CORPORATE PRESENTATION November 2017 FORWARD-LOOKING INFORMATION: - - PowerPoint PPT Presentation

CORPORATE PRESENTATION

November 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

• ther 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; the Asset Sales, including the total expected proceeds from the Asset Sales; the 2017 Capital Program and Birchcliff’s proposed exploration and development activities and the timing thereof, including the amount and allocation of capital expenditures, the number and types of wells to be drilled and brought on production and the timing thereof, estimates of total and net capital expenditures, 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: that the Asset Sales will be completed on the terms and the timing anticipated; the ability to obtain any necessary regulatory approvals and the satisfaction of all conditions to the Asset Sales; the scope of and the effects of the expected benefits of the Asset Sales; Birchcliff’s ability to continue to develop its assets and obtain the anticipated benefits therefrom; 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 2017 Capital Program (including estimates of capital expenditures and statements that the entirety of the 2017 Capital Program will be fully funded out of Birchcliff’s forecast 2017 funds flow from operations and the proceeds from the Asset Sales), such program is based on the following commodity price and

exchange rate assumptions during 2017: an annual average WTI price of approximately US$50.00 per bbl of oil (revised from US$55.00 as announced on February 8, 2017); an AECO price of approximately CDN $2.35 per GJ of natural gas (revised from $3.00 as announced on February 8, 2017); and an exchange rate of CDN$/US$

• f 1.30.
• With respect to Birchcliff’s estimates of capital expenditures, such estimates assume that the 2017 Capital Program will be carried out as currently contemplated and, in the case of its estimate of net capital expenditures and, that the Asset Sales are completed on the terms and timing anticipated.
• The amount and allocation of capital expenditures for exploration and development activities by area and the number and types of wells to be drilled is dependent upon results achieved and is subject to review and modification by management on an ongoing basis throughout the year. Actual spending may vary

due to a variety of factors, including commodity prices, economic conditions, results of operations and costs of labour, services and materials.

• 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
• ccur 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: that the Asset Sales do not close on the terms or the timing anticipated or at all; the failure to obtain any required approvals or satisfy other closing conditions for the Asset Sales in a timely manner or at all; the failure to realize the anticipated benefits of acquisitions and dispositions, including the Asset Sales; 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 “Asset Sales” refers to a series of agreements Birchcliff has either completed or entered into for expected total proceeds to Birchcliff of approximately $142 million ($132 million in cash; $10 million in securities) (subject to closing adjustments). The Assets Sales collectively represent forecast 2017 production of 3,600 boe/d (approximately 62% light oil and NGLs) “Deloitte” means Deloitte LLP, independent qualified reserves evaluator to the Corporation. “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

4 Corporate Snapshot & Select Guidance

Q3 2017 average production 65,276 boe/d Estimated 2017 annual average production 67,000 – 68,000 boe/d % oil and NGL 21% Estimated Q4 2017 average production 79,000 – 80,000 boe/d % oil and NGL 20% Estimated 2017 net capital expenditures (millions) $262 Total debt as at September 30, 2017 (millions) $667 Credit facilities limit as at September 30, 2017 (millions) $950 Common shares (basic) as at September 30, 2017 (millions) 266 Q4/17 natural gas hedging summary % of Q4/17 natural gas production hedged 48% Average Price (CDN$/Mcf)(1) $3.51 Market capitalization as at September 30, 2017 (billions) $1.6 Enterprise value as at September 30, 2017 (billions)(2) $2.3 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(3) 5,703.1 Gross proved developed producing reserves as at December 30, 2016(4) 165,507 Mboe Gross proved plus probable reserves as at December 30, 2016 (4) 880,464 Mboe TSX 300 BIR, BIR.PR.A, BIR.PR.C Quarterly dividend to common shareholders $0.025/sh

(1) The conversion from GJ to Mcf is calculated using an estimated corporate average heat content value of 40.80 MJ/m3 for 2017. (2) Enterprise value is calculated by multiplying the closing price of the common shares on the TSX by the total number of common shares outstanding as at December 31, 2016 and adding total debt as at December 31, 2016, including the face value of the Series A Preferred Shares and Series C Preferred Shares. (3) See “Advisories – Drilling Locations”. (4) See appendix at the end of this presentation for disclosures on oil & gas reserves and related metrics.

• Record quarterly average production of 65,276 boe/d, a 20% increase from

54,538 boe/d in Q3 2016

• Cash flow of $64.4 million ($0.24/basic common share), a 55% increase from

$41.7 million ($0.18/basic common share) in Q3 2016

• Drilled a total of 9 (9.0 net) wells in the Q3 2017, consisting of 6 (6.0 net)

Montney/Doig horizontal natural gas wells in Pouce Coupe, 1 (1.0 net) Montney/Doig vertical science and technology well in Pouce Coupe and 2 (2.0 net) Montney horizontal oil wells in Gordondale

• Paid quarterly dividend to common shareholders in the amount of

$0.025/common share for the quarter ended September 30, 2017

• Completed the sale of the Worsley Charlie Lake Light Oil Pool for approximately

$100 million (prior to closing adjustments)

Q3 2017 HIGHLIGHTS

5

• Focused assets in the Peace River Arch Area of Alberta on the Montney/Doig

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 260

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 years as at December 31, 2016
• 346 (340.7 net) Montney/Doig horizontal wells drilled as at September 30, 2017
• 5,703.1 net future potential Montney/Doig horizontal drilling locations as at December

31, 2016(3)

• To-date in 2017, Birchcliff has completed a number of asset sales, including the sale
• f the Worsley Charlie Lake Light Oil Pool, for total proceeds of approximately $148

million (prior to closing adjustments)

INVESTMENT HIGHLIGHTS

6

(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”.

