zargon corporate presentation (august 9 2017) (rev...
TRANSCRIPT
zargon.ca
Corporate PresentationAugust 9, 2017
Forward Looking-Advisory
Forward-Looking Statements - This presentation offers our assessment of Zargon's future plans and operations as at August 4, 2017, and contains forward-looking statements. Such statements are generally identified by the use of words such as "anticipate", "continue", "estimate", "expect", "forecast", "may", "will", "project", "should", "plan", "intend", "believe" and similar expressions (including the negatives thereof). In particular, this presentation contains forward-looking information as to Zargon’s corporate strategy and business plans, Zargon’s oil exploration project inventory and development plans, Zargon’s dividend policy and the amount of future dividends, future commodity prices, Zargon’s expectation for uses of funds from financing, Zargon’s capital expenditure program and the allocation and the sources of funding thereof, Zargon’s cash flow and dividend model and the assumptions contained therein and the results there from, anticipated payout rates, 2017 and beyond production and other guidance and the assumptions contained therein, estimated tax pools, Zargon’s reserve estimates, Zargon’s hedging policies, Zargon’s drilling, development and exploitation plans and projects and the results there from and Zargon’s ASP project plans 2017 and beyond, strategic alternatives review process, the source of funding for our 2017 and beyond capital program including ASP, capital expenditures, costs and the results therefrom. By their nature, forward-looking statements are subject to numerous risks and uncertainties, some of which are beyond our control, including such as those relating to results of operations and financial condition, general economic conditions, industry conditions, changes in regulatory and taxation regimes, volatility of commodity prices, escalation of operating and capital costs, currency fluctuations, the availability of services, imprecision of reserve estimates, geological, technical, drilling and processing problems, environmental risks, weather, the lack of availability of qualified personnel or management, stock market volatility, the ability to access sufficient capital from internal and external sources and competition from other industry participants for, among other things, capital, services, acquisitions of reserves, undeveloped lands and skilled personnel. Risks are described in more detail in our Annual Information Form, which is available on our website. Forward-looking statements are provided to allow investors to have a greater understanding of our business.You are cautioned that the assumptions, including, among other things, future oil and natural gas prices; future capital expenditure levels; future production levels; future exchange rates; the cost of developing and expanding our assets; our ability to obtain equipment in a timely manner to carry out development activities; our ability to market our oil and natural gas successfully to current and new customers; the impact of increasing competition; our ability to obtain financing on acceptable terms; and our ability to add production and reserves through our development and acquisition activities used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be imprecise and, as such, undue reliance should not be placed on forward-looking statements. Our actual results, performance, or achievement could differ materially from those expressed in, or implied by, these forward-looking statements. We can give no assurance that any of the events anticipated will transpire or occur, or if any of them do, what benefits we will derive from them. The forward-looking information contained in this presentation is expressly qualified by this cautionary statement. Our policy for updating forward-looking statements is that Zargon disclaims, except as required by law, any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.Barrels of Oil Equivalent - Natural gas is converted to a barrel of oil equivalent (“Boe”) using six thousand cubic feet of gas to one barrel of oil. In certain circumstances, natural gas liquid volumes have been converted to a thousand cubic feet equivalent (“Mcfe”) on the basis of one barrel of natural gas liquids to six thousand cubic feet of gas. Boes and Mcfes may be misleading, particularly if used in isolation. A conversion ratio of one barrel to six thousand cubic feet of natural gas is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion ratio on a 6:1 basis may be misleading as an indication of value. The estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation. Estimated reserve values disclosed in this presentation do not represent fair market value. Discovered Petroleum Initially-In-Place (“DPIIP”) is that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior to production. The recoverable portion of discovered petroleum initially in place includes production, reserves, and contingent resources; the remainder is unrecoverable.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.
