In Investor Update Ju June 2017 What is is Modern? Success in a - - PowerPoint PPT Presentation

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In Investor Update Ju June 2017 What is is Modern? Success in a - - PowerPoint PPT Presentation

In Investor Update Ju June 2017 What is is Modern? Success in a Low Modern GRANDE PRAIRIE Market Pipelines Price Environment (NGTL, Alliance) Pembina Peace Clean, safe, low liability HS&E Leadership Liquids Pipeline HWY 40


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SLIDE 1

In Investor Update

Ju June 2017

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SLIDE 2

What is is Modern?

Designed to Prosper in the ‘Modern’ Resource World

2 Success in a Low Price Environment Modern

HS&E Leadership

 Clean, safe, low liability

Resource Diversification  2 Top Plays - Spirit River gas, Cardium oil Scalable, Focused Asset  296,000 net acres 689 Locations Top Tier F&D1

~$0.54/mcfe Spirit River ~$9.94/boe Cardium Low Operating Cost

~$4.69/boe2 Corporate ~$2.00/boe3 Spirit River Control of Asset

 ~100% working interest

Strong Balance Sheet

 Material ELOC remaining

Owned Infrastructure

50 mmcf/d processing capacity expanding to 125 mmcf/d by Q4 2017 Access to Market

Firm NGTL calibrated to production

Wapiti

GRANDE PRAIRIE

HWY 40

Pembina Peace Liquids Pipeline Market Pipelines (NGTL, Alliance)

Greater Kakwa

(1) Half cycle development economics (2) Q1/17 Corporate Opcost (3) Dec 2016/Jan 2017 actuals for Kakwa UOA

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SLIDE 3

Who is is Modern rn?

Experienced and Invested Team

3 Board of Directors

Brian Boulanger - Chairman ARC Financial Corp. John Dielwart ARC Financial Corp. Hilary Foulkes Tudor, Pickering, Holt & Co. Keith MacPhail Bonavista Energy Corporation David Miller EnCap Investments L.P. Mark Welsh, IV EnCap Investments L.P.

Management

Chris Slubicki, MBA, P. Eng. President, CEO & Director (OPTI, Scotia

Waterous)

Mike Belenkie, P. Eng. VP Engineering (Painted Pony, Talisman) Jason Chadwick, B. Comm., PLM VP Land (Mancal, Rio Alto) Francois Legault, P. Geol. VP Geosciences (Vermilion, Talisman) Derek Mendham, CA, CFA CFO (Ensign, Genuity Capital, RBC Capital

Markets)

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SLIDE 4

4

Envir ironmental l Advantage – Ca Carbon In Intensit ity

2 4 6 8 Marcellus Tight Gas Barnett Shale Conventional Domestic Average Coal Bed Methane Associated Modern Offshore gCO2e/MJ

Gas Plays

Extraction and Processing Field Transport and Processing 50 100 150 200 250

Oil Plays

Oil Production and Upgrading Oil Transport, Refining, Refined Product Transport kgCO2e/barrel US Refined Average Iraq Kirkuk Modern Cardium Eagle Ford VO Saudi Ghawar US Gulf Thunderhorse US California Indonesia

Amongst the Lowest Carbon Intensity in the World = Carbon Security

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SLIDE 5

5

Modern rn La Landscape

Rapid Growth – Value Driven

Operations Update

Growth1

2016 production 7,892 boe/d 197% April production ~10,500 boe/d

(~15% liquids2)

78% Behind pipe prod. 4,000 boe/d n/a Q1/18F production ~20,800 boe/d 84% Wells drilled to date 33 37% Full time employees 25 8%

Spirit River Gas: 13 HZs and 1 strat test Cardium Oil: 19 HZs

7 Gen Jupiter Conoco (Cenovus) Tourmaline

Wapiti Red Rock Route

(1) Relative to respective prior year period (2) Substantial oil production shut in due to road conditions reduced liquids percentage in April

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SLIDE 6

6

Red Rock Sp Spir irit it Riv iver Gas Pla lay

Regional Deep Basin Resource with Outlier Results In Stacked Zones

Spirit River Fairway

13-18: Peak Month 8.4 mmcf/d 16-11: Peak Month 16.4 mmcf/d 01-02: Peak Month 14.1 mmcf/d

