1. Corporate Presentation October 7, 2013

2. Cautionary Notes
Forward-looking Statements
This document contains certain forward-looking information and forward-looking statements within the meaning of applicable securities legislation (collectively “forward-looking statements”). The use of any of the
words “being”, “will”, “until”, “estimate”, “will be”, “is considering”, “will proceed”, “plans”, “reactivate”, “recommence”, “would be”, “could be”, “will bring”, “could bring”, “expected”, and similar expressions are
intended to identify forward-looking statements. These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in
such forward-looking statements. Such forward-looking statements should not be unduly relied upon. The Company believes the expectations reflected in those forward-looking statements are reasonable, but no
assurance can be given that these expectations will prove to be correct. This document contains forward-looking statements and assumptions pertaining to the following: business strategy, strength and focus; the
granting of regulatory approvals; the timing for receipt of regulatory approvals; geological and engineering estimates relating to the resource potential of the Properties; the estimated quantity and quality of the
Company’s oil and natural gas resources; supply and demand for oil and natural gas and the Company’s ability to market crude oil, natural gas and; expectations regarding the ability to raise capital and to continually
add to reserves and resources through acquisitions and development; the Company’s ability to obtain qualified staff and equipment in a timely and cost-efficient manner; the ability of the Company to obtain the
necessary approvals to conclude the acquisition of assets from Origin on schedule, or at all; the ability of the Company to conclude the TWN Joint Venture on schedule, or at all; the ability of the Company’s subsidiaries
to obtain mining permits and access rights in respect of land and resource and environmental consents; the recoverability of the Company’s crude oil, natural gas reserves and resources; and future capital expenditures
to be made by the Company. Actual results could differ materially from those anticipated in these forward-looking statements as a result of the risk factors set forth below and elsewhere in the document, such as the
speculative nature of exploration, appraisal and development of oil and natural gas properties; uncertainties associated with estimating oil and natural gas resources; changes in the cost of operations, including costs of
extracting and delivering oil and natural gas to market, that affect potential profitability of oil and natural gas exploration; operating hazards and risks inherent in oil and natural gas operations; volatility in market
prices for oil and natural gas; market conditions that prevent the Company from raising the funds necessary for exploration and development on acceptable terms or at all; global financial market events that cause
significant volatility in commodity prices; unexpected costs or liabilities for environmental matters; competition for, among other things, capital, acquisitions of resources, skilled personnel, and access to equipment and
services required for exploration, development and production; changes in exchange rates, laws of New Zealand or laws of Canada affecting foreign trade, taxation and investment; failure to realize the anticipated
benefits of acquisitions; and other factors. Readers are cautioned that the foregoing list of factors is not exhaustive. Statements relating to “reserves and resources” are deemed to be forward-looking statements, as
they involve the implied assessment, based on certain estimates and assumptions, that the resources described can be profitably produced in the future. The forward-looking statements contained in the document are
expressly qualified by this cautionary statement. These statements speak only as of the date of this document and the Company does not undertake to update any forward-looking statements that are contained in this
document, except in accordance with applicable securities laws. More information is available in the Company’s Annual Information Form for the year ended December 31, 2012, filed on June 17, 2013 on SEDAR at
www.sedar.com.
Reserve & Resource Estimates
The oil and gas reserve and resource calculations and net present value projections were estimated in accordance with the Canadian Oil and Gas Evaluation Handbook (“COGEH”) and National Instrument 51-101 (“NI
51-101”). The term barrels of oil equivalent (“boe”) may be misleading, particularly if used in isolation. A boe conversion ratio of six Mcf: one bbl was used by NZEC. This conversion ratio is based on an energy
equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Reserves are estimated remaining quantities of oil and natural gas and related
substances anticipated to be recoverable from known accumulations, as of a given date, based on: the analysis of drilling, geological, geophysical, and engineering data; the use of established technology; and specified
economic conditions, which are generally accepted as being reasonable. Reserves are classified according to the degree of certainty associated with the estimates. Proved Reserves are those reserves that can be
estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves. Probable Reserves are those additional reserves that are
less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves. Possible Reserves
are those additional reserves that are less certain to be recovered than probable reserves. There is a 10% probability that the actual remaining quantities recovered will exceed the sum of the estimated proved plus
probable plus possible reserves. Revenue projections presented are based in part on forecasts of market prices, current exchange rates, inflation, market demand and government policy which are subject to
uncertainties and may in future differ materially from the forecasts above. Present values of future net revenues do not necessarily represent the fair market value of the reserves evaluated. Information concerning
reserves may also be deemed to be forward looking as estimates imply that the reserves described can be profitably produced in the future. These statements are based on current expectations that involve a number
of risks and uncertainties, which could cause the actual results to differ from those anticipated. Contingent resources are those quantities of oil and gas estimated on a given date to be potentially recoverable from
known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may
include factors such as economic, legal, environmental, political and regulatory matters, or a lack of markets. Prospective resources are those quantities of oil and gas estimated on a given date to be potentially
recoverable from undiscovered accumulations. Undiscovered resources means those quantities of oil and gas estimated on a given date to be contained in accumulations yet to be discovered. The resources reported
are estimates only and there is no certainty that any portion of the reported resources will be discovered and that, if discovered, it will be economically viable or technically feasible to produce.
Private Placement
On September 19, 2013, NZEC announced a non-brokered private placement (“Offering”) of up to $15 million to consist of up to 45.5 million Subscription Receipts at a price of $0.33 each. The Subscription Receipts will
be convertible into Units consisting of one common share and one-half of one non-transferable share purchase warrant entitling the holder to acquire one share at a price of $0.45 for a period of 12 months following
closing of the Offering. The proceeds from the sale of the Subscription Receipts will be used to compete the Acquisition of assets from Origin Energy and for general working capital. The funds will be held in escrow and
released on closing of the Acquisition. If the Company is unable to close the Acquisition, the proceeds from the sale of the Subscription Receipts will be returned to the subscribers. NZEC will file a short form prospectus
with the applicable regulatory authorities in each of the provinces of Canada where Subscription Receipts are sold. On October 1, 2013, NZEC announced that it had met the finance condition precedent for the
Acquisition and would continue to raise up to $7.1 million in working capital through the sale of Subscription Receipts. See September 19 and October 1 press releases for more details.
2

