividing reserves estimated by Deloitte at December 31, 2016 by 72,000 boe/d, which production rate represents the mid-point of Birchcliff’s annual average production guidance range for 2017. (3) See “Advisories – Drilling Locations”.

6 2021 FIVE YEAR PLAN(1) 140,000 125,000

120,000 110,000 105,000

100,000 91,000

80,000 72,000(2)

60,000

40,000 Production (boe/d) Production

20,000 Approximate Annual Average Average Annual Approximate

0 2017E 2018E 2019E 2020E 2021E

Approximate Annual Average 72,000(2) boe/d 91,000 boe/d 105,000 boe/d 110,000 boe/d 125,000 boe/d Production (boe/d)

Approximate Exit Production (boe/d) 80,000(1) boe/d 106,000 boe/d 106,000 boe/d 124,000 boe/d 130,000 boe/d

Estimated Number of Wells(3) 46 (46.0 net) 104 (104.0 net) 56 (56.0 net) 89 (89.0 net) 70 (70.0 net)

Light Oil – WTI Cushing (USD$/bbl) $55.00 $55.00 $55.00 $55.00 $55.00

Natural Gas – AECO – C daily $3.00 $3.00 $3.00 $3.00 $3.00 (CDN$/GJ)

(1) The 2021 Five Year Plan reflects the plan outlined in the Corporations November 9, 2016 press release and assumes the following with respect to timing of PC Gas Plant expansions: Phase V (260 MMcf/d) being completed in October 2017; Phase VI (340 MMcf/d) being completed in October 2018; and Phase VII (420 MMcf/d) being completed in October 2020. (2) Represents the mid-point of 2017 guidance (3) Well count includes both Montney/Doig horizontal wells and Charlie Lake Light Oil horizontal wells

7 HEDGING SUMMARY

2017 Natural Gas Hedging Summary 2017 Crude Oil Hedging Summary

MMcf/d(1) $CDN/Mcf(1) bbl/d $CDN/bbl

Q1 2017 157.0 $3.44 Q1 2017 1,500 $69.90

Q2 2017 157.0 $3.44 Q2 2017 1,500 $69.90

Q3 2017 157.0 $3.44 Q3 2017 1,500 $69.90

Q4 2017 183.2 $3.50 Q4 2017 1,500 $69.90

Approximately 50% of estimated 2017 natural gas production Approximately 20% of estimated 2017 crude oil production is is hedged at an average AECO price of CDN$3.46/Mcf(1) hedged at an average WTI price of CDN$69.90/bbl

(1) The conversion from GJ to Mcf is calculated using an estimated corporate average heat content value of 40.69 MJ/m3 for 2017

8 BIRCHCLIFF’S HISTORY A Track Record of Execution KEYS TO SUCCESS . Executives with proven track record, continuity since inception and significant ownership Management . Highly experienced Management Team with excellent technical knowledge and a long history with the company . 295 (289.7 net) Montney/Doig horizontal natural gas wells and 61 Charlie Lake horizontal light oil Operational wells all utilizing multi-stage fracture stimulated technology drilled to December 31, 2016 Execution . Construction of the 180 MMcf/d PC Gas Plant in four separate phases on time and on budget . Own, control or have access to infrastructure and operate 99% of production . Significant in-house technical expertise and experience on the Peace River Arch Technical . Supports continual improvements in high grading portfolio for the decision making process Expertise . Continued improvements in estimated reserve recovery per well, drilling & completion practices and operating costs . Consistent, repeatable, predictable growth and results Scale & . 5,703.1 potential Montney/Doig horizontal locations and 300+ potential Charlie Lake horizontal light Repeatability oil locations as at December 31, 2016(1)

. Full cycle profitability with top tier F&D costs and netbacks through 2016 and prior years Financial . Accurate and reliable real time forecasts supported by a detailed capital management and production Execution forecasting process which is fully integrated into our financial reporting systems

. Mr. Seymour Schulich, our largest shareholder, holds 35 million common shares representing 12% of Shareholder Base the issued and outstanding common shares at December 31, 2016; we thank Mr. Schulich, for his advice, unwavering commitment and his ongoing financial support

(1) See “Advisories – Drilling Locations”

10 PRODUCTION HISTORY

80,000 70,000 – 74,000 70,000

60,000 Compound annual growth of 30% per year since 2005 49,236 50,000

38,950 40,000 33,734

Average Production (boe/d) Production Average 30,000 25,829 22,802

20,000 18,136 13,079 10,148 11,216 10,000 6,711 5,368 2,793

0 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017E

11 CORPORATE RESERVES

1,000,000 PDP

TP 880 MMboe 900,000 2P 800,000 On a per share basis PDP, 1P and 2P 700,000 reserves have increased at a compound

annual growth rate of 14%, 22% and 23% (1) ) 600,000 per year since 2005, respectively 549 MMboe

500,000

400,000 Reserves (Mboe Reserves

300,000

200,000 166 MMboe

100,000

0 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016

(1) See appendix at the end of this presentation for disclosures on oil & gas reserves and related metrics.

12 CORPORATE NPV10 (BT)

$7,000 PDP

TP $5.8 Billion $6,000 2P

PDP and 2P NPV10 (BT) increased by $5,000 66% and 50% year over year, respectively

$4.1 Billion $4,000

$3,000 NPV10 ($million) NPV10

$1.9 Billion $2,000

$1,000

$0 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016

(1) See appendix at the end of this presentation for disclosures on oil & gas reserves and related metrics.

13 PROVEN TRACK RECORD AS A LOW COST PRODUCER

5 Year Profitability Breakdown: 2012 2013 2014 2015 2016 Average Average AECO (CAD$/GJ) $2.27 $2.99 $4.27 $2.55 $2.05 $2.83

Average WTI (USD$/bbl) $94.21 $97.97 $92.99 $48.80 $43.32 $75.46

P&NG Revenue ($/Mcfe) $5.13 $5.60 $6.40 $3.72 $3.12 $4.55

PDP F&D ($/Mcfe)(1) ($2.06) ($2.49) ($2.23) ($1.35) ($1.07) (1.79)

Total Cash Costs(2) ($/Mcfe) ($2.73) ($2.59) ($2.34) ($1.83) ($1.77) ($2.15)

Profit ($/Mcfe)(3)(4) $0.34 $0.52 $1.83 $0.53 $0.29 $0.61

Profit Margin (%)(3) 7% 9% 29% 14% 9% 13%

(1) Cost to find and develop proved developed producing (PDP) reserves based on finding and development (“F&D”) costs. (2) Comprised of royalty, operating, transportation and marketing, general and administrative and interest expenses. (3) Profit measures the amount, if any, during the relevant period by which revenues resulting from production exceed the sum of: (i) PDP F&D (i.e. the costs of replacing production excluding acquisitions and dispositions), (ii) royalty, operating and transportation and marketing expenses and, in the case of Birchcliff at the business-entity level, (iii) general and administrative expense, and (iv) interest expense. This measure is not intended to represent net income or net income to common shareholders as presented in accordance with IFRS. Profit margin is calculated by dividing profit before non-cash items for the period by petroleum and natural gas revenue for the period. We believe that profit and profit margin are useful measures as they assist management and investors in assessing our ability during a period of declining commodity prices to bear all of our total cash costs and the costs of replacing our production during the relevant period. See “Non- GAAP Measures” in this presentation. (4) Numbers may not add due to rounding

14 PROVEN TRACK RECORD AS A LOW COST FINDER

$16 PDP F&D 1P F&D 2P F&D 1.2x Cash flow $12 1.8x 1.8x 1.9x 1.2x 1.2x netback recycle 1.3x ratios 2.0x $8 2.3x 2.0x 1.4x 2.6x 1.3x 3.7x

F&D Cost ($/boe) Cost F&D $4 1.7x 1.8x

4.7x 7.3x $0 2011 2012 2013 2014 2015 2016

Corporate F&D Costs (incl. FDC) & Cash Flow Recycle Ratios 2011 2012 2013 2014 2015 2016 PDP F&D ($/boe) $5.30 $12.34 $14.94 $13.40 $8.11 $6.42 1P F&D ($/boe) $8.78 $11.10 $9.39 $13.51 $2.41 $4.89 2P F&D ($/boe) $7.59 $11.99 $9.03 $12.57 $1.55 $4.43

PDP Recycle Ratio 3.7x 1.2x 1.2x 1.8x 1.4x 1.3x 1P Recycle Ratio 2.3x 1.3x 2.0x 1.8x 4.7x 1.7x 2P Recycle Ratio 2.6x 1.2x 2.0x 1.9x 7.3x 1.8x

15 2016 ACCOMPLISHMENTS

 Completed the acquisition of significant petroleum and natural gas properties and related assets located in the Gordondale area of Alberta for a purchase price of $613.5 million, after final adjustments

 In connection with the Gordondale Acquisition, Birchcliff completed equity financings for gross proceeds of $690.8 million

 Record annual average production of 49,236 boe/d, a 26% increase from 2015 annual average production of 38,950 boe/d

 Cash flow of $147.4 million ($0.74 per basic common share), an 8% decrease from $160.8 million ($1.06 per basic common share) in 2015

 Drilled a total of 22 (22.0 net) wells in 2016, including 14 (14.0 net) Montney/Doig horizontal natural gas wells in the Pouce Coupe area and 6 (6.0 net) Montney horizontal oil and natural gas wells in the Gordondale area

 Delivered significant reserves growth in all categories

16 LOOKING FORWARD 2017 Plans & Beyond 2017 CAPITAL PROGRAM

2017 CAPITAL BUDGET: $355.0 MILLION Net Capital Gross Wells Net Wells ($millions) Drilling & Development Pouce Coupe - Montney D1 HZ Gas Wells 22.0 22.0 86.1 Pouce Coupe - Basal Doig/Upper Montney HZ Gas Wells 7.0 7.0 30.2 Pouce Coupe - Montney D4 HZ Gas Wells 3.0 3.0 12.9 Gordondale - Montney D2 HZ Oil Wells 7.0 7.0 40.7 Gordondale - Montney D1 HZ Oil Wells 5.0 5.0 28.9 Gordondale - Montney D1 HZ Gas Wells 2.0 2.0 11.6 2016 Carry Forward Capital(1) - - 19.4 Total Drilling & Development(2) 46.0 46.0 $229.8 Facilities & Infrastructure(3) 85.6 Production Optimization(4) 19.4 Land & Seismic 4.6 Acquisitions & Dispositions(5) (0.2) Other 15.4 Total Net Capital(5) $355.0 (1) Primarily completion, equipping, and tie-in costs associated with 10 (10.0 net) wells rig released in 2016. (2) On a drill, case, complete, equip and tie-in basis (3) Includes approximately $27.3 million of capital in 2017 for the Phase V expansion and $26.0 million of capital in 2017 for the Phase VI expansion. (4) Includes $13.6 million of sustaining capital. (5) The 2017 Capital Program has been presented on a net basis, meaning net of acquisitions and dispositions. Certain dispositions that have been completed as at the date of this press release have been included in the table above. Birchcliff makes acquisitions and dispositions in the ordinary course of business. Any further acquisitions and dispositions completed during 2017 could have an impact on Birchcliff’s capital expenditures, production and cash flow for 2017, which impact could be material.

