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Forward Looking-Advisory
Forward-Looking Statements - This presentation offers our assessment of Zargon's future plans and operations as at May 14, 2018, 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, 2018 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 2018 and beyond, strategic alternatives review process, the source of funding for our 2018 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.
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Q1 2018 Results
Pro Forma BalanceSheet
3
Q1 2018 was a challenging quarter:
WTI oil realized losses were $0.85 million: (1,000 bbl/d @ $70.15 Cdn./bbl (WTI)
WTI – WCS differentials were $30.76 Cdn./bbl in Q1 18 (compared to $15.60 Cdn./bbl in Q4 2017); the impact of these increased differentials on Zargon’s Q1 18 Alberta revenue was $2.08 million.
Operating costs exceeded expectations by $1.21 million, primarily due to specific problem well reactivations, increased electricity costs and weather related challenges.
Q1 2018 Results
For H2 2018, Zargon’s outlook has improved materially:
WTI ($Cdn.) has increased from Q1 average of $79.51 Cdn./bbl to current levels of almost $90 Cdn./bbl.
Zargon’s remaining WTI hedges expire at the end of this June (Q2 2018 Hedges: 1,000 bbl/d @ $70.50 Cdn./bbl )
WTI – WCS forward differentials for Q3 18 have declined substantially to about $25 Cdn./bbl.
Operating Costs – the high Q1 costs related to specific events; H2 costs are forecast to return to prior guidance levels of $19.2 million (annualized).
Q1 2018 Challenges
Reasons for
optimism
Zargon’s Q1 2018 Production and Financial Results:
Q1 field cash flow of $2.42 million; Q1 funds flow were a negative $0.30 million
Q1 production volumes of 2,427 boe/d; comprised of 1,949 bbl/d of oil & liquids and 2.87 mmcf/d.
Net Working Capital – Positive $1.15 million (March 31 - unaudited)
Convertible Debentures – $41.94 million outstanding
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 2017 year-end McDaniel reserve report books 13 P+P exploitation locations with average per well parameters of 63 Mbbl oil reserves, 49 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. Zargon’s Alberta LMR is 1.33 (May 2018).
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 ~$199 million of high quality tax pools (Mar. 31, 2018), includes $154 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 and North Dakota 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.
2018 (H2) Revised Cash Flow Estimates
Oil 1,830 bbl/d (revised to reflect restricted H1 2018 capital) Gas 1.89 mmcf/d (revised for shut-in of uneconomic properties) Equiv. 2,145 boe/d (85% oil and liquids). Royalties 9% Alberta, 24% North Dakota (includes state and severance taxes)
Oil Prices Alta field price: WCS plus $1.0 Cdn./bblND field price: WTI less $11.0 Cdn./bbl
Gas Prices $1.21/mcf Alberta average field price (assumed AECO price less $0.20/mcf adj.) Exchange $0.78 US/Cdn (assumed) G&A Costs $1.95 million (reflects continued improvements) Interest $1.68 million – revised debenture cost, no interest received on cash balances
Production
2018 (H2) Costs & Capital
Other Parameters
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Operating $9.60 million (unchanged from prior estimate - annualized cost of $19.2 million) Abd. & Reclam. $0.70 million (to meet regulatory obligations) US Taxes $ nil ASP Capital $0.84 million chemical costs (status quo polymer only) Main. Capital $0.70 million non-discretionary land and other costs Exploit Capital $1.90 million (Little Bow non-ASP waterfloods and recompletions, North Dakota
waterflood optimizations); no wells to be drilled
6
Average Field Pricing (Cdn./bbl)
Annualized Field Cash Flow
(million)
Annualized Corporate Funds
Flow (million)
$45 $ 7.9 $ 0.7
$55 $13.8 $ 6.5
$65 $19.7 $12.4
$75 $25.6 $18.3
$85 $31.4 $24.2
Zargon’s cash flows are closely correlated to Western Canada Select (“WCS”) oil prices. Including North Dakota, Zargon’s field price tends to reflect a small premium to the WCS price.
