Saguaro Resources Ltd. - RBC Capital Markets€¦ · horizontal wells; peak daily ... and...

Private and Confidential – January 2017 1

Saguaro Resources Ltd.Montney Liquids Rich Growth Story

Corporate Presentation

January 2017

Confidential


• Q4 2016 production averaged approximately 8,800 boed from 32 producing Montneyhorizontal wells; peak daily production in December 2016 exceeded 12,000 boed

• Reserves were evaluated by an Independent Qualified Reserves Evaluator; 2P reserves increased to 270 MMBoe at year end 2016 from 108 MMBoe at year end 2015(2)

• Well financed; $400 MM line of equity and $65 MM bank revolver(3)

1. See advisories on pages 23 to 25 hereof.2. Based on reports prepared by Sproule Associates Limited effective December 31, 2016 and December 31, 2015, respectively.3. See page 19 for additional information.

Saguaro Highlights(1)

• 100% working interest on 160 sections in the NE BC Montney• Derisked/tested 138 sections (86%) through drilling to date and competitor activity• Wells on most recent step‐out pad have produced highest Saguaro test rates to date

• 100% working interest plant capacities of 60 MMcfd compression/dehydration and 30 MMcfd amine sweetening with ability to expand to 1 Bcfd

• Procured equipment to expand compression/dehydration to 100 MMcfd• Licensed pipelines from our plant to Aitken Creek takeaway hub

• Liquids‐rich Montney wells have attractive economics at current strip pricing• 58 bbl/MMcf of liquids to date (72% condensate)• Over‐pressured Deep Basin trap; three stacked Montney zones; 1,200+ well inventory• Low capital cost due to shallow depth (1,400 to 1,900 m TVD)

Large contiguous land base

High caliber liquids rich resource

Expandable takeaway capacity

Well positioned for continued growth


2012‐2013Land Acquired 109 sectionsCapital Program

• 1 HZ Montney drill• 2 km of pipelines

Production 117 boed (annualized 2014)76 boed (exit 2014)

Total Spend(2) $117 MM

2014 2015 2016 (Estimate)Land Acquired 52 sections Land n/a Land n/aCapital Program

• 13 HZ Montney drill• 35 MMcfd facility• 41 km of pipelines

Capital Program

• 6 HZ Montney drills • 40 MMcfd facility

Capital Program

• 12 HZ Montney drills • 60 MMcfd facility• 6 km pipeline

Production 1,404 boed (annualized)2,243 boed (exit)

Production 4,240 boed (annualized)6,380 boed (exit)

Production ~7,060 boed (annualized)

~10,800 boed (exit)

Total Spend(2) $187 MM Total Spend(2) $83 MM Total Spend(2) ~$90 MM

Saguaro Evolution

• Since the inception of Saguaro Resources(1), capital has been spent on various value‐adding activities:

Montney Fairway

BC AB

Saguaro

Land acquired in 2012Land acquired in 2013Land acquired in 2014Open Crown (Montney rights)

Land acquired in 2012Land acquired in 2013Land acquired in 2014Open Crown (Montney rights)

Land acquired in 2012Land acquired in 2013Open Crown (Montney rights)

Saguaro 2016 Land positionOpen Crown (Montney rights)

5 miles

1. Saguaro’s first capital raise occurred in November 2012 and our initial private equity financing closed in July 2013.2. The total annual spend includes land, development and corporate capital.


Potential Captured to Date - Montney(1)(2)

• Internal estimate of resource size on 160 sections of a liquids rich Montney natural gas play with stacked potential:

1. See advisories on pages 23 to 25 hereof.2. Saguaro’s internal estimates of resource are supported by Sproule’s contingent resource evaluation dated July 31, 2015.