18 2017 CAPITAL PROGRAM

• The 2017 Capital Program reflects Birchcliff’s long-term plan of the continued exploration and development of Birchcliff’s low-cost natural gas, crude oil and liquids-rich assets on the Montney/Doig Resource Play and achieving controlled growth, maintaining balance sheet strength and the payment of a sustainable quarterly dividend

• Birchcliff is targeting a 2017 annual average production rate of 70,000 to 74,000 boe/d

• The program is anticipated to be funded out of internally generated cash flow, which we expect will be protected by our recently implemented hedging program

• Birchcliff plans to drill, complete, equip and tie-in a total of 46 (46.0 net) new wells and complete, equip and tie-in 10 wells drilled in 2016

• The program includes investment of approximately $85.6 million for facilities and infrastructure (approximately 24% of the budget) to provide for future growth

19 BORROWING BASE DETAILS

• Birchcliff has extendible revolving credit facilities in the aggregate principal amount of $950 million with maturity dates of May 11, 2018, which are comprised of an extendible revolving syndicated term credit facility of $900 million and an extendible revolving working capital facility of $50 million

• The credit facilities contain no financial maintenance covenants

• At December 31, 2016, Birchcliff’s long-term bank debt was $573 million, leaving $357 million of unutilized credit capacity after adjusting for outstanding letters of credit and unamortized interest and fees

• Total debt at December 31, 2016 was $600 million, which is below Birchcliff’s previous guidance of $607 million

• The credit facilities are subject to a semi-annual review of the borrowing base limit by Birchcliff’s syndicate of lenders

20 MONTNEY/DOIG RESOURCE PLAY A Significant Position in a World Class Play MONTNEY/DOIG - A WORLD CLASS RESOURCE PLAY Resource density. Stacked resource up to 300 metres thick. Large areal extent. Extends over 50,000 square miles. Exceptional “fracability”. Low clay Birchcliff Montney/Doig content, low Poisson’s Ratio and high Young’s Modulus. Exceptional fracture stability. Fractures stay open due to very low propant embedment. High permeability. Formation is dominated by siltstones allowing natural fluid flow. Over pressured. Indicative of high gas in place. Repeatability. Widespread “blanket” style deposit provides for more repeatable results. Source: Canadian Discovery, RBC Rundle

22 MONTNEY/DOIG MINEROLOGY LEADS TO EXCELLENT “FRACABILITY”

The Montney/Doig Resource Play rock type is composed of a Some other Resource Plays have a high percentage of clays high percentage of hard minerals, and a low percentage of and soft minerals. When fractured this results in the rock clays and soft minerals. When fractured this results in a breaking similar to concrete, in a simple bi-wing fracture complex fracture system similar to shattering glass. This system. This simple bi-wing fracture system can lead to less complex fracture system enhances stimulated rock volume stimulated rock volume, which in tight shale reservoirs can and allows hydrocarbons to flow at greater quantities into the lead to less effective long term hydrocarbon production rates horizontal wellbore leading to enhanced production rates and and EUR’s. EUR’s.

23 BIRCHCLIFF MONTNEY/DOIG

• The Gordondale Acquisition adds a fourth commercial development interval in the Montney D2 • Large contiguous land base with 441 sections prospective for the Montney/Doig • Birchcliff has contiguous land block at Pouce Coupe and Gordondale of 261 net sections • Stacked resource in some of the thickest Montney with 5,703.1(1) net potential horizontal locations identified • Low cost structure through ownership of PC Gas Plant & surrounding infrastructure • Low decline production

(1) See “Advisories – Drilling Locations”

24 STACKED RESOURCE PROVIDES SUBSTANTIAL FUTURE UPSIDE

25 MONTNEY/DOIG MULTI LAYER OPPORTUNITY

3 2 1 4 5 6

5 6

4 3

2

1

26 PROXIMAL TO INFRASTRUCTURE WITH LONG TERM EXPOSURE TO LNG EXPORT Montney/Doig Birchcliff Pouce Coupe Production Montney/Doig & PC Gas Plant Owned Infrastructure

PC Gas Plant

Nova Pipeline System

North American Market

LNG Export

Source: RBC Energy Insights: The Montney – Tracking an Elephant August 12, 2014

27 POUCE COUPE OVERVIEW

• Proven asset in development phase • Wells show high initial deliverability, low terminal decline and stable long 2017 February 8th term production Montney D1 Test Results • Predictable results with improving rates & liquids yields • 100% owned and operated • Expect to drill 32 (32.0 net) Montney/Doig horizontal natural gas wells in 2017 • 2017 program will focus on evolving completion techniques including an increased number of stages and higher frac intensity • No land expiry issues

28 2017 FEBRUARY 8TH POUCE COUPE TEST RESULTS

• The table below sets forth the recent test results from Birchcliff’s two Montney horizontal natural gas wells drilled in the Pouce Coupe area as a part of our budget expansion in Q4 2016 • These wells were completed utilizing Birchcliff’s latest engineered completion designs including an increased number of stages and higher frac intensity

Pouce Coupe Test Results(1)(2)(3) Average Oil Natural Gas(4) Condensate Test(1) Area Interval Well (boe/d) (bbl/d) (MMcf/d) (bbl/d) (days) Pouce Coupe Montney D1 Gas 100/15-05-79-12 W6 1,297 - 6.0 291 18

Pouce Coupe Montney D1 Gas 100/16-05-79-12 W6 2,098 - 10.0 430 9

(1) Test results for each well disclose the average rate of production over the last two days of the test. (2) "Load water” (i.e. water used in well completion stimulations) is still being produced and the test rates disclosed may include recovered load water fluids. (3) These test results should be considered preliminary at this stage because no pressure transient analysis or well-test interpretation was carried out on any of these wells. (4) The natural gas volumes recovered from the tests represent raw gas volumes as opposed to sales gas volumes and include NGLs which were not recovered separately.

29 POUCE COUPE LOWER MONTNEY (D1) PERFORMANCE VS. TYPE CURVE 7,000

6,000 Deloitte Tier 0 Type Curve IP (un-choked): 6.9 MMcf/d 5,000 IP (choked): 4.0 MMcf/d

2P Reserves: 8.2 Bcfe(1) )

4,000 Mcf/d

3,000 Gas Rate ( Rate Gas

2,000 Tier 0

Tier 1 1,000 Tier 2 Tier 3 Tier 4

0 0 4 8 12 16 20 24 Normalized Flowing Time (Months) Lower Montney (D1) Wells 2015 Lower Montney (D1) Wells 2016 Lower Montney (D1) Wells (1) 2P reserves calculated using of 3% and CGR of 3.9 bbl/MMcf

30 GORDONDALE ACQUISITION HIGHLIGHTS

 Completed the Gordondale Acquisition on July 28, 2016 for a purchase price of $613.5 million, after final adjustments

 Consolidated a sizeable and contiguous land base within Birchcliff’s existing Gordondale/Pouce Coupe area on the Montney/Doig Resource Play

 Significantly increased production and ability to generate cash flow

 Increased oil & NGL weighting

 Added strategic infrastructure

 Low base decline production

 High quality development opportunities including the addition of a fourth commercial development interval in the Montney D2

31 GORDONDALE BASE PRODUCTION HISTORY Montney D2 40,000 discovery well 2015 2014 Last well drilled in 2014 (on-stream 2015) 2013 2012 with peak production of ~35,000 boe/d 35,000 2011 2010 2009 2008 and Earlier 30,000 AltaGas Deep Cut Plant on stream October 2012 and Montney oil pool development commenced 25,000

20,000 Montney oil pool discovered in 2010 Production (boe/d) Production Horizontal gas 15,000 development in late 2000s

10,000

5,000

0 Jan-08 Jan-09 Jan-10 Jan-11 Jan-12 Jan-13 Jan-14 Jan-15 Jan-16

32 GORDONDALE OVERVIEW

• Drilled 6 (6.0 net) Montney horizontal oil and natural gas wells in 2016 including three Montney D2 oil wells 2017 February 8th and three Montney D1 natural gas Montney D1 Test Results wells • Early results from all 6 wells are meeting or exceeding expectations • The 2017 program is set to include 14 horizontal wells including 7 Montney D2 oil wells, 5 Montney D1 oil wells and 2 Montney D1 natural gas wells

2017 February 8th Montney D2 Test Results

33 2017 FEBRUARY 8TH GORDONDALE TEST RESULTS

• The table below sets forth the recent test results from Birchcliff’s first six Montney horizontal wells drilled on the Gordondale Assets in Q4 2016 • Preliminary results are meeting or exceeding Birchcliff’s expectations, and support an optimistic view of the Gordondale Assets while increasing Birchcliff’s confidence in the future drilling opportunities, production additions and low-cost repeatability of its Montney/Doig Resource Play in the Peace River Arch of Alberta

Gordondale Test Results(1)(2)(3) Average Oil Natural Gas(4) Condensate Test(1) Area Interval Well (boe/d) (bbl/d) (MMcf/d) (bbl/d) (days) Gordondale Montney D2 Oil 102/03-15-78-11 W6 820 628 1.1 - 9

Gordondale Montney D2 Oil 100/02-15-78-11 W6 878 619 1.6 - 12

Gordondale Montney D2 Oil 102/01-15-78-11 W6 1,157 862 1.8 - 11

Gordondale Montney D1 Gas 100/06-13-79-12 W6 1,495 - 7.5 249 11

Gordondale Montney D1 Gas 100/03-13-79-12 W6 1,611 - 7.9 293 8

Gordondale Montney D1 Gas 102/04-13-79-12 W6 1,299 - 6.3 254 4

(1) Test results for each well disclose the average rate of production over the last two days of the test. (2) "Load water” (i.e. water used in well completion stimulations) is still being produced and the test rates disclosed may include recovered load water fluids. (3) These test results should be considered preliminary at this stage because no pressure transient analysis or well-test interpretation was carried out on any of these wells. (4) The natural gas volumes recovered from the tests represent raw gas volumes as opposed to sales gas volumes and include NGLs which were not recovered separately.

