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Zargon Oil & Gas Ltd.
December 22, 2014 Corporate Presentation
WWW.ZARGON.CA
Advisory – Forward-Looking Information
Forward‐Looking Statements ‐ This presentation offers our assessment of Zargon's future plans and operations as at December 19, 2014, 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, 2014 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 2014 and beyond, plans to sell un‐strategic assets, the source of funding for our 2014 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
Dec. 22, 2014 News Release: Key Points
Prudent action to protect balance sheet in low oil price environment
• Dividend reduced from $0.06 per month to $0.03 per month • Hamilton Lake property sale closed
• 2015 conventional capital budget reduced
Saves $11 million in 2015
Provides $22.5 million of cash
Saves $13 million in 2015
Little Bow ASP ramp up begins
• Definitive ASP production of 50 bbl/d (total) observed in primarily four wells
• Production trends continue to point to the targeted 12% reservoir recovery
2015 production guidance revised for sales, budgets and ASP ramp‐up delay
• Prior Oil: 4,700 bbl/d (4,000 bbl/d plus 700 bbl/d ASP)
• Revised Oil: 4,200 bbl/d (3,800 bbl/d plus 400 bbl/d ASP)
• Prior Natural Gas: 6.4 mmcf/d; Revised Natural Gas: 4.8 mmcf/d Corporate transformation essentially completed
• Conventional assets are now high‐netback waterflood/waterdrive low‐decline properties,
• Little Bow ASP assets provides years of low‐cost growth,
• Net active well count has been reduced by 500 net wells (35 percent), during the last 18 months.
3
Zargon: Core Attributes
Oil Exploitation
• Pressure Supported (Waterflood and Waterdrive): 35+ prospective oil exploitation locations in pressure supported (low decline) properties.
• Tertiary (ASP): Little Bow ASP tertiary recovery project provides years of oil production growth. • 21.0 Mmbbl of 2P oil reserves (12.4 yr. rli –
based on year end 2013 McDaniel report).
Long‐lived Oil Assets
• 68% of 2P oil reserves are developed producing reserves.
• Non ASP assets have a very low oil production decline rate of less than 15%/yr. Dividend Paying
• $359 million ($17.84/share) of dividends and distributions paid over history on total historical equity investment of $210 million.
• Effective January 2015, the dividend has been reduced to $0.03 per share from $0.06 per share, in order to preserve capital in a low oil price period. 4
Zargon: Asset Description
Waterflood and Waterdrive Oil Properties
Waterflood and Waterdrive (Pressure Supported) Oil:
• Properties account for approximately 95% of oil production after the Hamilton Lake sale; very predictable with low declines,
• Substantial inventory of low risk oil exploitation wells, • Supports dividend through the rest of the decade. Little Bow ASP Enhanced Recovery Project:
Little Bow ASP Tertiary Oil Recovery Project
• Phase 1 displaying encouraging production trends,
• Phase 1‐4 ASP oil projects will provide significant oil production growth well into the next decade, • Scalable technology that can be used for other fields.
Other Non‐Strategic Assets:
Other Non‐Strategic
• Remaining non‐strategic properties have “atrophied” in recent years, as capital was redeployed to core assets,
• In 2014 have disposed more than 350 net wells producing a combined 220 bbl/d and 9.50 mmcf/d
(1,800 boe/d).
5
Zargon Overview
(As at December 19, 2014 unless otherwise stated)
Capitalization
– Toronto Stock Exchange:
– Common Shares Outstanding: – Market Capitalization:
– Approximate Net Debt at Dec. 19, 2014:
•
•
•
Convertible Debentures,
Bank Debt and Net Working Capital Deficit
Authorized Bank Debt Symbols: ZAR; ZAR.DB
30.18 million (basic)
$110 million ($3.66 per share) (1)
$113 million (after Hamilton Lake sale), comprised of
$57.5 million (face value)
$56 million
$130 million (43 percent drawn)
Dividend & Yield
– Monthly Dividend (Commencing January 2015):
– Yield at current share price:
$0.03 per share (reduced from $0.06 per share)
9.8% (1)
Q3 2014 Production – Equivalent:
– Oil: – Gas: 6,054 boe/d 4,194 bbl/d (69% of production)
11.16 mmcf/d
Q3 2014 Financial Results
– Funds Flow from Operations
– Dividends Paid
– Payout ratio $0.36 per basic share ($10.9 million)
$0.18 per basic share ($5.4 million)
50% based on Q3 2014 funds flow.