3,500 MMBoe in Place(21 Tcf Gas in Place)

1,100‐1,700 MMBoeRecoverable

Estimated 26% Liquids

Liquids RecoveriesTo Date

bbl/MMcf (Sales)

Propane 7Butane 9Condensate (includes Free)

42

Total 5819 miles

Saguaro


• Geology:▫ Average 260 m of gross pay across

three stacked porous zones ▫ Over‐pressured; 11‐15 kPa/m ▫ Shallower depth of ~1,400‐1,900 m

2016 drilling costs ranged from $1.7 MM to $2.4 MM (excluding pilot well)

Excludes ~$1.0 MM deep well royalty credit

• Activity to date (100% WI):▫ Drilled 32 wells

Drilling program recommenced in December 2016 on an existing pad

▫ Expanding 60 MMcfd gas facility to 100 MMcfd in Q1/Q2 2017

▫ Installed three stages of 12” backbone gathering system

Laprise Montney and Saguaro Activity(1)

1. See advisories on pages 23 to 25 hereof.

SaguaroOpen Crown (Montney rights)Montney PenetrationsSaguaro 12” Gathering LinesSaguaro Proposed Future Egress

c‐81‐G5 HZ wells

b‐34‐H11 HZ wells

a‐14‐I3 HZ wells

5 miles

c‐76‐D8 HZ wells

b‐24‐HFacility c‐78‐C

5 HZ wells


c‐81‐G Saguaro b‐34‐H Saguaro c‐76‐D Saguaro c‐78‐C Saguaro

Core

x5wells

d‐49‐D BS(3)

Core

Core

Core

x5wells

x1well

x1well

x3wells

x4wells

x3wells

x1well

x3wells

x1well

x1 well

x1 well

x1 well

x2wells Upper Hz

Lower Hz

Middle Hz

> 175 m Net POR263 m Gross



Logs truncated; vertical well not drilled



TR_MONT

TR_M_MONT

TR_L_MONT

a‐14‐I Saguaro

Stacked Pay Zones(1)(2)

1. See advisories on pages 23 to 25 hereof.2. Porosity from Nutech Petrophysical analysis. 3% porosity cut off.3. d‐49‐D offset is a Black Swan well approximately 3 km from Saguaro’s c‐76‐D pad.


0

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0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30

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ucing Da

y Sales P

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d)

Calendar Months

6 Bcf Type Curve (2,000 m HZ) 8 Bcf Type Curve (2,000 m HZ) Development Program (15 wells; 2,000 m HZ)

Development Well Performance Update(1)(2)

1. See advisories on pages 23 to 25 hereof.2. See page 9 for the 2,000 m Type Curve Economic Metrics.


• Realized cost savings and optimization of technical design

▫ Increased HZ length from pilot program to 2,000 m development program

▫ Continuously refining completions program

▫ Drilling costs shown do not include Deep Well Drilling Credit of ~$1.0 MM per well

Drilling and Completion Costs(1)


$3.4 $3.0

$2.1 $2.3

$3.8

$3.0

$2.6 $2.5

$0.0

$1.0

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Pre‐2015Pilot

Program

2015DevelopmentProgram

2016DevelopmentProgram(Forecast)

2017Budget

Average Drilling and Co

mpletion Co

st per W

ell ($M

M)

Drilling Completions


2,000 m Type Curve Economic Metrics(1)

Type Curve Comparison 6 Bcf Type Curve

8 BcfType Curve

DC&E Capital(2) ($MM) $5.25 $5.25

IRR(3)(4)(% BTax) 46% 98%

Net PIR0(3) 2.21 3.60

Net PIR10(3) 0.92 1.71

NPV0 ($MM) $11.6 $18.9

NPV10 ($MM) $4.8 $8.9

Supply Cost(3) ‐ Gas ($/MMBtu)

Supply Cost(3) ‐ Condensate ($/bbl)$1.52$38.47

$0.87$24.64

Total Peak (Sales MMcfd / Mboed incl. liquids) 5.6 / 1.3 8.2 / 1.9

IP30 (Raw MMcfd / Sales Mboed) 5.1 / 1.0 7.5 / 1.5

EUR(3)(Raw Bcf / Sales MMboe) 6.3 / 1.2 8.3 / 1.6

• Development plan is modelled using a 2,000 m HZ well and 6 Bcf type curve

• Will continue to use advancing completions technologies in an effort to enhance recoveries

