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 the meaning of applicable Canadian securities laws. Such forward-looking information relates to future events or Birchcliff’s future performance. All information other than historical fact may be forward-looking information. Such forward-looking information is often, but not always, identified by the use of words such as “seek”, “plan”, “expect”, “project”, “intend”, “believe”, “anticipate”, “estimate”, “estimated”, “forecast”, “potential”, “proposed”, “predict”, “budget”, “continue”, “targeting”, “may”, “will”, “could”, “might”, “should” and other similar words and expressions. This information involves known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking information. Birchcliff believes that the expectations reflected in the forward-looking information are reasonable in the current circumstances but no assurance can be given that these expectations will prove to be correct and such forward-looking information included in this presentation should not be unduly relied upon. In particular, this presentation contains forward-looking information relating to the following: Birchcliff’s plans and other aspects of its anticipated future operations, focus, objectives, strategies, opportunities, 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’s preliminary plans and guidance for 2019 (including that Birchcliff will 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 Birchcliff will 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’s hedging strategy and the use of risk-management techniques; Birchcliff’s future growth plans for the Elmworth area, including Birchcliff’s intention to construct and operate the Elmworth Gas Plant and the anticipated processing capacity and timing thereof; Birchcliff’s dividend policy and the payment of dividends, including the amount of and timing of the payment of future dividends and statements regarding the sustainability of dividends; reference to the potential for LNG export in the future; proposed completion techniques for Pouce Coupe core area Montney D1 horizontal wells in 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 Birchcliff operates; the regulatory framework regarding royalties, taxes and environmental laws; the sources of funding for Birchcliff’s capital expenditure programs and other activities; anticipated timing and results of capital expenditures; the sufficiency of budgeted capital expenditures to carry out planned operations; Birchcliff’s ability to find opportunities to reduce costs and defer certain capital expenditures; results of future operations; future operating, transportation, marketing and general and administrative costs; the performance of existing and future wells, well production rates and well decline rates; well drainage areas; success rates for future drilling; reserves and resource volumes and Birchcliff’s ability to replace and expand oil and gas reserves through acquisition, development or exploration; the impact of competition on Birchcliff; the availability of, demand for and cost of labour, services and materials; Birchcliff’s ability to access capital; the ability to obtain financing on acceptable terms; the ability to obtain any necessary regulatory approvals in a timely manner; the ability of Birchcliff to secure adequate transportation for its products; Birchcliff’s ability to market oil and gas; and the availability of hedges on terms acceptable to Birchcliff. In addition to the foregoing assumptions, Birchcliff has made the following assumptions with respect to certain forward-looking information contained in this presentation: • With respect to the Acquisition, Birchcliff has 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. o 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 Birchcliff relies on to produce its wells and that any transportation service curtailments or unplanned outages that occur will be short in duration or otherwise insignificant; the construction of new infrastructure meets timing and operational expectations; existing wells continue to meet production expectations; and future wells scheduled to come on production meet timing, production and capital expenditure expectations. • With respect to estimates of reserves volumes and the net present values of future net revenue associated with Birchcliff’s reserves, the key assumption is the validity of the data used by Deloitte and McDaniel in their independent reserves evaluations. • With respect to statements of future wells to be drilled and brought on production and estimates of potential future drilling locations and opportunities, the key assumptions are: the continuing validity of the geological and other technical interpretations performed by Birchcliff’s technical staff, which indicate that commercially economic volumes can be recovered from Birchcliff’s lands as a result of drilling future wells; and that commodity prices and general economic conditions will warrant proceeding with the drilling of such wells. • With respect to statements regarding proposed expansions of the PC Gas Plant, including the anticipated processing capacities of the PC Gas Plant after such expansions and the anticipated timing of such expansions, the key assumptions are that: future drilling is successful; there is sufficient labour, services and equipment available; Birchcliff will have access to sufficient capital to fund those projects; the key components of the plant will operate as designed; and commodity prices and general economic conditions will warrant proceeding with the construction of such facilities and the drilling of associated wells. • With respect to statements regarding Birchcliff’s intention to construct and operate the Elmworth Gas Plant, including the anticipated processing capacity of such plant and the anticipated timing thereof, the key assumptions are that: future drilling in the Elmworth area is successful; the acid gas disposal well drilled by 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; Birchcliff will have access to sufficient capital to fund the Elmworth Gas Plant; and commodity prices and general economic conditions warrant proceeding with the construction of the Elmworth Gas Plant and the drilling of associated wells. Birchcliff’s actual results, performance or achievements could differ materially from those anticipated in the forward-looking information as a result of both known and unknown risks and uncertainties including, but not limited to: the failure to realize the anticipated benefits of acquisitions and disposition, including the Gordondale Acquisition; unforeseen difficulties in integrating the Gordondale Assets into Birchcliff’s operations; variances in Birchcliff’s actual 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’s firm marketing and transportation arrangements; the inability to secure adequate production transportation for Birchcliff’s products; the occurrence of unexpected events such as fires, equipment failures and other similar events affecting