montney liquids-rich growth story - … presentation january 2018.pdf1,200+ drilling locations on...

Saguaro Resources | Private and Confidential | January 2018 1

Montney Liquids-Rich Growth Story

Private and ConfidentialJanuary 2018

Corporate Presentation


Track Record of Success Sets Stage for Material Long-Term Value Creation(1)

Privately-held pure play NE BC Montney producer 100% working interest in a large,

contiguous land position

1,200+ drilling locations on de-risked land base 59 wells drilled with 55 onstream at

year end 2017

Full development plan is executable with cash flow and moderate leverage

Medium-term egress solution already in place

1. See advisories and definitions on pages 32 and 33 hereof. 2. Based on field estimates for December 2017 (unaudited).3. Reserves CAGR calculated from December 31, 2014 to October 31, 2017.4. Inception to October 31, 2017.

Strong, continuously improving type curves drive attractive single well economics

Strong liquids production comprised predominantly of high value condensate

Shallow drilling depths reduce capital costs and improve economics

Competitive and improving cost structure

Low royalty structure with attractive royalty credits

Capital efficient execution led by experienced management team

102% 3 year production CAGR(2)

2017 exit production >16,600 Boed

140% ~3 year 2P reserves CAGR(3)

Industry leading inception-to-date 2P FD&A costs of $5.76 per Boe(4)

2017 corporate cash flow is >7x(2)

2016 corporate cash flow despite challenging commodity price environment

Extensive risk management program protects growing cash flow as a source of capital funding

Growth Potential Attractive Economics Proven Track Record


Growth Potential


0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

160,000

180,000

2013 2015 2017 2019 2021 2023 2025

Annualized Production (Boed)

Gas Condensate & Other Liquids

Full Development Plan Provides Material and Sustainable Organic Growth(1)(2)

1. See advisories on pages 32 and 33 hereof. 2. Full development plan (“FDP”) is based on a 1,200 well development program which develops ~80% of Saguaro’s existing land base. Assumes 2,500 m 7 Bcf type curve. FDP is based on 2017 YTD results and will continue to be updated throughout the delineation phase. Any

changes to the assumptions used in the FDP will impact the metrics and results including amount of equity raised3. Based on field estimates for December 2017 (unaudited).4. FDP capital includes all development capital (inclusive from 2013; undiscounted) excluding land. Economic metrics for FDP are unlevered project economics with flat pricing until 2022 at $2.50/GJ AECO, -$0.35/GJ Station 2 differential, US$50/Bbl WTI, 0.75 USD/CAD FX, then

escalated at 1.5% thereafter. Natural Gas Liquids pricing relative to WTI: C5+ 102%; C4 67%; C3 44%. Economic metrics are based on go forward assumptions. IRR is unlevered and does not include G&A, land costs and undeveloped land value.

Strategically advancing a low-risk development play 2013: initiated pilot program 2015: commercial development began 2017: added second drilling rig

Exit production of >16,600 Boed(3)

Target >100,000 Boed within a decade from inception Peak production held flat at ~170,000 Boed for over 10 years

Strategically advancing a low-risk development play 2013: initiated pilot program 2015: commercial development began 2017: added second drilling rig

Exit production of >16,600 Boed(3)

Target >100,000 Boed within a decade from inception Peak production held flat at ~170,000 Boed for over 10 years

Full Development Plan(4)

Capital ($B) $7.4

IRR (BT %) 34%

Net PIR0 (x)Net PIR10 (x)

3.51.0

NPV0 (BT $B)NPV10 (BT $B)

$25.1$3.2


High Quality Asset in One of North America’s Leading Oil & Gas Plays(1)

The Montney is a large, world class oil and gas play with leading supply costs and economics

Saguaro has acquired a large strategic land position in the NE BC Montney 100% working interest in 164 contiguous sections (~113,000 acres) Liquids-rich stacked potential Over-pressured with good permeability Shallow depth (1,400-1,900 m) reduces cost and improves economics

Scale and quality of land base supports impressive growth and capital efficiencies with a drilling inventory of 1,200+ locations

Access to multiple markets through existing and future egress options Existing and expanding access to AECO, Dawn, Station 2, Chicago, and

Sumas hubs TCPL North Montney Mainline project (in-service ~2019) Enbridge T-South expansion (in-service ~2020)

1. See advisories on pages 32 and 33 hereof. 19 miles


Best Estimate Prospective Resource of 372 MMBoe (24% liquids)(5)

Additional 387 locations (Best Estimate Risked) Best Estimate Prospective Resource of 372 MMBoe (24% liquids)(5)

Additional 387 locations (Best Estimate Risked)

Best Estimate Contingent Resource of 345 MMBoe (23% liquids)(4)

Additional 319 locations (Best Estimate Risked) Best Estimate Contingent Resource of 345 MMBoe (23% liquids)(4)

Additional 319 locations (Best Estimate Risked)

1P: 141 MMBoe 2P: 400 MMBoe 3P: 675 MMBoe(22% liquids) (23% liquids) (23% liquids)1P HZ Well Count: 169 2P HZ Well Count: 353 3P HZ Well Count: 462

1P: 141 MMBoe 2P: 400 MMBoe 3P: 675 MMBoe(22% liquids) (23% liquids) (23% liquids)1P HZ Well Count: 169 2P HZ Well Count: 353 3P HZ Well Count: 462

1. See advisories and definitions on pages 32 and 33 hereof.2. Based on Sproule Reserves Evaluations dated effective October 31, 2017 and Evaluation of the Contingent and Prospective P&NG Resources prepared by Sproule Associates Limited dated October 31, 2017 pursuant to National Instrument 51-101 Standards of Disclosure for Oil

and Gas Activities (“NI 51-101”) and the Canadian Oil and Gas Evaluation Handbooks (“COGE Handbook”); both evaluations based on Sproule Pricing as of September 30, 2017. For reference, PDP = Proved Developed Producing Reserves; 1P = Total Proved Reserves; 2P = Total Proved Plus Probable Reserves; 3P = Total Proved Plus Probable Plus Possible Reserves.