2
Zargon Statistical OverviewCapitalization(1) Asset Profile
Share Price (Aug. 4, 2017) $0.51 Last Quarter Production (Q2 2017) Gas (MMcf/d) Liquids (bbl/d) % Liquids Total (boe/d)% of
ProductionBasic Shares Outstanding 30.75 Market Capitalization $15.7 North Dakota 0.00 372 100% 372 15% Net Debt(2) $36.1 Alberta Plains 3.39 1,137 67% 1,703 68% Option Proceeds ‐ Little Bow ‐ ASP 0.08 412 97% 425 17%
Entity Value $51.8 Last Quarter Daily Production 3.47 1,921 77% 2,500 100%
52‐Week High $1.05 52‐Week Low $0.48
Net Debt Summary(2) Tax Pools ($mm)COGPE 0
Bank Debt $nil CDE 8Conv. Debs (Extended to Dec. 2019) $41.9 CEE 6Working Capital ($5.8) CCA 27Net Debt $36.1 Losses 148
Other 3Other Company Details Total 192
Employees 15 Office 5 Field
Head Office Calgary, Alberta, Canada Primary Exchange Listing TSE Reserve Evaluators McDaniel
Year End 2016 Reserves (McDaniel) Q2/2017 Prod.Oil
(mbbl)Gas
(mmcf)Total
(mBOE)PV10($mm) % Oil
Oil RLI(yrs)
Gas RLI(yrs)
PDP 6,284 4,753 7,076 84.3 89 9.0 3.8P+PDP 8,360 6,184 9,391 111.4 89 11.9 4.9
P+P 11,180 10,366 12,908 132.3 87 15.9 8.2
3
(1) All numbers in $millions except per share values
(2) Net debt calculated as convertible debentures plus net working capital as at June 30, 2017
0
500
1,000
1,500
2,000
2,500
Jan‐16 Apr‐16 Jul‐16 Oct‐16 Jan‐17 Apr‐17
Oil Prod
uctio
n (bbl/day)
Alberta (excluding ASP)
North Dakota
Little Bow ASP
Flat operated production, despite no wells drilled since 2015
Zargon Key Investment Highlights
4
Oil Exploitation Focus
• Zargon is an oil‐weighted company focused on the exploitation of mature oil properties.• Following 2012‐16 divestment programs, Zargon’s remaining operated oil reservoirs continue to be
characterized by significant oil‐in‐place, low recovery factors and low oil production declines.• Over its history, Zargon has raised $210 million of equity capital and paid out $367 million in dividends and
distributions.
Low Decline Oil Production• Zargon’s low corporate oil decline of less than 10% per year is enabled by reservoir pressure support from
natural aquifers, waterfloods and tertiary floods. Consequently, stable oil production can be delivered through relatively small capital programs focused on waterfloods, reactivations and facility modifications.
Oil Exploitation Opportunities
• Zargon’s properties provide waterflood optimization opportunities plus exploitation drilling opportunities that enable improved reservoir recovery factors in existing pools.
• The McDaniel reserve report books 12 P+P exploitation locations with average per well parameters of 63 Mbbl oil reserves, 47 bbl/d initial rate and $0.93 MM all‐in costs.
Control of Properties &Key Infrastructure
• Very high working interest and operatorship across core operating areas, batteries and facilities.• Majority of batteries and facilities have been upgraded in the last five years.• An actively managed abandonment and reclamation program.
Little Bow ASP Project• At higher oil prices, the existing ASP infrastructure can be utilized to resume AS injections in high‐graded
areas and for multiple other ASP phases and Polymer only projects seeking a 10 percent incremental oil recovery on over 80 million barrels of working interest oil‐in‐place.
Other Corporate Attributes
• Zargon holds ~$192 million of high quality tax pools (June 30, 2017), including $148 million of non‐capital losses.
• Zargon has retained a TSX listing, plus strong operating, accounting, land and finance capabilities, and can readily manage additional assets with minimal additional costs.
Zargon is a Canadian oil and gas producer that provides exceptional torque to higher oil prices, in addition to offering a variety of attractive oil exploitation opportunities including oil exploitation horizontal infill drills and a long term Southern Alberta tertiary recovery project.