HEDGING SUMMARY

2017 Natural Gas Hedging Summary MMcf/d(1) $CDN/Mcf(1) Q1 2017 157.0 $3.44 Q2 2017 157.0 $3.44 Q3 2017 157.0 $3.44 Q4 2017 182.7 $3.51 7

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

(1) The conversion from GJ to Mcf is calculated using an estimated corporate average heat content value of 40.80 MJ/m3 for 2017

2017 Crude Oil Hedging Summary bbl/d $CDN/bbl Q1 2017 1,500 $69.90 Q2 2017 1,500 $69.90 Q3 2017 1,500 $69.90 Q4 2017 1,500 $69.90

Approximately 20% of estimated 2017 crude oil production is hedged at an average WTI price of CDN$69.90/bbl

BIRCHCLIFF’S HISTORY

A Track Record of Execution

KEYS TO SUCCESS

Management ▪ Executives with proven track record, continuity since inception and significant ownership ▪ Highly experienced Management Team with excellent technical knowledge and a long history with the company Operational Execution ▪ 346 (340.7 net) Montney/Doig horizontal wells drilled to September 30, 2017 all utilizing multi-stage fracture stimulated technology ▪ Construction of the 260 MMcf/d PC Gas Plant in five separate phases on time and on budget ▪ Own, control or have access to infrastructure and operate 99% of production Technical Expertise ▪ Significant in-house technical expertise and experience on the Peace River Arch ▪ Supports continual improvements in high grading portfolio for the decision making process ▪ Continued improvements in estimated reserve recovery per well, drilling & completion practices and

• perating costs

Scale & Repeatability ▪ Consistent, repeatable, predictable growth and results ▪ 5,703.1 potential Montney/Doig horizontal locations and as at December 31, 2016(1) Financial Execution ▪ Full cycle profitability with top tier F&D costs and netbacks through 2016 and prior years ▪ Accurate and reliable real time forecasts supported by a detailed capital management and production forecasting process which is fully integrated into our financial reporting systems 9

(1) See “Advisories – Drilling Locations”

PRODUCTION HISTORY

2,793 5,368 6,711 10,148 11,216 13,079 18,136 22,802 25,829 33,734 38,950 49,236 10,000 20,000 30,000 40,000 50,000 60,000 70,000 80,000 90,000 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017E Q4/17E Average Production (boe/d)

Compound annual growth of 30% per year since 2005 10

67,000 – 68,000 79,000 – 80,000

100,000 200,000 300,000 400,000 500,000 600,000 700,000 800,000 900,000 1,000,000 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 Reserves (Mboe)(1) PDP TP 2P

CORPORATE RESERVES

11

166 MMboe 549 MMboe 880 MMboe

On a per share basis PDP, 1P and 2P reserves have increased at a compound annual growth rate of 14%, 22% and 23% per year since 2005, respectively

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

$0 $1,000 $2,000 $3,000 $4,000 $5,000 $6,000 $7,000 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 NPV10 ($million) PDP TP 2P

CORPORATE NPV10 (BT)

12

$1.9 Billion $4.1 Billion $5.8 Billion

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

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

PROVEN TRACK RECORD AS A LOW COST PRODUCER

Profitability Breakdown: 2012 2013 2014 2015

2016

5 Year 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%

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

3.7x 1.2x 1.2x 1.8x 1.4x 1.3x 2.3x 1.3x 2.0x 1.8x 4.7x 1.7x 2.6x 1.2x 2.0x 1.9x 7.3x 1.8x $0 $4 $8 $12 $16 2011 2012 2013 2014 2015 2016 F&D Cost ($/boe) PDP F&D 1P F&D 2P F&D

PROVEN TRACK RECORD AS A LOW COST FINDER

14

Cash flow netback recycle ratios

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

LOOKING FORWARD

2017 Plans & Beyond

2017 CAPITAL PROGRAM

16

2017 CAPITAL PROGRAM(1)

Gross Wells Net Wells Capital ($millions)(1) Difference in Capital ($millions) (1) Drilling & Development New Old New Old New Old Pouce Coupe – Montney D1 HZ Gas Wells 26 22 26.0 22.0 113.9 86.1 27.8 Pouce Coupe – Basal Doig/Upper Montney HZ Gas Wells 7 7 7.0 7.0 30.6 30.2 0.4 Pouce Coupe – Montney D4 HZ Gas Wells 3 3 3.0 3.0 13.0 12.9 0.1 Pouce Coupe – Montney/Doig Vertical Science/Technology Well(2) 1

• 1.0
• 3.0
• 3.0

Gordondale – Montney D2 HZ Oil Wells 9 7 9.0 7.0 45.9 40.7 5.3 Gordondale – Montney D1 HZ Oil Wells 5 5 5.0 5.0 27.2 28.9 (1.7) Gordondale – Montney D1 HZ Gas Wells 2 2 2.0 2.0 11.4 11.6 (0.2) 2018 Pre-Spend Capital(3) 1

• 1.0
• 9.9
• 9.9

2016 Carry Forward Capital(4)

• 17.0

19.4 (2.4)

Total Drilling & Development(5) 54 46 54.0 46.0 $272.0 $229.8 $42.2

Facilities & Infrastructure(6) 87.7 85.6 2.1 Production Optimization(7) 23.9 19.4 4.5 Land & Seismic 4.5 4.6 (0.0) Other 15.9 15.9 0.0

Total Capital $404.0 $355.2 $48.8

Acquisitions & Dispositions(8) (141.6) (0.2) (141.4)

