Investor Update March 26, 2020 Why we do what we do…
Our Mission is to establish PONY as a low-cost supplier of clean natural gas to Canada and the world.
Percentage of Global Energy Needs
Oil Gas
Coal Renewables
Hydro Nuclear
We believe: • world demand for clean and reliable energy is rapidly growing • technological advancements makes our energy cost competitive on a world scale • in developing our world-class resource using the highest standards, environmentally and socially • the world trusts doing business with Canada
Source: BP Global Energy Outlook, 2019 *Renewables includes wind, solar, geothermal, biomass, and biofuels 2 Clean-Burning Natural Gas PONY supplements diesel Lowest GHG Emissions fuel with natural gas fuel for completion operations which reduces per well capital costs and lowers PONY’s GHG emissions Converting coal-fired electricity 250 generation plants to natural gas 229 (including LNG) reduces GHGs Compared to clean by 48%...a REAL solution to burning natural gas, lowering emissions CO2 emissions from 200 coal are 96% higher while diesel emissions 161 157 are 37% higher 150 139
Emissions MMBtu / Emissions 117 2
100 Pounds of CO of Pounds 50
0 Coal Diesel Gasoline Propane Natural Gas
Source: US Energy Information Administration (EIA) June 4, 2019 3 Global LNG Market Demand Growth Mtpa (Million Tonnes per Annum) is a typical measurement unit in Global LNG LNG markets .for production demand forecast 500 to increase Approximate conversion: 1 mtpa = 0.132 Bcf/d 34% (1) 57 1 Bcf/d = 7.576 mtpa 2020 – 2025 Bcf/d Global LNG 55 demand increased 52 433 400 Mtpa 49 413 78% 47 393 2009 - 2019 45 374
(1) 43 357 41 340 300 38 323 308 34 287 32 32 32 31 32 257 29 245 240 241 236 240 200 24 221 Bcf/d 181
Global LNG DemandLNG Global Mtpa
100
0 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
1 - Source: BP statistical review, Kepler Cheuvreux estimates (Equity Research Q&A Report, April 23, 2019) Global LNG demand could reach 433 Mtpa (57 Bcf/d) in 2025
4 Proposed West Coast LNG & LPG Projects Game Changers
LNG Projects Capacity LNG Canada Shell, Petronas, Mitsubishi, Petro- China, KOGAS 1.9 – 3.8 Bcf/d • Phase 1 - under construction
T-North Enbridge Mainline Woodfibre LNG Pacific Oil & Gas 0.3 – 1.0 Bcf/d (FID expected in 2020)
Tilbury LNG FortisBC • Phase 1 - under construction 0.13 – 0.5 Bcf/d Coastal GasLink • Phase 2 - construction 2022
T-South Enbridge Mainline LNG Canada (Shell) 36” and 30” Export Facility (Under Construction) TOTAL 2.3 – 5.3 Bcf/d
Woodfibre LNG (Pacific Oil & Gas)
5.3 Bcf/d represents over 30% Tilbury LNG (FortisBC) of current Canadian natural gas Natural Gas Pipeline production removed from Coastal GasLink Pipeline domestic supply 5 LNG Canada Construction Underway Kitimat, BC Site August 2018
“In 2019, the global LNG market continued to evolve according to the latest Shell LNG Outlook, with demand increasing for LNG and natural gas in power and non-power sectors. Record supply investments have been made to meet people’s growing need for the most flexible and cleanest- burning fossil fuel. In China, LNG imports increased by 14% in 2019, as that country continues to value improved urban air quality.”
