CORPORATE UPDATE Managing Volatili lity Wit ith Strength & - - PowerPoint PPT Presentation

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CORPORATE UPDATE Managing Volatili lity Wit ith Strength & - - PowerPoint PPT Presentation

CORPORATE UPDATE Managing Volatili lity Wit ith Strength & Bala lance December 2018 Modern rn Elem lements of f Valu lue Success in a Low Price Environment Modern Environmental Leader Clean, safe, low liability NuVista LMR of


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SLIDE 1

CORPORATE UPDATE

Managing Volatili lity Wit ith Strength & Bala lance

December 2018

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SLIDE 2

Modern rn Elem lements of f Valu lue

2 Success in a Low Price Environment Modern

Environmental Leader ✓ Clean, safe, low liability LMR of 18 Commodity & Play Diversification

Premium resource plays: Spirit River gas, Cardium oil Significant Resource 1

2P reserves = 222 mmboe 2P BTNPV10 = ~$1.1 billion Scalable, Focused Asset ✓ 274,000 net acres, 541 gross locations, ~100% WI 2 Top Tier F&D 3

$0.57/mcfe Spirit River Rich $9.35/boe Cardium Tier 1 Low Operating Cost 4

$4.36/boe corporate $0.39/mcfe Spirit River Strong Balance Sheet 4 ✓ $90mm available capital (ELOC + bank line) Owned Infrastructure

✓ 125 mmcf/d processing

capacity Access to Market

Firm NGTL calibrated to production

1 12/31/17 McDaniel reserves report; Forecast pricing 2 Effective WI for active development areas – actual avg. WI ~85% 3 Half cycle economics – see pgs. 10 & 12; Cardium is midpoint 4 Q3/18 financial results

Wapiti Greater Kakwa

Pembina Peace Liquids Pipeline Market Pipelines (NGTL, Alliance) Modern Pipelines

Jupiter Cenovus Tou NuVista Husky 7 Gen WCP

Designed to Prosper in the ‘Modern’ Resource World

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SLIDE 3

0.0 2.0 4.0 6.0 8.0 10.0 12.0 14.0 16.0 18.0 Imported LNG Unconventional Marcellus Shale Unconventional Tight Gas Unconventional Barnett Shale Conventional Onshore U.S. Average Domestic Natural Gas (2010) Unconventional Coal Bed Methane Conventional Associated Modern Resources Conventional Offshore

gCO2e/MJ Natural Gas Production Field Transport and Processing

3

Envir ironmental l Advantage – Low Carbon In Intensit ity

Modern Cardium

Low Emissions = Carbon Security

Source: ARC Financial

Gas Plays Oil Plays

KgCO2e/barrel Production and Upgrading Oil and Product Transport and Refining

Norway Ekofysk

Kuwait Burgan Texas Spraberry

California Midway Sunset

Venezuela Merey Blend Iran Abuzar

100 200 300

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SLIDE 4

All Electric

4

Envir ironmental l Le Leadership ip

Moving Toward Zero Methane Emissions

OLD – Methane Emitting Devices NEW – 100% Electric Drive

30

m3 methane emissions per day m3 methane emissions Equal to taking 30 cars off the road 1

1 Per EPA guidelines

Modern Ultra-Low Emission Sites (“MULE”)

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SLIDE 5

3,741 boe/d 8,776 boe/d 10,969 boe/d 16,810 boe/d Q4/15 Q4/16 Q4/17 Q1/18

Oil & Liquids Natural Gas

Premium Resource Supports Significant Growth

5

Deep Basin in Growth with ith Runnin ing Room

18 mmboe 69 mmboe 119 mmboe 222 mmboe 2014 2015 2016 2017

Oil & Liquids Natural Gas

24 217 26 324

Production Growth 541 Gross Undrilled Locations 1 Proved + Probable Reserves Growth 2

0 mmcf/d 50 mmcf/d 60 mmcf/d 125 mmcf/d Q4/15 Q4/16 Q3/17 Q4/17

Gas Processing Capacity

Cardium – Drilled Cardium – Undrilled Spirit River – Drilled Spirit River – Undrilled

1 Includes a mixture of 1.0, 1.5 and 2.0 mile lateral lengths 2 McDaniel & Associates reserves as at year-end with forecast pricing

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SLIDE 6

2015 2016 2017 2018 Current

$11. 3 $6.9 $6.6 $5.5 $5.5 Spirit River ~$15 /boe ~$7.50 /boe ~$5.70 /boe ~$5.60 /boe 2015 2016 2017 2018F