3. All figures include Montney production, reserves, and resources only; excludes Coplin / Charlie Lake / other conventional production, reserves, and resources.4. Contingent resources are classified as development pending, subject to evaluation drilling, corporate commitment and development timing contingencies, and the chance of development and therefore chance of commerciality has been estimated to be 90%.5. Prospective resources are undiscovered volumes with an estimated chance of discovery of 95% and a chance of development of 90%, resulting in an aggregated 85% chance of commerciality.

Sproule’s Assessment of Saguaro’s Reserves and Risked Resource Base(1)(2)(3)

8MMBoe Produced

141 MMBoe 1P Reserves



280 MMBoe Low Estimate

Risked Prospective

372 MMBoe Best Estimate

Risked Prospective

489 MMBoe High Estimate

Risked Prospective

262 MMBoe Low Estimate

Risked Contingent

345 MMBoe Best Estimate

Risked Contingent

449 MMBoe High Estimate

Risked Contingent


Stacked Zone Exploitation Multiplies Productive Potential(1)

1. See advisories on pages 32 and 33 hereof. Porosity from Nutech Petrophysical analysis. 3% porosity cut off.2. As at December 31, 2017.

All three Montney targets proven productive Over pressured: 11-15 kPa/m Shallow depth: 1,400-1,900 m Gross pay: ~260 m across

3 stacked porous zones

Development plan focuses on Upper and Middle targets

59 wells drilled to date(2): 19 Upper Target 36 Middle Target 4 Lower Target

1,600 m


Sections To Be De‐Risked18

De‐Risked Sections

146

Successful De-Risking & Delineation Drives Reserve Growth(1)

De-Risking & Delineation Well Advanced

89% of land base (146 sections) de-risked through drilling and competitor activity

Reserve Bookings(2)

High quality asset has allowed impressive, consistent reserve growth to date and provides large future growth potential 2P Reserves represent ~23% of Saguaro’s estimated well inventory

1. See advisories on pages 32 and 33 hereof.2. Illustration based on Sproule’s reserves evaluation dated October 31, 2017.

ProvedProbable

81-G 14-I34-H 76-D

81-G

14-I78-C81-G 34-H

34-H

78-C

14-I

76-D

76-D

5 miles

Upper Target

Middle Target

Lower Target


$0.00

$10.00

$20.00

$30.00

$40.00

$50.00

$60.00

PDP 1P 2P

$ pe

r Boe

2014 2015 2016 Jan‐Oct 2017

0

100

200

300

400

500

Dec‐14 Jul‐15 Dec‐15 Jun‐16 Sep‐16 Dec‐16 Jun‐17 Oct‐17

MMBo

e

PDP PDNP+PUD Total Probable

Substantial, Low Cost Reserve Growth(1)

Sproule October 31, 2017 Reserves Summary

1. See advisories and definitions on pages 32 and 33 hereof.2. Saguaro has Total Gross Reserves of 140,728 MBoe (1P) and 400,386 MBoe (2P) as of October 31, 2017.

PDP reserves are comprised of 78% Gas, 22% NGLs, 0.2% Oil. 1P and 2P reserves are comprised of 77% Gas, 23% NGLs. 1P includes 1,122 MBoe of net Proved Developed Non-Producing (PDNP) reserves.3. Based on Sproule Reserves Evaluations dated effective October 31, 2017 and June 30, 2017, respectively and based on Sproule Pricing as of September 30, 2017 and May 31, 2017, respectively.4. Based on reserves evaluations prepared by Sproule Associates Limited pursuant to NI-51-101 and the COGE Handbook. Sproule Reserves Evaluations based on Sproule Pricing as of September 30, 2017 for Oct-2017, May 31, 2017 for Jun-2017, December 31, 2016 for Dec-2016;

July 31, 2016 for Sep-2016; June 30, 2016 for Jun-16; December 31, 2015 for Dec-15; July 31, 2015 for Jul-15; December 31, 2014 for Dec-14.5. Jan-Oct 2017 Development Capital of $131.4 MM (includes unaudited estimate for October 2017). FD&A and F&D includes Full Development Capital (FDC).

Proved Developed

Producing (PDP)Total

Proved (1P)

Total Proved Plus

Probable (2P)

Total Reserves (MBoe)(2) 24,509 140,723 400,378

NPV10 (BT $MM) $276 $1,129 $2,968

NPV10 (BT $/Boe) $11.27 $8.02 $7.41

F&D (Incl. FDC) ($/Boe) $10.74 $5.27 $3.60

FD&A (Incl. FDC) ($/Boe) $10.81 $5.29 $3.61

Locations (#) 43 169 353

2P reserves increased by 36% since Jun. 30, 2017 400 MMBoe at Oct. 31, 2017 vs. 295 MMBoe at Jun. 30, 2017(3)

1P NPV10 value increased by 52% since Jun. 30, 2017 $1,129 MM at Oct. 31, 2017 vs. $741 MM at Jun. 30, 2017(3)

Attractive FD&A Costs(4)(5)

2P Reserves Growth(4)


Attractive Economics


0

250

500

750

1,000

1,250

1,500

1,750

0 2 4 6 8 10 12 14 16 18 20 22 24

Prod

ucing Day Sales Produ

ction (Boed)

Ca lendar Months

6 Bcf Type Curve 7 Bcf Type Curve8 Bcf Type Curve Second Generation (2,000 m HZ; 29 wells)Third Generation (2,500 m HZ; 4 wells)

Advancing Well Design Drives Material Type Curve Improvement(1)

Three Generations of Saguaro Drills Increasing Length Improves Results(2)

1. See advisories and definitions on pages 32 and 33 hereof.2. Data set includes all Upper and Middle targets.

6 Bcf 7 Bcf 8 Bcf

GenerationHZ Length meters

First~1,500

Second2,000

Third2,500

IP30 Raw MMcfdSales MBoed

5.01.0

6.11.2

7.41.5

EUR Raw BcfSales MMBoe

6.21.2

7.31.4

8.31.6

5 miles


$3.4 $3.0

$2.1 $2.4 $2.2

$0

$500

$1,000

$1,500

$2,000

$2,500

$3,000

$0.0

$1.0

$2.0

$3.0

$4.0

$5.0

$6.0

Pre‐2015Pilot

Program

2015Development

2016Development

2017Development

2018Forecast

Cost ($) per HZ m

Averag

e Co

st per W

ell ($M

M)

Drilling $ per HZ m

Drilling: Efficiencies Offset Cost of Longer Laterals(1)

Continuous improvement in drilling practices have reduced days from spud to rig release 2,000 m pacesetter well drilled in 11 days in 2016 and 10 days in 2017 2,500 m pacesetter well drilled in 11 days in 2017

Reducing drilling days allows more efficient rig utilization Increases wells per year per rig which simplifies operations Reducing days decreases drilling cost per well

1. See advisories on pages 32 and 33 hereof.2. Drilling costs shown do not include Deep Well Drilling Credit of ~$1.0 MM per well. 2017 costs are based on field estimates.