3. Strategic
Acquisition
1
TWN Assets in Taranaki Basin
• Three new Petroleum Licences in the main
production fairway
• Full-cycle production facility central to
NZEC’s permits and other oil/gas fields
• Immediate value creation on closing with
production from existing wells, followed
by new exploration opportunities
$33.5 million purchase price
• $18.25 million purchase price contribution
from L&M Energy to form 50/50 joint
venture across TWN Assets
• $15.25 million contribution by NZEC
• NZEC moving through private placement
to raise working capital 2
1. On September 30, 2013, NZEC met the financing condition precedent for the Acquisition
and now awaits New Zealand government approval, the final condition required to close the
Acquisition. 2. Reserves and Resources shown on 100% basis and will be attributable to NZEC
on a 50% basis once the Acquisition and TWN Joint Venture are complete. See TWN Reserves
and TWN Resources and Cautionary Notes. 2. See Private Placement in Cautionary Notes.
3

4. Asset Overview
Permit
Working
Interest
Net Acres
2P boe
Reserves 1
Contingent
Resource 2
Prospective
Resource 2
Eltham
100%
93,166
708 M boe
-
31.6 MM bbl
Alton
65%
77,482
-
-
45.0 MM bbl
Manaia
60%
16,456
-
-
Early stage
TWN 3
50%
11,525
1,072 M boe
581 M boe
11.78 MM boe
Castlepoint
100%
551,045
-
-
208.6 MM bbl
Wairoa 4
80%
214,290
-
-
Under review
Ranui
100%
223,087
East Cape 5
100%
1,067,495
Total
2,254,546
Considering relinquishment
-
-
2P Reserves 1,780 M boe
40.5 MM bbl
355.4 MM bbl
Conventional
Focus
East Cape
Conventional and
Unconventional
Targets
TWN
Manaia
Eltham
Wairoa
Alton
Castlepoint
Ranui
1. Estimated by Deloitte LLP with an effective date of April 30, 2013. 2. Best estimate of contingent and prospective resources assuming 9% to 14%
recovery for conventional oil resources and 50% for gas resources. Estimated 2% recovery for unconventional oil resources. See detailed Reserve
and Resource tables and Cautionary Notes. 3. Acquisition of TWN Petroleum Licences and Waihapa Production Station, and TWN Joint Venture,
pending. See Strategic Acquisition. 4. Acquisition of Wairoa Permit pending NZPAM approval. 5. Grant of East Cape Permit pending NZPAM
approval. 6. TWN Reserves and Resources will not transfer to NZEC until the Acquisition is complete and NZEC files an updated reserve report.
4