34 GORDONDALE KEY INFRASTRUCTURE

Key Natural Gas Processing Infrastructure

• Existing infrastructure has already AltaGas Gordondale CNRL Progress Sour Deep Cut Gas Plant Sour Shallow Cut Gas Plant supported peak production of 16-31-078-11W6 01-01-078-10W6 Licensed Capacity: ~135 MMcf/d Acquired W.I.: ~10% ~35,000 boe/d Current BIR Rate: ~100 MMcf/d Licensed Capacity: ~130MMcf/d Current Rate: ~125 MMcf/d • Natural gas is primarily processed at Key Light Oil Handling the AltaGas Deep Cut Sour Gas Infrastructure Birchcliff Plant which has a processing Oil Battery 02-06-079-11W6 capacity of ~135 MMcf/d Capacity: ~10,000 bbl/d Alliance Pipeline Birchcliff • Includes two light oil batteries with Oil Battery 07-29-078-11W6 Capacity: ~10,000 bbl/d combined oil handling capacity of NGTL Acquired Encana 20,000 bbl/d (100% W.I.) Compressors

Birchcliff • Includes a non-operated W.I. of Sour Compressor Station 02-05-079-11W6 ~10% in CNRL Progress Gas Plant, Capacity: ~12 MMcf/d adding to Birchcliff’s existing 3% W.I. Birchcliff Sour Compressor Station 05-27-078-11W6 • Long-term third party processing, Capacity: ~32 MMcf/d Birchcliff transportation and sale agreements, Sour Compressor Station 16-19-077-10W6 including firm transportation capacity Capacity: ~21 MMcf/d

on the Pembina pipeline system Gas Plants Pembina Pipeline Acquired Montney Land Oil Batteries NGTL Pipeline Acquired ECA Wells Alliance Pipeline Oil Well Effluent Pipeline Compressor Stations

35 ELMWORTH DEVELOPMENT

• Received regulatory approval for an acid gas injection well in August 2016 • Preliminary planning underway for a Second Exploration 100% owned and operated 40 Horizontal MMcf/d natural gas processing plant; currently expected to be operational in the fall of 2021 • Drilled two successful exploration First Exploration horizontal wells into the Montney D4 Approved Acid Horizontal Gas Injection interval, both of which are expected Well to result in follow up drilling and significant future reserve additions • Will leverage over 10 years of Montney experience

36 CONCEPTUAL MONTNEY/DOIG FIELD DEVELOPMENT MODEL

STATUS OF MODEL CALLIBRATION AND DERISKING

FACIES & PETROPHYSICAL GEOLOGICAL, GEOPHYSICAL, GEOMECHANCAL HYDRAULIC FRAC & MICRO SEIS. RESERVOIR MODEL OPTIMIZED DCC & PRODUCTION

BASAL DOIG / D5 T1

D4 T2

D3

D2 >T0

D1 >T0

C >T4

37 POUCE COUPE DRILLING PERFORMANCE Drill Cost Efficiency Yearly Average Drill Speed ( Spud – Rig Release) $700 300 $650 250 $600 $550 200

$/mD $500 mD/Day $450 150 $400 35% decrease in $/mD from 2007 Drilling twice as fast as 2007 $350 100 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 0 0 20% less cost for drilling operations compared to 2015 Drilling 10 days faster and 1,000 meters longer than 2007 1000 1,000

2000 2,000 2007 - 2013 2007 - 2013

3000 3,000 2016

2016 Measured Depth (m) Depth Measured 4000 (m) Depth Measured 4,000

2015 2014 2015 2014 5000 5,000 $- $500 $1,000 $1,500 $2,000 $2,500 $3,000 1 3 5 7 9 11 13 15 17 19 21 23 25 27 Cost ($000’s) Days from Spud

38 POUCE COUPE LOWER MONTNEY (D1) CORE AREA COMPLETION EVOLUTION Completion Cost per Stage vs. Number of Stages Proppant Intensity

$300 30 1.00 200

)

Average Number Average Average Interfrac Average

000's) $250 25 0.80 160

$200 20

Stage Stage ($ 0.60 120 Intensity Intensity (t/m

$150 15 of of

0.40 80 (m Spacing Stages (#) Stages $100 10

0.20 40

$50 5

) Average Average Proppant Completion Completion Cost Per $0 0 0.00 0 2012 2013 2014 2015 2016 2017E 2012 2013 2014 2015 2016 2017E

Completion Parameter 2012 2013 2014 2015 2016 2017E Surfactant SLW/ X-linked Completion Fluid (# of Wells) SLW / X-linked SLW SLW SLW SLW/ X-linked SLW Calculation Type Average Average Average Average Average Average Pumping Rate (m3/min) 2 - 4 4 - 8 4 - 8 8 - 10 8 - 10 8 - 10 Lateral Length (m) 1,800 1,722 1,997 2,086 2,060 2,295 Number of Stages (#) 14 15 16 17 17 29 Interfrac Spacing (m) 134 123 136 126 125 89 Technology Open Hole Ball Drop Open Hole Ball Drop Open Hole Ball Drop Open Hole Ball Drop Open Hole Ball Drop Open Hole Ball Drop(1) Tonnage (t) 70 70 75 74 75 64 Proppant Intensity (t/m) 0.54 0.61 0.60 0.60 0.62 0.81 Completions Cost Per Stage ($000's) 229 182 175 101 66 50

(1) Currently one cemented liner completion is planned for Pouce Coupe in 2017

39 ENGINEERED COMPLETIONS FOR MONTNEY/DOIG FULL FIELD DEVELOPMENT

Industry Range Birchcliff Best Practices Oil Birchcliff Best Practices Gas

Liner type Openhole or Cemented Openhole Openhole

Inter-well spacing 100 – 400 m (300 – 1,200 ft) 200 m (600 ft) 300 m (900 ft)

Inter-frac spacing 20 – 150 m (60 – 450 ft) 50 m (150 ft) 70 m (210 ft)

Stages 20 – 120 60 30

Proppant 0.5 – 6.0 tonne/m (335 – 4,023 lb/ft) 1.0 – 1.5 tonne/m (670 – 1,005 lb/ft) 0.7 – 1.0 tonne/m (470 – 670 lb/ft)

Fluid CO2, N2, Hybrid, Slickwater Slickwater Slickwater

Pump Rate 2 – 12 m3/min (12 – 75 b/m) 6 – 10 m3/min (37 – 62 b/m) 6 – 10 m3/min (37 – 62 b/m)

Avg. Lateral Length 1,500 – 4,000 m (4,500 – 12,000 ft) 2,700 m (8,850 ft) 2,300 m (7,500 ft)

Estimated DCCET $4.0 - $13.0 million $5.7 million(1) $4.5 million(2)

C* - Approximately $8.0 million Approximately $7.0 million

(1) Estimated by McDaniel. (2) Estimated by Deloitte. Up slightly compared to 2015 due to optimized well layouts resulting in more full length wells, as well as an increase in the deeper Montney D1 reserves locations.

40 TERMINAL DECLINE CHANGES

• Due to strong historical performance from both Birchcliff and industry Montney/Doig wells, Deloitte has reduced their forecast TP and 2P terminal declines to 11% and 9%, respectively • Deloitte’s Tier 0 type curve has increased from 7.7 Bcfe sales to 8.2 Bcfe sales, a 6% increase in estimated 2P reserves per well • Deloitte’s Tier 0 type curve estimates that the well enters its terminal decline after 4 years TP and 4.9 years 2P

2008 2009 - 2010 2011 2012 - 2015 2016 Terminal Decline Hyperbolic Exponential Exponential Exponential Exponential TP 30% 20% 17% 13% 11% 2P 20% 13.35% 13% 10% 9%

41 MONTNEY NORMALIZED VINTAGE PLOT Historical Pouce Coupe Montney D1 Performance(1) 8,000

7,000

2016 Engineered completions and improved drill placement have led 6,000 to substantial year over year

2015 increases in well results 5,000

4,000

2012 2013

3,000 Gas Rate (Mcf/d) Rate Gas

Tier 0 2011 2014 2,000 2010 2009 Tier 1 2008 Tier 2

Tier 3 1,000 Tier 4

0 0 2 4 6 8 10 12 Normalized Flowing Time (Months) 2008 - 2014 Wells 2015 (18 Wells) 2016 (9 Wells)

(1) Well results have been normalized to bottom hole flowing pressures using 70% drawdown to benchmark well performance of choked wells and account for changes in gathering pressure. Birchcliff continues to choke initial production to optimize both well and reservoir performance.

42 PC GAS PLANT The Engine for Future Growth Production Processed 2012 2013 2014 2015 2016 through the PC Gas Plant Average daily production, net to Birchcliff: Natural gas (Mcf) 59,327 91,666 132,808 163,641 168,444 Oil & NGLs (bbls) 204 527 1,065 1,287 960 Total boe (6:1) 10,092 15,805 23,200 28,560 29,034 Percentage of corporate natural gas production 56% 73% 78% 81% 68% Percentage of corporate production 44% 61% 69% 73% 59% Sales liquids yield (bbls/MMcf) 3.4 5.7 8.0 7.9 5.7 Average AECO price for period ($/Mcf) $2.39 $3.17 $4.50 $2.69 $2.16 Netback and cost: $/Mcfe $/boe $/Mcfe $/boe $/Mcfe $/boe $/Mcfe $/boe $/Mcfe $/boe Petroleum and natural gas revenue(1) 2.91 17.44 3.77 22.64 5.17 31.02 3.17 19.03 2.54 15.21 Royalty expense (0.11) (0.67) (0.16) (0.93) (0.24) (1.42) (0.11) (0.63) (0.06) (0.38) Operating expense (2) (0.35) (2.08) (0.37) (2.24) (0.42) (2.52) (0.31) (1.90) (0.25) (1.49) Transportation and marketing expense (0.23) (1.37) (0.25) (1.55) (0.30) (1.81) (0.31) (1.88) (0.33) (1.96) Estimated operating netback $2.22 $13.32 $2.99 $17.92 $4.21 $25.27 $2.44 $14.62 $1.90 $11.38 Operating margin 76% 76% 79% 79% 81% 81% 77% 77% 75% 75%

(1) Excludes the effect of hedges using financial instruments. (2) Represents plant and field operating costs.

