CORPORATE PRESENTATION November 14, 2018 FORWARD-LOOKING - - PowerPoint PPT Presentation

▶

Sep 02, 2023 355 likes •1.07k views

CORPORATE PRESENTATION November 14, 2018 FORWARD-LOOKING INFORMATION: Certain statements contained in this presentation constitute forward-looking statements and information (collectively referred to as forward-looking information ) within

SLIDE 1

CORPORATE PRESENTATION

November 14, 2018

SLIDE 2

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’sfuture 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. Birchcliffbelieves 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, the Acquisition (including the anticipated closing date of the Acquisition, the expected characteristics of the assets and the benefits of the Acquisition, Birchcliff’s plans for drilling and processing arrangements and the funding of the Acquisition); Birchcliff’spreliminary plans and guidance for 2019 (including that Birchcliffwill target capital spending within adjusted funds flow and focus on generating free funds flow, the ranges of capital spending and annual average and exit production, estimates of commodity mix, adjusted and free funds flow, total debt and natural gas market exposure during 2019, Birchcliff’s expectation that it will generate significant free funds during 2019, the possible uses of such free funds flow and that Birchcliffwill be well positioned to reduce debt, pursue additional growth, the flexibility of the 2019 capital program should economic conditions improve or deteriorate and the expected impact of changes to commodity prices on Birchcliff’s preliminary estimate of adjusted funds flow), priorities and goals, the 2018 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 2018 Capital Program; Birchcliff’s production guidance, including its estimates of its annual average production and commodity mix in 2018; 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’shedging strategy and the use of risk-management techniques; Birchcliff’s future growth plans for the Elmworth area, including Birchcliff’sintention 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 2018; the benefits to be obtained as a result of the Gordondale Acquisition. Information relating to reserves is forward-looking as it involves the implied assessment, based on certain estimates and assumptions, that the reserves exist in the quantities predicted or estimated and that the reserves can profitably be produced in the future. With respect to forward-looking information contained in this presentation, assumptions have been made regarding, among other things: Birchcliff’s ability to continue to develop 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 Birchcliffoperates; 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 competitionon 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 Birchcliffto 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, Birchcliffhas made the following assumptions with respect to certain forward-looking information contained in this presentation:

With respect to the Acquisition, Birchcliffhas assumed that the closing conditions to the Acquisition will be satisfied and that the Acquisition will be completed on the terms and the timing anticipated. In addition, Birchcliffhas made assumptions regarding the performance and other characteristics of the assets to be acquired

and the expected benefits of the Acquisition.

Birchcliff’s preliminary 2019 guidance (as announced on November 14, 2018) assumes the following commodity prices during 2019: an average WTI oil price of US$70.00/bbl; an average WTI-Edmonton Par differential of $16.00; an average AECO price of $1.85/MMBtu; an average Dawn price of $3.69/MMBtu; an average NYMEX-

Henry Hub price of US$3.00/MMBtu; and an exchange rate (CDN$ to US$1) of 1.28.

Birchcliff’s 2018 guidance (as updated November 14, 2018) assumes the following commodity prices during 2018: an average WTI oil price of US$66.67/bbl; an average AECO price of $1.63/MMBtu; an average Dawn price of $3.70/MMBtu; and an average wellhead natural gas price of $2.41/Mcf.
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 2018 and 2019 production guidance, the key assumptions are that: the 2018 and 2019 Capital Programs will be carried out as currently contemplated; no unexpected outages occur in the infrastructure that Birchcliffrelies on to produce its wells and that any transportation service curtailments or

unplanned outages that occur will be short in duration or otherwise insignificant; the construction of new infrastructure meets timing and operational expectations; existing wells continue to meet production expectations; and future wells scheduled to come on production meet timing, production and capital expenditure expectations.

With respect to estimates of reserves volumes and the net present values of future net revenue associated with Birchcliff’s reserves, the key assumption is the validity of the data used by Deloitte and McDaniel in their independent reserves evaluations.
With respect to statements of future wells to be drilled and brought on production and estimates of potential future drillinglocations 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’slands 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 drillingof associated wells.

With respect to statements regarding Birchcliff’sintention 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 Birchcliffis

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; Birchcliffwill have access to sufficient capital to fund the Elmworth Gas Plant; and commodity prices and general economic conditions warrant proceeding with the construction of the Elmworth Gas Plant and the drilling of associated wells. Birchcliff’s actual results, performance or achievements could differ materially from those anticipated in the forward-looking information as a result of both known and unknown risks and uncertainties including, but not limited to: the failure to realize the anticipated benefits of acquisitions and disposition, including the Gordondale Acquisition; unforeseen difficulties in integrating the GordondaleAssets into Birchcliff’s operations; variances in Birchcliff’sactual capital costs, operating costs, decline rates 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’sfirm marketing and transportation arrangements; the inability to secure adequate production transportation for Birchcliff’sproducts; the occurrence of unexpected events such as fires, equipment failures and other similar events affecting Birchcliffor 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 Birchcliffmay 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’smost 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 Birchcliffdisclaims 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:

“2017 Deloitte Reserves Report” means the evaluation by Deloitte LLP effective December 31, 2017 as contained in the report of Deloitte dated February 9, 2018. “2017 McDaniel Reserves Report” means evaluation by McDaniel with an effective date of December 31, 2017 as contained in the report of McDaniel dated February 14, 2017. “2017 Consolidated Reserves Report” means the consolidated report of Deloitte with an effective date of December 31, 2017 prepared by consolidating the properties evaluated by Deloitte in the 2017 Deloitte Reserves Report with the properties evaluated by McDaniel in the 2017 McDaniel Reserves Report, in each case using Deloitte’s forecast price and cost assumptions effective December 31, 2017 “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.