Recently, WTI oil prices have been climbing and now exceed $70 US/bbl. WCS-WTI differentials were high in Q1 2018 but have recently improved, and WCS prices are now quoted at better than $55 US/bbl ($70 Cdn./bbl). For Q1 2018, the average WCS price was $38.59 US/bbl or $48.76 Cdn./bbl.
The projected cash flows presented on this slide are based on the parameters provided on the previous slide.
2018 (H2) Projected Cash Flows (annualized)
05
101520253035
40 50 60 70 80 90
Cash
Flo
w ($
mill
ions
)
Zargon Field Price ($Cdn./bbl)
Zargon Cash Flows (annualized)
Field Cash Flow
Key Considerations
Zargon’s Board and management recognize that Zargon is a suboptimal size to operate as a public oil and gas Company. Consequently, Zargon will continue to explore strategic alternatives that will allow Zargon to continue as a part of a larger better capitalized entity.
Furthermore, recognizing that Zargon’s assets are inexpensively priced and provide significant unrecognized oil price option value, Zargon will continue to pursue alternatives that can unlock this upside and may include the sale of all or part of the company, a financing, merger or other business combination.
Strategic Process
Deep Discount to NAV
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Zargon’s base oil production decline is less than 10 percent per year.
Zargon’s proved developed producing net asset value is $1.40 per share: (McDaniel 2017 year end reserves).
Zargon has 10 “drill ready” undeveloped locations with good economics, that can be pursued once capital is available.
Zargon brings more than $150 million of valuable non-capital tax losses and a TSX listing.
Exceptional Torque to Higher oil Prices
Other Attributes
Zargon’s long-life oil reserves provide investors exceptional torque to higher oil prices: Financial – 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 larger scale ASP exploitation opportunities are significant; At current prices, the
North Dakota and Taber undeveloped locations provide attractive returns.
Alberta Exploitation Core Areas
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Bellshill Lake
TaberLittle Bownon-ASP
Little Bow ASP
Excluding the Little Bow ASP project, the Alberta core areas are mature operated oil properties, with low decline rates and waterflood and pressure supported exploitation opportunities. Taber and Bellshill Lake also provide undeveloped oil exploitation locations.
• Recent base annual oil production declines of less than 10 percent have been offset by oil exploitation projects (waterfloods, reactivations, and facility modifications).
• Similar projects and results are forecast for 2018.
9
Alberta Plains (excluding Little Bow ASP)
10
• Q1 2018 production of 1,564 boe/d
– No drilling in 2015-17 due to capital allocation decisions; less than 10% annual decline is offset by waterflood and reactivation expenditures.
– Multiple exploitation and development opportunities have been identified throughout Zargon’s asset base.
– 3D seismic coverage supported booked and un-booked locations
– 8 booked infill and exploitation drilling McDaniel locations.
– 67% liquids-weighted (16 – 32o API) and ~98% operated.
Q1 2018Prod
% Liquids API OOIP
Recoveryto Date
Gross UndevelopedLocations
(boe/d) (%) ( ⁰ ) (MMbbl) (%) McDaniel Additional
Bellshill Lake 423 94% 27 16 32% 5 1+
Taber 404 93% 16-24 27 15% 3 5+Little Bow
(Conventional) 319 63% 21 82 25% - tbd
Alberta Other 418 28% 18-32 n.a. n.a. - 2+
Total 1,564 70% 16-32 125+ 24% 8 8+
Liquids(Mbbl)
Total(Mboe)
PV 10%($MM)
PDP 2,692 3,579 39.2
TP 2,964 4,017 41.9
P+PDP 3,478 4,597 49.2
P+P 4,255 5,707 60.0
McDaniel Reserves Summary (December 2017)
Waterflood and reactivation projects stabilize production (no wells have been drilled since 2014)
0
100
200
300
400
500
600
Jan-15 Jan-16 Jan-17 Jan-18 Jan-19
Bellshill Lake History
McDaniel 2017 YE Fcst
Oil
Prod
uctio
n Ra
te (b
bl/d
ay)
Alberta Plains – Bellshill Lake
Bellshill Lake produces low-decline rate 27° API oil with remaining infill drilling potential.• Zargon operated, high working interest.