Status
Pro Forma BalanceSheet
5
Zargon’s Convertible Debentures were successfully amended in Q1 2017:
Maturity date extended from June 30, 2017 to December 31, 2019
Interest rate increased to 8.0% per annum
Conversion price reduced to $1.25 per share
$15.6 million of debentures were redeemed at a cash cost of $14.8 million.
Q2 2017 Results
Zargon’s capital structure provides stakeholders significant time to realize Zargon’s substantial option value relating to higher oil prices.
Bank debt – $nil
Working Capital – Positive $5.8 million
Remaining Convertible Debentures – $41.9 million
Net Debt – $36.1 million
Q3‐Q4 2017 Hedges: 1,300 bbl/d @ $69.24 Cdn./bbl with WTI‐WCS diff at $19.50 Cdn./bbl
Debentures Amended
Balance Sheet
Zargon’s Q2 2017 results:
Q2 production volumes of 2,500 boe/d, matched 2,500 boe/d guidance
Q2 funds flow of $1.14 million ($0.04/share)
Q2 field cash flow of $3.18 million was comparable to Q1 field cash flow of $3.58 million
$2.13 million Q2 capital program focused on facilities, waterfloods and well reactivations
2017 Outlook
2017 Projections
6
Based on the $7.8 million 2017 capital budget, production volumes are projected to meet or exceed 2,500 boe/d throughout calendar 2017.
A similar capital budget delivering stable production in 2018 is postulated. Without hedges, Zargon’sprice sensitivity for every $5 US per barrel (WTI) increase in oil price is an annualized $4.4 million ($0.14 per share)
Working with an improved balance sheet, Zargon’s will continue to focus on cost control and low cost oil exploitation projects (property/well reactivations, recompletions, waterflood modifications) that efficiently add oil production and oil reserves.
Recognizing that Zargon’s assets are comparatively inexpensively priced and provide significant unrecognized oil price option value, Zargon will continue with its strategic alternatives process that may include a sale of all or part of the company, a financing, merger or other business combination.
2017 Next Steps
2017 Capital Budget
Zargon’s $7.8 million 2017 capital budget is now allocated to $2.0 million for Little Bow polymer chemical purchases, $1.5 million of non discretionary land retention costs and $4.3 million to property/well reactivations, recompletions, waterflood modifications.
First half expenditures of $4.6 million includes pre‐spends on waterflood modifications and the Travers plant. Second half expenditures projected to be $3.2 million.
Zargon’s 2017 site reclamation and abandonment budget remains at $1.5 million.
zargon.ca
Conventional Properties
Alberta Plains (excluding Little Bow ASP)
8
The Alberta Plains properties provide low decline oil volumes with the potential for further development
• Q2 2017 production of 1,703 boe/d
– 67% liquids‐weighted (16 – 32o API)
– ~98% operated
– No drilling in 2015‐16 due to capital allocation decisions; approximate 9% annual decline is offset by waterflood and reactivations expenditures
– Drilling programs could provide production growth
– Multiple exploitation and development opportunities have been identified throughout Zargon’s asset base including:
– 8 booked infill and exploitation drilling opportunities (McDaniel locations)
– Good 3D seismic coverage over key properties support an additional 8+ un‐booked locations
Q2 2017Production
% Liquids API OOIP
Recoveryto Date
Gross UndevelopedLocations
(boe/d) (%) ( ⁰ ) (MMbbl) (%) McDaniel Additional
Bellshill Lake 442 95% 27 16 32% 5 1+
Taber 456 92% 16‐24 27 15% 3 5+
Little Bow (Conventional) 313 65% 21 82 25% ‐ tbd
Alberta Other 492 21% 18‐32 n.a. n.a. ‐ 2+
Total 1,703 67% 16‐32 125+ 24% 8 8+
T 1 W4
T 10
T 20
T 30
T 40
R 10R 20
Bellshill Lake
Little Bow
Taber
Alberta Plains
9
Alberta Plains Properties Overview (Excluding Little Bow ASP)