Over-pressured 1.75 Tcf net OGIP 230+ locations

09-30: Peak Month 6.4 mmcf/d MRI 10” Pipeline To MRI Gas Plant 16-17: Peak Month 10.7 mmcf/d 01-07: Peak Month 13.0 mmcf/d 01-11: Falher Pilot Peak Month 19.0 mmcf/d 08-32: Tested (16 days) Averaged 13.8 mmcf/d 102/01-08: First 30 days 11.0 mmcf/d 01-10: First 30 days 10.9 mmcf/d 16-32: Tested (5 days) Averaged 15.1 mmcf/d

1. Except for 16-11 and 09-30, all wells were restricted 2. All wells to date have targeted the Wilrich with exception of 01-11 Falher

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SLIDE 7

7

Route Sp Spir irit it Riv iver Gas Pla lay

Emerging Prolific Resource Adjacent to Modern Plant

Spirit River Fairway

02/04-06: Drilled and Cased Frac’ing in June ‘17

MRI 10” Pipe from Red Rock

Over-pressured 0.75 Tcf net OGIP 80+ locations Spirit River Fairway

Market gas and liquids lines MRI 50 mmcf/d Gas Plant Expanding to 115 mmcf/d 13-04: Peak Month 8.2 mmcf/d (restricted) MRI 10 mmcf/d Gas Plant Online June ‘17 MRI joint-owner 12” gas sales line 05-34: Wilrich/Dunvegan Recompletion producing 0.5 mmcf/d with 15 bbls/mmcf C5+

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SLIDE 8

8

Sp Spir irit it Riv iver r Well ll Perf rform rmance – Red Rock Co Core

Repeatable - Predictable - Prolific MRI 2016 Type Well

Well 1 Well 2 Well 5 Well 6 Well 7 Well 8 Well 9 Well 10 Well 11

(1) Excludes 13-04 well at Route and 09-30 well drilled in Type 2 rock.

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SLIDE 9

P99 P98 P95 P90 P80 P70 P60 P50 P40 P30 P20 P10 P5 P2 P1

100 1,000 10,000 100,000

Percentile >>>

Peak Month Gas Rate mmscf/d 9

Sp Spir irit it Riv iver r Well ll Dis istrib ibutio ion

Modern Wells Among the Best in the Basin

Facility Restricted Rates

Half Cycle Economics, May 31 2017 Strip Price(2) EUR mboe 1,839 Liquids Ratio C5+ bbls/mmcf 5(3) Well Costs $MM (gross) 6.0 NPV10% $MM (gross) 6.4 DPI 10% Discount Rate 1.1 Payout yrs 1.5 IRR % 63 Capital Cost (IP6) $/boe/d 4,699 F&D $/boe 3.32

(1) Source: geoScout and Modern data (2) Strip price as per Bloomberg (3) Liquids ratio range 3.5 to 18.0 bbls/mmcf

18 mmcf/d 16 mmcf/d

Modern First 8 Wells All AB Deep Basin Spirit River Wells (post Jan 1, 2015)

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Sp Spir irit it Riv iver r Se Sensit itiv ivit itie ies

Impact Of Liquids Yields and Well Costs is Meaningful

10

40 50 60 70 80 90 100 110 120 130 2 4 6 8 10 12 14 16 18 20 ROR % C5+ Yield (bbl/mmcf) C5+ bbl/mmcf Sensitivity 40 50 60 70 80 90 100 5.5 6.0 6.5 ROR % Capital - $MM Capital Sensitivity (5 bbls/mmcf C5+)

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SLIDE 11

Sp Spir irit it Riv iver r H2/17 Pla lan

Low-Risk Development Program Designed to Maximize Returns

11

* MRI proposed wells: Red = Gas Rig 1, Blue = Gas Rig 2, Brown = Oil Rig (Dunvegan target; moves to Cardium in Wapiti after)

  • Program is a blend of richer and leaner locations (3-18 bbls/mmcf)
  • Piloting of longer wells and larger fracs anticipated to yield stronger results
  • Most locations selected to leverage existing infrastructure (existing pads on main trunklines)
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SLIDE 12

Co Competit itiv ive Advantage- Owned In Infr frastructure

Strategic Control Established – Top-Tier Opcosts Accomplished

12 Project Cost Completed Cutbank Crossing $2.5 MM Oct 2015 RRR1 pipeline $11.5 MM Mar 2016 Route Phase 1 $48.0 MM April 2016 Route Phase 2 $25.0 MM Oct 2017 Copton sales line Land Swap March 2016 Lynx Plant Upgrade $1.1 MM July 2017