Total Net Capital $262.4 $355.0 $(92.6)

(1) Numbers may not add due to rounding. (2) Capital includes pad construction, drilling and core cutting and analysis. (3) Capital includes the drilling of 1 (1.0) Montney D1 horizontal natural gas well in Pouce Coupe, 3 surface holes and surface pad construction in anticipation of our 2018 drilling program. (4) Primarily completion, equipping and tie-in costs associated with 10 (10.0 net) wells rig released at the end of 2016. (5) All drilling and development costs have been presented on a drill, case, complete, equip and tie-in basis except for 1 Montney D1 well referred to in note (3) above and the Montney/Doig vertical science/technology well. (6) Includes approximately $26.3 million of capital in 2017 for the Phase V expansion and $26.5 million of capital in 2017 for the Phase VI expansion. (7) Includes $12.3 million of sustaining capital. (8) The 2017 Capital Program has been presented on both a total and net basis (net of acquisitions and dispositions). Dispositions that have been completed or announced at the date of this presentation have been accounted for in the table above.

2017 CAPITAL PROGRAM

• Given our completed and planned dispositions for 2017, our board of directors

has approved an increase to our capital expenditure budget for 2017 to approximately $404 million, up from $355 million that was previously announced

• Net capital expenditures in 2017 are expected to be approximately $262 million
• The additional capital under our increased 2017 Capital Program will be

primarily directed towards the infrastructure needed for the Phase VI expansion

• f our Pouce Coupe Gas Plant and the drilling of eight additional wells
• After giving effect to the anticipated dispositions and expanded capital

program, 2017 annual average production is expected to be 67,000 to 68,000 boe/d and fourth quarter average production is expected to be 79,000 to 80,000

17

BORROWING BASE DETAILS

• Birchcliff has extendible revolving credit facilities in the aggregate principal

amount of $950 million, which are comprised of an extendible revolving syndicated term credit facility of $900 million and an extendible revolving working capital facility of $50 million

• Birchcliff’s syndicate of lenders completed their semi-annual review, and have

agreed to an extension of the maturity dates from May 11, 2018 to May 11, 2020 and to the borrowing base remaining unchanged at $950 million

• In addition, the lenders have consented to the disposition of the Charlie Lake

Light Oil Resource Play and to the borrowing base remaining at $950 million after giving effect to such disposition

• The credit facilities contain no financial maintenance covenants
• At September 30, 2017, Birchcliff’s long-term bank debt was $585.3 million,

leaving $342.4 million of unutilized credit capacity after adjusting for

• utstanding letters of credit and unamortized interest and fees

18

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 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

20 Birchcliff Montney/Doig

MONTNEY/DOIG MINEROLOGY LEADS TO EXCELLENT “FRACABILITY”

21

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

• system. This simple bi-wing fracture system can lead to less

stimulated rock volume, which in tight shale reservoirs can lead to less effective long term hydrocarbon production rates and EUR’s.

• 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 as at December 31, 2016

• Birchcliff has contiguous land block at

Pouce Coupe and Gordondale of approximately 260 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
• f PC Gas Plant & surrounding

infrastructure

• Low decline production

22

(1) See “Advisories – Drilling Locations”

BIRCHCLIFF MONTNEY/DOIG

STACKED RESOURCE PROVIDES SUBSTANTIAL FUTURE UPSIDE

23

MONTNEY/DOIG MULTI LAYER OPPORTUNITY

24

1 2 3 4 5 6 1 2 3 4 5 6

Montney/Doig Production Owned Infrastructure PC Gas Plant Nova Pipeline System North American Market LNG Export

PROXIMAL TO INFRASTRUCTURE WITH LONG TERM EXPOSURE TO LNG EXPORT

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

Birchcliff Pouce Coupe Montney/Doig & PC Gas Plant 25

POUCE COUPE OVERVIEW

• Proven asset in development phase
• Wells show high initial deliverability,

low terminal decline and stable long term production

• Predictable results with improving

rates & liquids yields

• 100% owned and operated
• Expect to drill 36 (36.0 net)

Montney/Doig horizontal natural gas wells and 1 (1.0 net) vertical science and technology well in 2017

• 2017 program will focus on evolving

completion techniques including an increased number of stages and higher frac intensity

• No land expiry issues

26

1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000 10,000 2 4 6 8 10 12 Gas Rate (Mcfd) Normalized Producing Time (Months)

Lower Montney (D1) Wells 2016 Lower Montney (D1) Wells 2017 Lower Montney (D1) Wells

POUCE COUPE LOWER MONTNEY (D1) PERFORMANCE VS. TYPE CURVE

27

Deloitte Tier 0 Type Curve IP (un-choked): 6.9 MMcf/d IP (choked): 4.0 MMcf/d 2P Reserves: 8.2 Bcfe(1)

(1) 2P reserves calculated using of 3% and CGR of 3.9 bbl/MMcf

Tier 0

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 & NGLs 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

28

GORDONDALE BASE PRODUCTION HISTORY

Last well drilled in 2014 (on-stream 2015) with peak production of ~35,000 boe/d AltaGas Deep Cut Plant on stream October 2012 and Montney oil pool development commenced Horizontal gas development in late 2000s Montney oil pool discovered in 2010 Montney D2 discovery well

Production (boe/d)

GORDONDALE OVERVIEW

• Drilled 6 (6.0 net) Montney horizontal
• il and natural gas wells in 2016

including three Montney D2 oil wells and three Montney D1 natural gas wells; early results from all 6 wells are meeting or exceeding expectations

• The 2017 drilling program is now

complete and included 16 (16.0 net) horizontal wells including 9 Montney D2 oil wells, 5 Montney D1 oil wells and 2 Montney D1 natural gas wells