Birchcliff or other parties whose operations or assets directly or indirectly affect Birchcliff; potential delays or changes in plans with respect to exploration or development projects or capital expenditures; stock market volatility; loss of market demand; environmental risks, claims and liabilities; incorrect assessments of the value of acquisitions and exploration and development programs; shortages in equipment and skilled personnel; the absence or loss of key employees; uncertainties associated with the outcome of litigation or other proceedings involving Birchcliff; uncertainty that development activities in connection with its assets will be economical; competition for, among other things, capital, acquisitions of reserves, undeveloped lands, equipment and skilled personnel; uncertainties associated with credit facilities; counterparty credit risk; risks associated with Birchcliff’s hedging program and the risk that hedges on terms acceptable to Birchcliff may not be available; and risks associated with the declaration and payment of dividends, including the discretion of Birchcliff’s board of directors to declare dividends. Readers are cautioned that the foregoing lists of factors are not exhaustive. Additional information on these and other risk factors that could affect results of operations, financial performance or financial results are included in Birchcliff’s most recent Annual Information Form and in other reports filed with Canadian securities regulatory authorities. Any future-orientated financial information and financial outlook information (collectively, “FOFI”) contained in this presentation, as such terms are defined by applicable securities laws, is provided for the purpose of providing information about management’s current expectations and plans relating to the future and is subject to the same assumptions, risk factors, limitations and qualifications as set forth in the above paragraphs. FOFI contained in this presentation was made as of the date of this presentation and Birchcliff disclaims any intention or obligation to update or revise any FOFI contained in this presentation, whether as a result of new information, future events or otherwise, unless required by applicable law. Readers are cautioned that any FOFI contained herein should not be used for purposes other than those for which it has been disclosed herein. Management has included the above summary of assumptions and risks related to forward-looking information provided in this presentation in order to provide readers with a more complete perspective on Birchcliff’s future operations. Readers are cautioned that this information may not be appropriate for other purposes. The forward-looking information contained in this presentation is expressly qualified by the foregoing cautionary statements. The forward-looking information contained in this presentation is made as of the date of this presentation. Birchcliff is not under any duty to update or revise any of the forward-looking information except as expressly required by applicable securities laws. SELECTED DEFINITIONS: “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.
2 PEOPLE, FOCUS & EXECUTION
3 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.
4 Q3 2018 HIGHLIGHTS
• 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
5 INVESTMENT HIGHLIGHTS
• 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)
(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”.
6 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
7 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
8 BIRCHCLIFF’S HISTORY A Track Record of Execution KEYS TO SUCCESS
. Executives with proven track record, continuity since inception and significant ownership Management . Highly experienced Management Team with excellent technical knowledge and a long history with the company . 348 (342.8 net) Montney/Doig horizontal wells drilled to December 31, 2017 all utilizing multi-stage Operational fracture stimulated technology Execution . 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 . Significant in-house technical expertise and experience on the Peace River Arch Technical . Supports continual improvements in high grading portfolio for the decision making process Expertise . Continued improvements in estimated reserve recovery per well, drilling & completion practices and operating costs
Scale & . Consistent, repeatable, predictable growth and results Repeatability . 4,710 potential Montney/Doig horizontal locations and as at December 31, 2017(1)
. Full cycle profitability with top tier F&D costs and netbacks through 2017 and prior years Financial . Accurate and reliable real time forecasts supported by a detailed capital management and production Execution forecasting process which is fully integrated into our financial reporting systems
(1) See “Advisories – Drilling Locations”
10 90,000 PRODUCTION HISTORY
76,000 - 80,000 78,000
70,000 Compound per-share production 67,963 growth of 12% per year since 2005. (14% since PC Gas Plant Phase I 60,000 Completion)
49,236 50,000
38,950 40,000 33,734 Average Production (boe/d) 30,000 25,829 22,802 20,000 18,136 13,079 10,148 11,216 10,000 5,368 6,711 2,793 0 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018E
11 BIRCHCLIFF CORPORATE DECLINE(1)
Long life, low decline asset allows for smaller capital wedge YoY needed to maintain volumes
26% 20% Base Decline Base Decline Corporate Production (boe/d)
2005-2017 2018 2019 (1) Production profile provided for general illustrative purposes only and not indicative of expected production profile
12 CORPORATE RESERVES 1,000,000 $7,000 PDP - Reserves
900,000 TP - Reserves 2P - Reserves $6,000 800,000 PDP - NPV10 On a per share basis PDP, 1P and 2P TP - NPV10 reserves have increased at a compound 700,000 $5,000 2P - NPV10 annual growth rate of 14%, 22% and 21% per year since 2005, respectively 600,000 $4,000
500,000
$3,000 400,000 Reserves (Mboe) Reserves NPV10 - Btax ($MM) Btax - NPV10
300,000 $2,000
200,000 $1,000 100,000
0 $0 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017
(1) See appendix at the end of this presentation for disclosures on oil & gas reserves and related metrics.
13 PROVEN TRACK RECORD AS A LOW COST PRODUCER
5 Year Profitability Breakdown: 2013 2014 2015 2016 2017 Average Average AECO (CAD$/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) ($2.59) ($2.34) ($1.83) ($1.77) ($2.06) ($/Mcfe) ($1.78) Profit ($/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
14 PROVEN TRACK RECORD AS A LOW COST FINDER
$16 PDP F&D 1P F&D 2P F&D 1.2x $12 1.8x 1.8x 1.9x Cash flow netback recycle 1.6x $8 2.0x 2.0x ratios 1.4x 1.6x 2.3x 1.8x 3.0x 1.3x 2.0x
& ot ($/boe) CostF&D $4 1.7x 1.8x
4.7x 7.3x $0 2013 2014 2015 2016 2017 5 Yr Avg
Corporate F&D Costs (incl. FDC) & Cash Flow Recycle Ratios 2013 2014 2015 2016 2017 5 Yr Avg PDP F&D ($/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
15 LOOKING FORWARD 2018 Plans & Beyond 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$3.00/MMBTU Henry Hub, 1.28 CAD/USD.