1. See advisories on pages 23 to 25 hereof. Assumes 2,000 m horizontal wells and a heat value of 1,150 btu/scf. Assumes drilling in Q1 2017 with an associated onstream in Q2 2017. Pricing assumes strip pricing estimate from Peters & Co Energy Update as at January 3, 2017. AECO $ per MMBtu of $3.45 (2017); $2.99 (2018); $2.80 (2019+). Canadian Par $ per bbl of $72.99 (2017); $72.78 (2018); $71.04 (2019+).

2. Includes capital for drilling, completions and equipping. Capital is not adjusted for deep well royalty credit.3. Refer to definitions on page 25 hereof. 4. IRR does not include G&A, land costs and undeveloped land value.


0%

20%

40%

60%

80%

100%

120%

140%

160%

‐10%Base price

Base priceAECO $3.45 per mcfC5 $76.08 per bbl

(2017)

+10%Base price

IRR %

2,000 m Single Well Sensitivities(1)(2)

1. See advisories on pages 23 to 25 hereof.2. Half‐cycle single well economic sensitivity is based on the assumption of drilling in Q1 2017 and the associated well being onstream in Q2 2017.3. Pricing assumes strip pricing estimate from Peters & Co Energy Update as at January 3, 2017. AECO $ per MMBtu of $3.45 (2017); $2.99 (2018); $2.80 (2019+). Canadian Par $ per bbl of

$72.99 (2017); $72.78 (2018); $71.04 (2019+).

• IRR impact of type curve and pricing assumptions

• Type curves are based on the following criteria:▫ Drill, complete and equip capital of $5.25 MM 2016 Forecasted DCE cost of $5.0 MM

▫ Deep Well Drilling Credit of ~$1.0 MM per well

▫ Horizontal length of ~2,000 m(3)

8 Bcf Type Curve

6 Bcf Type Curve


De‐risked119 sections To Be

De‐risked22 sections

Drilled19 sections

Montney Delineation IRR at Strip(2) by Montney Target

De-risked Inventory with Strong Well Economics(1)

1. See advisories on pages 23 to 25 hereof.2. IRR is an estimate only and well results will vary. IRR is based on a 2,000 m horizontal well and strip pricing estimate Peters & Co Energy Update as at January 3, 2017. AECO $ per MMBtu

of $3.45 (2017); $2.99 (2018); $2.80 (2019+). Canadian Par $ per bbl of $72.99 (2017); $72.78 (2018); $71.04 (2019+).

5 miles

De‐riskedTo be De‐riskedKey HZ Wells

• 86% of land base de‐risked with 1,500+ locations

147223

13880

505

80

516

80

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600

700

800

>40% IRR 24%‐40%IRR

<24% IRR To BeTested

Drilling Locatio

ns

Upper TargetMiddle TargetLower Target


01,0002,0003,0004,0005,0006,0007,0008,0009,00010,000

2014Q2

2014Q3

2014Q4

2015Q1

2015Q2

2015Q3

2015Q4

2016Q1

2016Q2

2016Q3

2016Q4

Prod

uctio

n (boe

d)

Gas Oil Condensate Butane Propane

1. See advisories on pages 23 to 25 hereof.2. 2016 Q4 production is based on field estimates.

Production Update(1)

• Continued production growth▫ Q4 2016 production of approximately 8,800 boed

▫ December 2016 production exceeded 10,800 boed from 32 Montney wells

▫ Daily production for the last two weeks of December 2016 exceeded 12,000 boed

• Liquids yield has stabilized at attractive levels▫ Recoveries vary somewhat depending on third party processing facilities used

(2)

0102030405060708090100

2014Q2

2014Q3

2014Q4

2015Q1

2015Q2

2015Q3

2015Q4

2016Q1

2016Q2

2016Q3

2016Q4

NGLs (b

bl/M

Mcf Sales)

Free Condensate Entrained Condensate Butane Propane

(2)