(1)
Based on a monthly dividend rate of $0.03/share and using the December 19, 2014 closing share price of $3.66. 6
2014 Corporate Objectives
• ASP Related:
– Commission the Little Bow ASP project on budget, with first chemical injections occurring by the end of the 2014 first quarter. (completed)
– Deliver Little Bow Phase 1 ASP operational and production (now adjusted) targets of 100 barrels of oil per day in Q1 2015 climbing to 750 barrels of oil per day in Q4 2015. (some delays, but technical indicators are promising)
– Finalize the design of the Little Bow Phase 2 ASP project and advance the Little Bow Phase 3 and 4 ASP engineering studies. (in progress)
• Waterflood and Waterdrive Oil Exploitation Related:
– Deliver high‐graded and profitable oil exploitation programs at remaining four long‐life low‐
decline oil properties. (Solid Q2/Q3/Q4 Taber, Bellshill and Williston Basin results)
• Corporate Related:
– Conclude property dispositions that high‐grade and concentrate the Company’s properties on our core oil exploitation (ASP and waterflood/waterdrive) business. (essentially completed)
– Improve corporate netbacks by targeting all costs, including operating, g&a and capital costs. (enabled by property sales)
– Maintain (and ultimately improve) our balance sheet. (targeting stable debt through 2015‐2016)
– Maintain dividend of $0.06 per common share per month. (not achieved; dividend has been reduced to $0.03 per share to reflect sharply lower oil prices)
7
Waterflood and Waterdrive Oil Exploitation Projects
Current Drilling Inventory
The Q4 2014 conventional oil exploitation drilling program includes 3 Williston Basin and 2 Taber wells. The existing oil exploitation well inventory will support non‐ASP oil production volumes for many years. Property
Bellshill Lake Bellshill Lake – Killam
Taber Williston Basin
Project
Net Locations
Increase fluid withdrawal
Develop Glauconite pool
Develop Sunburst pool
Elswick, Midale, Weyburn, Ralph, Steelman, Mackobee
5
5
5
20+
Facility optimization; infills and step‐outs
Implement waterflood with development
Expand and enhance waterfloods
Horizontal drainage wells in relatively tight reservoirs; additional pressure support required in some cases
35+
Large inventory of oil exploitation opportunities
Total Available
Comments
8
Long-Life, Low-Decline Oil Production Base
Average Annual Decline Rate (%)
10
20
30
40
Zargon Corporate Decline Analysis ‐ Total Oil Production Rate
6,000
50
Zargon
Gross W.I. Oil Production Rate ( bbl/day )
0
5,000
4,000
3,000
2,000
1,000
0
2005
2013 Additions
2012 Additions
2011 Additions
2010 Additions
2009 Additions
2008 Additions
Base Production
2006
2007
2008
2009
2010
2011
2012
2013
Data to Dec 31, 2013
Based on vintage Zargon operated production plots, we calculate base oil production declines of less than 15%. Independent research by Peters supports our view of industry low base declines.
Average 31%
Source: Peters & Co. Limited, Intermediate & Junior Universe (November 3, 2014)
Oil sands and SAGD producers are not included.
9
Canadian Alkaline Surfactant Polymer (ASP) Projects
• 10 Canadian ASP Projects in operation
Sask.
Alberta
Grande Prairie
Mooney
(Black Pearl)
2011
• 2 additional projects have regulatory approval
Edmonton
• Major operators: Husky, CNRL, Cenovus
• Significant implementation in Saskatchewan: historically more favorable EOR royalty treatment
• Technology utilized in Asia since 1980’s
Coleville (Penn West)
2011
Suffield
(Cenovus)
2007
In Progress
Scheme Approved
Calgary
Little Bow (Zargon)
Taber (Husky)
2008
Lethbridge
Taber South (Husky)
2006
Fosterton (Husky)
2012
Bone Creek (Husky) Medicine Hat
Grand Forks
(CNRL)
Battrum
(Hyak Energy)
Gull Lake (Husky) 2009
Instow
(Crescent Point)
2007/11
10
Little Bow ASP
Enhanced Oil Recovery (EOR) With Proven Technology
EOR in a mature, southern Alberta waterflood
• Phased Development; ASP injection commenced March 2014
Little Bow ASP: Phase 1&2 Development
Alberta
15-18W4
Little Bow Mannville “P” Pool
Capital:
• Completed Phase 1 Capital: $51 Million (excludes chemical)
• Upcoming Phase 2 Capital: $12 million evenly split in 2015‐16
Little Bow
• 2015 Chemical Costs: $12 million
Little Bow Mannville “I” Pool
Incremental ASP production (Zargon forecast):
Zargon Land
Zargon Wells
Phase 1 Area
Phase 2 Area
2015 Q1‐Q4: 100, 250, 500 and 750 bbl/d
2015 Avg: 400 bbl/d
2016 Avg: 1,200 bbl/d
Incremental ASP Reserves:
• Zargon forecast incremental oil recovery (phases 1 & 2):
5.2 million barrels (12% doiip)
• McDaniel forecast incremental oil recovery (phases 1 & 2): 4.5 million barrels (proved and probable) 11
1.5 million barrels (proved)
Little Bow ASP Project Milestones
RECENT HIGHLIGHTS
Photo Courtesy STRIKE Energy Services
•
ASP facility, oil battery and field construction complete and online in March 2014 ($50 million capital construction and startup costs).