17 REVISED 2018 CAPITAL PROGRAM DETAILS 2018 CAPITAL PROGRAM Drilling & Development Gross Wells Net Wells Capital ($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. (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. (5) Includes: (i) $3.5MM for the construction of two water reservoirs; (ii) $0.4MM of 2019 pipeline pre-spend capital. (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".
18 2018YTD NATURAL GAS MARKETING
AECO November 14, 2018 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 $1.11 283,000 GJ/d
67% 29%
4% 125,000 GJ/d Dawn 17,000 GJ/d Q1 Q2 Q3 YTD Alliance $3.63 $3.40 $3.60 $3.54 Q1 Q2 Q3 YTD $0.14 $0.13 $0.15 $0.15 $3.11 $1.16 $1.43 $2.09 $1.16 $1.16 $1.12 $1.14 $0.11 $0.02 $0.02 $0.05 $2.33 $2.11 $2.33 $2.25 $1.11 $0.11 $0.18 $0.57 $1.89 $1.04 $1.23 $1.46 Note: All Birchcliff gas realizes a 9% heat premium(1)
Pricing Hub Realized Sales Price at Hub (C$/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)
(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
19 2019 NATURAL GAS MARKETING
November 14, 2018 AECO $1.75 $0.02 $0.29 $1.44
158,000 GJ/d
38%
36%
1% 154,000 GJ/d Dawn $3.50 6,000 GJ/d $0.13 Alliance $1.20 25% $2.10 $2.17 $0.02 $0.33 105,000 GJ/d $1.75 Note: All Birchcliff gas realizes a Henry Hub 9% heat premium(1) Dif. US$3.00/MMBTU $3.64 Pricing Hub US$1.28/MMBTU $1.55 Forecasted Sales Price at Hub (C$/GJ)(2) $0.02 Hedged Differential (C$/GJ)(2) $0.29 Estimated Fuel Cost From Field to Sales Point (C$/GJ)(3) $1.78 Estimated Transportation Cost From Field to Sales Point (C$/GJ)(4) Estimated Sales Netback (C$/GJ)(5)
(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
20 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
Product Type of contract Quantity Term Natural Gas Dawn Firm Service 120,000 GJ/d Nov. 1, 2017 - Nov. 1, 2027 Natural Gas Firm Egress – Dawn 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
21 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 outstanding letters of credit and unamortized interest and fees
22 MONTNEY/DOIG RESOURCE PLAY A Significant Position in a World Class Play MONTNEY/DOIG - A WORLD CLASS RESOURCE PLAY Resource density. Stacked resource up to 300 metres thick. Large areal extent. Extends over 50,000 square miles. Exceptional “fracability”. Low clay Birchcliff Montney/Doig content, low Poisson’s Ratio and high Young’s Modulus. Exceptional fracture stability. Fractures stay open due to very low 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 MONTNEY/DOIG MINEROLOGY LEADS TO EXCELLENT “FRACABILITY”
The Montney/Doig Resource Play rock type is composed of a Some other Resource Plays have a high percentage of clays high percentage of hard minerals, and a low percentage of and soft minerals. When fractured this results in the rock clays and soft minerals. When fractured this results in a breaking similar to concrete, in a simple bi-wing fracture complex fracture system similar to shattering glass. This system. This simple bi-wing fracture system can lead to less complex fracture system enhances stimulated rock volume stimulated rock volume, which in tight shale reservoirs can and allows hydrocarbons to flow at greater quantities into the lead to less effective long term hydrocarbon production rates horizontal wellbore leading to enhanced production rates and and EUR’s. EUR’s.
25 BIRCHCLIFF MONTNEY/DOIG RESOURCE PLAY • 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”
26 STACKED RESOURCE PROVIDES SUBSTANTIAL FUTURE UPSIDE
27 MONTNEY/DOIG MULTI LAYER OPPORTUNITY
3 2 1 4 5 6
5 6
4 3
2
1
28 BIRCHCLIFF MONTNEY/DOIG INVENTORY
Note: Location counts based on Deloitte YE2017 Reserve Report
29 PROXIMAL TO INFRASTRUCTURE WITH LONG TERM EXPOSURE TO LNG EXPORT Montney/Doig Birchcliff Pouce Coupe Production Montney/Doig & PC Gas Plant Owned Infrastructure
PC Gas Plant
Nova Pipeline System
North American Market
LNG Export
Source: RBC Energy Insights: The Montney – Tracking an Elephant August 12, 2014
30 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
31 2018 WELL PERFORMANCE
Deloitte Tier 0 Type Curve
32 CONTINUED WELL IMPROVEMENT
Deloitte Tier 0 Type Curve
2018 Wells choked due to PC Gas Plant being full
33 CONTINUOUS COST AND DESIGN REFINEMENT Drilling costs have decreased while overall well costs have slightly Birchcliff Corporate Wellbore Evolution increased due to 7,500 increased2,500 frac intensity
6,000 2,000
4,500 1,500
3,000 1,000
Average DCE Cost per Well (k$) Well per Cost DCE Average 1,500 500 Lateral Length (m) and Frac Intensity (Ton 1000m) per (Ton Intensity Frac and (m) Length Lateral 0 0 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017