Peter Zebedee, CEO, LNG Canada February 24, 2020
November 2019
LNG Canada’s export facility at Kitimat has been under construction since October 2018
6 NEBC Montney Massive Resource Over the next 20 years, natural gas production from the Montney in BC will continue to grow and by 2040 is estimated to make up approximately 38% of Canada’s total natural gas production 25
20 Duvernay
AB Deep Basin Horn River Shale
15 Bcf/d BC Montney 10
Western Canadian Conventional AB Montney 5
Western Canadian CBM Western Canadian Solution Gas 0 2005 2010 2015 2020 2025 2030 2035 2040
Source: National Energy Board, Canada’s Energy Future, Energy Supply and Demand Projections to 2040, November 2018
7 Alberta Natural Gas Market Continued Demand Growth
Alberta is expected to increase natural gas 8.0 8.0
consumption by over 45% • Significant demand growth taking place in Alberta (Bcf/d) between 2018 and 2023 Electricity 6.0 6.0 Generation • Steady phase-out of coal in electrical generation (including Coal-to-Gas Conversions) • Increased demand for natural gas in the oilsands 4.0 4.0 Oilsands • Power demand continues to rise
2.0 2.0 • This does not include the impact of west coast LNG exports Industrial / Petrochemical / Other
0.0 Demand Gas Natural 0.0 2013 2014 20152012015 2016 2017 2018 2019 2020 2021 2022 2023 5
Electricity Generation Sources in Alberta
2015 75% increase 2030 51% in natural gas demand Coal 70% 40% Natural Gas Natural Gas 30% 9% Renewables Renewables
Source: CAPP, AER 8 Corporate Profile TSX: PONY
2019 Average Daily Production 294 MMcfe/d (48,979 boe/d)
Estimated Q1 2020 Average Daily Production 315 MMcfe/d (52,500 boe/d)
2019 2P Reserve Life Index* 64 Years
1H 2020 Capital Budget $25-30 million
Enterprise Value $370 million
Common Shares Outstanding 161 million
60-day Average Daily Trading Volume 600,000 shares per day
PONY Ownership • Employees (65 full-time; via company savings plan) 3.0 million • Officers (company savings plan and personal holdings) 2.7 million shares • 2019 Shares Purchases (company savings plan; Feb ‘19 – Feb ‘20) 1.8 million shares
Note: As at March 26, 2020 * RLI (Reserve Life Index) is calculated using 2019 year-end 2P reserves divided by 2019 average daily production volumes 9 World Class Resource Natural Gas Pipeline Coastal GasLink Pipeline Montney Pure Play
Asset • The Montney is the most economic natural gas and natural gas liquids play in Canada • 290 net sections (185,704 net acres) of Montney lands • 6,800 Bcfe (1,133 MMboe) Total Proved plus Probable reserves(1) • 880 Bcfe (146 MMboe) of Proved Developed Producing reserves Strategic Advantages • Firm transportation in-place allowing access to a diversity of markets, reducing commodity pricing risk • De-risked reserves with deep inventory of future drilling locations
1) As at December 31, 2019; see Advisories Section 10 2020 Capital Program Disciplined Capital Investment
• Investing $25 - $30 million for the first half of 2020
• PONY will review capital budget at mid-year to determine appropriate second half 2020 spending levels
• Program includes:
• Drilling 10 gross (4 net) wells
• Completing 2 gross (2 net) wells
11 Montney Pure Play Location, Location, Location
North River Jedney Plant PONY’s Montney Sweet Spot is: Jedney Facility Jedney • 4x thicker than the Marcellus at greater than 300 Dry Liquids meters (approximately 1,000 ft.) thick Beg • a continuous sweet natural gas-saturated zone with no associated or underlying water
North River • highly over pressured on PONY lands with up to Blair Highway Plant West Blair Facility AltaGas Blair 1.8x over-pressured reservoir West Plant Blair • liquids cut of approximately 9% of production Cypress Daiber North Facility Kanata Daiber Plant volumes during Q4 2019 with access in 2020 to Daiber West Facility Daiber South Daiber deep cut at the Townsend Facility expected to Facility increase liquid cut to >10% AltaGas Townsend Kobes Plant North Kobes • High liquids production of approximately 20% at Facility Townsend Townsend with potential at Beg and Jedney PaintedLEGEND Pony Lands Natural Gas Processing Plant • Liquids-rich production potential over a total of Dry Gas CompressionPainted Pony Facility Lands South Painted Pony / AltaGas Facilities Enbridge TThird-North-Party Pipeline Facilities Townsend approximately 100,000 acres or approximately TC EnergyEnbridge North Montney T-North Mainline Pipeline Pipeline Secondary Pipelines 55% of acreage Secondary Pipelines
12 The Sweet Spot BRITISH ALBERTA North Montney 6-Month Cumulative Production Volumes COLUMBIA
North Montney
2,250,000 PONY has the best well in North Montney with 6-month average daily 2,000,000 production rate of more 60 of top than 11 MMcf/d 100 wells 1,750,000 are PONY wells!