SLIDE 3

PEOPLE, FOCUS & EXECUTION

SLIDE 4

4 Corporate Snapshot & Select Guidance

Q3 2018 average production 79,331 boe/d Estimated 2018 annual average production 76,000 – 78,000 boe/d % oil and NGL 20% Q3 2018 cash flow (millions / per share) $75.4 / $0.28 Estimated 2018 capital expenditures (millions) $288 Total debt as at September 30, 2018 (millions) $641.5 Credit facilities limit as at September 30, 2018 (millions) $950 Common shares (basic) as at September 30, 2018 (millions) 265.9 Market capitalization as at November 7, 2018 (billions) - $4.42/sh $1.2 Enterprise value as at November 7, 2018 (billions)(1) - $4.42/sh $1.9 Montney/Doig land position as at December 31, 2017 (gross sections) 349.4 Montney/Doig potential net future horizontal drilling locations as at December 31, 2017(2) 4,710 Gross proved developed producing reserves as at December 31, 2017(3) 197,955 Mboe Gross proved plus probable reserves as at December 31, 2017 (3) 972,515 Mboe TSX 300 BIR, BIR.PR.A, BIR.PR.C Quarterly dividend to common shareholders $0.025/sh

(1) 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 September 30, 2018 and adding total debt, including the face value of the Series A Preferred Shares and Series C Preferred Shares. (2) See “Advisories – Drilling Locations”. (3) See appendix at the end of this presentation for disclosures on oil & gas reserves and related metrics.

SLIDE 5

Quarterly average production of 79,331 boe/d, a 22% increase from 65,276 boe/d

in Q3 2017

Quarterly cash flow of $75.4 million ($0.28/basic common share), a 17% increase

from $64.4 million ($0.24/basic common share) in Q3 2017

Completed and brought on production 9 (9.0 net) wells in Q3 2018, consisting of

6 (6.0 net) Montney/Doig horizontal oil wells in the Gordondale area and 3 (3.0 net) Montney/Doig horizontal natural gas wells in the Pouce Coupe area

Declared quarterly dividend to common shareholders in the amount of

$0.025/common share for the quarter ended September 30, 2018

Brought on-stream the 80 MMcf/d Phase VI expansion (combined processing

capacity of 340 MMcf/d) of Birchcliff’s 100% owned and operated natural gas processing plant in Pouce Coupe on budget and ahead of schedule

Subsequent to Q3 2018, Birchcliff entered into a definitive purchase and sale

agreement to acquire 18 gross (15.1 net) contiguous sections of Montney land located between Birchcliff’s Pouce Coupe and Gordondale properties

Q3 2018 HIGHLIGHTS

SLIDE 6

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 89% W.I.
Significant control of infrastructure including the 100% owned and operated 340

MMcf/d Pouce Coupe Gas Plant (“PC Gas Plant”)

Top tier cost structure driving peer leading profitability
Low decline production base
2P reserve life index (RLI)(1)(2) of approximately 34.6 years as at December 31, 2017
348 (342.8 net) Montney/Doig horizontal wells drilled as at December 31, 2017
4,710.0 net future potential Montney/Doig horizontal drilling locations as at December

31, 2017(3)

INVESTMENT HIGHLIGHTS

(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, 2017 by 77,000 boe/d, which production rate represents the mid-point of Birchcliff’s annual average production guidance range for 2018. (3) See “Advisories – Drilling Locations”.

SLIDE 7

STRATEGIC LAND ACQUISITION

Key Strategic Attributes

18 gross (15.1 net) Montney sections

adjacent to existing BIR infrastructure

Potential for 4 Montney intervals (Montney

D1, D2, C, Basal Doig/Upper Montney)

Strong anticipated condensate rates
Birchcliff Tech Pad learnings provide

competitive advantage

Preparing to drill 5 well pad Q1 2019
Total consideration of $39 MM with

anticipated closing on January 3, 2019

SLIDE 8

STRATEGIC LAND ACQUISITION – CONT’D

The acquisition provides a rare opportunity to acquire a large contiguous land

block in proximity to BIR 3-22 plant as there is currently no open Crown available

Extends liquids production fairway in Pouce Coupe
Provides additional liquids rich drilling inventory to fill Pouce Coupe Phase VI
Acquisition includes ~700 boe/d of legacy production
Last well drilled in 2014 using old completion technology
Acquisition was evaluated primarily on land acquisition metrics and future

drilling opportunities

SLIDE 9

BIRCHCLIFF’S HISTORY

A Track Record of Execution

SLIDE 10

KEYS TO SUCCESS

Management 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

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 Operational Execution

348 (342.8 net) Montney/Doig horizontal wells drilled to December 31, 2017 all utilizing multi-stage

fracture stimulated technology

Construction of the 340 MMcf/d PC Gas Plant in six separate phases on time and on budget
Own, control or have access to infrastructure and operate 99% of production
348 (342.8 net) Montney/Doig horizontal wells drilled to December 31, 2017 all utilizing multi-stage

fracture stimulated technology

Construction of the 340 MMcf/d PC Gas Plant in six separate phases on time and on budget
Own, control or have access to infrastructure and operate 99% of production

Technical Expertise 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
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 Scale & Repeatability

Consistent, repeatable, predictable growth and results
4,710 potential Montney/Doig horizontal locations and as at December 31, 2017(1)
Consistent, repeatable, predictable growth and results
4,710 potential Montney/Doig horizontal locations and as at December 31, 2017(1)

Financial Execution Financial Execution

Full cycle profitability with top tier F&D costs and netbacks through 2017 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

Full cycle profitability with top tier F&D costs and netbacks through 2017 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 10

(1) See “Advisories – Drilling Locations”

SLIDE 11

2,793 5,368 6,711 10,148 11,216 13,079 18,136 22,802 25,829 33,734 38,950 49,236 67,963 76,000 - 78,000 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 2017 2018E Average Production (boe/d)

PRODUCTION HISTORY

11 Compound per-share production growth of 12% per year since 2005. (14% since PC Gas Plant Phase I Completion)

SLIDE 12

Corporate Production (boe/d)

2005-2017 2018 2019 26% Base Decline 20% Base Decline 2018 2019

BIRCHCLIFF CORPORATE DECLINE(1)

12 Long life, low decline asset allows for smaller capital wedge YoY needed to maintain volumes

(1) Production profile provided for general illustrative purposes only and not indicative of expected production profile

SLIDE 13

$0 $1,000 $2,000 $3,000 $4,000 $5,000 $6,000 $7,000 100,000 200,000 300,000 400,000 500,000 600,000 700,000 800,000 900,000 1,000,000 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 NPV10 - Btax ($MM) Reserves (Mboe) PDP - Reserves TP - Reserves 2P - Reserves PDP - NPV10 TP - NPV10 2P - NPV10