Average Drill and Construction Cost (k$) Average Completion Cost (k$) Average of Equip_Total (k$) Average Lateral Length (m) Average Ton per 1000m
34 2017 LIQUIDS 2017 New Wells IP60 Rates (Avg. Per Well) SUMMARY MAP GORDONDALE: CRUDE OIL • Excellent Lower Montney oil inventory in D1 and D2 intervals • Engineered completions drive recovery factor improvements • EOR scheme under evaluation
POUCE COUPE: CONDENSATE (C5+) • 2017 well results demonstrate condensate rich multi-zone potential with excellent economics (IP60) • Montney D1: 120-240 bbl/d • Montney D4: 180 bbl/d • Basil Doig/Upper Montney: 110-140 bbl/d • 2018 program is expected to extend condensate rich fairways and improve individual well CGRs through Engineered Completions
35 2018 LIQUIDS 2018 New Well Production Test Rates SUMMARY MAP
GORDONDALE: CRUDE OIL • Strong Montney D2 oil and total BOE test rates • Strong Montney D1 oil and total BOE test rates • Further refinements of engineered completions having positive results
POUCE COUPE: CONDENSATE (C5+) • Strong Montney D1 gas condensate and total BOE test rates • Successfully delineating the Montney D1 condensate fairway • Montney D1 well economics attractive at current strip gas prices due to high rate gas, high value condensate
POUCE COUPE: SCIENCE & TECHNOLOGY PAD • Vertical well evaluation and learnings • Exploration success Montney D2, 49 bbls/MMcf CGR • New Engineered Completion success Montney C • Continued delineation of the Montney D1 condensate fairway
36 POUCE COUPE LIQUIDS TYPE CURVE – 2018 TARGETED WELL 5,000 Rate of Return (%) WTI ($US/bbl) $55/bbl $60/bbl $65/bbl $1.50/GJ 30% 32% 35% 4,000 $2.00/GJ 46% 49% 51% AECO $2.50/GJ 64% 68% 71%
3,000 NPV 10% ($MM) WTI ($US/bbl) $55/bbl $60/bbl $65/bbl 2,000 $1.50/GJ $3.2 $3.5 $3.8 $2.00/GJ $5.4 $5.7 $6.0 AECO
Sales Gas Rate (Mscfd) Rate Gas Sales $2.50/GJ $7.7 $8.0 $8.3 1,000 Payout (Years) WTI ($US/bbl) 0 $55/bbl $60/bbl $65/bbl 0 20 40 60 80 100 120 $1.50/GJ 3.0 2.9 2.7 $2.00/GJ 2.2 2.1 2.0 Producing Time (Months) AECO $2.50/GJ 1.7 1.6 1.6
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
*FX Assumption: 1.25 CAD/USD *All economics are before tax; reference date is January 1, 2018
37 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 opportunities 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
38 GORDONDALE KEY INFRASTRUCTURE
Key Natural Gas Processing Infrastructure
• Existing infrastructure has already AltaGas Gordondale CNRL Progress Sour Deep Cut Gas Plant Sour Shallow Cut Gas Plant supported peak production of 16-31-078-11W6 01-01-078-10W6 Licensed Capacity: ~135 MMcf/d Acquired W.I.: ~10% ~35,000 boe/d Current BIR Rate: ~100 MMcf/d Licensed Capacity: ~130MMcf/d Current Rate: ~125 MMcf/d • Natural gas is primarily processed at Key Light Oil Handling the AltaGas Deep Cut Sour Gas Infrastructure Birchcliff Plant which has a processing Oil Battery 02-06-079-11W6 capacity of ~135 MMcf/d Capacity: ~10,000 bbl/d Alliance Pipeline Birchcliff • Includes two light oil batteries with Oil Battery 07-29-078-11W6 Capacity: ~10,000 bbl/d combined oil handling capacity of NGTL Acquired Encana 20,000 bbl/d (100% W.I.) Compressors
Birchcliff • Includes a non-operated W.I. of Sour Compressor Station 02-05-079-11W6 ~10% in CNRL Progress Gas Plant, Capacity: ~12 MMcf/d adding to Birchcliff’s existing 3% W.I. Birchcliff Sour Compressor Station 05-27-078-11W6 • Third party processing and Capacity: ~32 MMcf/d Birchcliff transportation agreements, including Sour Compressor Station 16-19-077-10W6 firm transportation capacity on the Capacity: ~21 MMcf/d
Pembina pipeline system Gas Plants Pembina Pipeline Acquired Montney Land Oil Batteries NGTL Pipeline Acquired ECA Wells Alliance Pipeline Oil Well Effluent Pipeline Compressor Stations
39 GORDONDALE BASE PRODUCTION HISTORY
Last well drilled in 2014 (on-stream Birchcliff Scheduled 40,000 2015) with peak production of Acquisition AltaGas Plant ~35,000 boe/d (~22,000 BOE/d) Turnaround 35,000
30,000 AltaGas Deep Cut Plant on 2018 stream October 2012 and 2017 Montney oil pool development 25,000 commenced 2016 2015 20,000 Montney oil pool 2014 discovered in 2010 2013 15,000 Horizontal gas 2012 development in late 2000s 2011 Production Production (boe/d) 10,000 2010 2009 5,000 2008
0
40 GORDONDALE D2 OIL TYPE CURVE
D2 Oil Tier 1 - Rate of Return (%) D2 Oil Tier 1 Type Curve D2 Oil Tier 2 Type Curve WTI ($US/bbl) 300 $55/bbl $60/bbl $65/bbl $1.50/GJ 81% 97% 115% $2.00/GJ 94% 111% 130% 250 $2.50/GJ 108% 126% 146%