1,500,000
1,250,000
1,000,000
750,000 Cumulative Natural Gas Gas (Mcf) Natural Cumulative
500,000
250,000
- Source: GeoScout; As at March 16, 2020 Painted Pony Top 100 Wells - Northern Montney Field (sample set of 1,448 wells) Other Producers 13 2019 Reserves 2019 Operating Netback 2019 PDP Significant Resource, Significant Value $1.66/Mcfe Recycle Ratio 2019 Future Development = 2019 PDP Finding, Development 1.3x Capital was reduced by more & Acquisition Cost than 2019 capital spending, a significant achievement for $1.26/Mcfe 5.0x PONY but which makes the 1P and 2P recycle ratios incalculable 4.3x 4.0x 3.3x 3.0x
2.0x 1.5x 1.3x 1.0x
0.0x Proved Developed Producing Total Proved Proved plus Probable
2019 3-Year Weighted Average
Probable Proved Developed Producing 3.8 0.9 (PDP) Tcfe Tcfe Total Proved(1P) Maintained 1P reserves year-over- 3.0 Tcfe year with a 2019 net capital (44% of 2P) program of $42 million while 6.8 Tcfe Total 2P Reserves 2.1 reducing FDC costs by $171 million Proven Undeveloped Tcfe (PUD)
14 Significant Unrealized UpsideSignificantUnrealized Across 7 Layers of Montney Resource Development Horizons
~ 330 m
Lower Montney Middle Montney Upper Montney 1 Townsend 2 opportunities across PONY’s net 290sections Doig Deep Deep inventory of untapped Montney 3 Belloy formation formation 4 Blair 5 Productive Montney Layers Montney Productive De Prospective Montney Layers Montney Prospective - Risked Montney Layers Montney Risked Beg 6 4 5 3 6
2 ~ 290 m 1 15 Canbriam Transaction Closed June 2019 • Canbriam Energy sold to Pacific Oil & Gas for $1 billion • Offsetting acreage analog for PONY • Validates land sale prices in NEBC
Montney Landholdings Painted Pony Energy (185,704 net acres) • Canbriam Energy (171,436 net acres)
Major Gas Pipelines In 2019 PONY sold Alaska Highway 8,460 net acres for $45 million or $5,319/acre, further Valuation Metrics validating value of (based on $1 billion Canbriam valuation) acreage Canbriam $5,833/acre PONY $5,833/acre x 185,704 acres = $1.1 billion $1.1 billion - $320 million net debt = $780 million $780 million / 161 million shares = $4.84/sh
Canbriam $4.34/boe of 1P reserves PONY $4.34 x 496 MMboe (1P) = $2.15 billion $2.15 billion - $320 million net debt = $1.83 billion $1.83 billion / 161 million shares = $11.38/sh 16 Land Valuation Land sales not aligned with valuation
• In 2019 PONY sold 8,460 net acres for $45 million or $5,319/acre, further validating value of acreage • The weighted-average price per acre of Bernadet (Conoco) land transactions in recent years for $4,454/acre (34,580 acres) $154 million / April 2018 Montney parcels is $4,703/acre • 2019 corporate sale of Canbriam Energy to Pacific Oil & Gas (a west West Inga $3,984/acre (1,305 acres) coast LNG exporter) further verifies $5.2 million / Sept 2017
NEBC Montney value with 171,436 Bernadet $9,095/acre (4,618 acres) acres selling for $5,833/acre $42 million / June 2018
Montney Landholdings Painted Pony Energy Inga $3,117/acre (1,305 acres) • PONY’s 185,704 net Montney acres Petronas $4,067 million / July 2017 ConocoPhillips Townsend carry an implied value, using recent Tourmaline Oil $5,319/acre (8,460 acres) Canbriam Energy $45 million / November 2019 weighted-average per acre values, of Saguaro Resources Altares CNRL $5,623/acre (13,695 acres) $77 million / July 2017 roughly $878 million Black Swan Energy Crew Energy Storm Resources Kelt Exploration Bernadet $3,928/acre (23,422 acres) ARC Resources $92 million / March 2017 Leucrotta Exploration Todd Energy NEBC Montney Major Gas Pipelines Alaska Highway 17 Market Diversification Natural Gas Physical Delivery
PONY Sales / Pricing Exposure
PONY Western Markets St. 2 & AECO 174 MMcf/d AECO C A N AMEDICINE D A HAT 10 MMcf/d to Methanex’s Station 2 methanol plant in Alberta increasing to 20 MMcf/d in Medicine 2021 and 50 MMcf/d in 2023 Sumas Hat DAWN Market SUMAS Market 88 MMcf/d 33 MMcf/d Dawn
U N I T E D S T A T E S
NYMEX Growing US Natural Gas Exports Mexico Exports to Mexico 5.2 Bcf/d Export LNG LNG 8.2 Bcf/d Export 2020 LNG additions 1.6 Bcf/d 1Total (end 2020) 15 Bcf/d
M E X I C O 18 PONY’s Net ofExposure Physical andFinancialContracts Sales Diversification