− 100% working interest in all Dina production. • Areally extensive Dina sand with aquifer pressure support.
− Additional vertical wells in partially drained localized closures can be drilled when funding is available− water handling expansion that was completed in Q4 2017 will provide multiple for pumping optimization projects in H2 2018.
Liquids(Mbbl)
Total(Mboe)
PV 10%($MM)
PDP 799 843 9.9
TP 850 898 10.8
P+PDP 1,041 1,098 13.2
P+P 1,298 1,365 17.7
McDaniel Reserves Summary (December 2017)
McDaniel has recognized 5 P+PUD locationsZargon has defined 4 additional locations
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Proved Developed Producing Oil Rate Profile
Reported 2017 oil volumes showed flattening decline production trends.
McDaniel YE 2016 estimate
0
100
200
300
400
500
600
700
800
900
Jan-15 Jan-16 Jan-17 Jan-18 Jan-19
Taber History
McDaniel 2017 YE Fcst
Oil
Prod
uctio
n Ra
te (b
bl/d
ay)
Alberta Plains – Taber Mannville
• Sunburst development is seismically defined − 30 horizontal wells drilled since 2007 − 25 on production, 5 on injection
• North pool receives pressure maintenance from two vertical flank water injectors − Estimated recovery to date ~ 16% and forecast ultimate P+PDP recovery ~ 21.7% based on estimated OOIP of 6.7 MMbbl
• South pool oil rates are stabilizing due to waterflood effects (vertical well historical production was negligible due to higher density oil) − Estimated recovery to date ~10% − Ultimate forecasted P+PDP recovery ~18% − Estimated OOIP of 15.5 MMbbl
The Taber property offers low-decline production with remaining development potential
Liquids(Mbbl)
Total(Mboe)
PV 10%($MM)
PDP 1,032 1,111 16.8
TP 1,144 1,224 17.9
P+PDP 1,369 1,475 20.8
P+P 1,586 1,693 23.5
McDaniel Reserve Summary (December 2017)
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Proved Developed Producing Oil Rate Profile
Reported 2017 oil volumes showed flattening production decline trends.
McDaniel YE 2016 estimate
0
50
100
150
200
250
300
350
400
450
500
Jan-15 Jan-16 Jan-17 Jan-18 Jan-19
North Dakota History
McDaniel 2017 YE Fcst
Oil
Prod
uctio
n Ra
te (b
bl/d
ay)
North Dakota Properties
• Long life conventional oil properties, average of 27 API gravity oil- Stable production, large OOIP, more than 15 MMbbl oil produced. - Infrastructure and water disposal in place.- Infill drilling potential at each property (very low drilling density).- Oil price is based LSB stream, a significant premium to WCS crude.
• Established waterflood and unitized production − Ongoing waterflood modifications and reactivations are increasing production.− Two “drill ready” locations ready for funding (Truro and Mackobee Frobisher)
• North Dakota Williston Basin geology is very analogous to the offsetting Southeast Sask. geology. Yet, compared to Sask., there has been limited development.
Q1 2018Production OOIP
Recoveryto Date Decline
Gross UndevelopedLocations
(boe/d) (MMbbl) (%) (%) McDaniel Additional
Haas 214 51 23% 4% 1 5+Mackobee Coulee 82 17 12% 11% 3 7Truro 125 30 4% 7% 1 2
Total 421 98 15% 6% 5 14+13
Proved Developed Producing Oil Rate Profile
Liquids(Mbbl)
Total(Mboe)
PV 10%($MM)
PDP 1,674 1,674 16.7
TP 1,941 1,941 17.7
P+PDP 2,211 2,211 20.2
P+P 2,650 2,650 23.7
McDaniel Reserve Summary
(December 2017)
Reported 2017 oil volumes show improving rates from waterflood projects, that are expected to
exceed McDaniel YE 2017 projections
McDaniel YE 2016 estimate
0
100
200
300
400
500
600
Jan-15 Jan-16 Jan-17 Jan-18 Jan-19
Little Bow ASP History
McDaniel 2017 YE Fcst
Oil
Prod
uctio
n Ra
te (b
bl/d
ay)
Little Bow ASPEOR in a mature Southern Alberta Waterflood
Zargon constructed an Alkaline Surfactant Polymer (“ASP”) facility at Little Bow, Alberta, which enables the injection of dilute chemicals in a water solution to flush out undrained oil in existing reservoirs.