• The above table details Birchcliff’s annual net production and estimated operating netback for wells producing to the PC Gas Plant, on a production month basis

44 Corporate Operating Costs vs. % of Natural Gas Sales Volumes Processed at the PC Gas Plant

KEY STRATEGIC $10.00 100% Volume Through Volume ADVANTAGES $8.00 80%

$6.00 60% PC PC

• 100% owned and operated $4.00 40% Gas Plant Gas • Generates operating cost savings of

approximately $1.00/Mcf vs. third $2.00 20% Corporate Corporate Operating Cost ($/boe) party processing of an equivalent gas $0.00 0% 2009 2010 2011 2012 2013 2014 2015 2016 plant Corporate operating costs, net of recoveries ($/boe) • Provides flexibility to adjust % of total natural gas sales volumes processed at PC Gas Plant development pace at minimal cost Average AECO Price vs. PC Operating Netback 35,000 $5.00

and maximize profitability AECO/PC 30,000 • Control of the gas plant, infrastructure $4.00 25,000 and two acid gas disposal wells ($/Mcfe NetbackOp. 20,000 $3.00 provide predictable run times and the 15,000 ability to consistently meet production $2.00 10,000

and budget targets Plant Production (boe/d) $1.00

PC PC 5,000

0 $0.00 2011 2012 2013 2014 2015 2016 Produciton processed through the PC Gas Plant (boe/d) Average AECO Price ($/Mcf) PC operating netback ($/Mcfe)

45 PC GAS PLANT HIGHLIGHTS

• Current processing capacity of 180 MMcf/d • Expect Phase V expansion will be completed in October 2017, adding 80 MMcf/d bringing total processing 32% capacity to 260 MMcf/d • Expect Phase VI expansion will be 68% completed in October 2018, adding 80 MMcf/d bringing total processing capacity to 340 MMcf/d • The first installment of the Phase VII expansion is expected to include a deep cut capability and is proposed to 2016 Natural Gas Volumes Processed at PC Gas Plant be completed in mid 2019, bringing Other 2016 Natural Gas Volumes total processing capacity from 340 MMcf/d to 490 MMcf/d (from the 420 MMcf/d originally planned)

46 POUCE COUPE SERVICE OVERVIEW

• Virtually all of our natural gas production is transported on TransCanada’s NGTL System in Alberta pursuant to both firm and interruptible service agreements • Birchcliff recently entered into sales agreements with a third party to sell ~40 MMcf/d of natural gas under contracts commencing November 2017 and expiring March 2018 and ~5 MMcf/d of natural gas under contracts commencing April 2017 and expiring October 2020 with production being delivered into the Alliance Pipeline

500

450 November 2018 Phase VI & VII: 460 MMcf/d 400

350

300

250 October 2020(1) MMcf/d 200 Phase VII: 420 MMcf/d October 2018(1) 150 Phase VI: 340 MMcf/d 100 October 2017(1) 50 Phase V: 260 MMcf/d

0

Jul-17 Jul-18 Jul-19 Jul-20 Jul-21

Apr-17 Oct-17 Apr-18 Oct-18 Apr-19 Oct-19 Apr-20 Oct-20 Apr-21 Oct-21

Jan-17 Jan-18 Jan-19 Jan-20 Jan-21 TCPL Firm Service Alliance Service Plant Capacity (RAW) Meter Station Capacity (SALES)

(1) The timing of PC Gas Plant expansions in the above chart reflects Birchcliff’s expectations contained in the 2021 Five Year Plan outlined in the Corporations November 9, 2016 press release.

47 CHARLIE LAKE LIGHT OIL RESOURCE PLAY Dependable Light Oil Production WORSLEY CHARLIE LAKE LIGHT OIL

One 2016 well • Essentially 100% W.I. with operatorship continued 18 sections of land and extends and control of wells, pipelines and pool to N.E. off an facilities existing pad at minimal tie-in cost • Own over 190 net sections with 200+ horizontal locations currently identified • Mature, predictable, long life production base • The pool is characterized by high original oil in place (“OOIP”) with low recovery factors to date • Increasing recovery factor through waterflood, infill drilling and expanding pool boundaries

49 WORSLEY CHARLIE LAKE LIGHT OIL ACCOMPLISHMENTS SINCE SEPTEMBER 2007 ACQUISITION

• 2P reserves have increased over 150% to 38.9 MMboe from 15.1 MMboe

• 2016 year end 2P NPV10 (BT) was $537 million versus purchase price of $270 million

• Birchcliff has drilled over 100 wells and is using the latest horizontal drilling and multi-stage fracture stimulation technology

• Significantly expanded the area of the pool under waterflood

• Strategically acquired 3D seismic to aid in expanding pool boundaries, adding OOIP and new reserves

50 WORSLEY AREA RESERVES 45,000 PDP 38.9 MMboe 40,000 TP PDP reserves increased 15% as 2P success with the waterfood scheme 35,000 advanced proved reserves to PDP

30,000

25,000 (Mboe)

(1) 20.4 MMboe

20,000 Reserves 15,000

10,000 7.6 MMboe

5,000

0 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016

(1) See appendix at the end of this presentation for disclosures on oil & gas reserves and related metrics

51 WORSLEY AREA NPV10 (BT)

$1,200

2016 PDP NPV10 (BT) of $172 million, $1,000 a increase of 29% from year end 2015

$800

($million) $600 $537 Million

(1) NPV10 $400 $341 Million

$172 Million $200

$0 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 PDP ($million) TP ($million) 2P ($million)

(1) See appendix at the end of this presentation for disclosures on oil & gas reserves and related metrics

52 BUILDING ON OUR PAST Over 10 Years of Success Record annual average Birchcliff’s average daily production was 49,236 boe/d in production of 49,236 2016 compared to 2,793 boe/d in 2005, a compounded boe/d in 2016 annual growth rate of 30% per year over that span.

2,793 boe/d

1 2 3 4 5 6 7 8 9 10 11 12 13 14 2004 2017

1 July 6, 2004: Birchcliff incorporated as a private corporation. 9 March 20, 2010: Phase I of the PC Gas Plant commenced operations with a processing capacity of 30 MMcf/d. January 19, 2005: Completed $60 million equity financing & 2 common shares commenced trading on the TSX Venture. 10 November 2, 2010: Phase II of the PC Gas Plant commenced operations with a combined processing capacity of 60 MMcf/d. 3 February 6, 2005: Rig released first Montney/Doig vertical exploration gas well drilled by Birchcliff in the Pouce Coupe Area. 11 October 2, 2012: Phase III of the PC Gas Plant commenced operations with a combined processing capacity of 150 MMcf/d. 4 May 31, 2005: Completed acquisition of properties in the Peace River Arch for $242.8 million. 12 September 1, 2014: Phase IV of the PC Gas Plant commenced operations with a combined processing capacity of 180 MMcf/d. 5 July 21, 2005: Common shares commenced trading on the TSX. 13 July 13, 2016: Closed equity financings for total gross proceeds of $690.8 million. 6 September 22, 2007: Rig released first Montney/Doig horizontal natural gas well drilled by Birchcliff in the Pouce Coupe Area. 14 July 28, 2016: Completed acquisition of properties in the 7 September 27, 2007: Completed acquisition of the Worsley Charlie Gordondale area of Alberta for approximately $613.5 million. The Lake light oil Property for $270 million. assets included high working interest operated production and a large contiguous land base adjacent to Birchcliff’s existing 8 March 4, 2008: Rig released first Charlie Lake horizontal light oil operations on the Montney/Doig Resource Play. well in the Worsley area.

54 Production Growth

60,000 300 boe/d/million wtd. avg. shares 50,000 250 Birchcliff has increased production at a 40,000 200 compound annual growth rate of 30,000 150 boe/d 30% since 2005. 20,000 100

10,000 50

0 0 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016

Average Production (boe/d) Production per Common Share (boe/d/million wtd. avg. shares)

Operating & Cash Costs*

$20

$18 $16 Operating and cash costs have $14 $12 decreased by 60% and 46% since $10

$/boe 2008 largely due to horizontal drilling success $8

$6 and benefits achieved from processing gas at the

$4 PC Gas Plant which began operations in early $2 2010. $- 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016

Cash Cost* ($/boe) Operating Costs ($/boe)

* includes operating, transportation and marketing, general and administrative and interest

55 Reserves Growth 1000 4,000

800 3,200 Birchcliff has added significant low cost reserves boe/1,000shares

600 2,400 since commencing operations in 2005. On a per

MMboe 400 1,600 common share basis, PDP, 1P and 2P reserves grew 14% per year, 22% 200 800 per year and 23% per year, 0 0 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 respectively. PDP (MMboe) 1P (MMboe) 2P (MMboe) PDP (boe/1000 shares) 1P (boe/1000 shares) 2P (boe/1000 shares)

Over 12 years of operations, Birchcliff has…  Realized $212 million in net income  Invested $3.5 billion in capital to common shareholders  Generated $2.8 billion in revenue  Grown 2P NAV to $5.8 billion  Drilled 295 Montney/Doig horizontal  Delivered $1.5 billion in cash flow natural gas wells