  • 227 km (gross) owned pipeline network
  • 50mmcf/d Route plant; Phase 2 expansion

to 115mmcf/d underway

  • 4 compressor stations
  • Lynx plant upgrade underway – 10mmcf/d

1 RRR = Red Rock to Route 10” pipeline

Copton Sales Line Cutbank Crossing RRR 10” Pipeline Modern Route Gas Plant Lynx Plant Future RR Trunk Lines 11-25 Wapiti Compressor NGTL Cutbank Lateral NGTL Narraway Lateral Pembina Liquids Line Cutpick Compressor/Dehy Red Rock Water Hub

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SLIDE 13

13

Ca Cardiu ium Update

Commanding Position in a Leading Light Oil Play

  • 2,500 boe/d production
  • MRI wells with IP30 rates up

to 342 bbls/d oil

  • Low well costs
  • 42 API sweet oil
  • Strong solution gas drive
  • No formation water risk
  • Drill depths less than

1,600m

  • Conducted a broad

delineation program (19 wells to date)

  • Latest wells are 1.5 mile HZs

>500 MMbbl net OOIP 350+ locations

100/11-03 and 102/11-03: Producing on clean-up

Oil Pool Outline

Whitecap Wells (red): Strong early results (190-449 bbls/d IP30).

16-15 pad: >230,000 bbls Produced in 18 months

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Ca Cardiu ium Oil il Delin lineatio ion Program

Unique 100% WI Block, Extensive Inventory of High Graded Locations

High Graded Type Curve >200 locations 2015 Delineation Program Average

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P99 P98 P95 P90 P80 P70 P60 P50 P40 P30 P20 P10 P5 P2 P1 10 100 1000

Percentile >>>

Peak Month Oil Rate (bbls/d, normalized per 1,600m of lateral)

Pembina Median: 134 bbls/d Wapiti Median: 164 bbls/d Modern 04/16-15-67-8W6

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Ca Cardiu ium Be Benchmarkin ing

Wapiti Cardium is a Leading Light Oil Play in Canada

Modern Wapiti Cardium Wells (17) 2014+ Wapiti Cardium Wells 2014+ All Pembina Cardium Wells

Half Cycle Economics, May 31, 2017 Strip Price(2) EUR mboe 252 Well Costs1 $MM (gross) 3.0 NPV10% $MM (gross) 1.6 DPI 10% Discount Rate 0.6 Payout yrs 2.0 IRR % 39 Capital Cost (IP6) $/boe/d 12,987 F&D $/boe 11.89

(1) Development costs assuming multi-well pads (2) Strip Pricing per Bloomberg (3) Source: geoScout and Modern data

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SLIDE 16

Cardiu ium Pric rice Se Sensit itiv ivit ity

16

Development Drilling to Begin in 2H 2017 = Reduced Variability, Reduced Costs

10 20 30 40 50 60 70 80 90 100 75% 100% 125% ROR % Variance to Base Assumptions Cardium Projected Play Type Well ROR vs. Production, Capital Sensitivity Strip Price - May 31, 2017 Production Capital

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SLIDE 17

Cardiu ium H2/17 Plan lan

Low-Risk Development Program Builds Oil Production to >2,200 bbls/d by Q1 2018

17

  • 11 wells proposed through from Oct 2017 to Feb 2018 (seven are during Q4 2017)
  • Most proposed wells offset existing producers, on existing infrastructure

1st Pad: Development + step-out 2nd Pad: Development 3rd Pad: Development 4th Pad: Step-out + expiry

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SLIDE 18
  • 20,000

40,000 60,000 80,000 100,000 120,000 140,000 2013 2014 2015 2016

Mboe

Independent Reserve Estimates (1)

PDP Proven (net of PDP) Probable

18

Fin inancia ial l Hig ighli lights

Steady Growth Through Disciplined Execution

(1) McDaniel & Associates Consultants Ltd.