•
By mid‐December 2014, have injected 2.8 million barrels of ASP solution (9 percent of phase 1 target pore volume). Reservoir pressure and injection data provides strong evidence of oil banks being formed in the reservoir. Now, 50 bbl/d of incremental ASP production primarily from four producers in close proximity to ASP injectors. •
In late July 2014, Alberta Energy announced retroactive revisions to the Enhanced Oil Recovery (“EOR”) Crown royalty program that have a very positive effect on Zargon’s Little Bow ASP economics. 12
ASP Enhanced Oil Recovery Process
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 could not recover.
Objective
Wash out more oil from an existing reservoir.
a) Water Injection:
More than half of oil is “trapped”
b) Alkali / Surfactant
Mobilizes trapped oil
Rock
Rock
•Surfactants (Detergent): Mobilizes trapped oil
Water
Injection
•Alkali: Increases effectiveness of the surfactant
Trapped
Oil Droplet
Water
a) Water Injection
Injector
•Polymer (Thickener):
Thickened water helps sweep oil from the reservoir
Alkali &
Surfactant
Solution
Water
Mobilized Oil Droplet
b) Polymer Injection
Producer
Injector
Polymer
Solution
Producer
Increased
Contact
Volume
13
ASP Chemical Flooding – Injection Sequence
1 – ASP Injection
A Blend of Alkali, Surfactant & Polymer mobilizes trapped oil
OIL BANK
2 ‐ Polymer “Push”
Polymer displaces mobilized oil to producing wells
ASP
POLYMER
3‐ Terminal Waterflood
Completes the Displacement
WATER
Little Bow Phase 1 & 2 Injection Schedule
2013
Phase 1
Phase 2
2014
ASP
2015
2016
2017
Polymer
ASP
2018
2019
2020
2021
Waterflood
Polymer
14
Little Bow ASP
Analog ASP Project: Husky Taber Mannville “B”
Taber Mannville “B” ASP Analog Project
Little Bow Mannville “I”
and “P” Pools (Zargon)
• Most mature Canadian ASP Project; Husky Operated
• Same geological setting, oil quality, reservoir size and was at same state of depletion as Zargon’s Little Bow Pool
• First ASP Injection: 2006
• Incremental recovery of greater than 12% is projected
Taber Production History
10,000
ERCB DPIIP = 43.1 mmbbl
Ult. Recovery *
ASP Recovery
% mmbbl
mmbbl
8
3.4
20.5
10
4.3
21.3
12
5.2
22.2
14
6.0
23.0
16
6.9
23.9
* Ultimate Recovery where ASP flood returns to pre‐ASP levels
First ASP Injection
May, 2006
Sep-08
Sep-10
Sep-12
Sep-07
1,000
Sep-09
?
Sep-11
100%
Oil Cut (%)
Oil Production (bbl/d)
Oil Rate, bbl/d
1000%
Sep-06
Sep-05
8 % R.F.
100
10 % R.F.
12 % R.F.
14 % R.F.
16 % R.F.
10%
?
Oil Cut (%)
Taber Mannville “B” Pool (Husky)
14.5 % R.F.
(Husky Application)
8 % R.F.
(Zargon PV10
Breakeven)
10
15,000
Data to July-2013
16,000
17,000
18,000
19,000
20,000
10 % R.F.
21,000
12 % R.F.
(Zargon Base
Case)
22,000
14 % R.F.
16 % R.F.