56 APPENDIX 2015 MONTNEY/DOIG RESOURCE ASSESSMENT Reserves and Resource Volumes (Bcfe)(1)(2) Resource Class Raw/Sales Low Estimate Case Best Estimate Case High Estimate Case Cumulative Production(3) Sales 286.2 286.2 286.2 Remaining Reserves(3)(4) Sales 1,938.1 3,114.7 4,474.9 Total Commercial Sales 2,224.3 3,400.9 4,761.1 Surface and Process Loss Raw 66.5 101.9 146.9 Total Commercial Raw 2,290.8 3,502.8 4,908.0 Contingent Resources(3) Sales 6,549.3 9,497.0 14,505.4 Development Pending Sales 4,334.4 6,348.0 9,952.4 Development On Hold Sales 1,140.8 1,719.5 2,605.2

Discovered Development Unclarified Sales 1,072.0 1,422.0 1,922.2 Development Not Viable Sales 2.1 7.6 25.6 Surface and Process Loss Raw 311.9 457.7 684.3 Unrecoverable Raw 10,685.3 13,165.7 13,833.8 Total Sub-Commercial Raw 17,546.5 23,120.4 29,023.6 TOTAL DISCOVERED PIIP Raw 19,133.6 25,589.4 32,398.1 Sales 7,954.3 12,718.0 21,026.0 Prospective Resources(3) Sales 7,954.3 12,718.0 21,026.0 Prospect(5) Raw 327.4 526.0 875.6 Surface and Process Loss Raw 11,253.9 15,098.2 16,498.5 Unrecoverable Undiscovered Raw 18,967.5 27,431.9 36,893.3 TOTAL UNDISCOVERED PIIP TOTAL PIIP Raw 38,101.1 53,021.3 69,291.4

(1) The volumes presented in the table above, other than cumulative production and reserves, have been presented on an unrisked basis, meaning that they have not been adjusted for the chance of commerciality. (2) The sum of the total commercial and total sub-commercial resource volumes differs from the total discovered PIIP resource volumes in the table above because the liquid yields included as sales resource volumes were converted to a gas equivalent using a 1:6 bbl/Mcf conversion factor, which is an energy- based conversion factor rather than a volume-based conversion factor. This methodology was also utilized for the components of the undiscovered PIIP volumes and results in a similar discrepancy in volumes. (3) Sales gas and NGL volumes combined at a ratio of 1 bbl is equivalent to 6 Mcfe. (4) Includes reserves assigned by Deloitte to both vertical and horizontal Montney/Doig wells. Deloitte prepared a reserves estimation and economic evaluation effective December 31, 2015 in respect of Birchcliff’s oil and natural gas properties, which is contained in a report dated February 5, 2016 (the “2015 Reserves Evaluation”). Proved, probable and possible reserves evaluated by Deloitte in an the 2015 Reserves Evaluation are included in above table for completeness; however, reserves were not the focus of the 2015 Resource Assessment. The low estimate case includes the estimate of proved reserves contained in the 2015 Reserves Evaluation, the best estimate case includes the estimate of proved plus probable reserves contained in the 2015 Reserves Evaluation and the high estimate case includes the estimate of proved plus probable plus possible reserves contained in the 2015 Reserves Evaluation. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves. (5) All of Birchcliff’s prospective resources were sub-classified into the project maturity sub-class of “prospect”.

58 2016 YEAR END MONTNEY/DOIG RESERVES Drilled 20 HZ M/D wells 900,000 and acquired 87 (82.5 net) HZ M/D wells 295 (289.7 net) Montney/Doig horizontal 800,000 Drilled 29 HZ wells drilled as of Dec 31, 2016 including M/D wells 87 (82.5 net) wells acquired in the 700,000 Drilled 41 HZ Gordondale Acquisition M/D wells

600,000 Drilled 25 HZ M/D wells

Drilled 22 HZ 500,000 M/D wells

Drilled 23 HZ PDP 400,000 M/D wells TP

Drilled 23 HZ Reserves (Mboe) Reserves 300,000 M/D wells 2P Drilled 8 HZ M/D wells 200,000 Drilled 15 HZ M/D wells 100,000 Drilled 2 HZ M/D wells 0 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 PDP 733 1,063 2,504 6,051 7,791 17,200 25,400 41,500 50,538 73,095 92,380 151,964 TP 2,376 3,351 9,661 29,158 61,880 85,900 127,100 156,500 193,705 255,208 321,752 518,966 2P 4,553 10,172 19,347 57,724 115,515 158,400 227,700 266,800 319,215 412,336 516,821 825,455

(1) See appendix at the end of this presentation for disclosures on oil & gas reserves and related metrics

59 SERIES A PERPETUAL PREFERRED SHARES Preferred Share Details Series A Number of Shares 2 million Issue Date August 8, 2012 TSX Trading Symbol BIR.PR.A Issue / Par Price $25.00 per share Quarterly Dividend $0.5000 per share Yield at Issue 8.0% Redeemable by Holder No

2016 2017 2018 2019 2020 2021 2022 1 2

September 30, 2022: Series A are redeemable by Birchcliff (and not 1 September 30, 2017: Series A are redeemable by Birchcliff (and not 2 by holder) on this date and every five years hereafter by holder) on this date and every five years hereafter September 30, 2017: Series A fixed rate will be reset on this date September 30, 2022: Series A fixed rate will be reset on this date and every five years hereafter to the five year Government of and every five years hereafter to the five year Government of Canada bond yield plus 6.83% Canada bond yield plus 6.83% September 30, 2017: Series A holders have right to convert to September 30, 2022: Series A (fixed rate) & B (variable rate) Series B variable rate preferred shares, subject to certain conditions, holders are entitled to convert between the two Series on this date which pays a floating quarterly dividend at a rate equal to the three and every five years hereafter, subject to certain conditions month Canadian Treasury Bill yield plus 6.83%

60 SERIES C PREFERRED SHARES

Preferred Share Details Series C Number of Shares 2 million Issue Date June 14, 2013 TSX Trading Symbol BIR.PR.C Issue / Par Price $25.00 per share Quarterly Dividend $0.4375 per share Yield at Issue 7.0% June 30, 2020 and each Redeemable by Holder quarter thereafter 2016 2017 2018 2019 2020 1 2 3

1 June 30, 2018: Series C redeemable by Birchcliff (and not by 3 June 30, 2020: Series C redeemable by Birchcliff at $25.00 per holder) at $25.75 per share (plus accrued and unpaid dividends) if share (plus accrued and unpaid dividends) form this date forward redeemed before June 30, 2019; Birchcliff has the option to convert subject to proper notice Birchcliff has the option to convert into into common shares (see note) common shares (see note) June 30, 2020: Series C redeemable by holder, on this date and the 2 June 30, 2019: Series C redeemable by Birchcliff (and not by last day of each quarter hereafter, at $25.00 per share (plus accrued holder) at $25.50 per share (plus accrued and unpaid dividends) if and unpaid dividends); upon receipt of notice for redemption, redeemed before June 30, 2020; Birchcliff has the option to convert Birchcliff may elect to convert into common shares (see note) into common shares (see note) Note: The number of common shares is determined by dividing the applicable redemption price, together with accrued and unpaid dividends, by the greater of $2.00 and 95% of the 20-day weighted average trading price ending on the fourth day prior to the date specified for conversion

61 EXECUTIVE OFFICERS

A. Jeffery Mr. Tonken is a Director and the President and CEO of Birchcliff. He has more than 35 years of experience in the oil and gas industry and is one of the Corporation’s founders. Prior to creating Birchcliff, Mr. Tonken founded and served as President Tonken and CEO of Case Resources Inc., Big Bear Exploration Ltd. and Stampeder Exploration Ltd. Mr. Tonken was previously a President, Chief Partner of the law firm Howard, Mackie (now Borden Ladner Gervais LLP). Mr. Tonken is a Governor of the Canadian Executive Officer and Association of Petroleum Producers (CAPP). Mr. Tonken received his Bachelor of Commerce degree from the University of Director Alberta and his Bachelor of Laws degree from the University of Wales.

Myles R. Mr. Bosman is the Vice-President, Exploration and Chief Operating Officer of Birchcliff and is a Professional Geologist. He has more than 25 years of experience in the oil and gas industry and is one of the Corporation’s founders. Prior to joining Bosman Birchcliff, Mr. Bosman served as Vice-President, Exploration and Chief Operating Officer of Case Resources Inc.; Vice-President, Exploration Manager of Summit Resources Ltd.; and as an Exploration Geologist with both Numac Energy Inc. and Exploration and Chief Canadian Hunter Exploration. Mr. Bosman received his Bachelor of Science degree in Geology from the University of Operating Officer Calgary and his Resource Engineering diploma from the Northern Alberta Institute of Technology.

Mr. Geremia is the Vice-President and Chief Financial Officer of Birchcliff and is a Chartered Accountant. He has more than Bruno P. 24 years of experience in the oil and gas industry and is one of the Corporation’s founders. Prior to joining Birchcliff, Mr. Geremia served as Vice-President and Chief Financial Officer of both Case Resources Inc. and Big Bear Exploration Ltd.; as Geremia Director, Commercial of Gulf Canada Resources; and as Manager, Special Projects of Stampeder Exploration Ltd. Mr. Vice-President and Chief Geremia was previously a Chartered Accountant with Deloitte & Touche LLP. Mr. Geremia received his Bachelor of Financial Officer Commerce degree from the University of Calgary.

62 EXECUTIVE OFFICERS

Christopher A. Mr. Carlsen was appointed Vice-President, Engineering on July 22, 2013. He previously served as Asset Team Lead and Senior Exploitation Engineer with Birchcliff. Mr. Carlsen is a Professional Engineer with more than 15 years of experience in Carlsen the oil and gas industry. Prior to joining Birchcliff in 2008, he was the Senior Engineer at Greenfield Resources Ltd. and held Vice-President, various engineering positions at both EnCana Corporation and PanCanadian Petroleum Ltd. Mr. Carlsen received his Engineering Bachelor of Science in Chemical Engineering from the University of Saskatchewan.

David M. Mr. Humphreys is the Vice-President, Operations of Birchcliff. He has more than 29 years of experience in the oil and gas industry. Prior to joining Birchcliff in 2009, he served as Vice-President, Operations of Highpine Oil & Gas Ltd., White Fire Humphreys Energy Ltd., and Virtus Energy Ltd.; Production Manager of both Husky Oil Operations Ltd. and Ionic Energy; and as a Vice-President, Senior Production Technologist with Northrock Resources Ltd. Mr. Humphreys received his Hydrocarbon Engineering Operations Technology diploma from the Northern Alberta Institute of Technology.