CORPORATE RESERVES

13 On a per share basis PDP, 1P and 2P reserves have increased at a compound annual growth rate of 14%, 22% and 21% per year since 2005, respectively

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

SLIDE 14

PROVEN TRACK RECORD AS A LOW COST PRODUCER

Profitability Breakdown: 2013 2014 2015 2016

2017

5 Year Average Average AECO (CAD$/GJ) $2.99 $4.27 $2.55 $2.05

$2.05

$2.78 Average WTI (USD$/bbl) $97.97 $92.99 $48.80 $43.32

$50.95

$66.81 P&NG Revenue ($/Mcfe) (1) $5.60 $6.40 $3.72 $3.12

$3.74

$4.52 PDP F&D ($/Mcfe)(2) ($2.49) ($2.23) ($1.35) ($1.07)

($1.05)

($1.64) Total Cash Costs(3) ($/Mcfe) ($2.59) ($2.34) ($1.83) ($1.77)

($1.78)

($2.06) Profit ($/Mcfe)(4)(5) $0.52 $1.83 $0.53 $0.29

$0.91

$0.82 Profit Margin (%)(4) 9% 29% 14% 9%

24%

17%

(1) Excludes the effects of hedges using financial instruments but includes the effects of fixed price physical delivery contracts and higher average realized pricing for a portion of natural gas sold at Dawn. (2) Cost to find and develop proved developed producing (PDP) reserves based on finding and development (“F&D”) costs. (3) Comprised of royalty, operating, transportation and marketing, general and administrative and interest expenses. (4) 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. (5) Numbers may not add due to rounding

SLIDE 15

Corporate F&D Costs (incl. FDC) & Cash Flow Recycle Ratios 2013 2014 2015 2016 2017 5 Yr Avg PDP F&D ($/boe) $14.94 $13.40 $8.11 $6.42 $6.29 $9.83 1P F&D ($/boe) $9.39 $13.51 $2.41 $4.89 $8.14 $7.67 2P F&D ($/boe) $9.03 $12.57 $1.55 $4.43 $7.27 $6.97 PDP Recycle Ratio 1.2x 1.8x 1.4x 1.3x 2.0x 1.6x 1P Recycle Ratio 2.0x 1.8x 4.7x 1.7x 1.6x 2.3x 2P Recycle Ratio 2.0x 1.9x 7.3x 1.8x 1.8x 3.0x 1.2x 1.8x 1.4x 1.3x 2.0x 1.6x 2.0x 1.8x 4.7x 1.7x 1.6x 2.3x 2.0x 1.9x 7.3x 1.8x 1.8x 3.0x $0 $4 $8 $12 $16 2013 2014 2015 2016 2017 5 Yr Avg F&D Cost ($/boe) PDP F&D 1P F&D 2P F&D

PROVEN TRACK RECORD AS A LOW COST FINDER

Cash flow netback recycle ratios

SLIDE 16

LOOKING FORWARD

2018 Plans & Beyond

SLIDE 17

2018 & 2019 CAPITAL PROGRAMS

2018

The revised 2018 capital budget of $288 MM includes the original (unchanged)

$255 MM 2018 capital budget and $33 MM of 2019 capital accelerated into Q4/18 to take advantage of development efficiencies and lower costs

Birchcliff will accelerate the drilling of an additional 9 (9.0 net) horizontal wells

in Q4 2018 that were originally targeted for 2019

2018 annual average production guidance remains at 76,000 - 78,000 boe/d

2019

Birchcliff’s 2019 strategy is focused on generating free funds flow
Preliminary 2019 plans are for capital spending of $210 MM (not inclusive of the

strategic land acquisition) to average 76,000 - 78,000 boe/d resulting in forecasted adjusted funds flow of $345 MM(1)

(1) Based on 2019E commodity pricing of: US$70.00/B WTI, $1.85/MMBTU AECO, $3.69/MMBTU Dawn, US$3.00/MMBTU Henry Hub, 1.28 CAD/USD.

SLIDE 18

2018 CAPITAL PROGRAM

Drilling & Development

Gross Wells Net Wells Capital ($MM) Pouce Coupe - Montney D1 Horizontal Gas Wells 12 12.0 $66.2 Pouce Coupe - Montney D2 Horizontal Gas Wells 1 1.0 $4.9 Pouce Coupe - Montney C Horizontal Gas Wells 1 1.0 $5.1 Gordondale - Montney D2 Horizontal Oil Wells 8 8.0 $42.2 Gordondale - Montney D1 Horizontal Oil Wells 5 5.0 $26.0 2017 Carry Forward Capital(1)

$5.5

Total Drilling and Development(2) 27 27.0 $149.9

Facilities and Infrastructure(3) $66.9 Sustaining and Optimization $17.1 Land & Seismic $4.6 Other $16.5

2018 Capital Program $255.0

2019 CAPITAL ACCELERATION

Drilling & Development

Gross Wells Net Wells Capital ($MM) Pouce Coupe - Montney D1 Horizontal Gas Wells 5 5.0 $17.3 Gordondale - Montney D2 Horizontal Gas Wells 2 2.0 $6.0 Gordondale - Montney D1 Horizontal Gas Wells 2 2.0 $5.8

Total Drilling and Development(4) 9 9.0 $29.1

Facilities, Infrastructure & Other(5) $3.9

2019 Capital Acceleration $33.0

Total Revised 2018 Capital Program(6) $288.0

(1) Primarily completion, equipping and tie-in costs associated with 2 (2.0 net) wells rig released in 2017. (2) On a drill, case, complete, equip and tie-in basis. (3) Includes: (i) $25.7 million for the completion of the Phase VI expansion; (ii) $11.2 million for a pipeline twinning project; (iii) $8.3 million for the construction of an additional sales line from the PC Gas Plant; and (iv) $6.0 million for water storage. The remaining capital primarily relates to new pipeline construction and other projects. (6) Birchcliff makes acquisitions and dispositions in the ordinary course of business. Any acquisitions and dispositions completed during 2018 could have an impact on Birchcliff's capital expenditures, which impact could be material. See "Advisories - Capital Expenditures". (5) Includes: (i) $3.5MM for the construction of two water reservoirs; (ii) $0.4MM of 2019 pipeline pre-spend capital. (4) Includes: (i) $16.9MM of drilling capital related to rig releasing 9 (9.0 net) wells and 1 (1.0 net) surface spud in 2018; (ii) $8.3MM of multi-well pad construction and water capital for 2019; (iii) $4.0MM of multi- well pad equip and tie-in capital for 2019.