1%
23,000
24,000
25,000
Cumulative Oil Production (mbbl)
15
Little Bow ASP
Development Optimization Study (Phases 1 & 2)
1,276 cases run
Zargon 2013 Optimized: 6,500
Zargon 2013 Economics: 5,200
Oil Recovery
McDaniel 2013 Year End: 4,500
ASP Oil Recovery 
ASP Oil Recovery (mbbl)
Base Waterflood Recovery
• Reservoir simulation model used to optimize ASP flood design
• Multiple scenarios:
‐ ASP chemical formulation
‐ Drilling & workover locations
‐ Pattern design
• Optimized case with increased polymer bank predicts 6.5 million barrels incremental ASP oil recovery
• Using a conservative 5.2 million barrels for economics which equates to a 12% incremental recovery factor
16
Initial Oil Response at Producers Near ASP Injectors
03/16-31-014-18W4/0
16
Oil Cut: 0.5 %
14
Oil (bbl/d)
12
10
8
6
4
Oil Cut: 0.2 %
2
0
Jul
Aug
Sep
Oct
Nov
Dec
Jan
02/10-32-014-18W4/0
50
Oil Cut: 6.0 %
45
40
Oil (bbl/d)
35
Oil Producer
ASP Injector
Waterflood Injector
30
Oil Cut: 2.0 %
25
20
15
Oil Cut: 0.8 %
10
5
0
Jul
Aug
00/07-32-014-18W4/0
Oct
Nov
Dec
Jan
16
16
14
Oil Cut: 1.0 %
14
Oil Cut: 0.5 %
12
Oil (bbl/d)
12
Oil (bbl/d)
Sep
02/02-32-014-18W4/0
10
8
6
10
8
6
4
4
Oil Cut: 0.1 %
2
2
Oil Cut: 0.%
17
0
0
Jul
Aug
Sep
Oct
Nov
Dec
Jan
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Jan
Little Bow Phase 1 ASP – Actual and Forecast Data
Little Bow ASP: Phase 1 Oil Production
1400
Updated Zargon Forecast
2015 Avg.  = 400 bbl/d
Ultimate: 5.2 million barrels
1200
bbl/d
1000
800
600
400
McDaniel TP+P
2015 Avg.  = 248 bbl/d
Ultimate: 4.5 million barrels
Daily Actuals
200
Base Waterflood (McDaniel PDP)
0
Oct-2014
Nov
Dec
Jan 2015 Feb
Mar
April
May
June
July
Aug
Sept
Oct
Nov
Dec
18
Little Bow ASP - Phase 1 Oil Response
Little Bow Phase 1 Oil Production
300
All Phase 1 Oil Producers (16)
250
OIl (bbl/d)
200
11 Selected Oil Producers
150
100
0
Jul-2014
Multi Well
ASP Response
Initial ASP
Response
50
Aug-2014
Sep-2014
Oct-2014
Nov-2014
Dec-2014
Jan-2015
19
Little Bow ASP Phase 1-4 Development Plan
(Incorporates Q2 2014 Acquisition of Phase 3 & 4 Interests)
15‐19W4
15‐18W4
ZAR W.I. (%)
Phases 1 & 2
LB “I” Pool
LB “P” Pool
ASP Phase 1&2
14‐19W4
Phases 3 & 4
U&W Unit
G Unit
MM Unit
Other
C8C / X8X
14‐18W4
“G”, “U&W” Units
“C8C/X8X” Pool
Zargon Land
Zargon Wells
W.I. DOIIP*
(mmbbl)
100
100
31
8
97
95
100
26
10
5
100 Total
9
89
“MM” Unit
*
AER DOIIP Data (Jan/2014)
Little Bow Phase 1 - 4 Injection Schedule
2013
Phase 1
Phase 2
Phase 3
Phase 4
2014
ASP
2015
2016
2017
Polymer
ASP
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
Waterflood
Polymer
ASP
Waterflood
Polymer
ASP
Waterflood
Polymer
20
Alberta Modified EOR Crown Royalty Program
PROGRAM HIGHLIGHTS AND IMPACT ON ZARGON
• Announced July 2014.
• Alberta conventional oil EOR royalties in line with Alberta oil sands and Saskatchewan conventional oil EOR programs. • 5 percent oil royalty rate for up to 10 years. • Little Bow Phase 1: Eight years expected.
• McDaniel has updated the Little Bow ASP evaluation with the new royalty program.
McDaniel (Phase 1 and 2)
McDaniel Oil & Liquids Reserves
(mmbbl)
Prev. EOR Roy. As Modified EOR Roy. of Jan. 1, 2014
As of July 1, 2014
($million)
($million)
Proved Undeveloped 1.53
25.1
39.6
Proved and Probable Undeveloped
4.48
66.3
98.6
21
Little Bow ASP Phases 1 & 2 Project Economics (Zargon est.)