1,000-1,500 m

2,000 m

2,000 m 2,500 m2,000-2,500 m

Drilling(2)


Multiple completion designs tested over time Open Hole vs. NCS systems; 10 to 85 frac stages; 1.0 to 2.0 tonnes/m

Multiple completion designs tested over time Open Hole vs. NCS systems; 10 to 85 frac stages; 1.0 to 2.0 tonnes/m

$3.8 $3.0

$2.6 $2.8 $2.5

$0

$50

$100

$150

$200

$250

$300

$0.0

$1.0

$2.0

$3.0

$4.0

$5.0

$6.0

Pre‐2015Pilot

Program

2015Development

2016Development

2017Development

2018Forecast

Cost ($000) per Stage

Averag

e Co

st per W

ell ($M

M)

Completions $000 per stage

Completions: Evolving Design Enhances Recoveries and Reduces Costs(1)

1. See advisories on pages 32 and 33 hereof.2. 2017 costs are based on field estimates.

10-18 stages

23-35 stages35-65 stages 35-85 stages

65 stages

(2)


0%

20%

40%

60%

80%

100%

120%

140%

160%

AECO $1.50/GJWTI US$50.00/Bbl



Half Cycle IRR (%

)

6 Bcf Type Curve 7 Bcf Type Curve 8 Bcf Type Curve

Strong and Improving Single Well Economics at Flat Prices(1)

1. See advisories and definitions on pages 32 and 33 hereof. Assumes drilling in January 2018 with an associated onstream in March 2018. Includes capital for drilling, completions, and equipping. Capital is not adjusted for Deep Well Royalty Credit.Economic metrics based on operating costs and processing recoveries at Enbridge Highway. Blended variable and fixed operating costs of $4.04/Boe in the first year of production based on third party processing.Assumes: 2,500 m wells and a heating value of 1,165 Btu/scf; and Natural Gas Liquids pricing relative to WTI: C5+ 102%; C4 67%; C3 44%. Economics do not include G&A, land costs, or undeveloped land value.

2. Based on flat pricing at $2.50/GJ AECO, -$0.35/GJ Station 2 differential, US$50/Bbl WTI, 0.75 US$/C$ FX.3. Based on flat pricing at -$0.35/GJ Station 2 differential; 0.75, 0.78, and 0.80 US$/C$ FX at US$50/Bbl, US$60/Bbl, and US$70/Bbl WTI, respectively.

Based on AECO $2.50/GJ & WTI US$50/Bbl(2) 6 Bcf 7 Bcf 8 Bcf

GenerationHorizontal Well Length (m)

First~1,500 m

Second2,000 m

Third2,500 m

DC&E Cost ($MM) $5.05 $5.05 $5.05

IRR (BT %) 46% 65% 88%

NPV0 (BT $MM)NPV10 (BT $MM)

$12.0$4.9

$14.9$6.5

$18.1$8.3


2.41.0

3.01.3

3.61.7

Gas Supply Cost (AECO $/GJ)Condensate Supply Cost (Edm. $/Bbl)

$0.94$25.25

$0.71$18.88

$0.52$13.94

Payout (years) 1.8 1.3 1.0

Economics at low gas prices supported by strong liquids volumes; material uplift on returns from underlying condensate production Technological advancements continue to increase recoverable resource and strengthen associated economics Economics at low gas prices supported by strong liquids volumes; material uplift on returns from underlying condensate production Technological advancements continue to increase recoverable resource and strengthen associated economics

Single Well Sensitivities(2)(3)


Proven Track Record


0

15

30

45

60

75

Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4

2015 2016 2017

NGLs (B

bl/M

Mcf Sales)

Free Condensate Entrained Condensate Butane Propane

02,0004,0006,0008,000

10,00012,00014,00016,000

Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4

2015 2016 2017

Prod

uction

(Boed)

Gas Oil Condensate Butane Propane

Consistent Liquids-Rich Production Growth Since Inception(1)

Production by Product

Liquids Yield

1. See advisories on pages 32 and 33 hereof.2. Based on field estimates (unaudited).3. Inception to September 30, 2017.

Inception-to-date liquids of 52 Bbl/MMcf (sales)(3)

High value of condensate consistently exceeds 70% of liquids volumes

Liquids yield has stabilized at attractive levels Recoveries vary depending on third party processing facilities

Inception-to-date liquids of 52 Bbl/MMcf (sales)(3)

High value of condensate consistently exceeds 70% of liquids volumes

Liquids yield has stabilized at attractive levels Recoveries vary depending on third party processing facilities

Record Q4 2017 production of >15,000 Boed(2)

Production records set for eight consecutive quarters

Additional 15 Montney wells brought onstream in Q4 2017 Estimated 2017 exit production exceeded 16,600 Boed(2)

Record Q4 2017 production of >15,000 Boed(2)

Production records set for eight consecutive quarters

Additional 15 Montney wells brought onstream in Q4 2017 Estimated 2017 exit production exceeded 16,600 Boed(2)

(2)

(2)


$0.54 $5.05 $7.35

$1.95 $2.79 $3.48 $7.31

$9.80

$17.24 $13.79

$11.83

$17.61

52%

58%

53%

60% 47% 65%

48%

48%

47%

48%

61%

69%

0%

10%

20%

30%

40%

50%

60%

70%

$0.00

$5.00

$10.00

$15.00

$20.00

$25.00

$30.00

Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4

2015 2016 2017

% Revenue from

Liquids$ pe

r Boe

Operating Netback (Incl. Hedging Gains / Losses) Royalties Operating Costs Transportation

Strengthening Netbacks During a Period of Low Commodity Prices(1)(2)

1. See advisories and definitions on pages 32 and 33 hereof.2. Operating netback is calculated as the difference between the revenue per Boe and related costs (royalties, operating costs, and transportation); includes hedging gains and losses realized in each quarter.3. Based on estimates for Q4 2017 (unaudited).