Low Cost Supplier Wins

6

Cost St Stru ructure to Th Thri rive in in All ll Envir ironments

Decreasing Cash Costs – Leading Peers Capital Efficiencies – Continuous Improvement

$21 $19 $16 $15 $15 $15 $14 $14 $13 $11 $10 $8 $7 $6 $5 Historical Modern Cash Costs (C$/boe) Peer Group 2019E Cash Costs (C$/boe) 1 $11 $10 $10 $9 $8 $7 $7 $7 $6 $6 $5 $5 $4 $4 $1 D&C Cost Improvements (C$mm) 2 Peer Group 2017 1-Yr 2P FD&A Costs (C$/boe) 1

1 Peers include AAV, ARX, BIR, BNP, BXE, CQE, CR, DEE, KEL, NVA, PEY, PMT, POU, SRX, TOU & VII and based on Peter’s & Co. estimates November 5, 2018; cash costs include opex, G&A & interest 2 Years represent winter drilling seasons (i.e. 2017 = Q2 2016-2017 Breakup); well costs normalized to 1.0 mile (1,600m) lateral length on a $/m basis

2016

$3.6 $2.9 $2.6 $2.2 Cardium

2015 2017

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SLIDE 7

Cardium Piloting & Development

7

Evolu lutio ion of a Versatil ile Asse sset Base

Spirit River At Critical Mass – Switching to Liquids Focus

2013 2014 2015 2016 2017 2018 F % of Capital Expenditures Resource Capture Validation Spirit River Infrastructure

Note: Spirit River represents Kakwa CGU, Cardium represents Wapiti CGU

Spirit River Cardium Land / A&D

Spirit River Development

Spirit River Infrastructure

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SLIDE 8

8

Wapit iti i Ca Cardiu ium Lig Light Oil il Develo lopment

Commanding Position in a Leading Light Oil Play

  • >500 MMBbl Oil in Place (Net)
  • Two tiers of locations; top tier

has best-in-class Cardium EURs (up to 174 Mbbl oil)

  • MRI wells IP301 rates up to

~350 bbls/d oil

  • 3rd generation frac design

resulting in stronger IPs

  • Latest D&C < $2.0MM
  • 2018 program development

focussed, but includes delineation wells and frac pilot

Pool Limit

1 Calendar daily rate

13-15 Central Tank Treating Facility

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SLIDE 9

9

La Latest Ca Cardiu ium Wells lls – Oil il Rate vs.

  • s. Cu

Cum

40 Wells Drilled to Date – Two Tiers of Type Curves Based on Geological Mapping

Tier 11 Area

Oil Rate bbls/d

1. Revised type curve formally referred to as “Northern Type Curve” 2. Formally referred to as “Southern Type Curve” (unchanged)

Q1/18 Drills (4) Q4/17 Drills (3) Q3/18 Drills (3)

Tier 22 Area

November 1, 2018 Effective Date Price Forecast - October 31, 2018 Strip Tier 11 Tier 22 Half Cycle IP30 (Restricted) bbls/d 200 125 IP30 (Restricted) boe/d 300 271 Technical Type Curve Primary product 178 mmbls 159 mmbls GOR scf/bbl 2500 5000 EUR mboe 259 308 Liquids Ratio C2+ bbls/mmcf 79% liquids 70% liquids Well Costs $MM (gross) 2.425 2.425 NPV10% $MM (gross) 2.3 1.9 DPI 10% Discount Rate 0.9 0.8 Payout yrs 1.3 1.6 IRR % 65 50 IP6 boe/d 249 250 Capital Cost (IP6) $/boe/d 9,739 9,700 F&D $/boe 9.35 7.86

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SLIDE 10

10

Red Rock Sp Spir irit it Riv iver Gas Pla lay

Limited Gas Program for 2H 2018; Drilled Locations with Resilient Economics

  • 21 wells currently producing into MRI’s Route gas plant
  • Owned infrastructure (roads, pipe, water) keep DCTE costs down
  • Latest pad is MRI’s longest laterals to date (up to 2.4km)

Latest Pad (06-08): 08-09 testing in-line; 01-09 fracking 1st week Dec

MRI 10” Pipeline To MRI Route Gas Plant

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SLIDE 11

Sp Spir irit it Riv iver r Perf rform rmance - Most Recent Drill rills

24 Wells Drilled to Date – Results Warrant Lean/Rich Type Curves

11

Gas Rate mmcf/day Cumulative Gas bcf

Latest Lean Gas Wells (7) Latest Rich Gas Wells (4)