5. Multiple Prospective Conventional Formations in
Taranaki Basin
Approximate Depth
2,500 metres
Mt Messenger
Moki
3,000 metres
Tikorangi
Kapuni Group
3,500 metres
Kapuni
4,000 metres
5

6. Understanding the Mt. Messenger Formation
• Four successful NZEC Mt. Messenger wells drilled to date
• 265,636 bbl produced to end of August 2013
• Initial production and decline rates varied
- Results consistent with Mt. Messenger wells on adjacent permits
• Engaged RPS, world leader in well evaluation, to complete independent
reservoir study to better understand reservoir characteristics and declines
- Used data from Copper Moki, Waitapu and other Mt. Messenger wells in region
- Resulted in a better understanding of reservoir characteristics and concluded that
declines are not related to wax buildup or mechanical issues
• Allowed NZEC to develop a composite type curve for Mt. Messenger production
• Proprietary merged 3D seismic provides better identification of targets
• Go-forward exploitation strategy
- Can more accurately estimate economic pool size with knowledge from RPS study
- Reduce costs by drilling multiple wells from each pad
- Prioritize targets close to Waihapa Production Station  expedited tie-in
6

7. TWN Joint Venture = 50/50 NZEC/L&M 1
2
3
3
3
2
1. On September 30, 2013, NZEC met the financing
condition precedent for the Acquisition and now awaits
New Zealand government approval, the final condition
required to close the Acquisition. NZEC will become the
operator of all permits and assets.
2. Total purchase consideration agreed with Origin
amounts to ~$33.5 million, of which L&M will pay $18.25
million and NZEC will pay $15.25 million.
3. TWN reserves and resources shown at a 100% basis, of
which 50% will be attributable to NZEC upon closing of
the Acquisition and TWN Joint Venture.
7

8. Investment Highlights Post Acquisition
Based on NZEC’s Mid-case Production and Financial Model
Strategic
Acquisition
• Resulting in a fully integrated upstream/midstream company with cash flow,
infrastructure and inventory to support long-term growth
Accretive to
Reserves,
Production and
Cash Flow
• Additional 1.07 million boe 2P reserves 1 with estimated before tax NPV (10%) of $31.4
million ($13.84/boe acquisition cost) 2
• Forecast production of 2,300 boe/day exit 2014 (81% oil) 3
• Forecast cash flow from operations of $26.1 million from early Q4-2013 closing to
exit 2014 3
Cornerstone
Joint Venture
Investment
• $18.25 million from L&M Energy to form 50/50 JV for TWN Licences and Waihapa
Production Station
• NZEC is operator, L&M adds technical expertise and financial participation
• L&M will pay 50% of all TWN and WPS costs  reduces NZEC’s capital spend and G&A
Immediate
Valuation
Triggers
• Reactivate six existing Tikorangi wells with gas lift  total initial production net to NZEC
of 120 bbl/d (risked) 3
• Install high volume lift on six reactivated wells  total initial production net to NZEC of
810 bbl/d (risked) 3
• Uphole Mt. Messenger completions in two existing wells  total initial production of
300 bbl/d (risked) 3
• Large inventory of high-impact deeper targets and development opportunities across
multiple horizons to access 88.96 million boe in resources 4
1. NZEC’s share of TWN Reserves. See TWN Reserve Estimate and Cautionary Notes. 2. Purchase Price = C$33.5M total - C$18.25M from L&M Energy = C$15.25M (not including transaction costs). 3. NZEC midcase forecast based on 50% ownership of TWN. See Assumptions. 4. NZEC’s share of Prospective Resources across Taranaki permits. See Resource Estimates and Cautionary Notes. Production, Reserves and
Resources stated are NZEC’s share unless otherwise noted.
8