Natural Gas Volume Net Exposure by Hub (%) 100% 10% 20% 30% 40% 50% 60% 70% 80% 90% 0% 2020 annual production percentages assume flat annual production 20192020to productionannual flatassume percentagesproduction2020annual 2020full 201931,Decemberof as Percentages Note: AECO /ST 2 - year annual production guidance has not been disclosedbeen guidancehasnotyearproduction annual Q1 2020 PONY PONY regularly adds new contracts as part of ongoing risk 15% 36% 11% 29% 9% management through sales hub diversification Sumas Index Q2 2020 22% 34% 16% 10% 18% Dawn Index Q3 2020 24% 37% 18% 11% 11% NYMEX Index Q4 2020 10% 35% 17% 12% 26% Fixed Price 19 Transportation Firm Transportation & Toll Advantage to West Coast
Enbridge T-North (St 2 or TC Energy Sunset Creek) NMML $0.24/Mcf $0.59/Mcf to Sunset Creek
PONY has a net $0.35/Mcf transportation toll advantage delivering natural gas to Sunset Creek (start of the Coastal Gaslink pipeline)
20 Historical Costs Drilling & Completions Efficiency
As capital well costs fell, production type curves Continued type curve improvement with dramatically improved average Total 2P(1) well booking of 9.2 Bcfe/well Management Perf & Plug Systems Type Curve 21 wells increased 50% D&C cost $7.7 million $14,000,000
1st Generation Open $12,000,000 Hole Ball Drop System Current Generation Open Hole Ball Drop 33 wells System D&C cost $6.9 million 131 wells $10,000,000 Drill & Complete cost $4.3 million
$8,000,000
$6,000,000 $4.3 mm average
Drill Drill Cost Completion and ($) $4,000,000
$2,000,000
$0
2011 2012 2013 2014 2015 2016 2017 2018 2019
(1) Total 2P - Total Proved Plus Probable Well Cost (drill + complete) 2,700 meter long lateral wells
21 Blair Long Lateral Wells Encouraging Performance Using longer laterals, PONY has the opportunity to improve
14 capital efficiency to approximately $6,000/boe/d
12 Longer lateral wells of 2,700 meters have Jedney
(MMcf/d) consistently outperformed 10 2,700 m longer management’s 1,800 meter lateral length wells (see advisories for well locations) lateral length production
type curve for the Blair / Beg 8 Daiber area
Blair 6 West Blair
Cypress 4 Calendar Day Natural Gas Rate Natural Gas Day Calendar Daiber
Townsend Kobes 2
South 2,700 m lateral wells Townsend (see advisories for well locations) 0 0 6 12 18 24 Months on Production 1,800 m standard lateral length management production type curve
22 Single Well Economics by Area Driving Increased Capital Efficiencies Through Longer Lateral Wells
Well Capital Costs Single Well Economics* IRR NPV10 Pay Out
1,800 meter lateral 1.6 Daiber 1,800 m lateral 64% $6.2 mm Drilling $2.2 million (dry) years
Completion $2.1 million 1.3 Daiber 2,700 m lateral 92% $10.4 mm Equip and Tie-in $0.6 million (dry) years
Total $4.9 million 2.0 Blair 1,800 m lateral 51% $5.4 mm 2,700 meter lateral (lean; 15 bbls/MMcf) years
Drilling $2.3 million 1.4 Blair 2,700 m lateral 80% $9.6 mm Completions $2.9 million (lean; 15 bbls/MMcf) years
Equip and Tie-in $0.6 million Single Well Economics based on flat pricing of: WTI US$45/bbl, AECO $2.25/Mcf, NYMEX US$2.40/MMBtu, FX $0.71 Total $5.8 million
PONY’s longer laterals at 2,700+ Longer lateral wells require meters deliver higher rates of return approximately 20% more capital than previous standard length but deliver, on average, a 45% laterals drilled to 1,800 meters. increase in booked reserves
23 ESG Environmental, Social, Governance Environmental
CO2 Emissions Reduction
0.01 0.009 0.008 0.0087 PONY is committed to
0.007 0.0076 e/boe
reducing GHG emissions 2 0.006 0.0064 through deliberate actions 0.005 which produce 0.004 0.0041
measurable improvements CO tonnes 0.003 0.0033 year after year 0.002 0.001 0 2014 2015 2016 2017 2018
• PONY is an industry leader in the use of the ‘EPOD Solar Hybrid Power Generation and Instrument Air Systems’ on well sites, which eliminates vented emissions from that location • All new PONY wellsite infrastructure will have zero venting protocol • Power generation on smaller sites and minor expansion projects use ‘EYOY Methanol Fuel Cell/Solar Hybrid Systems’ to electrify choke valves, chemical pumps and fluid dump valves which minimizes vented volumes and total GHG emissions
24 ESG Environmental, Social, Governance Environmental & Social
Water Optimization
• PONY anticipates using 100% produced / recycled water for all completion operations in 2020, a significant milestone in PONY’s water conservation
• Participate in a ‘Water Co-operative’ with other producers in operating areas to share completion water further reducing fresh water use and water disposal
Social Responsibility