200 D2 Oil Tier 1 - NPV 10% ($MM) WTI ($US/bbl) 150 $55/bbl $60/bbl $65/bbl $1.50/GJ $7.3 $8.3 $9.3
Oil Rate (Bblpd) Rate Oil 100 $2.00/GJ $8.3 $9.3 $10.3 AECO $2.50/GJ $9.3 $10.4 $11.3 50 D2 Oil Tier 1 - Payout (Years) WTI ($US/bbl) 0 $55/bbl $60/bbl $65/bbl 0 20 40 60 80 100 120 $1.50/GJ 1.3 1.2 1.1 Producing Time (Months) $2.00/GJ 1.2 1.1 1.0 EOAECO AECO $2.50/GJ 1.1 1.0 0.9
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
*FX Assumption: 1.25 CAD/USD *All economics are before tax; reference date is January 1, 2018
41 ELMWORTH DEVELOPMENT
• Received regulatory approval for an Second acid gas injection well in August 2016 Exploration Horizontal • 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 First • Drilled two successful exploration Exploration horizontal wells into the Montney D4 Approved Acid Horizontal Gas Injection interval, both of which are expected Well to result in follow up drilling and significant future reserve additions • Will leverage over 10 years of Montney experience
42 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 T1
D4 T2
D3
D2 >T0
D1 >T0
C >T4
43 POUCE COUPE DRILLING PERFORMANCE
Drill Cost Efficiency Average Drilling Speed (Spud to Rig Release) 800 300 750 2017 - $1,993k/well (4,832m MD, 32 Stages Planned) 250 2017 - 3.7 Days/1000m 700 2016 - $1,881k/well (4,492m MD, 20 Stages Planned) 2016 - 3.9 Days/1000m 650 200 600
550 150 500 100 450 Drilling Speed (m/Day)Speed Drilling
Cost per Drilled Length ($/m MD) ($/m Length Drilled per Cost 400 50 350
300 0 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017
Pouce Coupe Drilling Performance - Cost Pouce Coupe Drilling Performance - Speed 0 0
500 2017 Pacesetter (Cost) 500 2017 Pacesetter (Speed) 2016 Pacesetter (Cost) 2016 Pacesetter (Speed) 1,000 2015 Pacesetter (Cost) 1,000 2015 Pacesetter (Speed) 2007-2014 Pacesetter (Cost) 2007-2014 Pacesetter (Speed) 1,500 1,500 Tier 0
2,000 2,000
2,500 2,500
3,000 3,000
3,500 3,500
4,000 4,000 Total Measured Depth (m MD) (m Depth Measured Total Total Measured Depth (m MD) (m Depth Measured Total 4,500 4,500
5,000 5,000 0 200 400 600 800 1000 1200 1400 1600 1800 2000 2200 2400 0 3 6 9 12 15 18 21 24 27 30 Drilling Cost ($0,000's) Drilling Time (Days)
44 POUCE COUPE LOWER MONTNEY (D1) CORE AREA COMPLETION EVOLUTION Completion Cost per Stage vs. Number of Stages Proppant Intensity $400 40 1.00 200
0.90 180 $350 35 0.80 160 $300 30 0.70 140 $250 25 0.60 120
$200 20 0.50 100
$150 15 0.40 80 0.30 60 $100 10 0.20 40 Average Number of Stages (#) ofStages Number Average (m) Spacing InterfracAverage Completion Cost Per Stage ($000's) StagePer Cost Completion $50 5 (t/m) IntensityProppant Average 0.10 20
$0 0 0.00 0 2012 2013 2014 2015 2016 2017 2012 2013 2014 2015 2016 2017
Completion Parameter 2012 2013 2014 2015 2016 2017
Surfactant (10) SLW/ X-linked (4) Completion Fluid (# of Wells) SLW / X-linked (14) SLW (13) SLW (5) SLW (7) SLW/ X-linked (7) SLW (1)
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
45 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 $7.0 million
(1) Estimated by McDaniel. Down compared to 2016 based on actual costs incurred in 2017 and go forward DCCET costs. (2) Estimated by Deloitte. Up slightly compared to 2016 due to increased frac intensity in completions.
46 TERMINAL DECLINE CHANGES
• Continued support for low terminal decline rates from Birchcliff’s existing wells and offsetting industry wells with significant production history. • Deloitte’s Tier 0 type curve has remained at 8.2 Bcfe sales with the same terminal decline rates of 11% Proved and 9% Proved plus Probable. • Deloitte’s Tier 0 type curve estimates that the well enters its terminal decline after 4 years TP and 4.9 years 2P
2008 2009 - 2010 2011 2012 - 2015 2016 - 2017 Terminal Decline Hyperbolic Exponential Exponential Exponential Exponential TP 30% 20% 17% 13% 11% 2P 20% 13.35% 13% 10% 9%
47 PC GAS PLANT The Engine for Future Growth Production Processed 9 Mo. through the PC Gas 2013 2014 2015 2016 2017(4) 2018(4) Plant Average daily production, net to Birchcliff:
Natural gas (Mcf) 91,666 132,808 163,641 168,444 193,417 261,313
Oil & condensate (bbls) 527 1,065 1,287 960 1,316 2,910
Total boe (6:1) 15,805 23,200 28,560 29,034 33,552 46,462
% of corporate natural gas production 73% 78% 81% 68% 60% 70%
% of corporate production 61% 69% 73% 59% 49% 60%
Average AECO price for period ($/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%
(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.