REVISED 2018 CAPITAL PROGRAM DETAILS

SLIDE 19

2018YTD NATURAL GAS MARKETING

AECO Q1 Q2 Q3 YTD $1.96 $1.10 $1.12 $1.37 $0.03 $0.02 $0.02 $0.02 $0.24 $0.25 $0.23 $0.24 $1.68 $0.83 $0.87 $1.11 Pricing Hub Realized Sales Price at Hub (C$/GJ)(2) Fuel Cost From Field to Sales Point (C$/GJ)(3) Transportation Cost From Field to Sales Point (C$/GJ)(4) Sales Netback (C$/GJ)(5)

Note: All Birchcliff gas realizes a 9% heat premium(1)

(1) Birchcliff receives premium pricing for its natural gas production due to its high heat content. The conversion from $/Gj to $/Mcf is approximately 1.145 for Birchcliff compared to the standard 1.055 (2) Volume assumptions based on 2018 guidance & pricing based on 2018YTD realized sales pricing (3) Recorded net of extraction income (4) Recorded as transportation expense for: AECO & Dawn service. Transportation expense recorded net of realized sales price for Alliance service (5) Sales netback = realized sales price net of transportation back to wellhead, fuel and income sources *Pie charts indicate % of 2018E volumes sold at the respective hub

Alliance Q1 Q2 Q3 YTD $3.11 $1.16 $1.43 $2.09 $0.11 $0.02 $0.02 $0.05 $1.11 $0.11 $0.18 $0.57 $1.89 $1.04 $1.23 $1.46 Dawn Q1 Q2 Q3 YTD $3.63 $3.40 $3.60 $3.54 $0.14 $0.13 $0.15 $0.15 $1.16 $1.16 $1.12 $1.14 $2.33 $2.11 $2.33 $2.25 283,000 GJ/d 17,000 GJ/d 125,000 GJ/d November 14, 2018

29%

67%

SLIDE 20

2019 NATURAL GAS MARKETING

Pricing Hub Forecasted Sales Price at Hub (C$/GJ)(2) Hedged Differential (C$/GJ)(2) Estimated Fuel Cost From Field to Sales Point (C$/GJ)(3) Estimated Transportation Cost From Field to Sales Point (C$/GJ)(4) Estimated Sales Netback (C$/GJ)(5)

Note: All Birchcliff gas realizes a 9% heat premium(1)

(1) Birchcliff receives premium pricing for its natural gas production due to its high heat content. The conversion from $/Gj to $/Mcf is approximately 1.145 for Birchcliff compared to the standard 1.055 (2) Volume assumptions based on preliminary 2019 guidance; Pricing based on internal forecasts and 1.28 USD/CAD FX (3) Recorded net of extraction income (4) Recorded as transportation expense for: AECO & Dawn service. Transportation expense recorded net of realized wellhead price for Alliance service (5) Estimated sales netback = realized sales price net of transportation back to wellhead, fuel, income sources and net of any hedge differential *Pie charts indicate % of volumes forecast to be sold at the respective hub/contract based on preliminary 2019 production guidance

25% AECO $1.75 $0.02 $0.29 $1.44 Henry Hub Dif. $3.64 $1.55 $0.02 $0.29 $1.78 Alliance $2.10 $0.02 $0.33 $1.75 Dawn $3.50 $0.13 $1.20 $2.17 US$3.00/MMBTU US$1.28/MMBTU 1% 158,000 GJ/d 105,000 GJ/d 6,000 GJ/d 154,000 GJ/d November 14, 2018 38% 36%

SLIDE 21

Product Type of contract Quantity Term Natural Gas Dawn Firm Service 120,000 GJ/d

Nov. 1, 2017 - Nov. 1, 2027

Natural Gas Dawn Firm Service 30,000 GJ/d

Nov. 1, 2018 - Nov. 1, 2027

Natural Gas Dawn Firm Service 25,000 GJ/d

Nov. 1, 2019 - Nov. 1, 2027

Total 175,000 GJ/d

RISK MANAGEMENT & HEDGING

In 2019, approximately 62% of Birchcliff’s natural gas production will effectively be

sold at prices that are not based on AECO (based on preliminary 2019 production guidance of 76,000 - 78,000 BOE/d)

Crude Oil Swaps Natural Gas Swaps – NYMEX Henry Hub Natural Gas Firm Egress – Dawn

SLIDE 22

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 $850 million and an extendible revolving working capital facility of $100 million

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

agreed to an extension of the maturity dates from May 11, 2020 to May 11, 2021 and to the borrowing base remaining unchanged at $950 million

The credit facilities contain no financial maintenance covenants
At September 30, 2018, Birchcliff’s long-term bank debt was $635.1 million,

leaving $276.1 million of unutilized credit capacity after adjusting for

utstanding letters of credit and unamortized interest and fees

SLIDE 23

MONTNEY/DOIG RESOURCE PLAY

A Significant Position in a World Class Play

SLIDE 24

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 proppant 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

24 Birchcliff Montney/Doig

SLIDE 25

MONTNEY/DOIG MINEROLOGY LEADS TO EXCELLENT “FRACABILITY”

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.