With Indigenous Communities, PONY strives to: • Grow relationships with local Indigenous neighbours to instill trust and earn support for current and future operational activities • Strengthen employee effectiveness to create a culture of awareness and promote cohesiveness when working with our Indigenous neighbours • Increase local Indigenous opportunities for employment and contracts that deliver mutual benefits and promote sustainability
PONY supports a number of social initiatives and community charities: • Hopethiopia • YWCA Calgary • Halfway River First Nation Rodeo • Calgary Urban Project Society (CUPS) • Children’s Wish Foundation • Spirit of the Peace Pow Wow • Habitat for Humanity • The Salvation Army • Blueberry River First Nation Rodeo • KidSport Canada • Children’s Cottage Society • Halfway River First Nation Hockey Team • Adolescent Mental Health Foundation • Teen Challenge Alberta • Peace Aboriginal Youth Hockey Team
25 ESG Environmental, Social, Governance Governance
• Institutional Shareholder Services Inc. (ISS) is the world’s leading provider of corporate governance and responsible investment ratings. On a 1-10 scale where 1 is excellent and 10 is deficient, Painted Pony received a quality score of ‘1’ in 2019, the highest score attainable and the highest in our peer group of companies.
• Painted Pony has developed and implemented a complete portfolio of corporate policies including: • Code of Ethics • Corporate Disclosure • Health, Safety and Environment • Whistleblowing • Respectful Workplace • Compensation Clawback • Insider Trading • Director and Officer Share Ownership
• Painted Pony believes in diversity and this is reflected by the three women on the Board of Directors, with two chairing Board committees • Joan Dunne, Chair of Audit & Risk Committee • Lynn Kis, Chair of Reserves & HSE Committee • Betsy Spomer • PONY’s board is 38% women, more than double the average for all TSX-listed companies of 16.4%*
*Source: 2019 Diversity Disclosure Practices – published by Osler, Haskin & Harcourt 26 PONY Points Checking Off All of the Boxes
Well situated to supply Canadian west coast LNG projects
Diversified Market Access and Sales Points
Massive reserves base
Top well performance
Recent adjacent transaction shows significant upside value
Strong ESG Performance including Top Governance Score
27 Appendices & Advisories Financial Strength Term Debt and Credit Facility Provide Financial Flexibility
$375 Million Syndicated Credit Facility • Secured, Reserve Based Lending • Matures May 2021 Syndicated • $120 million drawn as at December 31, 2019 Credit Facility $120
Drawn (as at December 31, 2019) $255 Undrawn $145 Million Term Debt (Senior Unsecured Notes) (excluding Letters of Credit) • Held by Magnetar Capital • 8.5% Coupon • $150 million maturity in 2022 • Not callable until August 2020
Debt Capital $47 Diversification $48 Million Subordinated Convertible Debentures $120 • Held by Magnetar Capital Senior Notes • 6.5% Coupon Convertible Debentures • $5.60 Conversion Price Drawn on Credit Facility • $50 million maturity 2021 (subject to any conversion) $144 • ‘No Shorting’ Provision included
29 Equity Research Sell-Side Analyst Coverage
Institution Analyst AltaCorp Capital Patrick O’Rourke BMO Capital Markets Michael Murphy / Ray Kwan Canaccord Genuity Corp. Anthony Petrucci CIBC World Markets David Popowich Cormark Securities Inc. Garett Ursu Eight Capital Adam Gill Stifel FirstEnergy Cody Kwong iA Securities Michael Charlton National Bank Financial Dan Payne Raymond James Jeremy McCrea RBC Capital Markets Michael Harvey Scotiabank Global Banking & Markets Cameron Bean TD Securities Juan Jarrah
30 Corporate Overview
Auditor KPMG LLP
Evaluation Engineers GLJ Petroleum Consultants Ltd. Banks The Toronto-Dominion Bank Canadian Imperial Bank of Commerce The Bank of Nova Scotia Alberta Treasury Branches Royal Bank of Canada HSBC Bank Canada
Transfer Agent TSX Trust Company
Corporate Office Suite 1200, 520 – 3rd Avenue SW Calgary, Alberta T2P 0R3 Toll Free Investor 1 (866) 975-0440 Tel (403) 475-0440 Fax (403) 238-1487 Email: [email protected] www.paintedpony.ca
31 Advisory