• 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
49 Corporate Operating Costs vs. % of Natural Gas Sales Volumes Processed at the PC Gas Plant KEY STRATEGIC $10.00 100% Volume Through PC Gas PlantGas PC Through Volume ADVANTAGES $8.00 80% $6.00 60% • 100% owned and operated $4.00 40% • Generates operating cost savings of approximately $1.00/Mcf vs. third $2.00 20% Corporate Operating Cost($/boe) party processing of an equivalent gas $0.00 0% plant 2009 2010 2011 2012 2013 2014 2015 2016 2017 Corporate operating costs, net of recoveries ($/boe) • Provides flexibility to adjust % of total natural gas sales volumes processed at PC Gas Plant development pace at minimal cost Average AECO Price vs. PC Gas Plant Operating Netback 40,000 $5.00
and maximize profitability ($/Mcfe Netback Op. AECO/PC 35,000 $4.00 • Control of the gas plant, infrastructure 30,000
and two acid gas disposal wells 25,000 $3.00 provide predictable run times and the 20,000 ability to consistently meet production 15,000 $2.00 10,000 and budget targets $1.00
PC Plant Production PC Plant Production (boe/d) 5,000
0 $0.00 2011 2012 2013 2014 2015 2016 2017 Production processed through the PC Gas Plant (boe/d) Average AECO Price ($/Mcf) PC operating netback ($/Mcfe)
50 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 30% • 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 70% currently have no plans to proceed with any further expansion phases of the Pouce Coupe Gas Plant.
2018YTD Natural Gas Volumes Processed at PC Gas Plant
Other 2018YTD Natural Gas Volumes
51 BUILDING ON OUR PAST Over 10 Years of Success Forecasted record annual average production of Birchcliff’s average daily production was 67,963 boe/d in 76,000-78,000 boe/d in 2017 compared to 2,793 boe/d in 2005, a compounded 2018 annual growth rate of 30% per year over that span.
2,793 boe/d
1 2 3 4 5 6 7 8 9 10 11
2004 2018 July 6, 2004: Birchcliff incorporated as a private corporation. October 2, 2012: Phase III of the PC Gas Plant commenced 1 6 operations with a combined processing capacity of 150 MMcf/d. 2005: i) Completed $60 million equity financing & common shares commenced trading on the TSX Venture. ii) Rig released first 7 September 1, 2014: Phase IV of the PC Gas Plant commenced operations with a combined processing capacity of 180 MMcf/d. 2 Montney/Doig vertical exploration gas well drilled by Birchcliff in the Pouce Coupe Area. iii) Completed acquisition of properties in the July 28, 2016: Completed acquisition of properties in the Peace River Arch for $242.8 million. iv) Common shares Gordondale area of Alberta for approximately $613.5 million. The commenced trading on the TSX. assets included high working interest operated production and a 8 2007: i) Rig released first Montney/Doig horizontal natural gas well large contiguous land base adjacent to Birchcliff’s existing drilled by Birchcliff in the Pouce Coupe Area. ii) Completed operations on the Montney/Doig Resource Play. Closed equity 3 acquisition of the Worsley Charlie Lake light oil Property. financings for total gross proceeds of $690.8 million.
2008: Rig released first Charlie Lake horizontal light oil well in the 9 August 31, 2017: Completed disposition of the Worsley Charlie Worsley area. Lake Oil Pool. 4 October 2, 2017: Announced the early commencement of Phase V 2010: i) Phase I of the PC Gas Plant commenced operations with a 10 processing capacity of 30 MMcf/d. ii) Phase II of the PC Gas Plant of the PC Gas Plant with combined processing capacity of 260 5 commenced operations with a combined processing capacity of 60 MMcf/d. MMcf/d. 11 August 14, 2018: Announced the early commencement of Phase VI of the PC Gas Plant with combined processing capacity of 340 MMcf/d.
53 Production Growth
80,000 300
70,000 boe/d/million wtd. avg. shares 250 60,000 Birchcliff has increased production at a 200 50,000 compound annual growth rate of 40,000 150 boe/d 30% since 2005. 30,000 100 20,000 50 10,000
0 0 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017
Average Production (boe/d) Production per Common Share (boe/d/million wtd. avg. shares) Operating & Cash Costs* $20 $18 $16 $14 Operating and cash costs have $12 decreased by 57% and 46% since $10
$/boe largely due to horizontal drilling success $8 2008 $6 and benefits achieved from processing gas at the $4 PC Gas Plant which began operations in early $2 2010. $- 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 Cash Cost* ($/boe) Operating Costs ($/boe) * includes operating, transportation and marketing, general and administrative and interest
54 Reserves Growth 1200 4,000
1000 3,200 Birchcliff has added significant low cost
800 boe/1,000shares reserves since commencing operations in 2,400
600 2005. On a per common share MMboe 1,600 400 basis, PDP, 1P and 2P reserves
800 grew 14% per year, 22% per 200 year and 21% per year, 0 0 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 respectively. PDP (MMboe) 1P (MMboe) 2P (MMboe) PDP (boe/1000 shares) 1P (boe/1000 shares) 2P (boe/1000 shares)
Over 13 years of operations, Birchcliff has… Realized $161 million in net income Invested $3.8 billion in capital to common shareholders Generated $3.4 billion in revenue Grown 2P NAV to $5.1 billion Drilled 348 Montney/Doig horizontal Delivered $1.6 billion in cash flow natural gas wells