Operating Summary – Q2/2017Production 1,137 bbl/d (1,703 boe/d)
2017 Q3‐Q4 op. cost forecast $3.05 million per quarter
Reserves:McDaniel has recognized 8 gross (8.0) P+PUD locations and there is the potential of a further additional 8+ locations
Liquids(Mbbl)
Total(Mboe)
PV 10%($MM)
PDP 2,889 3,541 47.6
TP 3,124 4,032 50.2
P+PDP 3,713 4,563 59.0
P+P * 4,453 5,850 70.2
McDaniel Reserve Summary (December 2016)
* Includes new wells, tie‐ins and reactivations
0
1,000
2,000
3,000
4,000
5,000
Q1
Q2
Q3
Q4
Q1
Q2
Q3
Q4
Q1
Q2
Q3-
Q4
2015 2016 2017 Forecast
Qua
rter
ly E
xpen
se ($
M)
Alberta Operating Cost Trend (excluding ASP)
Major R&M Base Opex Total Opex
0
250
500
750
1,000
1,250
1,500
Jan-16 Apr-16 Jul-16 Oct-16 Jan-17 Apr-17
Oil Prod
uctio
n (bbl/day) Waterfloods and reactivations stabilize production;
no wells drilled since 2014
Excluding the Little Bow ASP project, the Alberta Plains assets are comprised of mature low decline properties at Bellshill Lake, Taber and Little Bow non‐ASP:
− Recently, base annual oil production declines of less than 10 percent, have been more than offset by oil exploitation projects: waterfloods, reactivations, and facility modifications.
− Similar projects and results are forecast for the next four quarters.
Alberta Plains – Bellshill Lake
Bellshill Lake produces low‐decline oil with remaining infill drilling potential
− Low produc on declines− Historical capital programs have kept produc on flat
since 2010 • Zargon operated, high working interest − 100% Working interest in all Dina produc on
• Areally extensive Dina sand with aquifer pressure support − Addi onal ver cal wells in par ally drained localized
closures can be drilled when funding is available− Low‐risk, low‐cost well pumping optimization projects
should provide production gains in H2 2017− 27 API oil
Liquids(Mbbl)
Total(Mboe)
PV 10%($MM)
PDP 910 955 13.5
TP 910 972 13.5
P+PDP 1,185 1,246 17.4
P+P 1,382 1,489 20.9
McDaniel Reserve Summary (December 2016)
McDaniel has recognized 5 P+PUD locations, Zargon has defined 4 additional locations10
Alberta Plains – Taber Mannville
• Sunburst development is seismically defined − 30 horizontal wells drilled since 2007 − 25 on produc on, 5 on injec on
• South pool is seeing stabilizing rates due to waterflood (vertical well historical production was negligible due to higher density oil)
− Es mated recovery to date ~10.1% − Ul mate forecasted P+PDP recovery ~18% − Es mated OOIP of 15.5 MMbbl
• North pool receives pressure maintenance from two vertical flank water injectors
− Es mated recovery to date ~ 16% and forecast ul mate P+PDP recovery ~ 21.7% based on estimated OOIP of 6.7 MMbbl
The Taber property offers low‐decline production with remaining development potential
Liquids(Mbbl)
Total(Mboe)
PV 10%($MM)
PDP 1,068 1,089 19.4
TP 1,182 1,204 20.4
P+PDP 1,416 1,442 24.0
P+P 1,634 1,663 26.9
McDaniel Reserve Summary (December 2016)
11
12
Costs &Impact
The Little Bow non‐ASP properties provide many low risk exploitation optimization opportunities, including:
− U&W Unit and G Unit: reactivation of waterflood schemes; entails reactivations of 6 producers, 3 water injectors and selected pipelines
− P Pool: initiate waterflood scheme with source well conversion, facility upgrades and 2 producer reactivations
− Enchant Pool: reactivate waterflood scheme with injector reactivation and 3 producer reactivations.
− Retlaw Non‐Unit waterflood extension: initiate waterfloodwith two injector conversions, 3 producer reactivations and related battery upgrades (refer to oil cut curve below, which shows significant target oil)
− Total cost for these four op miza on projects is approx. $2.5 million (over the next four quarters) which is forecast to offset the bulk of the corporate declines for the next 12 months.