Reserves Evaluation Summary(1)

1. See advisories on pages 23 to 25 hereof.2. Saguaro has 1P Total Gross Reserves of 83,541 Mboe and 2P Total Gross Reserves of 270,294 Mboe as of December 31, 2016. 3. Based on 2016 Sproule Reserves Evaluations dated effective December 31, 2016 and December 31, 2015, respectively and based on Sproule Pricing as of December 31, 2016 and December 31,

2015, respectively.4. PDP reserves are comprised of 75% Gas, 24% NGLs, 1% Oil. 1P and 2P reserves are comprised of 76% Gas, 24% NGLs.5. 1P includes 22 MBoe of net Proved Developed Non‐Producing (PDNP) reserves.6. 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 December 31,

2016 for Dec‐2016; July 31, 2016 for Sep‐2016; June 30, 2016 for Jul‐16; December 31, 2015 for Dec‐15; July 31, 2015 for Jul‐15; December 31, 2014 for Dec‐14; and August 31, 2014 for Aug‐14.

Reserves EvaluationNet(2), NBR

Year End 2016(3)

Total(4) NPV 10%Before Taxes

MontneyLocations

Mboe $000

Proved Developed Producing (PDP) 15,822 $190,592 32

Total Proved(5) (1P) 83,535 $604,005 134

Total Proved + Probable (2P) 270,286 $1,845,605 330

• Reserves evaluated by an Independent Qualified Reserves Evaluator▫ Total Proved + Probable (2P) reserves increased by 150% since year end 2015

270.3 MMBoe at year end 2016 compared to 108.0 MMBoe at year end 2015(3)

▫ NPV 10% value of Proved reserves (1P) increased by 140% since year end 2015 $604 MM at year end 2016 compared to $252 MM at year end 2015(3)

Remaining

Recoverable Reserves (MMbo

e)(6)

0

50

100

150

200

250

300PDPPDNP + PUDTotal Probable


Land Base Provides Large Future Reserves Potential(1)(2)

UpperTarget

MiddleTarget

LowerTarget

1. See advisories on pages 23 to 25 hereof. Illustration based on Sproule’s reserves evaluation dated December 31, 2016.

ProvedProbable

• 2P Reserves represent ~19% of Saguaro’s estimated well inventory


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2013 2015 2017 2019 2021 2023 2025 2027

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alize

d Prod

uctio

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Mcfed

)

Annu

alize

d Prod

uctio

n (boe

d)

Gas NGLs

Full Development Plan – Activity & Production(1)(2)

1. See advisories on pages 23 to 25 hereof.2. ~1,200 well development program which develops ~60% of Saguaro’s existing land base and assumes $7,700 MM of capital and does not include land. This Full Development Plan (FDP) is

based on 2016 results and will continue to be updated throughout the delineation phase.

• The Full Development Plan (FDP) is based on approximately 1,200 horizontal wells (2,000 m) and the 6 Bcf type curve▫ FDP will continue to be updated throughout the delineation phase

Production is held flat at ~650 MMcfd(>140,000 boed) for 10 years

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Rigs (at Y

ear E

nd)

Horizon

tal D

rills pe

r Year

Drills Rigs


Full Development Plan – Capital & Metrics(1)(2)(3)

1. See advisories on pages 23 to 25 hereof.2. FDP is based on an ~1,200 well development program which develops ~60% of Saguaro’s existing land base. Assumes 2,000 m 6 Bcf type curve. FDP is based on 2016 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. Pricing assumes strip pricing estimate from Peters & Co Energy Update as at January 3, 2017. AECO $ per MMBtu of $3.45 (2017); $2.99 (2018); $2.80 (2019+). Canadian Par $ per bbl of $72.99

(2017); $72.78 (2018); $71.04 (2019+). 4. Economics metrics for 6 Bcf well are based on half‐cycle single well economics. Economic metrics for FDP are project economics. 5. FDP includes all capital (inclusive from 2013; undiscounted) excluding land. Economic metrics are based on go forward assumptions.6. IRR does not include G&A, land costs and undeveloped land value. 7. Refer to definitions on page 25 hereof.