Continue to reduce operating and transportation costs; achieved lowest operating costs to date in Q3 2017 of $6.77 per Boe Risk management program implemented in 2016 to protect against commodity price volatility Continue to reduce operating and transportation costs; achieved lowest operating costs to date in Q3 2017 of $6.77 per Boe Risk management program implemented in 2016 to protect against commodity price volatility

(3)

Estimate


0

25,000

50,000

75,000

100,000

125,000

150,000

Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4

2018 2019 2020

Volumes Hed

ged (GJd)

Extensive Natural Gas Risk Management Program(1)

1. See advisories on pages 32 and 33 hereof. See page 30 for additional information.2. Based on Q4 2017 estimate (unaudited).

Risk management program is key to executing our development plan Protects cash flow as a source of capital

funding Program utilizes both financial hedging

and physical market contracts

Realized 2017 risk management gains of ~$24 MM(2)

Risk management in place through 2020 (mark-to-market ~$50 MM at Jan. 9, 2018)

Risk management program is key to executing our development plan Protects cash flow as a source of capital

funding Program utilizes both financial hedging

and physical market contracts

Realized 2017 risk management gains of ~$24 MM(2)

Risk management in place through 2020 (mark-to-market ~$50 MM at Jan. 9, 2018)

Chicago (Physical)Sumas (Physical)AECO to NYMEX Differential Hedged (Financial)

Station 2 to NYMEX Differential Hedged (Financial)

Fully Hedged Station 2 (Financial)

NYMEX (Financial)


0

150

300

450

600

750

900

1,050

0

25,000

50,000

75,000

100,000

125,000

150,000

175,000

2013 2015 2017 2019 2021 2023 2025

Annualized Production (MMcfed)An

nualized

Produ

ction (Boed)

Gas Condensate & Other Liquids

0

2

4

6

8

10

12

0

20

40

60

80

100

120

2013 2015 2017 2019 2021 2023 2025

Rigs (at Year End)

Horizontal Drills

per Ye

ar

Drills Rigs

Full Development Plan with Substantial Growth(1)(2)

Full development plan allows production growth to a peak of ~170,000 Boed (~800 MMcfd Sales) in 2025 Production maintained at this level for over 10 years Conservatively assumes ~1,200 Second Generation HZ wells (2,500 m; 7 Bcf type curve) Will be updated to reflect Third Generation wells following additional production results

1. See advisories on pages 32 and 33 hereof. See page 20 for additional information.2. 1,200 well development program which develops ~80% of Saguaro’s existing land base and assumes $7.4 B of capital. This full development plan is based on 2017 YTD results and will continue to be updated throughout the delineation phase.

Production PotentialDrilling Schedule


2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 $0

$250

$500

$750

$1,000

$1,250

$MM

Development Capital Corporate Cash Flow Private Equity Drawn Debt Drawn

Growth Funded Without Equity at Reasonable Debt Metrics(1)(2)

1. See advisories and definitions on pages 32 and 33 hereof. See page 19 for additional information.2. Full development plan (“FDP”) is based on a 1,200 well development program which develops ~80% of Saguaro’s existing land base. Assumes 2,500 m 7 Bcf type curve. FDP is based on 2017 YTD results and will continue to be updated throughout the delineation phase. Any

changes to the assumptions used in the FDP will impact the metrics and results including amount of equity raised.3. FDP capital includes all development capital (inclusive from 2013; undiscounted) excluding land. Economic metrics for FDP are unlevered project economics with flat pricing until 2020 at $2.50/GJ AECO, -$0.35/GJ Station 2 differential, US$50/Bbl WTI, 0.75 USD/CAD FX, then

escalated at 1.5% thereafter. Natural Gas Liquids pricing relative to WTI: C5+ 102%; C4 67%; C3 44%. Economic metrics are based on go forward assumptions. IRR is unlevered and does not include G&A, land costs and undeveloped land value.

Capital program increasingly funded by cash flow

Debt funding achievable while maintaining reasonable debt metrics

Material free cash flow after 2022

Capital program increasingly funded by cash flow

Debt funding achievable while maintaining reasonable debt metrics

Material free cash flow after 2022

Full Development Plan(3)

Capital ($B) $7.4

IRR (BT %) 34%


3.51.0

NPV0 (BT $B)NPV10 (BT $B)

$25.1$3.2

Debt / LTM EBITDA (x) - 1.8x N/A 4.8x 2.6x 2.6x 2.1x 1.9x 1.7x 1.4x 1.0x 0.6x 0.1x -

Debt / NTM EBITDA (x) - N/A 1.8x 0.8x 1.3x 1.4x 1.5x 1.3x 1.2x 1.1x 0.8x 0.5x 0.1x -


Existing Capital Structure(1)

Equity Capacity

Debt Capacity

1. See advisories on pages 32 and 33 hereof.2. 194.4 MM shares outstanding.3. Assumes full draw on line of equity and all future subscription warrants are exercised.

$165 MM syndicated bank revolver $54.5 MM drawn as at September 30, 2017 Expanded by $100 MM in 2017, will continue to expand with reserve

growth

$50 MM 8.5% second lien secured notes Issued in 2017, due in 2022

$165 MM syndicated bank revolver $54.5 MM drawn as at September 30, 2017 Expanded by $100 MM in 2017, will continue to expand with reserve

growth

$50 MM 8.5% second lien secured notes Issued in 2017, due in 2022

$18 MM remains on $400 MM private equity line

No additional equity required to execute our current business plan

$18 MM remains on $400 MM private equity line

No additional equity required to execute our current business plan

($MM) Capacity Outstanding(2) Remaining

Line of Equity $400.0 $382.1 $17.9

Subscription Warrants(3) $24.1 $21.4 $2.7

Private Placement $20.8 $20.8 -

Total Equity Capacity $444.9 $424.3 $20.6

($MM) Capacity

Second Lien Secured Notes $50.0

Syndicated Credit Facility $165.0

Total Debt Capacity $215.0


Installed three stages of 12” backbone gathering system on Saguaro lands Built to support future growth Fourth stage to be constructed in early 2018