SLIDE 26

The Gordondale Acquisition added a

fourth commercial development interval in the Montney D2

Large contiguous land base with 349.4

sections prospective for the Montney/Doig as at December 31, 2017

Birchcliff has contiguous land block at

Pouce Coupe and Gordondale of approximately 191 net sections

Stacked resource in some of the thickest

Montney (~300m of consistent thickness) with 4,710.0(1) net potential horizontal locations identified

Low cost structure through ownership of

PC Gas Plant & surrounding field infrastructure

Low decline production

(1) See “Advisories – Drilling Locations”

BIRCHCLIFF MONTNEY/DOIG RESOURCE PLAY

SLIDE 27

STACKED RESOURCE PROVIDES SUBSTANTIAL FUTURE UPSIDE

SLIDE 28

MONTNEY/DOIG MULTI LAYER OPPORTUNITY

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

SLIDE 29

BIRCHCLIFF MONTNEY/DOIG INVENTORY

Note: Location counts based on Deloitte YE2017 Reserve Report

SLIDE 30

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 30

SLIDE 31

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 gas

rates & liquids yields

100% owned and operated
Expect to drill 19 (19.0 net)

Montney/Doig horizontal natural gas wells in 2018 including 17 Montney D1 gas wells, 1 Montney D2 gas well and 1 Montney C gas well

No land expiry issues

SLIDE 32

2018 WELL PERFORMANCE

Deloitte Tier 0 Type Curve

SLIDE 33

CONTINUED WELL IMPROVEMENT

Deloitte Tier 0 Type Curve

2018 Wells choked due to PC Gas Plant being full

SLIDE 34

CONTINUOUS COST AND DESIGN REFINEMENT

500 1,000 1,500 2,000 2,500 1,500 3,000 4,500 6,000 7,500 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 Lateral Length (m) and Frac Intensity (Ton per 1000m) Average DCE Cost per Well (k$)

Birchcliff Corporate Wellbore Evolution

Average Drill and Construction Cost (k$) Average Completion Cost (k$) Average of Equip_Total (k$) Average Lateral Length (m) Average Ton per 1000m

Drilling costs have decreased while overall well costs have slightly increased due to increased frac intensity

SLIDE 35

2017 LIQUIDS SUMMARY MAP

GORDONDALE: CRUDE OIL

Excellent Lower Montney oil inventory in D1 and

D2 intervals

Engineered completions drive recovery factor

improvements

EOR scheme under evaluation

POUCE COUPE: CONDENSATE (C5+)

2017 well results demonstrate condensate rich

multi-zone potential with excellent economics (IP60)

Montney D1: 120-240 bbl/d
Montney D4: 180 bbl/d
Basil Doig/Upper Montney: 110-140 bbl/d
2018 program is expected to extend condensate

rich fairways and improve individual well CGRs through Engineered Completions 35 2017 New Wells IP60 Rates (Avg. Per Well)

SLIDE 36

2018 LIQUIDS SUMMARY MAP

GORDONDALE: CRUDE OIL

Strong Montney D2 oil and total BOE test rates
Strong Montney D1 oil and total BOE test rates
Further refinements of engineered completions

having positive results

POUCE COUPE: CONDENSATE (C5+)

Strong Montney D1 gas condensate and total BOE

test rates

Successfully delineating the Montney D1

condensate fairway

Montney D1 well economics attractive at current

strip gas prices due to high rate gas, high value condensate

POUCE COUPE: SCIENCE & TECHNOLOGY PAD

Vertical well evaluation and learnings
Exploration success Montney D2, 49 bbls/MMcf

CGR

New Engineered Completion success Montney C
Continued delineation of the Montney D1

condensate fairway

36 2018 New Well Production Test Rates

SLIDE 37

Tier 0 Production Summary Tier 0 Type Curve Inputs

Sales Gas C5+ Total Sales Raw Gas EUR

Bcf

8.2 mcf/d bbl/d boe/d Sales EUR

Mboe

1,443 IP30 3,880 57 704 Capped Rate (Sales)

MMcf/d

3.9 IP90 3,880 57 704 CGR (C5+)

bbl/MMcf

14.8 IP180 3,713 55 674 DCCET Capital

$MM

$4.70 IP360 3,189 47 579

1,000 2,000 3,000 4,000 5,000 20 40 60 80 100 120

Sales Gas Rate (Mscfd) Producing Time (Months)

POUCE COUPE LIQUIDS TYPE CURVE – 2018 TARGETED WELL

*FX Assumption: 1.25 CAD/USD *All economics are before tax; reference date is January 1, 2018

Rate of Return (%)

WTI ($US/bbl) $55/bbl $60/bbl $65/bbl AECO $1.50/GJ 30% 32% 35% $2.00/GJ 46% 49% 51% $2.50/GJ 64% 68% 71%

NPV 10% ($MM)

WTI ($US/bbl) $55/bbl $60/bbl $65/bbl AECO $1.50/GJ $3.2 $3.5 $3.8 $2.00/GJ $5.4 $5.7 $6.0 $2.50/GJ $7.7 $8.0 $8.3

Payout (Years)

WTI ($US/bbl) $55/bbl $60/bbl $65/bbl AECO $1.50/GJ 3.0 2.9 2.7 $2.00/GJ 2.2 2.1 2.0 $2.50/GJ 1.7 1.6 1.6

SLIDE 38

GORDONDALE OVERVIEW

Acquired in 2016, Gordondale

consolidated a sizeable and contiguous land base within Birchcliff’s existing core area

High oil & NGLs weighting
Strategic infrastructure
Low base decline production
High quality development
pportunities including the addition of

a fourth commercial development interval in the Montney D2

The 2018 drilling program includes 17

(17.0 net) horizontal wells including 10 Montney D2 oil wells and 7 Montney D1 oil wells

SLIDE 39

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

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

SLIDE 40

5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000 2018 2017 2016 2015 2014 2013 2012 2011 2010 2009 2008

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

Production (boe/d)

Birchcliff Acquisition (~22,000 BOE/d) Scheduled AltaGas Plant Turnaround

SLIDE 41

$55/bbl $60/bbl $65/bbl $1.50/GJ 81% 97% 115% $2.00/GJ 94% 111% 130% $2.50/GJ 108% 126% 146% $55/bbl $60/bbl $65/bbl $1.50/GJ $7.3 $8.3 $9.3 $2.00/GJ $8.3 $9.3 $10.3 $2.50/GJ $9.3 $10.4 $11.3 $55/bbl $60/bbl $65/bbl $1.50/GJ 1.3 1.2 1.1 $2.00/GJ 1.2 1.1 1.0 $2.50/GJ 1.1 1.0 0.9 AECO AECO

D2 Oil Tier 1 - NPV 10% ($MM)

WTI ($US/bbl) AECO

D2 Oil Tier 1 - Payout (Years)

WTI ($US/bbl)