Economic Metrics(4) 6 Bcf2,000 m HZ

FDP with 6 BcfType Curve

Capital – PV0(5)($MM) $5.25 $7,700

IRR(6)(7)(% BTax) 46% 24%

Net PIR0(7) 2.21 1.77

Net PIR10(7) 0.92 0.46

NPV0 ($MM) $11.6 $13,000

NPV10 ($MM) $4.8 $1,500

Total Peak (Sales MMcfd)(boed incl. liquids)

5.61.3

~650>140,000 $‐

$200

$400

$600

$800

$1,000

2013 2015 2017 2019 2021 2023 2025 2027

$MM

Development Year

Development CapitalCorporate Cash FlowDebt DrawnPrivate Equity Drawn


• Currently connected to three third party processing facilities▫ Contracted firm service of 40 MMcfd

▫ Significant interruptible service is also available

• Long term opportunities:▫ Evaluating the construction of our own full processing facility

▫ Shovel‐ready egress to hub▫ Investigating or participating in various third party infrastructure initiatives

Infrastructure Options(1)

Saguaro

Aitken Creek Takeaway Hub

Saguaro Proposed Sales Pipelines


19 miles


Process Current Capacity

TotalProcured(2)

Inlet (Upgraded) 80 MMcfd 100 MMcfd

Compression(3) 60 MMcfd 100 MMcfd

Dehydration(3) 60 MMcfd 100 MMcfd

Amine Sweetening 30 MMcfd 30 MMcfd

Saguaro b-24-H Facility(1)

• Modular expansions as required

• Full site expandable to 1 Bcfd

1. See advisories on pages 23 to 25 hereof.2. Total Procured includes current capacity plus procured equipment expected to be installed in 2017 and future years.3. Compression and dehydration will be expanded to 100 MMcfd in approximately Q1/Q2 2017.

Process Current Capacity

Total Procured(2)

Condensate Storage 7,000 bbl 7,000 bbl

Water Storage 3,000 bbl 3,000 bbl

Condensate Stabilization 3,000 bbld 3,000 bbld


Capitalization

1. Assumes full draw on Line of Equity and all future subscription warrants are exercised.

• $400 MM private equity line▫ $2.20 per share; drawn as required▫ $382.1 MM drawn to date

• $65 MM syndicated bank revolver▫ Next expansion in February 2017 based on 2016 year end reserve report

Millions Capacity Outstanding Remaining

Equity Summary:

Line of Equity $400.0 $382.1 $17.9

Subscription Warrants(1) $24.7 $21.2 $3.5

Private Placement $20.8 $20.8

Total Equity $445.5 $424.1 $21.4

Total Shares 204.1 194.4 9.7

Syndicated Credit Facility $65.0 Revolving


• Continued commodity price volatility impacts our field netback; hedges are in place to protect cash flow▫ Will continue to focus on capital discipline, capital efficiency improvements and operating cost reductions to offset decreased revenue

2016 Revenue and Netback(1)

1. See advisories on pages 23 to 25 hereof.2. Field Netback is calculated as the difference between the revenue per boe and related costs (royalties, operating costs and transportation). Excludes unutilized Take or Pay commitments.

Q3 2016 Netback(2)Q3 2016 Revenue

48%Oil + Liquids

Gas Oil Condensate Propane & Butane

41% 52%

5%

2%

$0.00

$2.50

$5.00

$7.50

$10.00

$12.50

$15.00

$17.50

$20.00

Revenue Costs

$ pe

r boe

Gas OilCondensate Propane & ButaneRoyalties Operating CostsTransportation Realized Hedging Losses

Field Netback$8.41 per boe


• Saguaro highlights include:▫ 32 producing Montney wells(2) on five different pads▫ 138 of 160 sections (86%) have been de‐risked/tested through Saguaro drilling and competitor activity

▫ Most recent delineation well produced highest Saguaro test rate to date

▫ Continually seeking to improve ultimate resource recovery through the application of advancing technologies

• Saguaro will continue to be focused on capital discipline, operating cost reductions and maintaining a strong balance sheet▫ Will remain prudent and flexible with capital expenditures▫ Activity focused on low risk development▫ Our liquids‐rich natural gas Montney wells have attractive economics at current strip pricing

Summary (1)

1. See advisories on pages 23 to 25 hereof.2. 32 wells drilled inception to date. Drilling program recommenced in late December 2016.