− Incremental reserves are not recognized by McDaniel.
1
10
100
0 250,000 500,000 750,000 1,000,000 1,250,000
Oil Cu
t (%)
Cumulative Oil (bbl)
Little Bow‐Retlaw Non‐Unit ‐ Oil Cut Trend
McDaniel P+P (2016 YE)
Alberta Plains – Little Bow Non-Unit
North Dakota Properties
• Long life conventional oil properties, average of 27 API gravity oil‐ Stable production, more than 15 MMbbl oil produced to date ‐ Infrastructure and water disposal in place
• Established waterflood and unitized production − Waterflood modifications and reactivations have increased production from 350 bbl/d (Q4 2016) to 372 bbl/d (Q2 2017) − Waterflood modifications and well reactivations continue in H2 2017
• Total 2P Reserves NPV10 ~$26.2 MM (McDaniel year end 2016)− 4 PUD loca ons
• Large OOIP with bypassed pay opportunities‐ Infill drilling potential at each property (very low drilling density)‐ Frobisher recompletions (deferred until 2018) could unlock significant step‐out opportunities
Undercapitalized area with high working interest, waterflood exploitation and horizontal drilling opportunities
North Dakota Williston Basin geology is directly analogous to the offsetting Southeast Saskatchewan Williston Basin geology, however activity levels are substantially lower and the properties are less developed.
Q2 2017Production OOIP
Recoveryto Date Decline
Gross UndevelopedLocations
(boe/d) (MMbbl) (%) (%) McDaniel Additional
Haas 191 51 23% 3% 1 5+Mackobee Coulee 91 17 12% 12% 3 7Truro 90 30 4% 11% None 2
Total 372 98 15% 7% 4 14+13
(High workover costs in Q4 2016 & Q1 2017)
0250500750
1,000
Q1
Q2
Q3
Q4
Q1
Q2
Q3
Q4
Q1
Q2
Q3-
Q4
2015 2016 2017 Forecast
Qua
rter
ly E
xpen
se ($
M)
North Dakota Operating Cost Trend
Major R&M Base Opex Total Opex
zargon.ca
Little Bow ASP (Tertiary EOR)
Little Bow ASPEOR in a mature Southern Alberta Waterflood
Zargon constructed an Alkaline Surfactant Polymer (“ASP”) facility at Little Bow, Alberta, which enables the injection of dilute chemicals in a water solution to flush out undrained oil in existing reservoirs.
At higher oil prices, the existing ASP infrastructure can be utilized for multiple ASP and Polymer only projects seeking a 10 percent incremental oil recovery on over 80 million barrels of working interest oil‐in‐place.
15
Zargon W.I.(%)
W.I. OIIP(mmbbl)
ASP Phase 1 (‘I’ Pool)North and Central 100 15
Southern Area 100 8Future Potential Phases
Remaining portions I&P Pools 97 16U&W Unit (D8D/H9H Pools) 97 26
G Unit (B8B Pool) 95 10MM Unit (E8E Pool) 100 5
C8C / X8X Pool 100 9Total 89
ASP Facility & Gas Plant
Zargon Battery site
ASP Central Facility
Future ASP Phase
Future PolymerProject
ASP Phase 1
ASP Phase 1 ConformanceRemediation & Extension
ASP Modified Phase 2 Area
Little Bow ASP Project
16
Zargon’s Little Bow ASP project has shown good oil banking, but the combination of low oil prices and Zargon’s weakened financial condition forced Zargon to “idle” the project in a manner that preserved future recoveries when reactivated.
• Phase 1 Alkali and Surfactant (“AS”) injections were suspended in Q1 2016, to reduce capital outflows during a very low oil price period. In September 2016, high water cut Phase 1 producers in AS under‐treated areas South (Phase 1) were suspended, thereby bypassing the untreated reservoir and permitting full AS recoveries upon reactivation.
• With higher oil prices, AS injections can initially be resumed in high‐graded Phase 1 areas and then a modified (truncated) Phase 2 area and ultimately the U&W Unit.