Building water pipelines in conjunction with gathering lines to assist in recycling water as part of our integrated water strategy Cost effective water management between

pads and water hub

Currently receiving Infrastructure Royalty Credits on two existing stages of gathering system Ultimately reduces the capital burden and

increases the economics on pipeline projects Fourth stage has also been approved for future

royalty credits

Field Infrastructure Designed to Support Long-Term Growth(1)

1. See advisories on pages 32 and 33 hereof.

5 miles


100% Owned and Operated Facility(1)


Recently expanded capacity to 100 MMcfd to support production growth Highly competitive cost-to-date of $0.75 MM/MMcfd Expect to expand to 240 MMcfd by ~2020 Full site expandable to 1 Bcfd

Recently expanded capacity to 100 MMcfd to support production growth Highly competitive cost-to-date of $0.75 MM/MMcfd Expect to expand to 240 MMcfd by ~2020 Full site expandable to 1 Bcfd

Process Capacity

Inlet (Upgraded) 130 MMcfd

Compression 100 MMcfd

Dehydration 100 MMcfd

Amine Sweetening 30 MMcfd

Condensate Stabilization 3,000 Bbld

Condensate Storage 7,000 Bbl


Third Party Processing & Transportation(1)

Third Party Processing

Currently connected to three third party processing facilities Contracted firm service: 70 MMcfd Executed a competitive processing agreement to manage mid-term

production growth up to 130 MMcfd

Significant interruptible service is also available


Transportation

Firm service on Enbridge T-North pipeline expanding with processing commitments

Firm shipper on TCPL North Montney Mainline project (in-service ~2019) and Enbridge T-South (in-service ~2020)

Additional expansions planned for NGTL and Alliance systems

49 km 6” condensate pipeline from Saguaro’s facility to a new truck terminal on the Alaska Highway under construction (in-service ~Q2 2018)

CondensatePipeline

TruckTerminal


Station 2

Chicago

Henry Hub

AECOSumas

WTI

Expanding North American Market Access(1)


Physically connected to five gas pricing hubs across North America (AECO, Station 2, Sumas, Chicago, and Dawn)

Financial hedging contracts in place to access additional markets including Henry Hub (NYMEX Natural Gas) and Cushing, OK (WTI)

Physically connected to five gas pricing hubs across North America (AECO, Station 2, Sumas, Chicago, and Dawn)

Financial hedging contracts in place to access additional markets including Henry Hub (NYMEX Natural Gas) and Cushing, OK (WTI)

Enbridge to Station 2 and Sumas

NGTL to AECO and Dawn

Dawn


Saguaro’s Value Proposition(1)


Experienced management team has consistently delivered material, capital efficient growth since inception in 2012 Continuous improvement initiatives have improved well productivity while

driving down costs

Strong and improving economics achievable in a sustained low commodity price environment Condensate production supports competitive economics and diversifies

sources of revenue

Large, high-quality asset in one of North America’s leading oil and gas plays Fundable, full development plan to grow production to ~170,000 Boed and

sustain at this level for more than 10 years

Experienced management team has consistently delivered material, capital efficient growth since inception in 2012 Continuous improvement initiatives have improved well productivity while

driving down costs

Strong and improving economics achievable in a sustained low commodity price environment Condensate production supports competitive economics and diversifies

sources of revenue

Large, high-quality asset in one of North America’s leading oil and gas plays Fundable, full development plan to grow production to ~170,000 Boed and

sustain at this level for more than 10 years


Supplementary Materials


Corporate Information

Officers

Stacy Knull President & Chief Executive Officer

Scott Carrothers Vice President Finance & Chief Financial Officer

Tannis Gibson Vice President Geology & Geophysics

Jason Hager Vice President Drilling & Construction

John Christoffersen Vice President Operations & Facilities

Darcy McLaughlin Vice President Engineering

Esther Troyan Vice President Land & Business Development

Michael Graham Chairman

James C. (Pep) Lough Independent Businessman

M. Scott Bratt Independent Businessman

Robert Chaisson Independent Businessman

Stacy Knull President & Chief Executive Officer

Richard Aube Pine Brook Road Partners LLC

Andre Burba Pine Brook Road Partners LLC

Richard Stoneburner Pine Brook Road Partners LLC

Ted Maa Pine Brook Road Partners LLC

Cameron McVeigh Camcor Partners Inc.

BankersAuditors

Directors

PricewaterhouseCoopers LLP3100, 111 – 5th Ave SWCalgary, AB T2P 5L3

Independent Qualified Reserves Evaluator

Sproule Associates LimitedSuite 900, 140 – 4th Ave SWCalgary, AB T2P 3N3

Legal Counsel

Burnet, Duckworth & Palmer LLPSuite 2400, 525 – 8th Ave SWCalgary, AB T2P 1G1

Canadian Imperial Bank of Commerce595 Bay St., 5th Floor, Toronto, ON M5G 2C2

Alberta Treasury Branch239 - 8th Ave SW, Calgary, AB T2P 1B9

National Bank of Canada600 De La Gauchetiere St. West, 3th Floor, Montreal, QC H3B 4L2

Royal Bank of CanadaRoyal Bank Plaza, 200 Bay Street, Toronto, ON M5J 2J5

Business Development Bank of Canada5, Place Ville Marie, Suite 400, Montreal, QC H3B 5E7

440, 222 – 3rd Ave SWCalgary, AB T2P 0B4Phone: (403) 453-3040Fax: (403) 452-5129Website: www.saguaroresources.com

Head Office For more information, please contact

Stacy KnullPresident & Chief Executive OfficerPhone: (403) 453-2680Email: [email protected]

Scott CarrothersVice President Finance & Chief Financial OfficerPhone: (403) 453-2451Email: [email protected]


YE 2015 YE 2016 MY 2017 Oct. 2017 YE 2015 YE 2016 MY 2017 Oct. 2017 YE 2015 YE 2016 MY 2017 Oct. 2017

Proved Developed Producing (PDP)

9,181 15,822 18,933 24,509 $10.42 $12.05 $11.84 $11.27 19 32 34 43

Total Proved (1P)

31,781 83,541 92,690 140,723 $7.94 $7.23 $7.99 $8.02 52 134 134 169

Total Proved Plus Probable (2P)