30

GORDONDALE KEY INFRASTRUCTURE

Key Natural Gas Processing Infrastructure AltaGas Gordondale Sour Deep Cut Gas Plant 16-31-078-11W6 Licensed Capacity: ~135 MMcf/d Current BIR Rate: ~100 MMcf/d CNRL Progress Sour Shallow Cut Gas Plant 01-01-078-10W6 Acquired W.I.: ~10% Licensed Capacity: ~130MMcf/d Current Rate: ~125 MMcf/d

31

Key Light Oil Handling Infrastructure Birchcliff Oil Battery 02-06-079-11W6 Capacity: ~10,000 bbl/d Birchcliff Oil Battery 07-29-078-11W6 Capacity: ~10,000 bbl/d

Alliance Pipeline NGTL

Acquired Encana Compressors Birchcliff Sour Compressor Station 02-05-079-11W6 Capacity: ~12 MMcf/d Birchcliff Sour Compressor Station 05-27-078-11W6 Capacity: ~32 MMcf/d Birchcliff Sour Compressor Station 16-19-077-10W6 Capacity: ~21 MMcf/d

• Existing infrastructure has already

supported peak production of ~35,000 boe/d

• Natural gas is primarily processed at

the AltaGas Deep Cut Sour Gas Plant which has a processing capacity of ~135 MMcf/d

• Includes two light oil batteries with

combined oil handling capacity of 20,000 bbl/d (100% W.I.)

• Includes a non-operated W.I. of

~10% in CNRL Progress Gas Plant, adding to Birchcliff’s existing 3% W.I.

• Third party processing and

transportation agreements, including firm transportation capacity on the Pembina pipeline system

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

ELMWORTH DEVELOPMENT

• Received regulatory approval for an

acid gas injection well in August 2016

• Preliminary planning underway for a

100% owned and operated 40 MMcf/d natural gas processing plant; currently expected to be operational in the fall of 2022

• Drilled two successful exploration

horizontal wells into the Montney D4 interval, both of which are expected to result in follow up drilling and significant future reserve additions

• Will leverage over 10 years of

Montney experience

32

Second Exploration Horizontal First Exploration Horizontal Approved Acid Gas Injection Well

CONCEPTUAL MONTNEY/DOIG FIELD DEVELOPMENT MODEL

33

STATUS OF MODEL CALLIBRATION AND DERISKING

FACIES & PETROPHYSICAL GEOLOGICAL, GEOPHYSICAL, GEOMECHANCAL HYDRAULIC FRAC & MICRO SEIS. RESERVOIR MODEL OPTIMIZED DCC & PRODUCTION BASAL DOIG / D5 D4 D3 D2 D1 C T1 T2 >T0 >T4 >T0

1000 2000 3000 4000 5000 $- $500 $1,000 $1,500 $2,000 $2,500 $3,000 Measured Depth (m) Cost ($000’s)

POUCE COUPE DRILLING PERFORMANCE

34

100 150 200 250 300 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 mD/Day Yearly Average Drill Speed ( Spud – Rig Release) $350 $400 $450 $500 $550 $600 $650 $700 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 $/mD Drill Cost Efficiency 1,000 2,000 3,000 4,000 5,000 1 3 5 7 9 11 13 15 17 19 21 23 25 27 Measured Depth (m) Days from Spud 2016

2015 2014 2007 - 2013

2016

2015 2014 2007 - 2013 Drilling 10 days faster and 1,000 meters longer than 2007 20% less cost for drilling operations compared to 2015 35% decrease in $/mD from 2007 Drilling twice as fast as 2007

POUCE COUPE LOWER MONTNEY (D1) CORE AREA COMPLETION EVOLUTION

35

5 10 15 20 25 30 $0 $50 $100 $150 $200 $250 $300 2012 2013 2014 2015 2016 2017E Average Number of Stages (#) Completion Cost Per Stage ($000's)

Completion Cost per Stage vs. Number of Stages

40 80 120 160 200 0.00 0.20 0.40 0.60 0.80 1.00 2012 2013 2014 2015 2016 2017E Average Interfrac Spacing (m) Average Proppant Intensity (t/m)

Proppant Intensity

Completion Parameter 2012 2013 2014 2015 2016 2017E Completion Fluid (# of Wells) Surfactant SLW/ X-linked SLW/ X-linked SLW SLW / X-linked SLW SLW 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

ENGINEERED COMPLETIONS FOR MONTNEY/DOIG FULL FIELD DEVELOPMENT

36

Industry Range Birchcliff Best Practices Oil Birchcliff Best Practices Gas Liner type Openhole or Cemented Openhole or Cemented 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.

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

37

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%

PC GAS PLANT

The Engine for Future Growth

Production Processed through the PC Gas Plant 2012 2013 2014 2015 2016 9 Months 2017

Average daily production, net to Birchcliff: Natural gas (Mcf)

59,327 91,666 132,808 163,641 168,444 173,351

Oil & NGLs (bbls)

204 527 1,065 1,287 960 1,146

Total boe (6:1)

10,092 15,805 23,200 28,560 29,034 30,038

% of corporate natural gas production

56% 73% 78% 81% 68% 58%

% of corporate production

44% 61% 69% 73% 59% 47%

Average AECO price for period ($/Mcf)

$2.39 $3.17 $4.50 $2.69 $2.16 $2.31

Netback and cost:

$/Mcfe $/boe $/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 3.05 18.28

Royalty expense

(0.11) (0.67) (0.16) (0.93) (0.24) (1.42) (0.11) (0.63) (0.06) (0.38) (0.08) (0.48)