9. Significant Growth in Reserves Post Acquisition 1
Estimated Reserves
Mboe
2500
2000
1500
1000
500
0
NZEC Reserves
Proved
TWN Reserves
Probable
Total NZEC Reserves
Post Acquisition 1
Possible
1. Reserves estimated by Deloitte LLP. NZEC reserves have an effective date of December 31, 2012 and are restricted to the Eltham Permit.
TWN Reserves have an effective date of April 30, 2013 and are restricted to the Tikorangi Formation on the Waihapa and Ngaere Permits. See
detailed Reserve tables and Cautionary Notes. Reserves reflect NZEC’s 50% working interest upon completion of the TWN Joint Venture. The
TWN Reserves will not be attributable to NZEC until the Acquisition closes and NZEC files an updated reserve report.
9

10. Planned Post Acquisition Work Program
(Balance of 2013 and 2014)
Balance of 2013
Existing Tikorangi Well Reactivations
• Reactivate six Tikorangi wells with gas lift
• High volume lift installation on two initial wells
$2.1 million
Mt. Messenger development
• Waitapu artificial lift and tie-in
• Two Mt. Messenger uphole completions in existing wells
• Horoi exploration well (including surface infrastructure)
$5.2 million
2013 Total (to be funded initially by existing working capital and cash flow from production)
$7.3 million
2014
Existing Tikorangi Well Reactivations
• Increase water handling capacity
• High volume lift installation on four remaining wells
$8.4 million
New Tikorangi wells
• Drill two new Tikorangi wells
$7.9 million
Mt. Messenger development
• Three new Mt. Messenger wells (including surface infrastructure)
$6.1 million
Seismic acquisition, G&G studies and Other
$2.0 million
2014 Total
$24.4 million
Expenditures reflect NZEC’s net working interest in its various permits. See Assumptions.
10

11. Near-term Work Program
11

12. Immediate Catalyst – Existing Tikorangi Well Reactivations
Drill-proven formation
• 23.6 million bbl historical production from 11 wells since 1992 1
• Remaining 2P reserves estimated at 1,852,700 bbl oil,
1.45 Bcf gas, 50,700 bbl NGL (100% basis) 2
• Fractured limestone reservoir oil recoveries can be as high as
65% of OOIP (OIIP range estimated at 25 to 100 million bbl)
Recommence production from six existing wells
• Proof of concept  Origin reactivated Ngaere-1 well
intermittently in June and July
• Gas lift system in place, standard technology
• Permanent gas supply identified
• Gathering systems in place to deliver product to market
• NZEC operations team has hands-on experience with the assets
Low cost, high reward
• $400,000 (NZEC share) to reactivate gas lift
• Forecast total forecast initial production of 120 bbl/d (risked) 3
• High volume lift on six wells adds total forecast initial
production of 810 bbl/d (risked) 3
• Flush production not included in model = upside
1. See Historical Production – Tikorangi Formation. 2. Reserve estimate completed by Deloitte LLP with an
effective date of April 30, 2013. Reserves restricted to the Tikorangi Formation on the Waihapa and Ngaere
Permits. See Cautionary Note Regarding Reserve & Resource Estimates. Reserves will be attributable to NZEC on
a 50% basis when the Acquisition and TWN Joint Venture are complete and NZEC files an updated reserve
report. 3. NZEC mid-cases. See Assumptions and Planned Post Acquisition Work Program.
12

13. Tikorangi Reactivations
Forecast Production and Cash Flow Attributable to NZEC
780 bbl/d from Tikorangi Reactivations (exit 2014)
C$11.09 million additional cash flow from operations (exit 2014)
900
800
700
Tikorangi - Gas Lift
(Gas lift replaced with High Volume Lift)
600
Daily production (bbl/day)
Tikorangi - High Volume Lift
500
400
300
200
100
-
T+1M
T+2M
T+3M
T+4M
T+5M
T+6M
T+7M
T+8M
T+9M
T+10M
T+11M
T+12M
T+13M
T+14M
T+15M
T+16M
NZEC’s share of production and cash flow from operations. See Planned Post Acquisition Work Program and Assumptions.
13