55 APPENDIX ENOUGH RESOURCE TO FILL A 2.1 Bcf/d LNG TRAIN FOR OVER 20 YEARS!
1 Bcf/d LNG 365 Days 20 Years 7.3 Tcf Train X X =
BIR Remaining Reserves as BIR Contingent Resource as at Dec 31, 2017 (gas only) at Dec 31, 2017 (gas only)
4.9 Tcf +10.3 Tcf / 20 Years = 2.1 Bcf/d
Birchcliff 2017 Montney/Doig Resource Assessment 25,000 Low Estimate Case 20,629 19,561 20,000 Best Estimate Case High Estimate Case 15,000 13,484 12,358 (Bcfe) 10,000 8,409 8,857 7,195 5,812 5,000 3,971 ReservesResource& Volumes 0 Remaining Reserves Contingent Resources Prospective Resources
57 2017 YEAR END MONTNEY/DOIG
Drilled 53 HZ RESERVES M/D wells 1,000,000 Drilled 20 HZ M/D wells and acquired 87 HZ M/D wells 900,000 348 (342.8 net) Montney/Doig horizontal Drilled 29 HZ M/D wells 800,000 wells drilled as of Dec 31, 2017 Drilled 41 HZ M/D wells 700,000 Drilled 25 HZ M/D wells 600,000 Drilled 22 HZ M/D wells 500,000 Drilled 23 HZ PDP M/D wells 400,000 TP Drilled 23 HZ Reserves (Mboe) Reserves M/D wells 2P
300,000 Drilled 8 HZ M/D wells
200,000 Drilled 15 HZ M/D wells
100,000 Drilled 2 HZ M/D wells 0 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 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
(1) See appendix at the end of this presentation for disclosures on oil & gas reserves and related metrics
58 MONTNEY/DOIG WELL LOCATIONS
59 SERIES A PERPETUAL PREFERRED SHARES Preferred Share Details Series A Number of Shares 2 million Issue Date August 8, 2012 TSX Trading Symbol BIR.PR.A Issue / Par Price $25.00 per share Quarterly Dividend $0.523375 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
60 SERIES C PREFERRED SHARES
Preferred Share Details Series C Number of Shares 2 million Issue Date June 14, 2013 TSX Trading Symbol BIR.PR.C Issue / Par Price $25.00 per share Quarterly Dividend $0.4375 per share Yield at Issue 7.0% June 30, 2020 and each Redeemable by Holder quarter thereafter 2016 2017 2018 2019 2020 1 2 3
1 June 30, 2018: Series C redeemable by Birchcliff (and not by 3 June 30, 2020: Series C redeemable by Birchcliff at $25.00 per holder) at $25.75 per share (plus accrued and unpaid dividends) if share (plus accrued and unpaid dividends) form this date forward redeemed before June 30, 2019; Birchcliff has the option to convert subject to proper notice Birchcliff has the option to convert into into common shares (see note) common shares (see note) June 30, 2020: Series C redeemable by holder, on this date and the 2 June 30, 2019: Series C redeemable by Birchcliff (and not by last day of each quarter hereafter, at $25.00 per share (plus accrued holder) at $25.50 per share (plus accrued and unpaid dividends) if and unpaid dividends); upon receipt of notice for redemption, redeemed before June 30, 2020; Birchcliff has the option to convert Birchcliff may elect to convert into common shares (see note) into common shares (see note) Note: The number of common shares is determined by dividing the applicable redemption price, together with accrued and unpaid dividends, by the greater of $2.00 and 95% of the 20-day weighted average trading price ending on the fourth day prior to the date specified for conversion
61 EXECUTIVE OFFICERS
Mr. Tonken is the President, Chief Executive Officer and Chairman of the Board of Birchcliff. He has more than 36 years of A. Jeffery 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 Tonken Stampeder Exploration Ltd. Mr. Tonken was previously a Partner of the law firm Howard, Mackie (now Borden Ladner President, CEO and Gervais LLP). Mr. Tonken is a Governor of the Canadian Association of Petroleum Producers (CAPP). Mr. Tonken received Chairman of the Board his Bachelor of Commerce degree from the University of Alberta and his Bachelor of Laws degree from the University of Wales.
Myles R. Mr. Bosman is the Vice-President, Exploration and Chief Operating Officer of Birchcliff and is a Professional Geologist. He has more than 26 years of experience in the oil and natural gas industry and is one of the Corporation’s founders. Prior to Bosman joining Birchcliff, Mr. Bosman served as Vice-President, Exploration and Chief Operating Officer of Case Resources Inc., Vice-President, Exploration Manager of Summit Resources Ltd. and as an Exploration Geologist with both Numac Energy Inc. and Canadian Exploration and Chief Hunter Exploration. Mr. Bosman received his Bachelor of Science degree in Geology from the University of Calgary and his Operating Officer Resource Engineering diploma from the Northern Alberta Institute of Technology. Mr. Bosman is a member of APEGA.
Mr. Geremia is the Vice-President and Chief Financial Officer of Birchcliff and is a Chartered Accountant. He has more than Bruno P. 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 Geremia Ltd., as Director, Commercial of Gulf Canada Resources and as Manager, Special Projects of Stampeder Exploration Ltd. Vice-President and Chief Mr. Geremia was previously a Chartered Accountant with Deloitte & Touche LLP. Mr. Geremia received his Bachelor of Financial Officer Commerce degree from the University of Calgary.