This presentation contains a summary of management’s assessment of results and should be read in conjunction with the Financial Statements and related Management’s Discussion and Analysis for the year ended December 31, 2019, as filed on SEDAR. This presentation contains certain forward-looking statements, which include assumptions with respect to (i) drilling success; (ii) commodity prices; (iii) production; (iv) reserves; (v) future capital expenditures; (vi) future operating costs; (vii) availability of gas processing facilities; (viii) cash flow; (ix) potential markets for the Corporation’s production; (x) the availability of LNG export facilities; (xi) global LNG demand; and (xii) natural gas consumption. The reader is cautioned that assumptions used in the preparation of such information may prove to be incorrect.
Certain information regarding the Corporation set forth in this presentation, including statements regarding management’s assessment of the Corporation’s future plans and operations, the planning and development of certain prospects, production estimates, reserve estimates, productive capacity and economics of new wells, undeveloped land holdings and values, capital expenditures and the timing and allocation thereof (including the number, location and costs of planned wells), facility expansion plans, the total future capital required to bring undeveloped proved and probable reserves onto production, and expected production growth, may constitute forward-looking statements under applicable securities laws and necessarily involve substantial known and unknown risks and uncertainties. These forward-looking statements are subject to numerous risks and uncertainties, certain of which are beyond the Corporation’s control, including without limitation, risks associated with oil and gas exploration, development, exploitation, production, marketing and transportation, loss of markets, failure of foreign markets to become accessible, the impact of general economic conditions, industry conditions, volatility of commodity prices, currency fluctuations, environmental risks, competition, the lack of availability of qualified personnel or management, inability to obtain drilling rigs or other services, capital expenditure costs, including drilling, completion and facility costs, unexpected decline rates in wells, wells not performing as expected, stock market volatility, delays resulting from or inability to obtain required regulatory approvals and ability to access sufficient capital from internal and external sources, the impact of general economic conditions in Canada, the United States and overseas, industry conditions, changes in laws and regulations (including the adoption of new environmental laws and regulations) and changes in how they are interpreted and enforced, increased competition, fluctuations in foreign exchange or interest rates and market valuations of companies with respect to announced transactions and the final valuations thereof. There is ongoing litigation involving the Blueberry River First Nation ("BRFN") and the British Columbia government regarding the obligations of natural resource companies and the Crown relative to the adequacy of consultation and cumulative effects in respect of upstream oil and gas development in northeast British Columbia, where a substantial portion of the Corporation’s land and assets are situated. The Corporation is not a party to the litigation. While a successful claim by BRFN may be adversely material to the Corporation, at this point, the success of the claim and any corresponding impact is indeterminable. If the claim is decided in BRFN’s favour, it would have an adverse impact on the Corporation, its operations and production, particularly for those operations that may be considered to impact Aboriginal traditional lands or rights. The Corporation is therefore, actively monitoring the status of the BRFN claim. The Corporation’s actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward-looking statements and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking statements will transpire or occur, or if any of them do so, what benefits the Corporation will derive therefrom. All subsequent forward-looking statements, whether written or oral, attributable to the Corporation or persons acting on its behalf are expressly qualified in their entirety by these cautionary statements. Additional information on these and other factors that could affect the Corporation’s operations and financial results are included in reports on file with Canadian securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com) or the Corporation’s website (www.paintedpony.ca), including the Corporation’s MD&A for the year ended December 31, 2019.