Operating expense (2)

(0.35) (2.08) (0.37) (2.24) (0.42) (2.52) (0.31) (1.90) (0.25) (1.49) (0.35) (2.07)

Transportation and marketing expense

(0.23) (1.37) (0.25) (1.55) (0.30) (1.81) (0.31) (1.88) (0.33) (1.96) (0.34) (2.08)

Estimated operating netback

$2.22 $13.32 $2.99 $17.92 $4.21 $25.27 $2.44 $14.62 $1.90 $11.38 $2.28 $13.65

Operating margin

76% 76% 79% 79% 81% 81% 77% 77% 75% 75% 75% 75%

• 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

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

39

KEY STRATEGIC ADVANTAGES

• 100% owned and operated
• Generates operating cost savings of

approximately $1.00/Mcf vs. third party processing of an equivalent gas plant

• Provides flexibility to adjust

development pace at minimal cost and maximize profitability

• Control of the gas plant, infrastructure

and two acid gas disposal wells provide predictable run times and the ability to consistently meet production and budget targets

40

0% 20% 40% 60% 80% 100% $0.00 $2.00 $4.00 $6.00 $8.00 $10.00 2009 2010 2011 2012 2013 2014 2015 2016 Volume Through PC Gas Plant Corporate Operating Cost ($/boe)

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

Corporate operating costs, net of recoveries ($/boe) % of total natural gas sales volumes processed at PC Gas Plant $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 5,000 10,000 15,000 20,000 25,000 30,000 35,000 2011 2012 2013 2014 2015 2016 AECO/PC Op. Netback ($/Mcfe PC Plant Production (boe/d)

Average AECO Price vs. PC Operating Netback

Produciton processed through the PC Gas Plant (boe/d) Average AECO Price ($/Mcf) PC operating netback ($/Mcfe)

PC GAS PLANT HIGHLIGHTS

• Current processing capacity of 260

MMcf/d

• Phase V expansion was completed

ahead of it’s initially scheduled October 1, 2017 completion date, adding 80 MMcf/d bringing total processing capacity to 260 MMcf/d

• Expect Phase VI expansion will be

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 be completed in mid 2020, bringing total processing capacity from 340 MMcf/d to 490 MMcf/d

41

58% 42%

9 Month 2017 Natural Gas Volumes Processed at PC Gas Plant Other 9 Month 2017 Natural Gas Volumes

BUILDING ON OUR PAST

Over 10 Years of Success

43

2004 2018 Forecasted record annual average production of 67,000-68,000 boe/d in 2017

Birchcliff’s average daily production was 49,236 boe/d in 2016 compared to 2,793 boe/d in 2005, a compounded annual growth rate of 30% per year over that span.

1

July 6, 2004: Birchcliff incorporated as a private corporation. 2005: i) Completed $60 million equity financing & common shares commenced trading on the TSX Venture. ii) Rig released first Montney/Doig vertical exploration gas well drilled by Birchcliff in the Pouce Coupe Area. iii) Completed acquisition of properties in the Peace River Arch for $242.8 million. iv) Common shares commenced trading on the TSX. 2007: i) Rig released first Montney/Doig horizontal natural gas well drilled by Birchcliff in the Pouce Coupe Area. ii) Completed acquisition of the Worsley Charlie Lake light oil Property for $270 million. 2008: Rig released first Charlie Lake horizontal light oil well in the Worsley area. 2010: i) Phase I of the PC Gas Plant commenced operations with a processing capacity of 30 MMcf/d. ii) Phase II of the PC Gas Plant commenced operations with a combined processing capacity of 60 MMcf/d.

2

October 2, 2012: Phase III of the PC Gas Plant commenced

• perations with a combined processing capacity of 150 MMcf/d.

September 1, 2014: Phase IV of the PC Gas Plant commenced

• perations with a combined processing capacity of 180 MMcf/d.

July 13, 2016: Closed equity financings for total gross proceeds of $690.8 million. July 28, 2016: Completed acquisition of properties in the Gordondale area of Alberta for approximately $613.5 million. The assets included high working interest operated production and a large contiguous land base adjacent to Birchcliff’s existing

• perations on the Montney/Doig Resource Play. Closed equity

financings for total gross proceeds of $690.8 million. August 31, 2017: Completed disposition of the Worsley Charlie Lake Oil Pool for approximately $100.0 million. October 2, 2017: Announced the early commencement of Phase V

• f the PC Gas Plant with combined processing capacity of 260

MMcf/d.

2,793 boe/d 3 4 5 6 7 8 9 10 11

1 2 3 4 5 7 6 8 9 10 11

Birchcliff has increased production at a

compound annual growth rate of 30% since 2005. Operating and cash costs have decreased by 60% and 46% since 2008 largely due to horizontal drilling success

and benefits achieved from processing gas at the PC Gas Plant which began operations in early 2010.

44

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

50 100 150 200 250 300 10,000 20,000 30,000 40,000 50,000 60,000 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 boe/d/million wtd. avg. shares boe/d

Production Growth

Average Production (boe/d) Production per Common Share (boe/d/million wtd. avg. shares) $- $2 $4 $6 $8 $10 $12 $14 $16 $18 $20 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 $/boe

Operating & Cash Costs*

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

Birchcliff has added significant low cost reserves since commencing operations in 2005. On a per

common share basis, PDP, 1P and 2P reserves grew 14% per year, 22% per year and 23% per year, respectively.