Mr. Surbey is the Vice-President, Corporate Development of Birchcliff and is a member of the Law Society of Alberta. He has James W. more than 38 years of oil and gas industry experience and is one of the Corporation’s founders. Prior to joining Birchcliff, he served as Vice-President, Corporate Development of Case Resources Inc.; Senior Vice-President, Corporate Development Surbey of Big Bear Exploration Ltd.; and Vice-President, Corporate Development of Stampeder Exploration Ltd. Mr. Surbey was Vice-President, previously a Senior Partner of the law firm Howard, Mackie (now Borden Ladner Gervais LLP). Mr. Surbey received his Corporate Development Bachelor of Engineering degree and Bachelor of Laws degree from McGill University.

63 BOARD OF DIRECTORS Mr. Shaw is a Director of Birchcliff and has more than 28 years of experience in the oil and gas industry and is one of the Larry A. Shaw Corporation’s founders. Prior to joining Birchcliff, Mr. Shaw served as Chairman of the Board of Case Resources Inc., Big Independent Director & Bear Exploration Ltd. and Stampeder Exploration Ltd. He was President of Shaw Automotive Group Ltd. and Shaw G.M.C. Chairman of the Board Pontiac Buick Hummer Ltd. Mr. Shaw received his Honors Degree in Business Administration from the University of Western Ontario.

Kenneth N. Mr. Cullen is a Director of Birchcliff and has more than 34 years of experience working with companies in the oil and gas industry as a partner at Deloitte & Touche LLP in the Assurance and Advisory (Audit) group prior to his retirement in 2006. (Ken) Cullen Mr. Cullen currently serves as a director of Southern Pacific Resource Corp. Mr. Cullen received his Chartered Accountant Independent Director Designation from the Institute of Chartered Accountants of British Columbia.

Mr. Dawson was formerly the Vice-President General Counsel and Corporate Secretary of AltaGas. Mr. Dawson joined AltaGas as Associate General Counsel in August 1997, after consulting with AltaGas Services Inc. from July 1996. Effective Dennis July 1998, he became AltaGas’ General Counsel and Corporate Secretary and effective December 1998, Mr. Dawson became Vice-President General Counsel and Corporate Secretary. Mr. Dawson has over 26 years of oil and natural gas Dawson experience including nine years as General Counsel for Pan-Alberta Gas Ltd., a major Canadian natural gas marketing Independent Director company. Mr. Dawson received his Bachelor of Arts degree from the University of Lethbridge and his Bachelor of Laws degree from the University of Alberta.

Ms. Morley has 15 years of experience in the capital markets, having worked as an Equity Research Associate at TD Securities and GMP Securities and then as a Partner and Research Analyst at Paradigm Capital. Ms. Morley then moved to Rebecca Cypress Capital where she worked as a Research Analyst and Associate Portfolio Manager and was most recently Vice President of Corporate Development at Rayne Capital. Ms. Morley is currently the Chair of the Board of Directors of the Morley YWCA of Calgary, was the Chair of the Audit Committee in 2014 and 2015 and has been a director since 2012. Ms. Morley Independent Director has a Bachelor of Business Administration with a Major in Finance (Honours) from St. Francis Xavier University and is a CFA Charterholder. A. Jeffery Tonken See Mr. Tonken’s biography under “Executive Officers”. Director

64 PRESENTATION OF OIL AND GAS RESERVES AND RESOURCES: Deloitte prepared the 2016 Consolidated Reserves Report, the 2016 Deloitte Reserves Report and the 2015 Deloitte Reserves Report. McDaniel prepared the 2016 McDaniel Reserves Report. In addition, Deloitte prepared the 2015 Resource Assessment. The 2015 Resource Assessment was prepared in accordance with the standards contained in the COGE Handbook and NI 51-101 in effect at the relevant time. In addition, Deloitte or its predecessors, AJM Deloitte and AJM Petroleum Consultants, prepared reserves evaluations in respect of Birchcliff’s oil and natural gas properties effective December 31, 2014 to 2005. Such evaluations were prepared in accordance with the standards contained in NI 51‐101 and the COGE Handbook that were in effect at the relevant time. Reserves and resource estimates stated herein are extracted from the relevant evaluation. There are numerous uncertainties inherent in estimating the quantities of reserves, resources and the future cash flows attributed to those reserves and resources, including many factors beyond the control of Birchcliff. There is no assurance that the forecast prices and costs assumptions will be attained and variances could be material. The recovery, reserves and resource estimates of Birchcliff’s reserves and resources provided herein are estimates only and there is no guarantee that the estimated reserves or resources will be recovered. Actual oil, natural gas and NGL reserves and resources may be greater than or less than the estimates provided herein and variances could be material. All anticipated results disclosed herein were prepared by Deloitte. Deloitte utilized probabilistic methods to generate high, best, and low estimates of reserves and resources volumes. For further information regarding the risks and uncertainties associated with Birchcliff’s resources, please see Birchcliff’s Annual Information Form for the year ended December 31, 2015, a copy of which is available on SEDAR at www.sedar.com. With respect to the disclosure of reserves contained herein relating to portions of Birchcliff’s properties, the estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation. Estimates of future net revenue, whether calculated without discount or using a discount rate, do not represent fair market value. In this presentation, all references to “reserves” are to Birchcliff’s gross company reserves unless otherwise stated. Certain information in this presentation may constitute “analogous information” as defined in NI 51-101, including, but not limited to, the reservoir data, production rates of industry wells, cumulative production information, and economics information relating to the areas in which Birchcliff has an interest. Such information has been obtained from government sources, regulatory agencies or other industry participants. Management of Birchcliff believes the information is relevant as it helps to define the reservoir characteristics and the reserves and production potential in which Birchcliff holds an interest. Such information has not been prepared in accordance with NI 51-101. Birchcliff is also unable to confirm that the analogous information was prepared by a qualified reserves evaluator or auditor. Such information is not an estimate of the resources attributable to lands held or to be held by Birchcliff and there is no certainty that the reservoir data, resource estimates, production and decline rates and economics information for the lands held by Birchcliff will be similar to the information presented herein. The reader is cautioned that the data relied upon by Birchcliff may be in error and/or may prove not to be analogous to the lands be held by Birchcliff. The information set forth in this presentation relating to the reserves and future net revenues of Birchcliff constitutes forward-looking information which are subject to certain risks and uncertainties. See “Advisories – Forward-Looking Information” on Page 2 of this presentation. Definitions Certain terms used herein but not defined are defined in NI 51-101, CSA Staff Notice 51-324 – Revised Glossary to NI 51-101 Standards of Disclosure for Oil and Gas Activities (“CSA Staff Notice 51-324”) and/or the COGE Handbook and, unless the context otherwise requires, shall have the same meanings herein as in NI 51-101, CSA 51- 324 and the COGE Handbook, as the case may be. Reserve Categories Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date, based on the analysis of drilling, geological, geophysical and engineering data; the use of established technology; and specified economic conditions, which are generally accepted as being reasonable. Reserves are classified according to the degree of certainty associated with the estimates: “Proved reserves” are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves. “Probable reserves” are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves. “Possible reserves” are those additional reserves that are less certain to be recovered than probable reserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated proved plus probable plus possible reserves. Development and Production Status of Reserves Each of the reserves categories (proved, probable and possible) may be divided into developed and undeveloped categories: “Developed reserves” are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (e.g., when compared to the cost of drilling a well) to put the reserves on production. The developed category may be subdivided into producing and non‐producing. “Developed producing reserves” are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut‐in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty. “Developed non‐producing reserves” are those reserves that either have not been on production, or have previously been on production but are shut‐in and the date of resumption of production is unknown. “Undeveloped reserves” are those reserves expected to be recovered from known accumulations where a significant expenditure (e.g., when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves category (proved, probable, possible) to which they are assigned. In multi‐well pools it may be appropriate to allocate total pool reserves between the developed and undeveloped categories or to subdivide the developed reserves for the pool between developed producing and developed non‐producing. This allocation should be based on the estimator’s assessment as to the reserves that will be recovered from specific wells, facilities, and completion intervals in the pool and their respective development and production status. Levels of Certainty for Reported Reserves The qualitative certainty levels referred to in the definitions above are applicable to “individual reserves entities”, which refers to the lowest level at which reserves calculations are performed, and to “reported reserves”, which refers to the highest level sum of individual entity estimates for which reserves estimates are presented. Reported reserves should target the following levels of certainty under a specific set of economic conditions: at least a 90% probability that the quantities actually recovered will equal or exceed the estimated proved reserves; at least a 50% probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable reserves; and at least a 10% probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable plus possible reserves. A quantitative measure of the certainty levels pertaining to estimates prepared for the various reserves categories is desirable to provide a clearer understanding of the associated risks and uncertainties. However, the majority of reserves estimates are prepared using deterministic methods that do not provide a mathematically derived quantitative measure of probability. In principle, there should be no difference between estimates prepared using probabilistic or deterministic methods. Resources and Production Resources encompass all petroleum quantities that originally existed on or within the earth’s crust in naturally occurring accumulations, including discovered and undiscovered (recoverable and unrecoverable) plus quantities already produced. Resources are classified as follows: Total PIIP is that quantity of petroleum that is estimated to exist originally in naturally occurring accumulations. It includes that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations, prior to production, plus those estimated quantities in accumulations yet to be discovered. “Total resources” is equivalent to “total PIIP”. Discovered PIIP is that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior to production. The recoverable portion of discovered PIIP includes production, reserves and contingent resources; the remainder is unrecoverable. Contingent resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Undiscovered PIIP is that quantity of petroleum that is estimated, on a given date, to be contained in accumulations yet to be discovered. The recoverable portion of undiscovered PIIP is referred to as prospective resources; the remainder is unrecoverable. Prospective resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Unrecoverable is that portion of discovered and undiscovered PIIP quantities which is estimated, as of a given date, not to be recoverable by future development projects. A portion of these quantities may become recoverable in the future as commercial circumstances change or technological developments occur; the remaining portion may never be recovered due to the physical/chemical constraints represented by subsurface interaction of fluids and reservoir rocks. Production is the cumulative quantity of petroleum that has been recovered at a given date.