The forward-looking statements contained in this presentation are made as of the date on the front page and the Corporation assumes no obligation to update publicly or to revise any of the included forward- looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable securities laws. Certain information contained herein is based on, or derived from, information provided by independent third-party sources. The Corporation believes that such information is accurate and that the sources from which it has been obtained are reliable. The Corporation cannot guarantee the accuracy of such information, however, and has not independently verified the assumptions on which such information is based. The Corporation does not assume any responsibility for the accuracy or completeness of such information.
This presentation also contains future-oriented financial information and financial outlook information (collectively, "FOFI") about prospective results of operations, future net revenue, share capital, cash flow, capital expenditures, net debt and components thereof, all of which are 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 was provided for the purpose of providing information about management's current expectations and plans relating to the future, including with respect to the Corporation’s ability to fund its expenditures. The Corporation disclaims any intention or obligation to update or revise any forward looking statements or FOFI contained in this presentation, whether as a result of new information, future events or otherwise, unless required pursuant to applicable securities law. Readers are cautioned that the forward looking statements and FOFI contained in this presentation should not be used for purposes other than for which it is disclosed herein. The forward looking statements and FOFI contained in this presentation are expressly qualified by this cautionary statement.
31 Advisory
Non-GAAP Measures: This presentation may make reference to the terms “adjusted funds flow from operations”, “adjusted funds flow from operations per share”, "corporate netback" and “net debt”, which do not have standardized meanings prescribed by IFRS and therefore may not be comparable with the calculation of similar measures presented by other issuers. Management of the Corporation believes these measures are useful supplemental measures of the net position of current assets and current liabilities of the Corporation and the profitability relative to commodity prices. Readers are cautioned, however, that these measures should not be construed as alternatives to other terms such as current and long-term debt or comprehensive income determined in accordance with IFRS as measures of performance. The Corporation's method of calculating these non-GAAP measures may differ from other companies, and accordingly, may not be comparable to similar measures used by other entities.
Management uses “adjusted funds flow from operations” to analyze operating performance and considers adjusted funds flow from operations to be a key measure as it demonstrates the Corporation’s ability to generate the cash necessary to fund future capital investment and to repay debt. Adjusted funds flow denotes cash flow from operating activities before the effects of changes in non-cash working capital and decommissioning expenditures. “Adjusted funds flow from operations per share” is calculated using the basic and diluted weighted average number of shares for the period. These terms should not be considered alternatives to, or more meaningful than, cash flows from operating activities as determined in accordance with IFRS as an indicator of the Corporation’s performance.
Management uses “net debt” as useful supplemental measures of the liquidity of the Corporation. Net debt is calculated as bank debt, senior notes, liability portion of convertible debentures, and working capital (deficiency), adjusted for the net current portion of fair value of risk management contracts and current portion of finance lease obligation. These terms should not be considered alternatives to, or more meaningful than, current and long-term debt as determined in accordance with IFRS.