Production plot shows Fall 2016 rate reduction to preserve long term re‐start optionality and also recent positive oil banking in the Central area.
Forecast Q4 2016 Op. cost of $1.0 million
Upper Mannville P Pool
North Extension
North
CentralN.E. Spur
South (Phase 1)
South (Phase 2)
0250500750
1,0001,2501,5001,7502,000
Q1
Q2
Q3
Q4
Q1
Q2
Q3
Q4
Q1
Q2
Q3‐Q4
2015 2016 2017 Forecast
Qua
rterly Expen
se ($
M) ASP ‐ Phase 1 Operating Cost Trend
Major R&M Base Opex Total Opex
ASP Enhanced Oil Recovery Process
Dilute concentrations of chemicals (Alkali, Surfactant and Polymer) in water are injected into an existing oil pool to “scrub” out oil that waterflooding alone will not recover.
Surfactants: Detergent; mobilizes trapped oil.
Alkali: Increases surfactant effectiveness.
Polymer (Thickener): Thickened water helps sweep oil from the reservoir.
17
1) ASP InjectionA blend of Alkali,
Surfactant & Polymer mobilizes trapped oil
2) Polymer “Push”Polymer displaces
mobilized oil to producing wells
3) Terminal WaterfloodReturn to waterflood to
complete oil displacement
OIL BANK ASP POLYMER WATER
Husky/CNRL Taber Mannville “B” ASP Husky/Whitecap Gull Lake ASP
Analog ASP Performance (The Prize)
The Taber Mannville B and Gull Lake ASP projects are good analogs to our Little Bow ASP project. Successful ASP projects provide stable production volumes for many years after the first three years
of cost intensive AS injections are completed. With higher oil prices, and the reactivation of AS injections in phase 1 and subsequent phases, we
continue to foresee the potential for many years of production growth followed by many years of free cash generating stable production for our Little Bow property.
18
zargon.ca
2016 Year End Reserves Information
McDaniel Reserves Review (Year End 2016)Future Oil & Gas Production
TeamPDP
RLI (yrs)PDP
DeclineP+PDPRLI (yrs)
P+PDPDecline
Alberta (excl ASP) 6.7 12 % 8.7 10 %
Little Bow ASP 11.0 n/a 15.7 n/a
W.B. (ND) 12.9 9 % 16.8 7 %
Zargon 8.8 8 % 11.7 5 %
McDaniel Oil Reserves & Production CharacteristicsRLI (yrs) & 2017 Decline Rate (%/yr)
20
0
500
1,000
1,500
2,000
2,500
3,000
2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027
Gas Production Forecast (PDP & P+PDP)
PDP from Base PDP from ASP PADP from Base PADP from ASP
Gas Produ
ction Ra
te (M
cf/d)
0
250
500
750
1,000
1,250
1,500
1,750
2,000
2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027
Oil Prod
uctio
n Ra
te (b
bl/d)
Oil Production Forecast (PDP & P+PDP)
PDP from Base PDP from ASP PADP from Base PADP from ASP
‐ The McDaniel report predicts a first year proved developed producing oil and liquids annual decline of 8 percent.
‐ The corresponding proved developed producing oil and liquids reserve life is 8.8 years.