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SLIDE 19

Su Summary ry

Designed to Prosper in the ‘Modern’ Resource World

19

Modern Culture

  • Community: open,

respectful communication

  • People: engaged,

invested, aligned

  • Environment: leadership,

innovation, commitment

  • Focus: Modern in all we

do "Set the Precedent”

Modern Assets

  • Quality: top North

American natural gas and

  • il resource plays(1)
  • Scale: 689 locations; 296K

net acres; multi-Tcf OGIP; 500 mmbbl OOIP

  • Control: 100% owned

infrastructure

  • Clean: low emissions,

minimal liabilities (LLR >15)

  • Balance Sheet: financial

flexibility; material ELOC remaining

Modern Results

  • Drilling Results: repeatable,

predictable and prolific

  • Production Growth: 197%

2016 YoY growth

  • Cost Structure: $4.69/boe

corporate operating costs(2), <$2.00/boe @ Route Gas plant

  • Reserves: $6.00/boe FD&A(3)

including $32MM infrastructure

  • Infrastructure: 125 mmcf/d

greenfield, integrated processing capacity

(1) Peters & Co. Research (2) Q1/17 (3) 2016 including FDC

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Set the Precedent

20

Questio ions?

Chris Slubicki President, CEO & Director 403.542.7375 chriss@modernresources.ca Derek Mendham CFO 403.608.7030 derekm@modernresources.ca

Modern 7-9-62-8W6 Gas Plant

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21

This presentation may contain "forward-looking statements" within the meaning of applicable securities legislation, including estimates of future production, cash flows and reserves, business plans for drilling and exploration, the estimated amounts and timing of capital expenditures, the assumptions upon which estimates are based and related sensitivity analyses, and other expectations, beliefs, plans, objectives, assumptions or statements about future events or performance (often, but not always, using words or phrases such as "expects" or "does not expect", "is expected", "anticipates" or "does not anticipate", "plans", "estimated" or "intends", or stating that certain actions, events or results “may", "could", "would", "might" or "will" be taken, occur or be achieved). In particular, this presentation contains forward-looking statements pertaining, to the following: estimates of infrastructure processing capacity, well costs, payout and IRR estimates. Statements relating to "reserves" are deemed to be forward looking statements, as they involve the implied assessment, based

  • n certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and that the reserves can be profitably

produced in the future. There are numerous uncertainties inherent in estimating crude oil and natural gas reserves and the future cash flow attributed to such reserves. The reserve and associated cash flows therefrom are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserve recovery, timing and amount of capital expenditures, marketability of oil and natural gas, royalty rates, the assumed effects of regulation by governmental agencies and future operating expenses, all of which may vary materially. Actual reserve values may be greater than or less than the estimates provided herein. Unless otherwise noted, reserves referenced herein are given as at December 31, 2016. Also, estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates and future net revenue for all properties due to the effect of aggregation. All forward-looking statements are based on Modern’s beliefs and assumptions based on information available at the time the assumption was made. Modern believes that the expectations reflected in these forward-looking statements are reasonable but no assurance can be given that these expectations will prove to be correct and such forward-looking statements included in this presentation should not be unduly relied upon. By their nature, such forward-looking statements are subject to a number of risks, uncertainties and assumptions, which could cause actual results or other expectations to differ materially from those anticipated, expressed or implied by such statements. Risk factors include: financial risk

  • f marketing reserves at an acceptable price given market conditions; volatility in market prices for oil and natural gas; delays in business operations;

pipeline restrictions; infrastructure construction schedule delays and cost overruns; blowouts; the risk of carrying out operations with minimal environmental impact; industry conditions including changes in laws and regulations including the adoption of new environmental laws and regulations and changes in how they are interpreted and enforced; uncertainties associated with estimating oil and natural gas reserves; economic risk of finding and producing reserves at a reasonable cost; increased competition for, among other things, capital, acquisitions of reserves and undeveloped lands; competition for and availability of qualified personnel or management; incorrect assessments of the value of acquisitions and exploration and development programs; unexpected geological, technical, drilling, construction and processing problems; availability of insurance; fluctuations in foreign exchange and interest rates; general economic, market and business conditions; uncertainties associated with regulatory approvals; uncertainty of government policy changes; uncertainties associated with credit facilities and counterparty credit risk; and changes in income tax laws, tax laws, crown royalty rates and incentive programs relating to the oil and gas industry. These risks and uncertainties could cause actual results or other expectations to differ materially from those anticipated, expressed or implied by such statements. The impact of any one risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as these are interdependent. Modern assumes no obligation to update forward-looking statements should circumstances or management's estimates or opinions change. Certain information contained herein have been prepared by third-party sources. The information provided herein has not been independently audited or verified by the Company.

Disc iscla laim imer – Forw rward Lo Lookin ing St Statements