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

45

800 1,600 2,400 3,200 4,000 200 400 600 800 1000 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 boe/1,000shares MMboe

Reserves Growth

PDP (MMboe) 1P (MMboe) 2P (MMboe) PDP (boe/1000 shares) 1P (boe/1000 shares) 2P (boe/1000 shares)

APPENDIX

2016 MONTNEY/DOIG RESOURCE ASSESSMENT

47

Reserves and Resource Volumes (Bcfe)(1)(2) Resource Class Raw/Sales Low Estimate Case Best Estimate Case High Estimate Case Discovered Cumulative Production(3) Sales 696.7 696.7 696.7 Remaining Reserves(3)(4) Sales 3,142.4 4,993.6 6,384.5 Total Commercial Recoverable Sales 3,839.1 5,690.3 7,081.2 Surface and Process Loss Raw 100.8 145.8 185.8 Total Commercial Raw 3,939.9 5,836.1 7,267.1 Contingent Resources(3) Sales 9,067.6 13,371.6 21,338.2 Development Pending Sales 5,784.8 8,570.4 13,797.4 Development On Hold Sales 3,117.3 4,539.2 6,667.5 Development Unclarified Sales 127.5 203.6 770.7 Development Not Viable Sales 38.0 58.4 102.5 Surface and Process Loss Raw 631.7 929.3 1,380.8 Unrecoverable Raw 19,132.9 21,131.5 21,903.9 Total Sub-Commercial Raw 28,832.1 35,432.5 44,622.9 TOTAL DISCOVERED PIIP Raw 32,772.0 41,268.5 51,890.0 Undiscovered Prospective Resources(3) Sales 10,781.9 16,586.3 25,731.2 Prospect(5) Sales 10,781.9 16,586.3 25,731.2 Surface and Process Loss Raw 542.0 823.7 1,262.0 Unrecoverable Raw 14,694.9 17,070.4 18,118.2 TOTAL UNDISCOVERED PIIP Raw 26,018.7 34,480.3 45,111.4 TOTAL PIIP Raw 58,790.8 75,748.9 97,001.4

(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, oil and NGLs volumes were combined at a ratio of 1 bbl: 6 Mcfe. (4) Includes reserves assigned to both vertical and horizontal Montney/Doig wells. Birchcliff retained two independent qualified reserves evaluators, Deloitte and McDaniel, to evaluate and prepare reports on 100% of Birchcliff’s light crude oil and medium crude oil (combined), conventional natural gas, shale gas and NGLs reserves effective December 31, 2016. Deloitte prepared a consolidated reserves report with an effective date of December 31, 2016 by consolidating the properties evaluated by Deloitte with the properties evaluated by McDaniel, in each case using Deloitte’s forecast price and cost assumptions effective December 31, 2016. Birchcliff has ongoing projects to drill horizontal wells targeting the Montney. This has resulted in some of these areas already having been assigned undeveloped reserves by its independent qualified reserves evaluators. The reserves assignments as of the effective date of the 2016 Resource Assessment have been subtracted from the resource estimates. Proved, probable and possible reserves as contained in the Consolidated Reserves Report are included in above table for completeness; however, reserves were not the focus of the 2016 Resource

• Assessment. The low estimate case includes the estimate of proved reserves contained in the Consolidated Reserves Report, the best estimate case includes the estimate of proved plus probable reserves contained in the Consolidated Reserves Report and the high estimate case includes the estimate
• f proved plus probable plus possible reserves contained in the Consolidated Reserves Report. 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”.

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 57,724 115,515 158,400 227,700 266,800 319,215 412,336 516,821 825,455 100,000 200,000 300,000 400,000 500,000 600,000 700,000 800,000 900,000 Reserves (Mboe) PDP TP 2P

2016 YEAR END MONTNEY/DOIG RESERVES

48

Drilled 2 HZ M/D wells Drilled 15 HZ M/D wells Drilled 8 HZ M/D wells Drilled 23 HZ M/D wells Drilled 23 HZ M/D wells Drilled 22 HZ M/D wells Drilled 25 HZ M/D wells Drilled 41 HZ M/D wells Drilled 29 HZ M/D wells

295 (289.7 net) Montney/Doig horizontal wells drilled as of Dec 31, 2016 including 87 (82.5 net) wells acquired in the Gordondale Acquisition

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

Drilled 20 HZ M/D wells and acquired 87 (82.5 net) HZ M/D wells

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 $0.523375 per share Current Yield 8.374% Redeemable by Holder No

49

• September 30, 2022: Series A are redeemable by Birchcliff (and not by holder) on this date and

every five years hereafter

• September 30, 2022: Series A fixed rate will be reset on this date and every five years hereafter

to the five year Government of Canada bond yield plus 6.83%

• September 30, 2022: Series A (fixed rate) & B (variable rate) holders are entitled to convert

between the two Series on this date and every five years hereafter, subject to certain conditions

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% Redeemable by Holder June 30, 2020 and each quarter thereafter

50

2016 2017 2018 2019 2020

1 2 3 June 30, 2018: Series C redeemable by Birchcliff (and not by holder) at $25.75 per share (plus accrued and unpaid dividends) if redeemed before June 30, 2019; Birchcliff has the option to convert into common shares (see note) 1 June 30, 2019: Series C redeemable by Birchcliff (and not by holder) at $25.50 per share (plus accrued and unpaid dividends) if redeemed before June 30, 2020; Birchcliff has the option to convert into common shares (see note) 2 June 30, 2020: Series C redeemable by Birchcliff at $25.00 per share (plus accrued and unpaid dividends) form this date forward subject to proper notice Birchcliff has the option to convert into common shares (see note) June 30, 2020: Series C redeemable by holder, on this date and the last day of each quarter hereafter, at $25.00 per share (plus accrued and unpaid dividends); upon receipt of notice for redemption, Birchcliff may elect to convert into common shares (see note) 3 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