80C$/bbl Flat (Edm) with new EOR royalty & January 2015 eff. date
Little Bow ASP: Phases 1&2 Production
Go Forward
IRR (%)
90
PV10 ($million)
106
2500
Phase s 1&2 12% Recovery (5.2 mmbbl)
2000
Netback ($/bbl) (1)
16
(1)
55
(1)
3.4
Recycle Ratio Phase 2
1500
BOPD
F&D ($/bbl) Phase 1
1000
Oil Reserves (mbbl)
5,200
(2)
Capital ($million)
12 Chemical ($million) (3)
71
500
Base Waterflood
0
2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Zargon internal production forecasts Oil Price: Flat 80 C$/bbl (at Edmonton)
Effective Date: January 1, 2015 McDaniel July 1, 2014 proved and probable undeveloped case: 2P reserves – 4.5 mmbl, 2P PV10 – $98.6 million
(1) ASP Chemical injectant booked as capital
(2) Phase 2 capital; incurred in 2015 and 2016
(3) Prior chemical estimate of $77 million; modified by US/Cdn exchange assumptions and 3 months of completed injections
22
Little Bow ASP Phases 3 & 4 Project Economics (Zargon est.)
80C$/bbl Flat (Edm) with new EOR royalty & January 2015 eff. date
ASP Development Forecast - Phases 1-4
Phases 1 ‐ 4 Go Forward Economics
3000
Phases 3 & 4 Phases 1 ‐ 4
37
82
PV10 ($million)
51
157
F&D ($/bbl) (1)
23
19
Netback ($/bbl) (1)
61
58
(1)
2.7
3.0
Oil Reserves (mbbl)
4,650
9,850
Capital ($million) (2)
20
32
(3)
85
156
Recycle Ratio Chemical ($million) Zargon W.I. Production
2500
Phases 3&4
11% Recovery
97% W.I.
2000
BOPD
IRR (%)
1500
Phases 1&2
12% Recovery
100% W.I.
1000
500
Base Waterflood
0
2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Zargon internal production forecasts Oil Price: Flat 80 C$/bbl (at Edmonton)
Effective Date: January 1, 2015 Reflects Current Zargon Working Interests varying from 97 – 100 %
(1) ASP Chemical injectant booked as capital
(2) Phase 3 & 4 capital; incurred in 2019 through 2021
(3) Phase 3 & 4 chemical costs; incurred in 2019 through 2027
23
Little Bow ASP Project
Excellent Go Forward Netbacks and Recycle Ratios
The Little Bow ASP project, provides a well‐defined, high‐return reinvestment program
through the end of the decade; and will be allocated the majority of Zargon’s capital in this current low price environment. Future Development Costs Future Capital Costs
Future Chemical Costs
Total Future Capital Oil Reserves (Zargon estimate)
Future Development Cost
Phase 1‐2
Phase 1‐4
$ 12 million
$ 71 million
$ 83 million 5,200 mbbl
$ 16/bbl $ 32 million $ 156 million
$ 188 million 9,850 mbbl
$ 19/bbl Incremental ASP Netbacks & Recycle Ratios for Phase 1‐2
Estimated Field Price (Cdn.)
Effective EOR Royalty, %
Incremental Op. Costs Incremental Field Netback
Future Development Costs (Phase 1‐2) Go Forward Recycle Ratio
$65 US/bbl
$85 US/bbl
$ 49/bbl
5 %
$ 8/bbl
$ 38/bbl $ 16/bbl 2.4 times
$ 72/bbl 5 %
$ 8/bbl
$ 60/bbl $ 16/bbl 3.8 times
Notes:
–
EOR royalties reflect recent Alberta EOR royalty modifications, which are calculated to be in effect for the first 8 years of each phase. –
Existing operations are carrying the battery, gas plant, and field costs; therefore incremental costs are low. Chemical costs are treated as capital.
24
2014 Property Disposition Program
Objective: Conclude property dispositions that high‐grade and concentrate the Company’s properties on our core oil exploitation business:
• Completed 2014 property sales: – $1.5 million of Q1 proceeds for one Saskatchewan property (9 bbl/d)
– $3.2 million (net) of Q2 proceeds relating to five Alberta transactions (23 bbl/d and 1,050 mcf/d)
– $6.6 million of Q3 proceeds relating to seven Alberta transactions (17 bbl/d and 7,080 mcf/d)
– $25.0 million ($22.5 million cash) of Q4 proceeds for Hamilton Lake property (170 bbl/d and 1,400 mcf/d)
– Total cash proceeds of $33.8 million (net) for approximately 220 bb/d and 9,500 mcf/d (or 1,800 boe/d)
• More than 350 net active wells have been removed in these sales.
• Only a few minor non‐core properties remain for potential sale.