Liquids Rich• Unique reservoir with

high free condensate• Attractive economics

at current pricing

Low Cost• Lower cost due to

shallow drilling depth• Approximately 1,400

– 1,900 m TVD

Resource Size• 160 sections • 86% de‐risked• Represents ~1,500

de‐risked locations


Corporate InformationOfficersStacy Knull President & Chief Executive OfficerScott Carrothers Vice President Finance & Chief Financial Officer Tannis Gibson Vice President Geology & GeophysicsJason Hager Vice President Drilling & ConstructionJohn Christoffersen Vice President Operations & FacilitiesDarcy McLaughlin Vice President EngineeringEsther Troyan Vice President Land & Business Development

DirectorsMichael Graham ChairmanJames C. (Pep) Lough Independent BusinessmanM. Scott Bratt Independent BusinessmanRobert Chaisson Independent BusinessmanStacy Knull President & Chief Executive OfficerRichard Aube Pine Brook Road Partners LLCAndre Burba Pine Brook Road Partners LLCEdward Donkor Pine Brook Road Partners LLCTed Maa Pine Brook Road Partners LLCCameron McVeigh Camcor Partners Inc.

BankersCanadian Imperial Bank of Commerce595 Bay St., 5th FloorToronto, ON M5G 2C2

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

Alberta Treasury Branch239 ‐ 8th Ave SWCalgary, AB T2P 1B9

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

For more information, please contactStacy KnullPresident & Chief Executive OfficerPhone: (403) 453‐2680Email: [email protected]

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

Head Office440, 222 – 3rd Ave SWCalgary, AB T2P 0B4Phone: (403) 453‐3040Fax: (403) 452‐5129Website: www.saguaroresources.com

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

Independent Qualified Reserves EvaluatorSproule Associates LimitedSuite 900, 140 – 4th Ave SWCalgary, AB T2P 3N3

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


Forward Looking Statements. Certain statements included in this investor presentation (the "Presentation") constitute forward looking statements or forward looking information under applicablesecurities 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 containstatements 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; potential drilling locations; development plansincluding pilot, demonstration and development, optimization plans, maintaining a strong balance sheet and effect on costs and production; exploration plans; the Corporation’s focus for 2016,including capital discipline, capital expenditures, budgeted drilling and completion costs per well, low risk development, maintaining a strong balance sheet and cost reductions; anticipated productionincluding production mix; estimated recoverable resources; proposed drilling locations; potential short and long term options for development and expansion of infrastructure; potential capitalexpenditures; anticipated well development program, including number of wells and anticipated timing of completions; plans to investigate or participate in various pipeline projects; the Corporation’splan to continue to evaluate construction of own processing facility and sales pipelines; forecasted pricing; actual and estimated internal rates of return, which include assumptions respectingoperating and other costs, pricing, well depths, royalty rates and taxes; forecasted processing recoveries; our 2016 budgeted activities; and economic metrics of our full development plan, includingcapital, IRR, net present values, EUR, netbacks, production rates, and anticipated debt and private equity drawn. In addition, the statements contained herein relating to "reserves" and "resources" areby 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 profitablyproduced 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 informationrespecting 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 topeak 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 whichsuch 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 fluidsused 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 proveto 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 forwardlooking 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 thisPresentation, assumptions have been made regarding, among other things: commodity prices; the accuracy of geological and geophysical data and its interpretations of that data; estimated declinerates; 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 operatingexpenditures 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 ofpipeline, 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 theCorporation’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. Readersare 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 causeactual 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 actualresults 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 businessconditions; 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 andproducing 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 uncertaintiesinvolving 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, developmentand 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; theuncertainty 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 interestrates; 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 associatedwith 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 programsrelated 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; andfinancial 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 updatepublicly 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 lookingstatements or information contained in this Presentation are expressly qualified by this cautionary statement.