107,995 270,294 295,124 400,378 $7.64 $6.83 $7.43 $7.41 118 330 330 353

YE 2015 YE 2016 MY 2017 Oct. 2017 YE 2016 MY 2017 Oct. 2017 ITD YE 2016 MY 2017 Oct. 2017 ITD

Proved Developed Producing (PDP)

$0 $0 $0 $0 $9.90 $12.75 $10.74 $12.87 $9.95 $12.85 $10.81 $16.33

Total Proved (1P)

$177.33 $511 $457 $699 $7.81 $0.93 $5.27 $7.39 $7.82 $0.97 $5.29 $8.21

Total Proved Plus Probable (2P)

$631 $1,543 $1,486 $1,893 $6.09 $0.24 $3.60 $5.46 $6.09 $0.26 $3.61 $5.76

Locations(#)

Company Share(2)(3)

(MBoe)NPV10 per Boe

(BT $/Boe)

Full Development Capital($MM)

(Net)

(Net)

Finding & Development Costs(4)

($/Boe)Finding, Development & Acquisitions Costs(4)

($/Boe)

Reserves Evaluations(1)

1. See advisories and definitions on pages 32 and 33 hereof. Based on reports prepared by Sproule Associates Limited effective December 31, 2015, December 31, 2016, June 30, 2017 and October 31, 2017. 2. YE 2015 PDP reserves are comprised of 70% Gas, 29% NGLs, 1% Oil. 1P and 2P reserves are comprised of 70% Gas, 30% NGLs.

YE 2016 PDP reserves are comprised of 75% Gas, 24% NGLs, 1% Oil. 1P and 2P reserves are comprised of 76% Gas, 24% NGLs. MY 2017 PDP reserves are comprised of 76% Gas, 24% NGLs, 0.3% Oil. 1P and 2P reserves are comprised of 76% Gas, 24% NGLs. Oct. 2017 PDP reserves are comprised of 78% Gas, 22% NGLs, 0.2% Oil. 1P and 2P reserves are comprised of 77% Gas, 23% NGLs.

3. YE 2015 Sproule Reserves Evaluation dated effective December 31, 2015 and based on Sproule Pricing as of December 31, 2015.YE 2016 Sproule Reserves Evaluation dated effective December 31, 2016 and based on Sproule Pricing as of December 31, 2016. MY 2017 Sproule Reserves Evaluation dated effective June 30, 2017 and based on Sproule Pricing as of May 31, 2017.Oct. 2017 Sproule Reserves Evaluation dated effective October 31, 2017 and based on Sproule Pricing as of September 30, 2017.

4. Oct. 2017 Development Capital of $131.4 MM (includes unaudited estimate for October 2017); MY 2017 Development Capital of $63.5 MM. Inception to Oct. 2017 (ITD) Development Capital of $483.2 MM or $610.3 MM including land and acquisition (includes unaudited estimate for October 2017). FD&A and F&D includes Full Development Capital (FDC).


Risk Management(1)(2)

1. See advisories on pages 32 and 33 hereof. 2. Summary of hedges and physical contracts by type. Does not detail each transaction.3. Includes a combination of full and partial years.

Weighted Average Price Total Volume Term(3)

Fina

ncia

l

NYMEX Swap C$3.372/GJ 90,000 GJd 2018

NYMEX / AECO Basis Swap -C$1.355/GJ 90,000 GJd 2018



AECO / Station 2 Basis Swap -C$0.429/GJ 90,000 GJd 2018

AECO / Station 2 Basis Swap -C$0.342/GJ 95,000 GJd 2019

WTI Swap C$66.77/Bbl 3,650 Bbld 2018

Phys

ical

Sumas / Station 2 Basis Swap -US$0.728/MMBtu 28,695 MMBtud 2018



Chicago -US$1.50/MMBtu 4,739 MMBtud 2018


0

250

500

750

1,000

1,250

1,500

1,750

0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 32 34 36 38 40

Prod

ucing Day Sales Produ

ction (Boed)

Normalized Months

Well Performance Update(1)(2)

1. See advisories on pages 32 and 33 hereof.2. See page 14 for single well economics.3. Pilot program included Lower, Middle and Upper targets.

Upper Montney Wells Middle Montney Wells Lower Montney Wells 8 Bcf Type Curve7 Bcf Type Curve6 Bcf Type CurveMiddle 78‐C Wells (2,500 m HZ)

Development Program2,000 – 2,500 m HZUpper & Middle Montney Wells

Pilot Program(3)

1,000 – 1,500 m HZ


Forward Looking Statements. Certain statements included in this investor presentation (the "Presentation") constitute forward looking statements or forward looking information under applicable securities legislation. Such forward looking statements or information are provided for the purpose of providing information about management's current expectations and plans relating to the future. Readers are cautioned that reliance on such information may not be appropriate for other purposes, such as making investment decisions. Forward looking statements or information typically contain statements with words such as "anticipate", "believe", "expect", "plan", "intend", "estimate", "propose", "project" or similar words suggesting future outcomes or statements regarding an outlook. Forward looking statements or information in this Presentation include, but are not limited to, statements or information with respect to: Saguaro Resources Ltd.'s ("Saguaro" or the "Corporation") business strategy and objectives; statements with respect to the performance characteristics of Saguaro’s oil and natural gas properties and wells; statements with respect to reserves growth; potential drilling locations; development plans including development in the upper and middle Montney targets, optimization plans, maintaining a strong balance sheet and effect on costs and production; exploration plans; expectations regarding target and peak production; the Corporation’s focus, including capital discipline, budgeted and forecasted drilling and completion costs per well, low risk development, maintaining a strong balance sheet and cost reductions; anticipated production including production mix; estimated recoverable resources; the Corporation's risk management strategy and the benefits derived therefrom; proposed drilling locations; potential short and long term options for development and expansion of infrastructure; anticipated well development program, including number of wells and anticipated timing of completions; development plans with respect to pipeline projects; benefits derived from Saguaro's infrastructure and expected timing of construction of infrastructure; expected timing of certain pipelines to be in service; the Corporation's expectations regarding receipt of future royalty credits; forecasted pricing; actual and estimated internal rates of return, which include assumptions respecting operating and other costs, pricing, well depths, royalty rates and taxes; and economic metrics of our full development plan, including capital, IRR, net present values, free cash flow, debt to EBITDA, PIR, production rates, and anticipated debt and private equity drawn. In addition, the statements contained herein relating to "reserves" and "resources" are by their nature forward looking statements, as they involve the implied assessment, based on certain estimates and assumptions that the reserves or resources described can be can be profitably produced in the future.