25
2014 Updated and 2015 Capital Programs
2014 (Oct. update)
2015
ASP Phase 1 Construction Capital
$ 8 million
$ nil
ASP Phase 1 Exploitation Capital
$ 2 million
$ 2 million
ASP Phase 2 Development Capital
$ nil
$ 6 million
ASP Phase 1 Chemical Costs $11 million
$12 million
$21 million $20 million $36 million
$12 million
$57 million $32 million Total ASP Capital Conventional (non ASP) Capital Total Capital Program If no change in debt is assumed, the $32 million of 2015 capital programs plus $11 million of dividends ($0.03 per share per month) must be balanced by $43 million of 2015 corporate cash flows, which (based on our corporate modeling – inputs provided on the next slide) will require an average WTI price of approximately $70 US per barrel during the next two years. Zargon’s cash flow models indicate that 2015 corporate cash flows are very sensitive to WTI oil prices (a $10 US/bbl WTI change in oil prices results in more than a $10 million change in corporate cash flows and a $15 million change in cash flows if the effect of hedges are excluded.) 26
Production Guidance and Cost Targets
•
•
•
Oil and Liquids Guidance:
‐ Q1 2014
4,300 barrels per day (4,320 bbl/d reported) (+)
‐ Q2 2014 4,200 barrels per day (4,096 bbl/d reported) (‐)
‐ Q3 2014
4,200 barrels per day (4,194 bbl/d reported) (even)
‐ Q4 2014 ‐ Q1 2015 4,100 barrels per day (reflects completed property sales)
4,100 barrels per day (includes Hamilton Lake sale and 100 bbl/d of ASP)
‐ Calendar 2015
‐ Calendar 2015
3,800 barrels per day (excl. ASP)
400 barrels per day (ASP)
Natural Gas Guidance:
‐ Q1 2014
‐ Q2 2014 ‐ Q3 2014
14.0 million cubic feet per day (14.1 mmcf/d reported) (+)
14.0 million cubic feet per day (14.8 mmcf/d reported) (+)
10.2 million cubic feet per day (11.2 mmcf/d reported) (+)
‐ Q4 2014 ‐ Q1 2015 6.5 million cubic feet per day (reflects completed property sales)
5.0 million cubic feet per day (reflects Hamilton Lake sale)
‐ Calendar 2015
4.8 million cubic feet per day
2015 Cost Targets (Average):
‐ Operating $20.00 per boe (includes fixed ASP and transportation costs); costs will improve during the year with growing ASP volumes.
‐ G&A $4.50 per boe; costs will improve during the year due to savings from corporate downsizing combined with growing ASP volumes. ‐ Royalties Conventional Oil 19%; ASP Oil 5%; Natural Gas 11%. 27
Net Asset Value Breakdown by Property:
McDaniel Proved and Probable 2013 Yr. End Reserves
Waterflood Waterdrive
Properties
Q3/14 Oil Prod. (bbl/d)
Q3/14 Gas Prod. (mmcf/d)
McD. Oil Res.
(mmbbl)
McD. Gas Res. (bcf)
H1/14 CF (million)
PV10 Asset Value (million)
Williston Basin
1,673
0.56
7.65
0.95
$ 17
$ 171
Taber South
737
0.08
2.35
0.20
$ 7
$ 66
Bellshill (incl. Killam)
863
0.59
2.36
2.26
$ 8
$ 62
Little Bow Conventional
Subtotal – Core
546
3,819
1.31
2.54
2.40
14.76
2.25
5.66
$ 4
$ 36
$ 48
$ 347
Non‐Core Assets
Q3/14 Oil Prod. (bbl/d)
Q3/14 Gas Prod. (mmcf/d)
McD. Oil Res.
(mmbbl)
McD. Gas Res.(bcf)
H1/14 CF ($million) PV10 Asset Value ($million)
Hamilton Lake Now Sold
168
1.38
0.70
3.02
$ 2
$ 15 (sold for $25)
Non Core Remaining
198
3.40
0.87
9.55
$ 3
$ 23
Non Core Now Sold
Subtotal – Non‐Core
9
375
3.84
8.62
0.16
1.73
20.31
32.88
$ 3
$ 8
$ 18 (sold for $12)
$ 56
Little Bow ASP Assets
Q3/14 Oil Prod. (bbl/d)
Q3/14 Gas Prod. (mmcf/d)
McD. Oil Res.