‐ Zargon’s mature, pressure supported reservoirs are characterized by low declines and long life indices for developed producing reserves
McDaniel 2016 Year End Reserves Summary
21
Reserve Category Oil & Liquids (mbbl)
Sales Gas (mmcf)
Total(mboe)
B.Tax PV 10% ($ million)
PDP 6,284 4,753 7,076 $ 84.3
Total Proved 7,152 6,381 8,215 $ 93.2
P+PDP 8,360 6,184 9,391 $ 111.4
Proved & Probable 11,180 10,366 12,908 $ 132.3
‐ Proved developed producing (PDP) reserves comprise 55% of the total reserves and proved and probable developed producing (P+PDP) reserves comprise 73 % of the total reserves
‐ On a total proved and probable basis, the Zargon reserve base is weighted 87% to oil and liquids
‐ Strong operational performance resulted in net positive revisions of 1.17 and 1.36 mmboe in the PDP and P+PDP categories respectively
Net Asset Value ComparisonMcDaniel Year End Pricing
NAV Calculation (Dec 31, 2016 Reserves)Proved + Prob. McDaniel Est. (BT DCF 10%) $ 132 million
Undeveloped Land (Seaton Jordan evaluation) $ 2 millionDeduct Net Working Capital & Conv. Deb. (unaudited) ‐ $ 34 millionNet Asset Value $ 100 million
Zargon Proved + Prob. Net Asset Value $3.27 per share
Reserve Category McDaniel PVBT 10% ($ million)
Net Asset Value ($ million)
Net Asset Value –no deb. conversion
($/share)
Net Asset Value –with deb. conversion
($/share)
PDP 84 52 1.70 1.48
Total Proved 93 61 1.99 1.62
P+PDP 111 79 2.58 1.90Proved & Prob. 132 100 3.27 2.23
(30.61 million shares at Dec 31, 2016)
22
Zargon Valuation with Debentures at Face ValueCommon Shares (30.75 million @ $0.51 on August 4, 2017) $ 15.7 millionDebentures (41.9 thousand @ $1,000 face value) $ 41.9 millionSubtract Positive Working Capital (June 30, 2017) ( $ 5.8 million)
Total Enterprise Value $51.8 million
2017 H1 Production (2,540 boe/d – 78% oil/liquids) $20,400 per boe/d2016 YE Reserves PDP (7.08 mmboe – 89% oil/liquids) $ 7.32 per boe2016 YE Reserves TP (8.22 mmboe – 87% oil/liquids) $ 6.30 per boe2016 YE Reserves 2PDP (9.39 mmboe – 89% oil/liquids) $ 5.52 per boe2016 YE Reserves 2P (12.91 mmboe – 87% oil/liquids) $ 4.01 per boe
Zargon’s market valuation of $51.8 million is significantly less than the McDaniel proved developed producing analysis.
zargon.ca
Cash Flow Projections & Valuations
2017 (H2) Cash Flow Parameters (excluding hedges)
Oil 2,000 bbl/d Gas 3.30 mmcf/d Equiv. 2,550 boe/d (78% oil and liquids). Royalties 9% Alberta, 24% North Dakota (includes state and severance taxes)
Oil Prices WTI – WCS diff.: $11.00 US/bbl; Field price at WCS less $0.70 Cdn./bbl Gas Prices $2.15/mcf Alberta average field price Exchange 0.78 $US/$Cdn G&A Costs $2.1 million (annualized rate of $4.3 million after 2016‐17 reorganization costs) Interest $1.7 million – revised debenture cost, no interest on cash balances
Production
2017 (H2) Costs & Capital
Other Parameters
24
Operating $9.6 million (annualized run rate of $19.3 million) Abd. & Reclam. $0.8 million ($0.7 million spent in H1) US Taxes $ nil ASP Capital $0.9 million chemical costs ($0.9 million spent in H1) Main. Capital $0.7 million non‐discretionary land and other costs ($0.8 million spent in H1) Exploit Capital $1.6 million ($2.7 million spent in H1, pre‐spending on Little Bow waterflood and
Travers gas plant)
25
WTI Pricing(US/bbl)
Field Pricing (Cdn./bbl)
Field Cash Flow (million)
Corporate Cash Flow (million)
Free Cash Flow After All Capital
(million)
$45 $42.89 $11.1 $ 3.4 ($4.5)
$50 $49.30 $15.2 $ 7.6 ($0.4)
$55 $55.71 $19.4 $11.7 $ 3.7
$60 $62.12 $23.5 $15.9 $ 7.9
$65 $68.53 $27.7 $20.0 $12.0
Zargon’s cash flows are exceptionally sensitive to oil prices.
This analysis examines cash flows for the remainder of the year, which have been annualized for comparative purposes. (For Q3‐Q4 2017, assumes $3.2 million of capital and $0.8 million of abandonment/reclamation costs.)