EXECUTIVE OFFICERS

• A. Jeffery

Tonken

President, CEO and Chairman of the Board

• Mr. Tonken is the President, Chief Executive Officer and Chairman of the Board of Birchcliff. He has more than 36 years of

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

Myles R. Bosman

Vice-President, Exploration and Chief Operating Officer

• Mr. Bosman is the Vice-President, Exploration and Chief Operating Officer of Birchcliff and is a Professional Geologist. He

has more than 26 years of experience in the oil and natural gas industry and is one of the Corporation’s founders. Prior to joining Birchcliff, Mr. Bosman served as Vice-President, Exploration and Chief Operating Officer of Case Resources Inc., Exploration Manager of Summit Resources Ltd. and as an Exploration Geologist with both Numac Energy Inc. and Canadian Hunter Exploration. Mr. Bosman received his Bachelor of Science degree in Geology from the University of Calgary and his Resource Engineering diploma from the Northern Alberta Institute of Technology. Mr. Bosman is a member of APEGA.

Bruno P. Geremia

Vice-President and Chief Financial Officer

• Mr. Geremia is the Vice-President and Chief Financial Officer of Birchcliff and is a Chartered Accountant. He has more than

25 years of experience in the oil and natural 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 Director, Commercial of Gulf Canada Resources and as Manager, Special Projects of Stampeder Exploration Ltd.

• Mr. Geremia was previously a Chartered Accountant with Deloitte & Touche LLP. Mr. Geremia received his Bachelor of

Commerce degree from the University of Calgary.

51

EXECUTIVE OFFICERS

Christopher A. Carlsen

Vice-President, Engineering

• Mr. Carlsen is the Vice-President, Engineering of Birchcliff and is a Professional Engineer. He previously served as Asset

Team Lead and Senior Exploitation Engineer with Birchcliff. Mr. Carlsen is a Professional Engineer with more than 16 years

• f experience in the oil and natural gas industry. Prior to joining Birchcliff in 2008, he was the Senior Engineer at Greenfield

Resources Ltd. and held various engineering positions at both EnCana Corporation and PanCanadian Petroleum Ltd. Mr. Carlsen received his Bachelor of Science degree in Chemical Engineering from the University of Saskatchewan. Mr. Carlsen is a member of APEGA.

David M. Humphreys

Vice-President, Operations

• Mr. Humphreys is the Vice-President, Operations of Birchcliff. He has more than 30 years of experience in the oil and natural

gas industry. Prior to joining Birchcliff in 2009, he served as Vice-President, Operations of Highpine Oil & Gas Ltd., White Fire Energy Ltd. and Virtus Energy Ltd.; Production Manager of both Husky Oil Operations Ltd. and Ionic Energy; and as a Senior Production Engineer with Northrock Resources Ltd. Mr. Humphreys received his Hydrocarbon Engineering Technology diploma from the Northern Alberta Institute of Technology. Mr. Humphreys is a member of APEGA.

52

BOARD OF DIRECTORS

53

• A. Jeffery

Tonken

President, CEO and Chairman of the Board See Mr. Tonken’s biography under “Executive Officers”.

Larry A. Shaw

Independent Director

• Mr. Shaw is a director of Birchcliff and has more than 29 years of experience in the oil and natural gas industry and is one of

the Corporation’s founders. Prior to joining Birchcliff, Mr. Shaw served as Chairman of the Board of Case Resources Inc., Big Bear Exploration Ltd. and Stampeder Exploration Ltd. He was President of Shaw Automotive Group Ltd. and Shaw G.M.C. Pontiac Buick Hummer Ltd. for many years. Mr. Shaw received his Honors Degree in Business Administration from the University of Western Ontario.

James W. Surbey

Director

• Mr. Surbey is a Director of Birchcliff and is a member of the Compensation Committee and Reserves Evaluation Committee.
• Mr. Surbey has more than 40 years of experience in the oil and natural gas industry and is one of the Corporation’s founders.

Prior to Birchcliff, he served as Vice-President, Corporate Development of Case Resources Inc., Senior Vice President, Corporate Development of Big Bear Exploration Ltd. and Vice-President, Corporate Development of Stampeder Exploration

• Ltd. Mr. Surbey was previously a Senior Partner of the law firm Howard, Mackie (now Borden Ladner Gervais LLP). Mr.

Surbey received his Bachelor of Engineering degree and Bachelor of Laws degree from McGill University and is a member of Law Society of Alberta.

BOARD OF DIRECTORS

54

Dennis Dawson

Independent Director

• Mr. Dawson is a director of Birchcliff. Prior to joining Birchcliff, Mr. Dawson was 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 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 31 years of oil and natural gas experience including nine years as General Counsel for Pan-Alberta Gas Ltd., a major Canadian natural gas export and marketing 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.

Rebecca Morley

Independent Director

• 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 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 YWCA of Calgary, was the Chair of the Audit Committee in 2014 and 2015 and has been a director since 2012. Ms. Morley has a Bachelor of Business Administration with a Major in Finance (Honours) from St. Francis Xavier University and is a CFA Charterholder.

Debbie Gerlach

Independent Director

• Ms. Gerlach is a director of Birchcliff and a Chartered Accountant. Prior to her retirement in September 2017, Ms. Gerlach

was a partner with Deloitte LLP for over 21 years where she practiced in the Assurance and Advisory group. During that time, she worked with many public oil and gas companies over her 35 year career with the firm. Ms. Gerlach holds a Bachelor of Commerce and a Master of Business Administration, both from the University of Calgary.