(mmbbl)
McD. Gas Res.(bcf)
H1/14 CF
($million)
PV 10 Asset Value ($million)
Subtotal – ASP
nil
nil
4.48
1.72
$ nil
$ 66 (revised $99)
Grand Total
4,194
11.16
20.97
40.26
$ 44 $ 469
Core waterflood and waterdrive property value of $347 million less estimated December 22/14 net debt of $113 million leaves $234 million or $7.75 per Zargon share (30.18 million shares outstanding). H1 2014 field cash flow for these properties was $36 million.
Based on the year end 2013 report, the Little Bow ASP and other remaining assets (after sales) added another $89 million of value, or $2.95/share. This calculation does not incorporate the negative effect of updated commodity prices or the 28
positive effect of new EOR royalties for the Little Bow ASP project. Key Takeaways at Current Share Price
(December 19, 2014)
• Due to a sharp declines in oil prices, Zargon monthly dividend has been reduced to $0.03 per share. – Zargon has reduced its dividend to balance cash inflows and outflows in a low oil price period. Improved oil prices and growing ASP production in subsequent years are expected to provide significant free cash flow that will deliver significant dividend growth.
• The Little Bow ASP project provides significant oil production per share growth for the 2015‐2017 period. – Little Bow phase 1‐2 production rates are forecast to peak in 2018. Phases 1‐4 peak rates are in 2021. ASP project success will lead to follow‐on projects at Little Bow and potentially other Southern Alberta properties. • Zargon shares represent exceptional value at the current share price of $3.66 per share.
– Investors buy Zargon at a large discount to the proved and probable net asset value for Zargon’s conventional waterflood and waterdrive oil assets. Arguably, no value is attributed to the substantial Little Bow ASP project. 29
Appendices
WWW.ZARGON.CA
Williston Basin Waterflood and Waterdrive Property
Summary
Historical ‐ Current Assets
2008
2009
2010
2011
2012
2013
2014
2900
• The Williston Basin properties have been developed with horizontal producers and injectors. Significant oil exploitation work remains.
• Since 2008, the Williston Basin properties have provided $281 million of property cash flow and $147 million of free cash flow after capital, in addition to providing a net $87 million of proceeds from property dispositions.
2800
2700
2600
2500
2400
2300
2200
2100
2000
1900
1800
1700
1600
1500
1400
1300
1200
1100
1000
2008
2009
2010
2011
2012
2013
2014
31
Williston Basin
Activity Summary and Orientation Map
Ongoing Activities
• Exploit long life low decline pools with horizontal wells and waterflood enhancements.
Saskatchewan
Manitoba
2014 Activities
• Drill 8 exploitation horizontal wells at Steelman, Weyburn, Ralph and Mackobee Coulee.
• Upgrade 2 central batteries (Weyburn, and Steelman).
• Modify and enhance existing waterflood projects (Steelman and Ralph).
Ralph
Frys
Weyburn
Steelman
2015 Activities
• The size and scope of the Williston Basin conventional oil exploitation capital programs will be dependent on the corporate cash flows available. • Drill multiple exploitation horizontal wells at Frys, Weyburn, Huntoon, Ralph and Mackobee Coulee.
• Upgrade 2 central batteries (Huntoon
and Elswick).
• Modify and enhance existing waterflood projects (Weyburn, Frys and Elswick).
Elswick
Estevan
Workman
North Dakota
Haas
Truro
Mackobee Coulee
32
Taber South Waterflood Property Summary
Taber S ‐ Production Contribution by Drilling Program Date (29 hz wells)
The Taber South waterflood property has been developed with horizontal producers and injectors. Now, mostly developed the property provides significant free cash flow.
1,000
Pre 2008 2008 2009 2010 Q1 2011 Q3 2011
Q4 2012
Q4 2013
Q2 2014
900
800
Oil Rate (bbl/d)
700
600
500
400
Since 2008, the property has provided $80 million of property cash flow and $43 million of free cash flow after capital. 300
2 wells converted to Water Injection
200
100
1 well converted to Water Injection
1 well converted to Water Injection
0
2007
2008
2009
2010
2011
2012
2013
2014
33
Taber South
Future Sunburst Hz Oil Development
• 2014 Activities
• Drilled 2 hz Sunburst wells in Q2
• Plan to drill 2 hz Sunburst wells in Q4
• (1 MM$/well)
• Injector conversion in south pool (04/6‐1 hz) in Q4 (300 M$)
• Oil tank replacement at 15‐36 battery (500 M$)
• Future Activities
• Continue drilling program (3‐5 wells)
• Increase water handling capacity at 14‐11 battery (FWKO & Disposal wells) (1‐2 MM$)
34
Little Bow Waterflood Property Summary
Existing assets prior to ASP increment
Little Bow Core Area Production
800
700
Oil Rate (bbl/d)
600
500
Zargon Operated Oilwells
400
No Drilling Activity ‐ Well Reactivation/Optimization Projects
300
200
Jan‐10
Jul‐10
Jan‐11
Jul‐11
Jan‐12
Jul‐12
Jan‐13
Jul‐13
Jan‐14
The Little Bow waterflood property is now being re‐developed for tertiary ASP potential. Since 2009, these waterflood assets have provided $38 million of property cash flow and $20 million of free cash flow after capital.