Type Well Production and Economics. This Presentation contains references to type well, or “type curve”, production and economics, which are derived, at least in part, from available information respecting the well economics of other companies and, as such, there is no guarantee that Saguaro will achieve the stated or similar results, capital costs and return costs per well. Any references to peak rates, test rates, IP30 or initial production rates or declines are useful for confirming the presence of hydrocarbons, however, such rates and declines are not determinative of the rates at which such wells will commence production and decline thereafter and are not indicative of long term performance or ultimate recovery. In addition, such rates or declines may also include recovered fluids used in well completion stimulation. Readers are cautioned not to place reliance on such rates in calculating aggregate production for the Corporation.

Assumptions. Forward looking statements or information are based on a number of factors and assumptions which have been used to develop such statements and information but which may prove to be incorrect. Although the Corporation believes that the expectations reflected in such forward looking statements or information are reasonable, undue reliance should not be placed on forward looking statements because the Corporation can give no assurance that such expectations will prove to be correct. In addition to other factors and assumptions which may be identified in this Presentation, assumptions have been made regarding, among other things: commodity prices; the accuracy of geological and geophysical data and its interpretations of that data; estimated decline rates; the impact of increasing competition; the general stability of the economic and political environment in which the Corporation operates; the timely receipt of any required regulatory approvals; the ability of the Corporation to obtain qualified staff, equipment and services in a timely and cost efficient manner; the ability of the Corporation to operate in a safe, efficient and effective manner; the ability of the Corporation to obtain financing on acceptable terms; that the Corporation will have sufficient cash flow, debt or equity or other financial resources to fund its capital and operating expenditures as needed; field production rates and decline rates; the ability to replace and expand oil and natural gas reserves through acquisition, development or exploration; the timing and costs of pipeline, storage and facility construction and expansion and the ability of the Corporation to secure adequate product transportation; availability of pipelines; future oil and natural gas prices; currency, exchange and interest rates; the regulatory framework regarding royalties, taxes and environmental matters in the jurisdictions in which the Corporation operates; that the estimates of the Corporation’s reserve volumes and assumptions related thereto are accurate in all material respects; and the ability of the Corporation to successfully market its oil and natural gas products. Readers are cautioned that the foregoing list is not exhaustive of all factors and assumptions which have been used.

Risks and Uncertainties. Forward looking statements or information are based on current expectations, estimates and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by the Corporation and described in the forward looking statements or information. These risks and uncertainties which may cause actual results to differ materially from the forward looking statements or information include, among other things: the ability of management to execute its business plan; general economic and business conditions; the risk of instability affecting the jurisdictions in which the Corporation operates; the risks of the oil and natural gas industry, such as operational risks in exploring for, developing and producing crude oil and natural gas and market demand; the possibility that government policies or laws may change or governmental approvals may be delayed or withheld; risks and uncertainties involving geology of oil and natural gas deposits; the uncertainty of reserves estimates and reserves life; the ability of the Corporation to add production and reserves through acquisition, development and exploration activities; the Corporation's ability to enter into or renew leases; potential delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of estimates and projections relating to production (including decline rates), costs and expenses; fluctuations in oil and natural gas prices, foreign currency exchange rates and interest rates; risks inherent in the Corporation's marketing operations, including credit risk; uncertainty in amounts and timing of royalty payments; health, safety and environmental risks; risks associated with potential future lawsuits and regulatory actions against the Corporation; uncertainties as to the availability and cost of financing; changes in income tax rates; changes in incentive programs related to the oil and gas industry; failure of investors to fund capital calls; availability of pipelines; that legal actions may have an adverse effect on Saguaro’s financial position or operations; and financial risks affecting the value of the Corporation’s investments. Readers are cautioned that the foregoing list is not exhaustive of all possible risks and uncertainties.

No Obligation to Update. The forward looking statements or information contained in this Presentation are made as of the date hereof and the Corporation undertakes no obligation to update publicly or revise any forward looking statements or information, whether as a result of new information, future events or otherwise unless required by applicable securities laws. The forward looking statements or information contained in this Presentation are expressly qualified by this cautionary statement.

Future Oriented Financial Information. This Presentation, in particular the information contained in the slides entitled, “Drilling: Efficiencies Offset Cost of Longer Laterals”, “Completions: Evolving Design Enhances Recoveries and Reduces Costs”, “Strong and Improving Single Well Economics at Flat Prices” and “Growth Funded Without Equity at Reasonable Debt Metrics” contains Future Oriented Financial Information ("FOFI") within the meaning of applicable securities laws. The FOFI has been prepared by Saguaro’s management to provide an outlook of the Corporation's activities and results. The FOFI has been prepared based on a number of assumptions including the assumptions discussed under the heading "Forward Looking Statements" and assumptions with respect to the costs and expenditures to be incurred by the Corporation, capital equipment and operating costs, foreign exchange rates, taxation rates for the Corporation, general and administrative expenses and the prices to be paid for the Corporation's production. Management does not have firm commitments for all of the costs, expenditures, prices or other financial assumptions used to prepare the FOFI or assurance that such operating results will be achieved and, accordingly, the complete financial effects of all of those costs, expenditures, prices and operating results are not objectively determinable. The actual results of operations of the Corporation and the resulting financial results will likely vary from the amounts set forth in the analysis presented in this Presentation, and such variation may be material. The Corporation and its management believe that the FOFI has been prepared on a reasonable basis, reflecting management’s best estimates and judgments. However, because this information is highly subjective and subject to numerous risks including the risks discussed under the heading "Forward Looking Statements", it should not be relied on as necessarily indicative of future results. Except as required by applicable securities laws, Saguaro undertakes no obligation to update such FOFI and forward looking statements and information.