At higher oil prices, the existing ASP infrastructure can be utilized for multiple ASP and Polymer only projects seeking a 10 percent incremental oil recovery on over 80 million barrels of working interest oil-in-place.
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ASP Facility & Gas Plant
Zargon Battery site
ASP Central Facility
Future ASP Phase
Future PolymerProject
ASP Phase 1
ASP Phase 1 ConformanceRemediation & Phase 2 Extension
ASP Modified Phase 2 Area
Liquids(Mbbl)
Total(Mboe)
PV 10%($MM)
PDP 1,638 1,675 23.2
TP 1,939 1,981 25.5
P+PDP 2,263 2,312 30.7
P+P 3,918 4,098 35.6
McDaniel Reserve Summary (December 2017)
Proved Developed Producing Oil Rate Profile
Recent production rates reflect specific well and conformance matters; remedial workovers are
scheduled for this summer.
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.
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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 early 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 (in a higher price environment) the potential for many years of production growth followed by many years of free cash generating stable production for our Little Bow property.
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Zargon Statistical Overview (Q1 18 Results)
Capitalization(1)
Share Price (May 11, 2018) $0.54 Basic Shares Outstanding 30.86 Market Capitalization $16.7 Net Debt(2) $40.8Option Proceeds -
Entity Value $57.5
52-Week High $0.63 52-Week Low $0.335
Net Debt Summary(2)
Bank Debt $nil Convertible Debs ( Dec. 2019) $41.9 Working Capital ($1.1) Net Debt $40.8
Other Company Details
Employees 12 Office 6 Field
Head Office Calgary, Alberta, Canada Primary Exchange Listing TSE Reserve Evaluators McDaniel
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(1) All numbers in $millions except per share values(2) Net debt calculated as convertible debentures plus
net working capital as at March 31, 2018
Four Qtr. Comparisons Q4 2016 Q1 2017 Q2 2017 Q3 2017 Q4 2017 Q1 2018
Oil Prod. (bbl/d) 1,952 2,016 1,921 2,037 1,924 1,949
Gas Prod. (mmcf/d) 2.98 3.38 3.47 3.55 2.95 2.87
Equiv. Prod. (boe/d) 2,449 2,579 2,500 2,628 2,416 2,427
Revenue & Hedges ($ million) 9.24 9.72 9.37 9.51 9.69 8.86
Royalties ($ million) 1.02 1.00 1.11 1.13 1.19 1.28
Op. Costs ($ million) 4.87 5.11 5.12 4.88 5.03 6.01
Property Cash Flow ($ million) 3.35 3.61 3.14 3.50 3.47 1.57
G&A Costs ($million) 1.33 1.16 1.11 0.89 1.00 0.97
Interest & Other ($ million) 1.10 0.95 0.89 0.85 0.88 0.90
Corp. Funds Flow ($ million) 0.92 1.50 1.14 1.76 1.59 (0.30)
Capital ($ million) 1.43 2.51 2.13 1.77 2.45 1.50
Abd. & Reclaim ($million) 0.05 0.14 0.55 0.55 0.87 0.61
In Q3 2016, Zargon sold significant assets in order to eliminate bank debt. Production and financial results have subsequently been relatively steady, except for Q1 2018 which was challenged by: hedge losses of $0.85 million, increased WTI-WCS differentials that reduced Alberta revenue by $2.08 million and higher operating costs of $1.21 million.Looking forward, we expect considerably improved results in H2 2018, due to a return to historical operating costs, the expiry of our hedges (June), the improvement in WTI oil prices and the reduction of the WTI-WCS differential.