62 EXECUTIVE OFFICERS
Mr. Carlsen is the Vice-President, Engineering of Birchcliff and is a Professional Engineer. He previously served as Asset Christopher A. Team Lead and Senior Exploitation Engineer with Birchcliff. Mr. Carlsen is a Professional Engineer with more than 16 years of experience in the oil and natural gas industry. Prior to joining Birchcliff in 2008, he was the Senior Engineer at Greenfield Carlsen Resources Ltd. and held various engineering positions at both EnCana Corporation and PanCanadian Petroleum Ltd. Mr. Vice-President, Carlsen received his Bachelor of Science degree in Chemical Engineering from the University of Saskatchewan. Mr. Carlsen Engineering is a member of APEGA.
David M. 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 Humphreys Fire Energy Ltd. and Virtus Energy Ltd.; Production Manager of both Husky Oil Operations Ltd. and Ionic Energy; and as a Vice-President, Senior Production Engineer with Northrock Resources Ltd. Mr. Humphreys received his Hydrocarbon Engineering Operations Technology diploma from the Northern Alberta Institute of Technology. Mr. Humphreys is a member of APEGA.
63 BOARD OF DIRECTORS
A. Jeffery Tonken See Mr. Tonken’s biography under “Executive Officers”. President, CEO and Chairman of the Board
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. James W. 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 Surbey Ltd. Mr. Surbey was previously a Senior Partner of the law firm Howard, Mackie (now Borden Ladner Gervais LLP). Mr. Director 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. 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 Dennis 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 Dawson has over 31 years of oil and natural gas experience including nine years as General Counsel for Pan-Alberta Gas Independent Director 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.
64 BOARD OF DIRECTORS
Ms. Morley has 15 years of experience in the capital markets, having worked as an Equity Research Associate at TD Securities and GMP Securities and then as a Partner and Research Analyst at Paradigm Capital. Ms. Morley then moved to Rebecca Cypress Capital where she worked as a Research Analyst and Associate Portfolio Manager and was most recently Vice President of Corporate Development at Rayne Capital. Ms. Morley is currently the Chair of the Board of Directors of the Morley YWCA of Calgary, was the Chair of the Audit Committee in 2014 and 2015 and has been a director since 2012. Ms. Morley Independent Director has a Bachelor of Business Administration with a Major in Finance (Honours) from St. Francis Xavier University and is a CFA Charterholder.
Debbie 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 Gerlach time, she worked with many public oil and gas companies over her 35 year career with the firm. Ms. Gerlach holds a Independent Director Bachelor of Commerce and a Master of Business Administration, both from the University of Calgary.
65 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 on SEDAR at www.sedar.com. With respect to the disclosure of reserves contained herein relating to portions of Birchcliff’s properties, the estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation. Estimates of future net revenue, whether calculated without discount or using a discount rate, do not represent fair market value. 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. o “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. o “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.
66 Uncertainty Ranges for Resources Estimates of resource volumes can be categorized according to the range of uncertainty associated with the estimates. Uncertainty ranges are described in the COGE Handbook as low, best and high estimates as follows: • A “low estimate” (1C) is considered to be a conservative estimate of the quantity that will actually be recovered. It is likely that the actual remaining quantities recovered will exceed the low estimate. If probabilistic methods are used, there should be at least a 90% probability (P90) that the quantities actually recovered will equal or exceed the low estimate. • A “best estimate” (2C) is considered to be the best estimate of the quantity that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. If probabilistic methods are used, there should be at least a 50% probability (P50) that the quantities actually recovered will equal or exceed the best estimate. • A “high estimate” (3C) is considered to be an optimistic estimate of the quantity that will actually be recovered. It is unlikely that the actual remaining quantities recovered will exceed the high estimate. If probabilistic methods are used, there should be at least a 10% probability (P10) that the quantities actually recovered will equal or exceed the high estimate. Project Maturity Subclasses for Resources The project maturity 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.
67 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 or 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 operating results on a per unit basis to better analyze its performance against prior periods on a comparable basis. The following table provides a breakdown of operating netback and cash flow netback:
“Operating margin” for the PC Gas Plant is calculated by dividing the estimated operating netback for the period by the petroleum and natural gas revenue for the period. Management believes that operating margin assists management and investors in assessing the profitability and efficiency of the PC Gas Plant and Birchcliff’s ability to generate operating cash flows (equal to petroleum and natural gas revenue less royalties, less operating expenses and less transportation and marketing expenses). “Total cash costs” are comprised of royalty, operating, transportation and marketing, general and administrative and interest expenses. Total cash costs are calculated on a per boe basis. Management believes that total cash costs assists management and investors in assessing Birchcliff’s efficiency and overall cash cost structure. “Profit” measures the amount, if any, during the relevant period by which revenues resulting from production exceed the sum of: (i) PDP FD&A (i.e. the costs of replacing production), (ii) royalty, operating and transportation and marketing expenses and, in the case of Birchcliff at the business-entity level, (iii) general and administrative expense, and (iv) interest expense. This measure is not intended to represent net income or net income to common shareholders as presented in accordance with IFRS. “Profit margin” is calculated by dividing profit for the period by petroleum and natural gas revenue for the period. Birchcliff believes that profit and profit margin are useful measures as they assist management and investors in assessing Birchcliff’s ability during a period of declining commodity prices to bear all of its total cash costs and the costs of replacing its production during the relevant period. Birchcliff does not believe that this measure can be properly reconciled to any GAAP measure. “Total debt” is calculated as the revolving term credit facilities plus adjusted working capital deficit. Management believes that total debt assists management and investors in assessing Birchcliff’s liquidity. The following table provides a reconciliation of the revolving term credit facilities, as determined in accordance with IFRS, to total debt:
68 THANK YOU TEAM BIRCHCLIFF
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