Excluding hedges, Zargon’s assets provide a positive corporate cash flow down to less than $45 US/bbl WTI.
At higher prices, Zargon’s assets provide significant free cash flow that can be used to retire debt, reactivation and facility modification projects, drill high‐graded horizontal oil exploitation wells and reinstate/initiate Little Bow ASP/Polymer floods.
2017 (H2) Projected Cash Flows (annualized)(excluding hedges)
0
5
10
15
20
25
30
40 45 50 55 60 65 70
Cash Flow ($
millions)
WTI Oil Price ($/bbl)
Zargon Cash FlowField Cash Flow
Corporate Cash Flow
26
WTI Pricing (US/bbl)
Field Cash Flow (million)
4.5 Times Field Cash Flow
(million)
ZargonNet Debt (million)
Attributed to Zargon Shares
(million)
Calculated Zargon Value
(per share)
$45 $11.1 $ 50.0 $ 36.1 $ 13.9 $0.46
$50 $15.2 $ 68.4 $ 36.1 $ 32.3 $1.05
$55 $19.4 $ 87.3 ($ 5.8) $ 93.1 $1.45
$60 $23.5 $105.8 ($ 5.8) $111.6 $1.74
$65 $27.7 $124.7 ($ 5.8) $130.5 $2.03
Calculations reflect the recent Cdn. dollar appreciation and: • $5.8 million of positive working capital as of June 30, 2017, $41.9
million of remaining debentures and 30.7 million shares outstanding.
• for $55+ cases, $41.9 million of remaining debentures are assumed to convert into Zargon shares at a $1.25 conversion price (33.5 million shares) taking the total outstanding shares to 64.2 million.
Zargon’s long‐life oil reserves provide investor’s with exceptional torque (both operational and financial leverage) to future increases in oil prices.
A corporate valuation based on a 4.5 times property cash flow multiple suggests that significantly higher share prices may be realized if/when WTI oil prices move to higher levels.
Valuation using 2017 (H2) projected (annualized) field cash flows
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40 45 50 55 60 65 70
Share Price ($/sha
re)
WTI Oil Price ($US/bbl)
Zargon Share Value4.5 Times Property Cash Flow
Key Considerations
Zargon’s Board and management believe that Zargon’s share price has not been reflective of the fundamental value inherent in the Company.
With the Q3 2016 sale of Zargon’s Williston Basin Saskatchewan and Killam Alberta assets, Zargon was able to eliminate all bank debt. With the Q1 2017 restructuring of Zargon’s convertible debentures, Zargon has deferred the debenture maturity until December 31, 2019, thereby permitting additional time to realize Zargon’s unrealized oil exploitation value.
Zargon continues to seek a strategic alternatives solution that will enable Zargon stakeholders to participate in Zargon’s exceptional torque to higher oil prices.
Strategic Process Ongoing
Deep Discount to NAV
27
For 2017, Zargon expects to deliver stable production volumes. This forecast is based on $7.8 million of 2017 capital, which includes $4.3 million of reactivations, recompletions and facility upgrades that were not pursued in the prior two years due to financial constraints.
With a sustainable 2017 business plan, investors are able to wait for materially higher oil prices (and the substantial upside to Zargon share price) without erosion of the underlying asset base.
Exceptional Torque to Higher oil Prices
Sustainable 2017 Corporate Model
Investors buy Zargon at a discount to the proved developed producing net asset value when evaluated at prices at (or above) current strip.
Zargon’s long‐life oil reserves provide investor’s exceptional torque to higher oil prices: Financial – Although improved, Zargon’s balance sheet remains over‐levered where small changes in
underlying corporate value result in large inferred changes in share price. Operational – Zargon’s production tends to be from mature low‐decline, low‐rate wells with
relatively higher operating costs. Small improvements in oil prices result in significantly improved cash flows.
Exploitation – Zargon’s exploitation opportunities are significant, but generally require higher prices.
zargon.ca
Corporate PresentationAugust 9, 2017