Wells drilled before Q2 2017 shown in grey

Lean Rich

Type Curve - 1.5 Mile Spirit River Nov 1,’18 Effective date Price Forecast October 31, 2018 Strip Rich Lean Spirit River Economics Half Cycle IP30 (Unrestricted) mcf/d 13,350 16,260 IP30 (Unrestricted) boe/d 2,410 2,577 Technical Type Curve Primary product 11 bcf 13 bcf EUR (Economic) mboe 2,015 2,104 Liquids Ratio C5+ bbls/mmcf 25 2 Well Costs1 $MM (gross) 6.9 6.9 Opex $/Mcfe 0.41 0.25 NPV10% $MM (gross) 7.6 2.5 DPI 10% Discount Rt 1.1 0.4 Payout yrs 1.8 3.9 IRR % 53 21 IP6 boe/d 1,470 1,572 Capital Cost (IP6) $/boe/d 4,694 4,389 F&D $/boe 3.42 3.28

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SLIDE 12

Co Competit itiv ive Advantage - Owned In Infr frastructure

Strategic Control & Sustainable Top Decile Op Costs

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  • Owned & operated infrastructure - the

backbone of Modern

  • Route plant - 115 mmcf/d
  • Lynx plant - 10 mmcf/d
  • Extensive network of pipelines (~230km)
  • 13-15 central oil-treating facility - 2500bbl/d
  • 3 water handling hubs
  • 80,000 m3 fresh water storage
  • 40,000 m3 produced water storage
  • 100% recycling, no disposal required
  • Diverse, secure water sources
  • Low-cost advantage is structural
  • No take-or-pays
  • No material midstream fees1
  • Low operating & capital costs

Copton Sales Line Modern 10” Pipeline Modern Route Gas Plant Lynx Gas Plant 11-25 Wapiti Compressor Red Rock Water Hub

1 Midstream fees are paid occasionally prior to pipeline construction or in non-core areas

13-15 Central Tank Treating Facility 13-35 & 04-09 Batteries

Pembina Peace Liquids Pipeline Market Pipelines (NGTL, Alliance)

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SLIDE 13

Active Hedging Program Mitigates Volatility

13

Risk isk Management

Winter 2018/19F Natural Gas Coverage November 2018 – December 2019 Oil Coverage Fixed Price Swaps 53% AECO Basis Swaps 3% Floating Gas 44% Fixed Price Swaps 41% Floating Oil 59%

  • 53% of winter gas

production hedged at C$2.33/mcf

  • Growing Cardium oil

production reducing gas exposure

  • 18% of revenue through

YE 2019 exposed to floating AECO pricing

1 Coverage levels are net of royalties.

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SLIDE 14

Su Summary ry – St Strength & Bala lance

Designed to Prosper in the ‘Modern’ Resource World

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1 Q3/18 results; cash costs include op costs, G&A & interest expense 2 Half cycle economics – see page 8&10; Rich Spirit River and Cardium Tier 1 3 12/31/17 McDaniel’s reserve report; forecast pricing

  • 274,000 net acres; 541 gross locations
  • 125 mmcf/d processing capacity

Top Tier Platform

  • Total corporate cash costs: $5.91/boe 1
  • Corp. op costs: $4.36/boe (Spirit River $0.39/mcfe) 1
  • F&D: $0.57/mcfe Spirit River, $9.35/boe Cardium 2

Industry Leading Cost Structure

  • Q1/18 production 16,800 boe/d (58% YoY growth)
  • 87% YoY 2P reserves growth to 222 mmboe 3

Material Growth

  • $90mm liquidity (ELOC & $120mm bank line) 1
  • Balance sheet strength guides capital expenditures

Financial Strength

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SLIDE 15

Who is is Modern rn?

Experienced & Invested Team

15 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)

Francois Legault, P. Geol. Chief Operating Officer

(Vermilion, Talisman)

Derek Mendham, CA, CFA Chief Financial Officer

(Ensign, Genuity Capital, RBC Capital Markets)

Jason Chadwick, B. Comm., PLM Senior VP Commercial

(Mancal, Rio Alto)

Geoff Keyser, P. Eng. Vice President Engineering

(Painted Pony, Cenovus, EnCana)

Darren Tisdale Vice President Geosciences

(Trident Exploration, Painted Pony)

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SLIDE 16

Set the Precedent

16

In Industry ry Recognit itio ion

Explorers and Producers Association of Canada

2017 Top Private Emerging Producer Nominated 2018 Top Junior Producer 2018 GPS Award for Environmental Excellence

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SLIDE 17

17

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, 2017. 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.

Dis iscla laim imer – Forw rward Lookin ing St Statements