Disclaimer


Future Oriented Financial Information. This Presentation, in particular the information contained in the slides entitled, “Drilling and Completion Costs”, “2,000 m Type Curve Economic Metrics” and“Full Development Plan – Capital & Metrics” contains Future Oriented Financial Information ("FOFI") within the meaning of applicable securities laws. The FOFI has been prepared by Saguaro’smanagement 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, taxationrates 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 thosecosts, 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 theamounts 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 reasonablebasis, 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 suchFOFI and forward looking statements and information.Oil and Gas AdvisoriesFuture 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 madeby 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, unlessotherwise 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, theCorporation 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. Thisdocument 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 drilledper 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‐yeardrilling 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 ifdrilled 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 uponthe 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 unbookeddrilling locations have been derisked by drilling existing wells in relative close proximity to such unbooked drilling locations, other unbooked drilling locations are farther away from existing wellswhere 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 moreuncertainty 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 developmentcosts generally will not reflect total finding and development costs related to reserves additions for that year.Reserves and Resources. Other than the reserves estimates disclosed on pages 2, 13, 14 and 28, the recovery, reserves and resources estimates provided herein are internal estimates only. Thereserve estimates disclosed on pages 2, 13, 14 and 28 were prepared by Sproule Associates Limited with an effective date of December 31, 2013, August 31, 2014, December 31, 2014, July 31, 2015,December 31, 2015, June 30, 2016, September 30, 2016 and/or December 31, 2016 in accordance with NI 51‐101 and the Canadian Oil and Gas Evaluation Handbook and using Sproule’s forecast pricesat December 31, 2013, August 31, 2014, December 31, 2014, July 31, 2015, December 31, 2015, June 30, 2016, July 31, 2016, and/or December 31, 2016 respectively. There is no guarantee that theestimated reserves or resources will be recovered. As a consequence, actual results may differ materially from those anticipated in the forward looking statements. "Gas in Place", “MMBoe in Place",“MMBoe Recoverable“, “Tcf Gas in Place” and “EUR” are not indicative of reserves, nor are they categories of resources recognized by the Canadian Oil and Gas Handbook. These volumes are basedupon Saguaro’s internal estimates only and are not derived from an independent resources evaluation prepared pursuant to NI 51‐101. There may be more specific sub‐categories of resourcesapplicable to these estimates that would provide a more accurate description of the resources and the work programs, technology and capital required to exploit such resources, but these have notbeen prepared by the Corporation. In addition, these volumes represent “best” case estimates, however “low” and “high” case estimates have not been prepared by the Corporation. There is nocertainty that any portion of the noted volumes or resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion thereof. Estimates ofthe net present value of the future net revenue from Saguaro’s reserves do not represent the fair market value of Saguaro’s reserves. Reserves and resource estimates contained herein have beenmade assuming that funding is likely to be available to Saguaro for the development of the applicable property.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 beenprepared 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 valueequivalency 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.

Disclaimer


DEFINITIONSCertain oil and gas metrics. Finding, development and acquisition costs, finding and development costs, reserves replacement and netbacks do not have standardized meanings or standard methodsof 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 indocuments 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 futureperformance 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 ofreturn 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 $1.50while 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: Natural gas price required to create an IRR (Before Tax) of 10% assuming the price is held flat over the life of the project.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 typecurves 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 froma well based on the type curves and economics presented.Reserves Replacement: The estimated amount of proved reserves added to the reserves base during the year relative to the amount of oil and gas produced.IP30: The average production rate over a 30 day period.