65 Uncertainty Ranges for Resources Estimates of resource volumes can be categorized according to the range of uncertainty associated with the estimates. Uncertainty ranges are described in the COGE Handbook as low, best and high estimates as follows: A “low estimate” (1C) is considered to be a conservative estimate of the quantity that will actually be recovered. It is likely that the actual remaining quantities recovered will exceed the low estimate. If probabilistic methods are used, there should be at least a 90% probability (P90) that the quantities actually recovered will equal or exceed the low estimate. A “best estimate” (2C) is considered to be the best estimate of the quantity that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. If probabilistic methods are used, there should be at least a 50% probability (P50) that the quantities actually recovered will equal or exceed the best estimate. A “high estimate” (3C) is considered to be an optimistic estimate of the quantity that will actually be recovered. It is unlikely that the actual remaining quantities recovered will exceed the high estimate. If probabilistic methods are used, there should be at least a 10% probability (P10) that the quantities actually recovered will equal or exceed the high estimate. Project Maturity Subclasses for Resources The project maturity subclasses for contingent resources are “development pending”, “development on hold”, “development unclarified” or “development not viable”, all as defined in the COGE Handbook. “Development pending” is when resolution of the final conditions for development is being actively pursued (high chance of development). “Development on hold” is when there is a reasonable chance of development, but there are major non-technical contingencies to be resolved that are usually beyond the control of the operator. “Development unclarified” is when the evaluation is incomplete and there is ongoing activity to resolve any risks or uncertainties. “Development not viable” is when no further data acquisition or evaluation is currently planned and hence there is a low chance of development. The project maturity subclasses for prospective resources are “prospect”, “lead” and “play”, all as defined in the COGE Handbook. A “prospect” is defined as a potential accumulation within a play that is sufficiently well defined to represent a viable drilling target. A “lead” is defined as a potential accumulation within a play that requires more data acquisition and/or evaluation in order to be classified as a prospect. A “play” is defined as a family of geologically similar fields, discoveries, prospects and leads. Product Types NI 51-101 requires a reporting issuer to disclose its reserves and resources in accordance with the product types contained in NI 51-101, which product types include light crude oil and medium crude oil (combined), conventional natural gas, shale gas and NGL. “Shale gas” as defined in NI 51-101 means natural gas: (i) contained in dense organic-rich rocks, including low-permeability shales, siltstones and carbonates, in which the natural gas is primarily adsorbed on the kerogen or clay minerals; and (ii) that usually requires the use of hydraulic fracturing to achieve economic production rates. With respect to Birchcliff’s natural gas reserves and resources attributable to its Montney/Doig Natural Gas Resource Play, such reserves and resources would most closely fit within the category of shale gas as opposed to conventional natural gas; however, the primary storage mechanism is gas stored in the pore space with contributions from gas adsorbed to kerogen, clay minerals and bitumen. Birchcliff considers that its natural gas reserves and resources attributable to the Montney/Doig Natural Gas Resource Play to be low permeability gas resources or “tight gas” (as such term is defined in the COGE Handbook), a generic term that includes “basin-centred”, “deep gas” and “shale gas”. Although Montney/Doig reservoirs usually consist of low permeability sandstones, siltstones, or shales, they may also contain carbonates. Although a small amount of gas may also be present in natural fractures, extensive hydraulic fracturing is invariably required to produce the “tight gas”. The trapping mechanisms may be the same as for conventional reservoirs, adsorption on kerogen or clays, or relative permeability effects. “Shale gas” is the NI 51-101 product type that most closely matches the natural gas from Birchcliff’s Montney/Doig Natural Gas Resource Play. Interest in Reserves, Resources, Production, Wells and Properties “Gross” means: (a) in relation to Birchcliff’s interest in production, reserves or resources, Birchcliff’s working interest (operating or non‐operating) share before deduction of royalties and without including any royalty interests of Birchcliff; (b) in relation to wells, the total number of wells in which Birchcliff has an interest; and (c) in relation to properties, the total area of properties in which Birchcliff has an interest. “Net” means: (a) in relation to Birchcliff’s interest in production, reserves or resources, Birchcliff’s working interest (operating or non‐operating) share after deduction of royalty obligations, plus Birchcliff’s royalty interests in production or reserves; (b) in relation to Birchcliff’s interest in wells, the number of wells obtained by aggregating Birchcliff’s working interest in each of its gross wells; and (c) in relation to Birchcliff’s interest in a property, the total area in which Birchcliff has an interest multiplied by the working interest owned by Birchcliff. Forecast Prices & Costs “Forecast prices and costs” means future prices and costs that are: (a) generally accepted as being a reasonable outlook of the future; (b) if, and only to the extent that, there are fixed or presently determinable future prices or costs to which Birchcliff is legally bound by a contractual or other obligation to supply a physical product, including those for an extension period of a contract that is likely to be extended, those prices or costs rather than the prices and costs referred to in paragraph (a). Gross Volumes of Reserves and Resources Unless otherwise indicated, all volumes of Birchcliff’s reserves and resources presented herein are on a “gross” basis. Unrisked Volumes Unless otherwise indicated, all volumes of Birchcliff’s resources presented herein are on an unrisked basis, meaning that they have not been adjusted for the chance of commerciality. ADVISORIES: Currency: All amounts in this presentation are stated in Canadian dollars unless otherwise specified. Boe, Mcfe and Tcfe Conversions: Boe amounts have been calculated by using the conversion ratio of 6 Mcf of natural gas to 1 bbl of oil and Mcfe amounts have been calculated by using the conversion ratio of 1 bbl of oil to 6 Mcf of natural gas. Boe, Mcfe and Tcfe amounts may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf: 1 bbl or an Mcfe conversion ratio of 1 bbl: 6 Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value. Conversion from GJ to Mcf – Wellhead Price: Birchcliff receives premium pricing for its natural gas production due to its high heat content from its properties. With respect to Birchcliff’s natural gas hedging contracts in 2017, the prices have been presented in both AECO CDN $/GJ and $/Mcf, with the latter representing the average expected natural gas wellhead price under contract. The conversion from GJ to Mcf is based on an expected corporate average natural gas heat content value of 40.69 MJ/m3 in 2017. Reserves for Portion of Properties: With respect to the disclosure of reserves contained herein relating to portions of Birchcliff’s properties, the estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties due to the effects of aggregation. Future Net Revenue: Estimates of future net revenue, whether calculated without discount or using a discount rate, do not represent fair market value. Possible Reserves: Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves. Discovered Resources: With respect to the discovered resources (including contingent resources) disclosed in this presentation, there is uncertainty that it will be commercially viable to produce any portion of the resources. Undiscovered Resources: With respect to the undiscovered resources (including prospective resources) disclosed in this presentation, there is no certainty that any portion of the resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources. Oil and Gas Metrics: This presentation contains metrics commonly used in the oil and natural gas industry, including netbacks, reserves life index, recycle ratio, reserves replacement, F&D costs and FD&A costs. These oil and gas metrics do not have do not have any standardized meanings or standard methods of calculation and therefore may not be comparable to similar measures presented by other companies where similar terminology is used and should not be used to make comparisons. Such metrics have been included herein to provide readers with additional measures to evaluate Birchcliff’s performance; however, such measures are not reliable indicators of Birchcliff’s future performance and future performance may not compare to Birchcliff’s performance in previous periods and therefore such metrics should not be unduly relied upon. Reserves life index is calculated by dividing reserves estimated by Birchcliff’s independent qualified reserves evaluators at December 31, 2016 by 72,000 boe/d, which production rate represents the mid-point of Birchcliff’s annual average production guidance range for 2017. Reserves life index may be used as a measure of a company’s sustainability. Recycle ratios are calculated by dividing the average operating netback per boe or cash flow netback per boe, as the case may be, by F&D costs and FD&A costs, as the case may be. Recycle ratios may be used as a measure of a company’s profitability.