* Includes ASP Exploitation CAPEX
35
Bellshill Lake (Waterdrive) & Killam Glauconite (Waterflood)
Property Summary
The Bellshill Lake waterdrive property has been developed with vertical producers and high volume lift. The Killam Glauconite property is a less mature property that is being developed with horizontal producers. Also, a pilot waterflood has been initiated. Since 2008, these two Bellshill Lake properties have provided $76 million of property cash flow and $36 million of free cash flow after capital. Oil Rate (bbl/day)
1,000
2008
2009
2010
2011
2012
2013
H1‐2014
Rate
(bbl/d)
488
738
607
688
703
713
718
Netback Elements
OPEX
Netback Netback
($/boe)
($/boe)
($M)
12.70
50.56
11,987
11.12
31.94
9,693
13.91
38.42
9,306
15.33
45.24
12,596
13.92
39.78
12,034
14.43
41.04
12,414
13.87
52.29
7,680
Total
75,710
CAPEX
Net Proceeds
($M)
($M)
6,302
5,686
3,684
6,009
4,863
4,443
7,570
5,026
9,185
2,849
4,067
8,348
4,368
3,312
40,037
35,673
base
2009
2010
2011
2012
2013
2014
100
Jan‐07
Jan‐08
Jan‐09
Jan‐10
Jan‐11
Jan‐12
Jan‐13
Jan‐14
36
Net Asset Value Calculations at 2013 Year End
NAV Calculation (Dec 31, 2013)
Proved + Prob. McDaniel Est. (PVBT 10%)
$ 469 million
Undeveloped Land
Deduct Est. Net Working Capital & Bank/Debenture Debt
Net Asset Value $ 17 million
‐ $ 116 million $ 370 million
Zargon Proved + Prob. Net Asset Value Reserve Category
PDP
Total Proved
P+PDP
Proved & Prob.
$12.29 per basic share
Net Asset McDaniel Value Net Asset PVBT 10% Value ($/basic ($ million)
($ million)
share)
280
181
6.03
322
223
7.40
351
251
8.36
469
370
12.29
(McDaniel January 1, 2014 price forecast and 30.09 million basic Zargon shares as of December 31, 2013)
2013 Year End Reserves – (Long‐life, low‐decline producing oil)

2P Equivalent Reserves:
27.7 million boe (RLI: 10.4 years)

Oil Reserves:
• P+P
• P+P Developed Producing
• Proved Developed Producing
21.0 million bbl (RLI: 12.4 years)
14.2 million bbl (RLI: 8.4 years)
10.6 million bbl (RLI: 6.2 years)
37
Hedging Strategy and Current Hedges
Zargon uses hedges to help fund dividends and capital programs during periods of lower commodity prices. Our oil hedging policies allow for the forward sale of:
–
up to a 70 percent maximum of estimated oil production volumes for the next 12 months. Then 60 percent for the following 12 months and 50 percent for the final 6 month period.
–
not to exceed a 30‐month period.
Current Forward Oil Sales:
Q4 2014: 2,600 bbl/d at $90.92 US/bbl (WTI) and
400 bbl/d at $99.60 Cdn/bbl (WTI)
Current Forward Natural Gas Sales:
Q4 2014: 3,000 gj/d at $4.03/gj (AECO)
Q1 2015: 3,000 gj/d at $4.18/gj (AECO)
Q1 2015: 1,600 bbl/d at $93.44 US/bbl (WTI)
Q2 2015: 1,200 bbl/d at $94.01 US/bbl (WTI) 38
Estimated (unaudited) Tax Pools (June 30, 2014)
Category
June 30, 2014
Canadian Exploration Expense
$ 55 million
Non Capital Losses
$113 million
Canadian Development Expense
$ 51 million
Canadian Oil & Gas Property Expense
$ 2 million
Canadian Undepreciated Capital Cost
$ 91 million
Other
($ 1 million)
Total Tax Pools $311 million Zargon has more than $300 million of very high quality Canadian tax pools that will shield increasing ASP revenues for many years. 39
Zargon Oil & Gas Ltd.
December 22, 2014 Corporate Presentation
WWW.ZARGON.CA