D2 Oil Tier 1 - Rate of Return (%)

WTI ($US/bbl)

D2 Oil Tier 1 Production Summary D2 Oil Type Curve Inputs

Oil Sales Gas C2+ Total Sales Tier 1 Tier 2 bbl/d mcf/d bbl/d boe/d Raw Gas EUR Bcf 4.0 2.1 IP30 257 3005 252 1010 Oil EUR Mbbl 274 200 IP90 229 2714 228 910 Sales EUR Mboe 1,121.1 648.4 IP180 200 2397 201 801 CGR (C2+) bbl/MMcf 84 84 IP360 164 1990 167 663 DCCET Capital $MM $5.30 $5.30

50 100 150 200 250 300 20 40 60 80 100 120

Oil Rate (Bblpd) Producing Time (Months)

D2 Oil Tier 1 Type Curve D2 Oil Tier 2 Type Curve

GORDONDALE D2 OIL TYPE CURVE

*FX Assumption: 1.25 CAD/USD *All economics are before tax; reference date is January 1, 2018

SLIDE 42

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

Second Exploration Horizontal Second Exploration Horizontal First Exploration Horizontal First Exploration Horizontal Approved Acid Gas Injection Well Approved Acid Gas Injection Well

SLIDE 43

CONCEPTUAL MONTNEY/DOIG FIELD DEVELOPMENT MODEL

STATUS OF MODEL CALIBRATION 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

SLIDE 44

Tier 0

500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 5,000 3 6 9 12 15 18 21 24 27 30 Total Measured Depth (m MD) Drilling Time (Days)

Pouce Coupe Drilling Performance - Speed

2017 Pacesetter (Speed) 2016 Pacesetter (Speed) 2015 Pacesetter (Speed) 2007-2014 Pacesetter (Speed) 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 5,000 200 400 600 800 1000 1200 1400 1600 1800 2000 2200 2400 Total Measured Depth (m MD) Drilling Cost ($0,000's)

Pouce Coupe Drilling Performance - Cost

2017 Pacesetter (Cost) 2016 Pacesetter (Cost) 2015 Pacesetter (Cost) 2007-2014 Pacesetter (Cost)

300 350 400 450 500 550 600 650 700 750 800

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 Cost per Drilled Length ($/m MD)

Drill Cost Efficiency

2017 - $1,993k/well (4,832m MD, 32 Stages Planned) 2016 - $1,881k/well (4,492m MD, 20 Stages Planned)

50 100 150 200 250 300 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 Drilling Speed (m/Day)

Average Drilling Speed (Spud to Rig Release)

2017 - 3.7 Days/1000m 2016 - 3.9 Days/1000m

POUCE COUPE DRILLING PERFORMANCE

SLIDE 45

20 40 60 80 100 120 140 160 180 200 0.00 0.10 0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00 2012 2013 2014 2015 2016 2017 Average Interfrac Spacing (m) Average Proppant Intensity (t/m)

Proppant Intensity

5 10 15 20 25 30 35 40 $0 $50 $100 $150 $200 $250 $300 $350 $400 2012 2013 2014 2015 2016 2017 Average Number of Stages (#) Completion Cost Per Stage ($000's)

Completion Cost per Stage vs. Number of Stages

Completion Parameter 2012 2013 2014 2015 2016 2017 Completion Fluid (# of Wells) Surfactant (10) SLW/ X-linked (7) SLW/ X-linked (4) SLW (1) SLW / X-linked (14) SLW (13) SLW (5) SLW (7) 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 2,258 Number of Stages (#) 14 15 16 17 17 29 Interfrac Spacing (m) 134 123 136 126 125 88 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 Tonnage (t) 70 70 75 74 75 60 Proppant Intensity (t/m) 0.54 0.61 0.60 0.60 0.62 0.74 Completions Cost Per Stage ($000's) 229 182 175 101 66 61

POUCE COUPE LOWER MONTNEY (D1) CORE AREA COMPLETION EVOLUTION

SLIDE 46

ENGINEERED COMPLETIONS FOR MONTNEY/DOIG FULL FIELD DEVELOPMENT

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 50 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) 2,500 m (8,200 ft) 2,300 m (7,500 ft) Estimated DCCET $4.0 - $13.0 million $5.3 million(1) $4.6 million(2) C*

Approximately $8.0 million

Approximately $7.0 million

(1) Estimated by McDaniel. Down compared to 2016 based on actual costs incurred in 2017 and go forward DCCET costs. (2) Estimated by Deloitte. Up slightly compared to 2016 due to increased frac intensity in completions.

SLIDE 47

TERMINAL DECLINE CHANGES

Continued support for low terminal decline rates from Birchcliff’s existing wells and
ffsetting industry wells with significant production history.
Deloitte’s Tier 0 type curve has remained at 8.2 Bcfe sales with the same terminal

decline rates of 11% Proved and 9% Proved plus Probable.

Deloitte’s Tier 0 type curve estimates that the well enters its terminal decline after 4

years TP and 4.9 years 2P

2008 2009 - 2010 2011 2012 - 2015 2016 - 2017 Terminal Decline Hyperbolic Exponential Exponential Exponential Exponential TP 30% 20% 17% 13% 11% 2P 20% 13.35% 13% 10% 9%

SLIDE 48

PC GAS PLANT

The Engine for Future Growth

SLIDE 49

Production Processed through the PC Gas Plant 2013 2014 2015 2016 2017(4) 9 Mo. 2018(4)

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

91,666 132,808 163,641 168,444 193,417 261,313

Oil & condensate (bbls)

527 1,065 1,287 960 1,316 2,910

Total boe (6:1)

15,805 23,200 28,560 29,034 33,552 46,462

% of corporate natural gas production

73% 78% 81% 68% 60% 70%

% of corporate production

61% 69% 73% 59% 49% 60%

Average AECO price for period ($/Mcf)

$3.17 $4.50 $2.69 $2.16 $2.16 $1.48

Netback and cost:

$/Mcfe $/boe $/Mcfe $/boe $/Mcfe $/boe $/Mcfe $/boe $/Mcfe $/boe $/Mcfe $/boe

Petroleum and natural gas revenue(1)

3.77 22.64 5.17 31.02 3.17 19.03 2.54 15.21 3.04 18.24 2.87 17.20

Royalty expense

(0.16) (0.93) (0.24) (1.42) (0.11) (0.63) (0.06) (0.38) (0.07) (0.44) (0.05) (0.29)

Operating expense (2)

(0.37) (2.24) (0.42) (2.52) (0.31) (1.90) (0.25) (1.49) (0.34) (2.07) (0.35) (2.08)

Transportation and marketing expense(3)

(0.25) (1.55) (0.30) (1.81) (0.31) (1.88) (0.33) (1.96) (0.44) (2.61) (0.56) (3.37)

Estimated operating netback

$2.99 $17.92 $4.21 $25.27 $2.44 $14.62 $1.90 $11.38 $2.19 $13.12 $1.91 $11.46

Operating margin

79% 79% 81% 81% 77% 77% 75% 75% 72% 72% 67% 67%

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.