66 With respect to disclosure of F&D costs disclosed in this presentation: F&D costs including FDC have been presented herein. F&D costs for each reserves category in a particular period are calculated by taking the sum of: (i) exploration and development costs incurred in the period; and (ii) the change during the period in FDC for the reserves category; divided by the additions to the reserves category before production during the period. F&D costs exclude the effects of acquisition and dispositions. In calculating the amounts of F&D costs for a year, the changes during the year in estimated reserves and estimated FDC are based upon the evaluations of Birchcliff’s reserves prepared by Deloitte, Birchcliff’s independent qualified reserves evaluator, effective December 31 of such year. The aggregate of the exploration and development costs incurred in the most recent financial year and any change during that year in estimated FDC generally will not reflect total F&D costs related to reserves additions for that year. F&D costs may be used as a measure of a company’s efficiency with respect to finding and developing its reserves. For information regarding netbacks, please see “Non-GAAP Measures”. Drilling Locations: This presentation discloses net existing horizontal wells and potential net future drilling locations in four categories: (i) proved locations; (ii) probable locations; (iii) unbooked locations; and (iv) an aggregate total of (i), (ii) and (iii). Of the 5,992.8 net existing horizontal wells and potential net future horizontal drilling locations identified herein, 721.7 are proved locations, 974.4 are proved plus probable locations and 5,018.4 are unbooked locations. Proved locations and probable locations are proposed drilling locations identified in the 2016 Consolidated Reserves Report that have proved and/or probable reserves, as applicable, attributed to them in the 2016 Consolidated Reserves Report. Unbooked locations are internal estimates based on Birchcliff’s prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal technical analysis review. Unbooked locations have been identified by management based on evaluation of applicable geologic, seismic, engineering, production and reserves information. Unbooked locations do not have proved or probable reserves attributed to them in the 2016 Consolidated Reserves Report. With respect to the 200 drilling locations identified at the Worsley property, 62 horizontal locations were included in the 2016 Reserves Evaluation prepared by Deloitte LLP as Proved locations, 71 were included as Probable locations and an additional 24 horizontal locations were identified as Possible locations. The remaining locations are based on are internal estimates on Birchcliff’s prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal technical analysis review. With respect to the 300 Charlie Lake Light Oil locations identified in this presentation, this estimate is based on the 200 horizontal Charlie Lake Light Oil locations identified at the Worsley property (as disclosed above) plus an internal estimate including unbooked locations at the Progress Charlie Lake property based on Birchcliff’s prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal technical analysis review. Birchcliff’s ability to drill and develop these locations and the drilling locations on which Birchcliff actually drills wells depends on a number of uncertainties and factors, including, but not limited to, the availability of capital, equipment and personnel, oil and natural gas prices, capital and operating costs, inclement weather, seasonal restrictions, drilling results, additional geological, geophysical and reservoir information that is obtained, production rate recovery, gathering system and transportation constraints, net price received for commodities produced, regulatory approvals and regulatory changes. As a result of these uncertainties, there can be no assurance that the potential future drilling locations that Birchcliff has identified will ever be drilled or if Birchcliff will be able to produce oil, NGLs or natural gas from these or any other potential drilling locations. As such, Birchcliff’s actual drilling activities may differ materially from those presently identified, which could adversely affect Birchcliff’s business. While certain of the unbooked drilling locations have been derisked by drilling existing wells in relative close proximity to such unbooked drilling locations, some of the other unbooked drilling locations are farther away from existing wells where management has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty that such wells will result in additional proved or probable reserves, resources or production. Test Results and Initial Production Rates: References in this presentation to production test rates, initial test production rates and other short-term production rates are useful in confirming the presence of hydrocarbons; however, such rates are not determinative of the rates at which such wells will continue to produce and decline thereafter and are not indicative of the long-term performance or of the ultimate recovery of such wells. Additionally, such rates may also include recovered “load oil” or “load water” fluids used in well completion stimulation. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production for Birchcliff. [A pressure transient analysis or well-test interpretation has not been carried out in respect of all wells.] Accordingly, Birchcliff cautions that the test results should be considered to be preliminary. Operating Costs: References in this presentation to “operating costs” exclude transportation and marketing costs. Payment of Dividends: The declaration of dividends in any quarter and the amount of such dividends, if any, is subject to the discretion of Birchcliff’s board of directors and may vary depending on a variety of factors and conditions existing from time to time, including fluctuations in commodity prices, the financial condition of Birchcliff, production levels, results of operations, capital expenditure requirements, working capital requirements, debt service requirements, operating costs, royalty burdens, foreign exchange rates, interest rates, contractual restrictions, Birchcliff’s hedging activities or programs, available investment opportunities, any credit ratings applicable to Birchcliff or its securities, Birchcliff’s business plan, strategies and objectives, the satisfaction of the solvency and liquidity tests imposed by the Business Corporations Act (Alberta) for the declaration and payment of dividends and other factors that Birchcliff’s board of directors may deem relevant. The payment of cash dividends to common shareholders in the future is not assured or guaranteed and dividends may be reduced or suspended. Birchcliff’s dividend policy will be periodically reviewed by its board of directors and no assurance or guarantee can be given that Birchcliff will maintain the dividend policy in its current form. For further information regarding the risks and uncertainties regarding the payment of dividends, please see Birchcliff’s presentation dated November 9, 2016. NON-GAAP MEASURES: This presentation uses “cash flow”, “cash flow per common share”, “netback”, “operating netback”, “cash flow netback”, “estimated operating netback”, “operating margin”, “total cash costs”, “profit”, “profit margin” and “total debt”. These measures do not have standardized meanings prescribed by GAAP and therefore may not be comparable to similar measures presented by other companies where similar terminology is used. Management believes that these non-GAAP measures assist management and investors in assessing Birchcliff’s profitability, efficiency, liquidity and overall performance. Each of these measures is discussed in further detail below. “Cash flow” denotes cash flow from operating activities before the effects of decommissioning expenditures and changes in non-cash working capital. “Cash flow per common share” denotes cash flow divided by the basic or diluted weighted average number of common shares outstanding for the period. Management believes that cash flow, cash flow from operations and cash flow per common share assist management and investors in assessing Birchcliff’s profitability, as well as its ability to generate the cash necessary to fund future growth through capital investments, pay dividends and repay debt. The following table provides a reconciliation of cash flow from operating activities, as determined in accordance with IFRS, to cash flow from operations:

“Netback” and “operating netback” denote petroleum and natural gas revenue less royalties, less operating expenses and less transportation and marketing expenses. “Estimated operating netback” of the PC Gas Plant (and the components thereof) is based upon certain cost allocations and accruals directly attributable to the PC Gas Plant and related wells and infrastructure on a production month basis. “Cash flow netback” denotes petroleum and natural gas revenue less royalties, less operating expenses, less transportation and marketing expenses, less net general and administrative expenses, less interest expenses and less any realized losses (plus realized gains) on financial instruments and plus any other cash income sources. All netbacks are calculated on a per unit boe basis, unless otherwise indicated. Management believes that netback, operating netback, estimated operating netback and cash flow netback assist management and investors in assessing Birchcliff’s profitability and its operating results on a per unit basis to better analyze its performance against prior periods on a comparable basis. The following table provides a breakdown of operating netback and cash flow netback:

“Operating margin” for the PC Gas Plant is calculated by dividing the estimated operating netback for the period by the petroleum and natural gas revenue for the period. Management believes that operating margin assists management and investors in assessing the profitability and efficiency of the PC Gas Plant and Birchcliff’s ability to generate operating cash flows (equal to petroleum and natural gas revenue less royalties, less operating expenses and less transportation and marketing expenses). “Total cash costs” are comprised of royalty, operating, transportation and marketing, general and administrative and interest expenses. Total cash costs are calculated on a per boe basis. Management believes that total cash costs assists management and investors in assessing Birchcliff’s efficiency and overall cash cost structure. “Profit” measures the amount, if any, during the relevant period by which revenues resulting from production exceed the sum of: (i) PDP FD&A (i.e. the costs of replacing production), (ii) royalty, operating and transportation and marketing expenses and, in the case of Birchcliff at the business-entity level, (iii) general and administrative expense, and (iv) interest expense. This measure is not intended to represent net income or net income to common shareholders as presented in accordance with IFRS. “Profit margin” is calculated by dividing profit for the period by petroleum and natural gas revenue for the period. Birchcliff believes that profit and profit margin are useful measures as they assist management and investors in assessing Birchcliff’s ability during a period of declining commodity prices to bear all of its total cash costs and the costs of replacing its production during the relevant period. Birchcliff does not believe that this measure can be properly reconciled to any GAAP measure. “Total debt” is calculated as the revolving term credit facilities plus adjusted working capital deficit. Management believes that total debt assists management and investors in assessing Birchcliff’s liquidity. The following table provides a reconciliation of the revolving term credit facilities, as determined in accordance with IFRS, to total debt:

67 THANK YOU TEAM BIRCHCLIFF

Jeffrey Akeroyd, Karen Allen, Camille Ashton, Rainer Augsten, Gates Aurigemma, Al Basnett, Angela Belbeck, Charmaine Belley, Tyrus Bender, Tim Berg, Perry Billard, Deborah Borthwick, Myles Bosman, Jeff Boswell, Robyn Bourgeois, David Boyle, Wayne Brown, James Burke, Madison Burns, Chris Carlsen, Alex Carlson, Caitlin Carrigy, Robert Charchuk, David Christensen, Bob Clark, Owen Clarke, Wendy Clay, Mike Cordingley, Ken Cullen, Krystal Dafoe, Dennis Dawson, Allan Dixon, Jesse Doenz, Joe Doenz, Keifer Dolen, Kelly Dolen, Emily Ebbels, Tim Etcheverry, Laura Ferguson, Jaryn Flower, Gordon Forbes, Grant Friesen, Marshall Fritz, George Fukushima, Andy Fulford, Carrie Fyfe, Alexandra Gatza, Bruno Geremia, Melina Geremia, Valerie Gertsch, Melodie Gilker, Chad Goddard, Jolanda Goertzen, David Graham, Bob Grisack, Tania Haberlack-Dolan, Ratha Halford, Sam Hampton, Theresa Hannouche, Trevor Harley, Richard Harris, Wanda Hiebert, Lorna Hildebrand, Paul Hirsekorn, Janet Hogan, Jasen Holmstrom, Daryl Hudak, Dave Humphreys, Derek Jamieson, Anna Johnson, Dave Johnson, Julie Johnson, Stacy Johnson, Dustin Kelm, Ryan Kennedy, Phyllis Kinzner, Diane Knoblauch, Heather Kwiatkowski, Dani Laird, Kristen Lewicki, Michael Lillejord, Thomas Lundquist, Joe Lyste, Scott MacDermott, John MacGillivray, Dallas MacLean, Darcy Macleod, Mary MacNeill, Janice Malainey, Maggie Malapad, Valerie Martin, Jeff McAndrews, Deb McFee, Angie McGonigal, Marc McIntosh, Ryan McIntosh, Darin McLarty, Jerilyn McLeod, Danielle McPhee, Richard Melling, Paul Messer, Melissa Meyers, Al Michetti, Emelyia Moghaddami, Tyler Montpellier, Ron Morgan, Stephen Morton, Shaun Moskalyk, Steve Mueller, Mckenzie Murdoch, Ed Murphy, Tyler Murray, Sarah Nance, Michael Ng, Marcel Njongwe, Christopher Olson, Laura O'Neill, Darlene Orr, Philomena Paisley, Bruce Palmer, Bill Partridge, Dean Paterson, Brenda Pearson, Paul Picco, Allan Pickel, Landon Poffenroth, Lindsay Postma, Shoni Proctor, Dale Richardson, Brian Ritchie, Michelle Rodgerson, Jeff Rogers, Sherri Rosia, Randy Rousson, Todd Sajtovich, Lee Sallenbach, Victor Sandhawalia, Andreas Scheel, Wade Schultz, Daniel Sharp, Larry Shaw, Amy Short, Nick Sizer, Ryan Sloan, Dwayne Spelay, Ben Stevenson, Darby Stolk, Lindsay Sturrock, Tracey Suchlandt, Jim Surbey, Jeff Tonken, Annie Tonken, Gillian Topping, Hue Tran, Tammy Tran, Trevor Trudeau, Becky Van De Reit, Theo van der Werken, Kara Vance, Greg Vreim, Linda Wang, Matthew Weiss, David Wetta, Jonathan White, Chris Wurz, John Yeo, Deirdre Yuzwa, Steve Zylinski

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