Oil and Gas Advisories

Future Drilling Locations. Unless otherwise expressly stated, the information in this Presentation pertaining to future drilling locations or drilling inventories is based solely on internal estimates made by management and such locations have not been reflected in any independent reserve or resource evaluations prepared pursuant to National Instrument 51-101 ("NI 51-101"). Similarly, unless otherwise expressly stated, the information in this Presentation pertaining to targeted reserve volumes from future drilling is intended to indicate that in making its internal drilling decisions, the Corporation seeks to target drilling locations that, based on previous drilling results and its own internal assessments, it believes will on average ultimately generate the indicated volumes. This document discloses drilling locations which are unbooked locations and are internal estimates based on Saguaro's prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Unbooked locations do not have attributed reserves or resources and have been identified by management as an estimation of multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that Saguaro will drill all unbooked drilling locations and if drilled there is no certainty that such locations will result in additional oil and gas reserves, resources or production. The drilling locations on which we actually drill wells will ultimately depend upon the availability of capital, regulatory approvals, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. While certain of the unbooked drilling locations have been de-risked by drilling existing wells in relative close proximity to such unbooked drilling locations, 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 oil and gas reserves, resources or production.

Finding and Development Costs. The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year.

Advisories


Reserves and Resources. Some of the reserve estimates disclosed on pages 6, 9, and 29 were prepared by Sproule Associates Limited with an effective date of December 31, 2014, July 31, 2015, December 31, 2015, June 30, 2016, September 30, 2016, December 31, 2016, June 30, 2017 and/or October 31, 2017 in accordance with NI 51-101 and the Canadian Oil and Gas Evaluation Handbook ("COGE Handbook") and using Sproule’s forecast prices at December 31, 2014, July 31, 2015, December 31, 2015, June 30, 2016, July 31, 2016, December 31, 2016, May 31, 2017 and/or September 30, 2017 respectively. Other than some of the reserves estimates disclosed on pages 6, 9, and 29, the recovery and reserves estimates provided herein are Saguaro's internal estimates only and are not derived from an independent reserves evaluation prepared pursuant to NI 51-101. There is no guarantee that the reserves or resources will be recovered. As a consequence, actual results may differ materially from those anticipated in the forward looking statements. “EUR” is not indicative of reserves, nor is it a category of resources recognized by the COGE Handbook. Estimates of the net present value of the future net revenue from Saguaro’s reserves do not represent the fair market value of Saguaro’s reserves. Some of the resources estimates disclosed on page 6 were prepared by Sproule Associates Limited with an effective date of October 31, 2017 in accordance with NI 51-101 and the COGE Handbook and using Sproule's forecast prices at September 30, 2017. The resources volumes represent "best" case estimates. Best estimate, as described by the COGE Handbook, is considered to be the best estimate of the quantity that will actually be recovered. There is no certainty that any portion of the prospective resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion thereof. There is uncertainty that it will be commercially viable to produce any portion of the contingent resources. Reserves and resource estimates contained herein have been made assuming that funding is likely to be available to Saguaro for the development of the applicable property.

Definitions of Oil and Gas Resources and Reserves

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. Reserves are classified according to the degree of certainty associated with the estimates as follows:

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.

Resources encompasses 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 in the following categories:

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. 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.

Pay Thickness. Estimates of pay thickness are considered to be anticipated results or information that indicate the potential value or quantities of resources under NI 51-101. Such estimates have been prepared by management of Saguaro and have not been prepared or reviewed by an independent qualified reserves evaluator or auditor. The risks associated with estimates of pay thickness include, but are not limited to, the risk that Saguaro's exploration and development drilling and related activities may provide different results; the risk that Saguaro may encounter unexpected drilling results; the occurrence of unexpected events involved in the exploration for, and the operation and development of, oil and gas; delays in anticipated timing of drilling and completion of wells; geological, technical, drilling and processing problems and other difficulties in producing petroleum reserves.

Boe Presentation. All boe conversions in the report are derived by converting gas to oil at the ratio of six thousand cubic feet of natural gas to one barrel of oil equivalent. Boe may be misleading, particularly if used in isolation. A Boe conversion rate of 1 Boe: 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 of oil compared to natural gas, based on current prevailing prices, is significantly different than the energy equivalency ratio of 1 Boe: 6 Mcf, utilizing a conversion ratio may be misleading.

Definitions

Certain oil and gas metrics. Finding, development and acquisition costs, finding and development costs, and netbacks do not have standardized meanings or standard methods of calculation and therefore such measures may not be comparable to similar measures used by other companies and should not be used to make comparisons. Such metrics have been included in documents provided by Saguaro to shareholders to give readers additional measures to evaluate the Saguaro's performance; however, such measures are not reliable indicators of the future performance of the Saguaro and future performance may not compare to the performance in previous periods and therefore such metrics should not be unduly relied upon.

Net Present Value (NPV10): The anticipated net present value of the future net revenue (before tax) discounted at a rate of 10% associated with the type curves presented.

IRR: Rate of return. IRR is the discount rate required to arrive at a NPV equal to zero. Rates of return set forth in this presentation are for illustrative purposes. There is no guarantee that such rates of return will be achieved in the future.

Profit to Investment Ratio (PIR): The ratio of payoff to investment for the project. For example, a net PIR (PIR0 for undiscounted future cash flow and PIR10 for future cash flow discounted by 10%) of $1.50 represents for every $1.00 of investment, the project will return the invested $1.00 plus an additional $1.50 of profit for a total cash flow of $2.50. The net PIR of such a project would be $1.50 while the gross PIR would be $2.50.

Netback: Price less royalties, operating expenses and transportation costs.

EUR: Estimated Ultimate Recovery. An approximation of the quantity of oil or gas that is potentially recoverable or has already been recovered from a reserve or well.

Supply Cost: Price required to create an IRR (Before Tax) of 10% assuming the price is held flat over the life of the project (Natural Gas price at AECO, Condensate price at Edmonton).

Finding and Development Costs (F&D): The anticipated full exploration and development costs associated with each barrel of oil equivalent expected to be recovered from a well based on the type curves and economics presented.

Finding, Development and Acquisition Costs (FD&A): The anticipated full exploration, development and acquisition costs associated with each barrel of oil equivalent expected to be recovered from a well based on the type curves and economics presented.

IP30: The average production rate over a 30 day period.

Advisories (cont’d)

montney liquids-rich growth story - … presentation january 2018.pdf1,200+ drilling locations on...

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