Disclaimer


Supplemental Information: Risk Management(1)

Hedge Type(2) Term(3) Weighted Average Price Total Volume

AECO Swap 2017 $2.958 CAD/GJ 40,000 GJ/d

AECO/Station 2 Basis Swap 2017 ‐$0.392 CAD/GJ 25,000 GJ/d

AECO/Station 2 Basis Swap 2018 ‐$0.443 CAD/GJ 15,000 GJ/d

WTI Collar 2017 $54.75 CAD/Bbl put $67.85 CAD/Bbl call 1,000 Bbl/d

WTI Collar 2017 $58.00 CAD/Bbl put $74.00 CAD/Bbl call 400 Bbl/d

WTI Swap 2018 $73.91 CAD/Bbl 750 Bbl/d

1. See advisories on pages 23 to 25 hereof. 2. Summary of hedges and physical contracts by type. Does not detail each transaction.3. Term can include full and partial years.

Physical Sales Contract(2) Term(3) Weighted Average Price Total Volume

Sumas/Station 2 Basis Swap 2017 ‐$0.759 USD/MMBtu 13,192 GJ/d



• Hedges and physical sales basis contracts have mitigated exposure to Station 2 prices

2017E Price Exposure:

AECOHedged22% Station 2

Hedged36%

Station 223%

Sumas19%

• Only 23% of 2017E production is exposed to Station 2 spot pricing


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

Prod

ucing Da

y Sales P

rodu

ction (boe

d)

Normalized Months

Upper Montney Wells Middle Montney Wells Lower Montney Wells

6 Bcf Type Curve (2,000 m HZ) 8 Bcf Type Curve (2,000 m HZ)

1. See advisories on pages 23 to 25 hereof.2. See page 9 for the 2,000 m Type Curve Economic Metrics.3. Pilot program included Lower, Middle and Upper Montney wells.

Pilot Program(3): Horizontal length of 1,000 – 1,500 m

Development Program:Upper & Middle Montney wells with horizontal length of 2,000 m

Well Performance Update(1)(2)


Supplemental Information: Reserves(1)

1. Based on reports prepared by Sproule Associates Limited effective December 31, 2015, September 30, 2016 and December 31, 2016. See advisories on pages 23 to 25 hereof.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.

Sept‐2016 PDP reserves are comprised of 74% Gas, 25% NGLs, 1% Oil. 1P and 2P reserves are comprised of 74% Gas, 26% 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.

3. YE 2015 Sproule Reserves Evaluation dated effective December 31, 2015 and based on Sproule Pricing as of December 31, 2015.Sept. 2016 Sproule Reserves Evaluation dated effective September 30, 2016 and based on Sproule Pricing as of July 31, 2016.YE2016 Sproule Reserves Evaluation dated effective December 31, 2016 and based on Sproule Pricing as of December 31, 2016.

4. YE 2016 Est. Development Capital of $88 MM. Inception to December‐2016 (ITD) Development Capital of $349 MM or $474 MM including land and acquisition. FD&A and F&D includes Full Development Capital (FDC).

Reserves Evaluation(Net)

CompanyShare(2)(3)

NPV10 per BoeBefore Taxes

Full DevelopmentCapital (FDC)

Finding, & Development

Costs (F&D)(4)

Finding, Development & Acquisition

Costs (FD&A)(4)Locations

MBoe $ per boe $MM $ per boe $ per boe

YE2015

Sept.2016

YE2016

YE2015

Sept.2016

YE2016

YE2015

Sept.2016

YE2016

YE2016Est.

ITDYE

2016Est.

ITD YE2015

Sept.2016

YE2016

Proved Developed Producing

9,181 13,240 15,822 $11.05 $11.94 $12.05 $0 $0 $0 $9.54 $17.45 $9.54 $23.53 19 27 32

Total Proved (1P)

31,781 74,507 83,535 $7.94 $7.51 $7.23 $177 $449 $511 $7.75 $9.80 $7.75 $11.21 52 118 134

Total Proved + Probable (2P)

107,995 235,142 270,286 $7.64 $7.19 $6.83 $631 $1,357 $1,543 $6.07 $6.90 $6.07 $7.35 118 278 330

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