(3)

Transportation and marketing expense includes Dawn firm service beginning November 1, 2017.

(4)

Revenue impacted by Dawn firm service beginning November 1, 2017. Dawn prices averaged $3.87/Mcf for Nov/Dec 2017 and $3.73/Mcf 2018 YTD.

SLIDE 50

$0.00 $1.00 $2.00 $3.00 $4.00 $5.00 5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000 2011 2012 2013 2014 2015 2016 2017 AECO/PC Op. Netback ($/Mcfe PC Plant Production (boe/d)

Average AECO Price vs. PC Gas Plant Operating Netback

Production processed through the PC Gas Plant (boe/d) Average AECO Price ($/Mcf) PC operating netback ($/Mcfe) 0% 20% 40% 60% 80% 100% $0.00 $2.00 $4.00 $6.00 $8.00 $10.00 2009 2010 2011 2012 2013 2014 2015 2016 2017 Volume Through PC Gas Plant Corporate Operating Cost ($/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

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

SLIDE 51

PC GAS PLANT HIGHLIGHTS

Current processing capacity of 340 MMcf/d
Phase VI expansion was completed ahead of

it’s initially scheduled October 1, 2018 completion date, adding 80 MMcf/d bringing total processing capacity to 340 MMcf/d

Phase V & VI (combined 160 MMcf/d)

configured with shallow-cut capability for removal of C3+ liquids

In light of the reduced processing fee

arrangement at Gordondale with AltaGas, we currently have no plans to proceed with any further expansion phases of the Pouce Coupe Gas Plant.

70% 30%

2018YTD Natural Gas Volumes Processed at PC Gas Plant Other 2018YTD Natural Gas Volumes

SLIDE 52

BUILDING ON OUR PAST

Over 10 Years of Success

SLIDE 53

2004 2018 Forecasted record annual average production of 76,000-78,000 boe/d in 2018

Birchcliff’s average daily production was 67,963 boe/d in 2017 compared to 2,793 boe/d in 2005, a compounded annual growth rate of 30% per year over that span.

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. 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.

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 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. October 2, 2017: Announced the early commencement of Phase V

f the PC Gas Plant with combined processing capacity of 260

MMcf/d. August 14, 2018: Announced the early commencement of Phase VI

f the PC Gas Plant with combined processing capacity of 340

MMcf/d.

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

1 2 3 4 5 7 6 11 8 9 10

SLIDE 54

$- $2 $4 $6 $8 $10 $12 $14 $16 $18 $20 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 $/boe

Operating & Cash Costs*

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

50 100 150 200 250 300 10,000 20,000 30,000 40,000 50,000 60,000 70,000 80,000 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 boe/d/million wtd. avg. shares boe/d

Production Growth

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

Birchcliff has increased production at a

compound annual growth rate of 30% since 2005. Operating and cash costs have decreased by 57% 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.

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

SLIDE 55

800 1,600 2,400 3,200 4,000 200 400 600 800 1000 1200 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 boe/1,000shares MMboe

Reserves Growth

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

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 21% per year, respectively.

Over 13 years of operations, Birchcliff has…  Invested $3.8 billion in capital  Realized $161 million in net income to common shareholders  Generated $3.4 billion in revenue  Grown 2P NAV to $5.1 billion  Delivered $1.6 billion in cash flow  Drilled 348 Montney/Doig horizontal natural gas wells

SLIDE 56

APPENDIX

SLIDE 57

ENOUGH RESOURCE TO FILL A 2.1 Bcf/d LNG TRAIN FOR OVER 20 YEARS!

4.9 Tcf

+ / =

10.3 Tcf 20 Years 2.1 Bcf/d

BIR Remaining Reserves as at Dec 31, 2017 (gas only) BIR Contingent Resource as at Dec 31, 2017 (gas only)

1 Bcf/d LNG Train

X X =

365 Days 20 Years 7.3 Tcf

3,971 8,409 8,857 5,812 12,358 13,484 7,195 19,561 20,629 5,000 10,000 15,000 20,000 25,000 Remaining Reserves Contingent Resources Prospective Resources Reserves & Resource Volumes (Bcfe)

Birchcliff 2017 Montney/Doig Resource Assessment

Low Estimate Case Best Estimate Case High Estimate Case

SLIDE 58

2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 PDP 733 1,063 2,504 6,051 7,791 17,200 25,400 41,500 50,538 73,095 92,380 151,964 194,145 TP 2,376 3,351 9,661 29,158 61,880 85,900 127,100 156,500 193,705 255,208 321,752 518,966 659,029 2P 4,553 10,172 19,347 57,724 115,515 158,400 227,700 266,800 319,215 412,336 516,821 825,455 963,836 100,000 200,000 300,000 400,000 500,000 600,000 700,000 800,000 900,000 1,000,000 Reserves (Mboe) PDP TP 2P

2017 YEAR END MONTNEY/DOIG RESERVES

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

348 (342.8 net) Montney/Doig horizontal wells drilled as of Dec 31, 2017

(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 HZ M/D wells Drilled 53 HZ M/D wells

SLIDE 59

MONTNEY/DOIG WELL LOCATIONS

SLIDE 60

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 Yield on Par Price 8.374% Redeemable by Holder No

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

SLIDE 61

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

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

SLIDE 62

EXECUTIVE OFFICERS

A. Jeffery

Tonken

President, CEO and Chairman of the Board

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.