Zargon Production and Financial Statistics (since Q3 2016 property sales)
Bellshill Lake03/16-34
02/16-34 00/3-35 Hz
03/4-26 Hz
00/15-24
Alberta “Drill Ready” Locations
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Taber
03/16-2 Hz
04/1-2 Hz
02/16-11 Hz
Drill Ready Location Target Cost ($million)
Prob. Of Success
(%)
Risked Prod
(bbl/d)
Risked Reserves
(mbbl)
(02) 16-34 Vertical Dina attic 0.60 85 43 34
(03) 16-34 Vertical Dina attic 0.60 85 43 34
(00) 15-25 Vertical Dina new closure 0.90 60 48 54
(03) 4-26 Horizontal Dina drainage 0.95 75 38 56
(00) 3-35 Horizontal Dina drainage 0.95 75 38 56
Total Bellshill Lake 4.00 210 234
(04) 1-2 Horizontal Sunburst drainage 0.95 90 36 68
(03) 16-2 Horizontal Sunburst drainage 0.95 90 36 68
(02) 16-11 Horizontal Sunburst drainage 0.95 80 40 68
Total Taber 2.85 112 204
Total Alberta 6.85 322 438
2019 Field Price ($Cdn./bbl)
Time to Payout (years)
Rate of Return (percent)
Profitability Index@ PV 10%
$45 2.7 30 0.53$55 2.0 48 0.95$65 1.6 68 1.37
Zargon has advanced eight of its Alberta undeveloped locations to a “drill ready” status. These locations can be drilled once funding is available. With the recent improvement in oil prices, the program’s risked returns are strong.
McDaniel Reserves YE 2017 Review (based on McDaniel Dec. 31, 2017 Pricing)
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NAV Calculation (Dec 31, 2017 Reserves)Proved + Prob. McDaniel Est. (BT DCF 10%) $ 119 million
Undeveloped Land (Seaton Jordan evaluation) $ 2 millionDeduct Net Working Capital & Bank Debt - $ 38 millionNet Asset Value $ 83 million
Zargon Proved + Prob. Net Asset Value $2.69 per share
Reserve Category McDaniel PVBT 10% ($ million)
Net Asset Value ($ million)
Net Asset Value ($/share)
PDP 79 43 1.40
Total Proved 85 49 1.59
P+PDP 100 64 2.08Proved & Prob. 119 83 2.69
(30.80 million shares; assumes no dilution from debentures)
TeamPDP *
RLI (yrs)PDP
DeclineP+PDP *RLI (yrs)
P+PDPDecline
Alberta (excl ASP) 6.9 11 % 8.9 9 %
Little Bow ASP 9.5 5 % 13.1 n/a
W.B. (ND) 11.6 8 % 15.3 6 %
Zargon 8.5 9 % 11.3 6 %
McDaniel Oil Reserves & Production CharacteristicsRLI (yrs) & 2018 Decline Rate (%/yr)
* Note: RLI based on annualized Q4 2017 oil production
6,928
2,192
1,012
2,323
Total Reserves (mboe)
Proved Producing
Probable Producing
Proven Undeveloped &nonProducing
Probable Undeveloped &nonProducing
NAV estimates do not include site reclamation and abandonment costs
for non-producing assets.
YE 2017 Reserve Report Highlights
Despite a restricted capital budget of $8.9 million (unaudited), Zargon’s 2017 proved developed producing reserve additions replaced 84% of Zargon’s 2017 production volumes (71% for proved and probable producing reserves).
• Proved and probable reserves: 12.45 mmboe (87% oil and liquids)• Proved and probable developed producing reserves: 9.12 mmboe (87% oil and liquids)• Proved and probable developed producing oil and liquids reserve life: 11.3 years• Proved and probable developed producing reserves net asset value: $100 million.
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Zargon’s oil properties are pressure supported by waterfloods, tertiary recovery schemes or natural aquifers. Base corporate oil production decline is
less than 10% per year. Stable production volumes can be
delivered with low cost, exploitation (plumbing type) capital programs focused on waterflood and other enhancements. With additional funds, production growth can be delivered by drilling North Dakota and Taber undeveloped locations.
Zargon Operated Oil Production