"Corporate netback" is used as a supplemental measure of the Corporation's profitability relative to commodity prices. Corporate netback is calculated on a per unit basis as natural gas and natural gas liquids revenues, adjusted for realized gains or losses on risk management contracts, less royalties, operating expenses, transportation costs and finance lease expense. This term should not be considered alternatives to, or more meaningful than net income (loss) and comprehensive income (loss) as determined in accordance with IRFS. Included in this presentation are estimates of the Corporation’s 2020 adjusted funds flow which are based on various assumptions as to production levels, commodity prices and other assumptions, are provided for illustration only and are based on budgets and forecasts that have not been finalized and are subject to a variety of contingencies including prior years’ results. To the extent such estimates constitute a financial outlook, they were approved by management of the Corporation in December 2018 and are included to provide readers with an understanding of the Corporation’s anticipated adjusted funds flow based on the capital expenditures and other assumptions described. Readers are cautioned that the information may not be appropriate for other purposes.
NOTE REGARDING RESERVES DISCLOSURE The securities regulatory authorities in Canada have adopted National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”), which imposes oil and gas disclosure standards for Canadian public issuers engaged in oil and gas activities. NI 51-101 permits oil and gas issuers, in their filings with Canadian securities regulatory authorities, to disclose proved, probable and possible reserves, and to disclose reserves and production on a gross basis before deducting royalties. Probable and possible reserves are progressively less certain estimates than proved reserves. All reserves information in this presentation are presented on a gross basis. Gross reserves are the total working interest reserves before the deduction of any royalties and including any royalty interests receivable. Reserves estimates set forth herein with respect to the Corporation are based on the independent engineering evaluation of the Corporation’s oil, natural gas liquids and natural gas reserves (the “GLJ Report”) prepared by GLJ Petroleum Consultants Ltd. (“GLJ”) effective December 31, 2019 and dated March 11, 2020. Before tax net present values set forth herein are based on a 10 percent discount rate and GLJ’s January 1, 2020 forecast prices as applicable.
All estimates of future revenue in this presentation and in the documents incorporated herein by reference are, unless otherwise noted, after the deduction of royalties, development costs, production costs and well abandonment costs but before deduction of future income tax expenses and before consideration of indirect costs such as administrative, overhead and other miscellaneous expenses. The estimated future net revenues contained in this presentation and in the documents incorporated herein by reference do not represent the fair market value of the applicable reserves.
In this presentation: a) the discounted and undiscounted net present value of future net revenues attributable to reserves do not represent the fair market value of reserves; b) there is no assurance that the forecast prices and costs assumptions will be attained and variances could be material. The recovery and reserve estimates of natural gas and liquids reserves provided in this presentation are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual natural gas and liquids reserves may be greater than or less than the estimates provided in this presentation; c) 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; d) boe amounts may be misleading, particularly if used in isolation. Boe amounts have been calculated using the conversion ratio of six thousand cubic feet (6 Mcf) to one barrel of oil (1 bbl). A conversion ratio of 6 Mcf to 1 bbl 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; and e) Mcfe amounts may be misleading, particularly if used in isolation. Mcfe amounts have been calculated by using the conversion ratio of 1 bbl to 6 Mcf. A conversion ratio of 1 bbl to 6 Mcfs 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 1:6, utilizing a conversion on a 1:6 basis may be misleading as an indication of value.
32 Advisory
Reserves are the estimated remaining quantities of conventional natural gas, shale gas and natural gas liquids anticipated to be recoverable from known accumulations, from a given date forward, based on: (i) analysis of drilling, geological, geophysical and engineering data; (ii) the use of established technology; and (iii) specified economic conditions which are generally accepted as reasonable.
Reserves are classified according to the degree of certainty associated with the estimates. a) 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; b) 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; and c) 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.
Other criteria that must also be met for the categorization of reserves are provided in the Canadian Oil and Gas Evaluation (“COGE”) Handbook.
Each of the reserves categories (proved and probable) may be divided into developed and undeveloped categories. a) 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. (i) 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 certainly. (ii) 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. b) Undeveloped reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, 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 classification (proved, probable) 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.
Slide 23 Long Lateral Wells:
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 reserve estimates are prepared). Reported reserves should target the following levels of certainty under a specific set of economic conditions: (a) at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimated proved reserves; and (b) at least a 50 percent probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable 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 will be 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. Additional clarification of certainty levels associated with reserves estimates and the effect of aggregation is provided in the COGE Handbook.
For additional information regarding the presentation of the Corporation’s reserves and other oil and gas information, see the Corporation’s Form 51-101F1, which may be accessed through the SEDAR website (www.sedar.com) or the Corporation’s website (www.paintedpony.ca).
33