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

Myles R. Bosman

Vice-President, Exploration and Chief Operating Officer

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.

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

Bruno P. Geremia

Vice-President and Chief Financial Officer

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.

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.

SLIDE 63

EXECUTIVE OFFICERS

Christopher A. Carlsen

Vice-President, Engineering

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.

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

David M. Humphreys

Vice-President, Operations

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.

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

SLIDE 64

BOARD OF DIRECTORS

A. Jeffery

Tonken

President, CEO and Chairman of the Board

A. Jeffery

Tonken

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

James W. Surbey

Director

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.

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.

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.

Dennis Dawson

Independent Director

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.

Mr. Dawson is a director of Birchcliff. Prior to joining Birchcliff, Mr. Dawson was the Vice-President General Counsel and

SLIDE 65

BOARD OF DIRECTORS

Rebecca Morley

Independent Director

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.

Ms. Morley has 15 years of experience in the capital markets, having worked as an Equity Research Associate at TD

Debbie Gerlach

Independent Director

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.

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

SLIDE 66

PRESENTATION OF OIL AND GAS RESERVES AND RESOURCES:

Deloitte prepared the 2017 Consolidated Reserves Report, the 2017 Deloitte Reserves Report, and the 2016 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.

SLIDE 67

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 2018. 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, 2017 by 77,000 boe/d, which production rate represents the mid-point of Birchcliff’s annual average production guidance range for 2018. 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.

SLIDE 68

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 5,052.8 net existing horizontal wells and potential net future horizontal drilling locations identified herein, 846.0 are proved locations, 1070.0 are proved plus probable locations and 3,982.8 are unbooked locations. Proved locations and probable locations are proposed drilling locations identified in the 2017 Consolidated Reserves Report that have proved and/or probable reserves, as applicable, attributed to them in the 2017 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 2017 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, decline rates, 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.

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 commodityprices 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:

SLIDE 69

THANK YOU TEAM BIRCHCLIFF

Jeffrey Akeroyd, Bradley Alexander, Karen Allen, Camille Ashton, Gates Aurigemma, Valerie Babkov, Bryce Baloun, Angela Belbeck, Charmaine Belley, Tyrus Bender, Daniel Blattler, Calvin Bohdan, Angela Boire, Darryl Bolch, Deborah Borthwick, Myles Bosman, Jeff Boswell, Robyn Bourgeois, David Boyle, Wayne Brown, Madison Burns, Dave Campbell, Chris Carlsen, Alex Carlson, Caitlin Carrigy, Ann Ceccanese, Bhuwan Chauhan, Matthew Chorney, Benjamin Christenson, Wendy Clay, Dallas Cline, Kalen Conrad, Mike Cordingley, Loren Damer, Dennis Dawson, Lara de Paula, Jesse Doenz, Joe Doenz, Kelly Dolen, Terrance Dyck, Darryl Easter, Emily Ebbels, John (Cliff) Ennis, Tim Etcheverry, Lindsay Fast , Laura Ferguson, Kelsey Frechette, Grant Friesen, Marshall Fritz, George Fukushima, Andy Fulford, Carrie Fyfe, Alexandra Gatza, Melina Geremia, Bruno Geremia, Debra Gerlach, Chad Goddard, David Graham, Lee Grant, Hannah Grigore, Ryan Gugyelka, Rylan Gulka, Tania Haberlack-Dolan, Mike Hale, Samuel Hampton, Trevor Harley, Richard Harris, Wanda Hiebert, Lorna Hildebrand, Warren Hingley, Jeremy Hingley, Paul Hirsekorn, Leah (Janet) Hogan, Jasen Holmstrom, Daryl Hudak, Dave Humphreys, Derek Jamieson, Anna Johnson, Julie Johnson, Kathyrn (Katy) Josephs, Katrina Keable, Dustin Kelm, Gregory Kilgour, Phyllis Kinzner, Melissa Kinzner, Diane Knoblauch, Ashley Kozlowski Urch, Danny Kutrowski, Dani Laird, Anji Lawrence, Katherine Lazaruk, Heather Leahey, Calvin Leithead, Kristen Lewicki, Michael Lillejord, Ryan Linsley, Thomas Lundquist, Scott Lundquist, Joe Lyste, John MacGillivray, Dallas MacLean, Darcy MacLeod, Mary MacNeill, Curtis Mah, Maggie Malapad, Arun Mann, Kevin Matiasz, John Matijevich, Deb McFee, Angie McGonigal, Marc McIntosh, Ryan McIntosh, Dani McPhee, Jennifer McPherson, Jerilyn McPherson (McLeod), Richard Melling, Paul Messer, Alfred Michetti, Derek Michetti, Emelyia Moghaddami, Rebecca Morley, Amy Morris, Stephen Morton, Steve Mueller, McKenzie Murdoch, Tyler Murray, Kody Naka, Sarah Nance, Michael Ng, Tam Nguyen, Matteo Niccoli, Christopher Olson, Laura O’Neill, Jason Orrock, Philomena Paisley, Bruce Palmer, Bill Partridge, Dean Paterson, Jesse Peterson, Paul Picco, Allan Pickel, Landon Poffenroth, Taylor Poole, Andrei Popescu, Austin Power, Glenn Power, Shoni Proctor, Brian Ritchie, Michelle Rodgerson, Blaine Rogers, Jeff Rogers, Sherri Rosia, Randy Rousson, Jared Rousson, Todd Sajtovich, Lee Sallenbach, Victor Sandhawalia, Wade Schultz, Mohammad (Sadeq) Shahamat, Dan Sharp, Larry Shaw, Amy Short, Ryan Sloan, Kiran Somanchi, Hilary Steinbach, Darby Stolk, Lindsay Sturrock, Tracey Suchlandt, Tyson Suderman, Jim Surbey, Theresa Sutton (Hannouche), Ryan Swanson, Duane Thompson, Jeff Tonken, Gillian Topping, Tammy Tran, Hue Tran, Theo van der Werken, Kara Vance, Kris Veach, Greg Vreim, Linda Wang, Michael Warrick, Shelby Watson, Matt Weiss, David Wetta, Philip Wu, John Yeo, Deirdre Yuzwa