PRESENTATION OF OIL AND GAS RESERVES AND RESOURCES:

Deloitte prepared the 2016 Consolidated Reserves Report, the 2016 Deloitte Reserves Report, the 2015 Deloitte Reserves Report and the 2016 Resource Assessment. McDaniel prepared the 2016 McDaniel Reserves Report. Such evaluations were prepared in accordance with the standards contained in the National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (the “NI 51-101”) and the Canadian Oil and Gas Evaluation Handbook (the “COGE Handbook”) that were in effect at the relevant time. 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 NGLs reserves and resources may be greater than or less than the estimates provided herein and variances could be material. 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, 2016, a copy of which is available

• n 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

• f aggregation. Estimates of future net revenue, whether calculated without discount or using a discount rate, do not represent fair market value.

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. 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. The information set forth in this presentation relating to the reserves and future net revenues of Birchcliff constitutes forward-looking information which is subject to certain risks and uncertainties. See “Advisories – Forward-Looking Information” in 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.

• “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. There is a 10% probability that the quantities

actually recovered will equal or exceed the sum of 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.

55

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
• r 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 sub-classes 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 sub-classes 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 40.80 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.

56

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

• r probable reserves attributed to them in the 2016 Consolidated Reserves Report.

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

• perating 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:

57

THANK YOU TEAM BIRCHCLIFF

Jeffrey Akeroyd, Bradley Alexander, Karen Allen, Laura Armstrong, Camille Ashton, Rainer Augsten, Gates Aurigemma, Bryce Baloun, Alan Basnett, Angela Belbeck, Charmaine Belley, Tyrus Bender, Tim Berg, Perry Billard, Daniel Blattler, Angela Boire, Deborah Borthwick, Myles Bosman, Jeff Boswell, Robyn Bourgeois, David Boyle, Wayne Brown, James Burke, Madison Burns, Dave Campbell, Chris Carlsen, Alex Carlson, Caitlin Carrigy, Ann Ceccanese, Robert Charchuk, Matthew Chorney, Dave Christensen, Benjamin Christenson, Bob Clark, Wendy Clay, Dallas Cline, Laura Conroy, Mike Cordingley, Kenneth Cullen, Krystal Dafoe, Chelsea Daku, Dennis Dawson, Claire Denley, Allan Dixon, Jesse Doenz, Joe Doenz, Keifer Dolen, Kelly Dolen, Terrance Dyck, Emily Ebbels, Tim Etcheverry, Laura Ferguson, Jaryn Flower-Phillips, Grant Friesen, Marshall Fritz, George Fukushima, Andy Fulford, Carrie Fyfe, Alexandra Gatza, Bruno Geremia, Melina Geremia, Melodie Gilker, Chad Goddard, Jolanda Goertzen, David Graham, Lee Grant, Hannah Grigore, Bob Grisack, Tania Haberlack-Dolan, Mike Hale, Samuel Hampton, Theresa Hannouche, Trevor Harley, Richard Harris, Wanda Hiebert, Lorna Hildebrand, Warren Hingley, Paul Hirsekorn, Janet Hogan, Jasen Holmstrom, Daryl Hudak, Dave Humphreys, Derek Jamieson, Anna Johnson, David Johnson, Stacy Johnson, Julie Johnson, Dustin Kelm, Ryan Kennedy, Gregory Kilgour, Phyllis Kinzner, Diane Knoblauch, Heather Kwiatkowski, Dani Laird, Calvin Leithead, Kristen Lewicki, Michael Lillejord, Scott Lundquist, Thomas Lundquist, Joe Lyste, Scott MacDermott, John MacGillivray, Dallas MacLean, Darcy MacLeod, Mary MacNeill, Curtis Mah, Janice Malainey, Maggie Malapad, Valerie Martin, Kevin Matiasz, John Matijevich, Jeff McAndrews, Deb McFee, Angie McGonigal, Ryan McIntosh, Marc McIntosh, Darin McLarty, Jerilyn McLeod, Dani McPhee, Richard Melling, John (Bill) Melnyk, Paul Messer, Melissa Meyers, Alfred Michetti, Emelyia Moghaddami, Tyler Montpellier, Ronald Morgan, Rebecca Morley, Stephen Morton, Shaun Moskalyk, Steve Mueller, Daniel Mullin, McKenzie Murdoch, Ed Murphy, Tyler Murray, Kody Naka, Sarah Nance, Matteo Niccoli, Michael Ng, Tam Nguyen, Marcel Njongwe, Tyler Ollenberger, Christopher Olson, Philomena Paisley, Bruce Palmer, Bill Partridge, Dean Paterson, Brenda Pearson, Paul Picco, Allan Pickel, Landon Poffenroth, Andrei Popescu, Lindsay Postma, Glenn Power, Shoni Proctor, Dale Richardson, Brian Ritchie, Michelle Rodgerson, Jeff Rogers, Sherri Rosia, Randy Rousson, Jared Rousson, Todd Sajtovich, Lee Sallenbach, Victor Sandhawalia, Wade Schultz, Sadeq Shahamat, Dan Sharp, Larry Shaw, Amy Short, Nicholas Sizer, Ryan Sloan, Dwayne Spelay, Ben Stevenson, Darby Stolk, Lindsay Sturrock, Tracey Suchlandt, Jim Surbey, Jeff Tonken, Gillian Topping, Hue Tran, Tammy Tran, Rebecca Van De Riet, Theo van der Werken, Kara Vance, Kris Veach, Greg Vreim, Linda Wang, Matt Weiss, David Wetta, Jonathan White, Chris Wurz, John Yeo, Deirdre Yuzwa

58