14. Tikorangi – Two New Wells in 2014
Drill new wells to access oil reserves
• 410,300 bbl (100% Basis) 2P Undeveloped
Reserves attributed to crestal well 1
- Crestal well planned for 2014
• NZEC study indicates higher productivity
within 250 metre fault buffer zone
• Two potential locations identified for
second well to be drilled in 2014
• Forecast total initial production of
750 bbl/d (both wells, risked) 2
1. Reserve estimate completed by Deloitte LLP with an effective date of April 30, 2013.
Reserves restricted to the Tikorangi Formation on the Waihapa and Ngaere Permits. See
Cautionary Note Regarding Reserve & Resource Estimates. Reserves will be attributable to
NZEC on a 50% basis when the Acquisition and TWN Joint Venture are complete and NZEC files
an updated reserve report. 2. See Assumptions and Planned Post Acquisition Work Program.
14

15. New Tikorangi Wells
Forecast Production and Cash Flow Attributable to NZEC
490 bbl/d from New Tikorangi Wells (exit 2014)
C$8.46 million additional cash flow from operations (exit 2014)
800
700
600
Daily production (bbl/day)
Tikorangi New Wells
500
400
300
200
100
T+7M
T+8M
T+9M
T+10M
T+11M
T+12M
T+13M
T+14M
T+15M
T+16M
NZEC’s share of production and cash flow from operations. See Planned Post Acquisition Work Program and Assumptions.
15

16. Mt. Messenger Work Program
Two Uphole Completions, Four New Wells in 2013/2014
Drill-proven formation
• Significant discoveries to the west (TAG: Cheal), south
(NZEC: Copper Moki, Waitapu, Arakamu) and east
(Kea: Puka)
• Contingent resources: 88,000 bbl oil (100% basis) 1
• Prospective resources: 2,061,000 bbl oil (100% basis) 1
Low-cost production potential in existing wells
• Well information shows uphole completion potential
in six existing Tikorangi wells
• Drill pads and gathering systems in place  reduced
drilling expense, expedited tie-in
• Work program includes two uphole completions in
existing Tikorangi wells by end 2014 with forecast total
initial production of 300 bbl/d (both wells, risked) 2
New exploration opportunities
• More than 18 new Mt. Messenger leads identified on
3D seismic
• Five targets at Waipapa site, permitting complete
• Work program includes four new wells by end of 2014
with forecast total initial production of 330 bbl/d
(risked) 2
1. Prospective resources for Mt. Messenger formation only, shown on a 100% basis. Additional ~880,000 bbl prospective
resources estimated for Urenui and Moki formations. See TWN Resource Estimate and Cautionary Notes. Resources will be
attributable to NZEC on a 50% basis when the Acquisition and TWN Joint Venture are complete. 2. See Assumptions and Planned
Post Acquisition Work Program.
Waipapa wellsite
16

17. Mt. Messenger Development Program
Forecast Production and Cash Flow Attributable to NZEC
540 bbl/d from Mt. Messenger Development (exit 2014)
C$6.21 million additional cash flow from operations (exit 2014)
Mt. Messenger - Uphole Completion in Existing Tikorangi Wells
700
600
Mt. Messenger - Development (incl. Horoi)
500
Daily production (bbl/day)
Waitapu - Artificial Lift
Copper Moki - Existing
400
300
200
100
T+1M
T+2M
T+3M
T+4M
T+5M
T+6M
T+7M
T+8M
T+9M
T+10M T+11M T+12M T+13M T+14M T+15M T+16M
NZEC’s share of production and cash flow from operations. See Planned Post Acquisition Work Program and Assumptions.
17

18. Kapuni Group – High Impact Deep Targets
Two Kapuni Wells to be Drilled in 2014
Drill-proven formation
• Kapuni Gas Field onshore oil/gas discovery (Shell)
producing since 1969, estimated ultimate recovery
of 1,365 billion cf (Bcf) natural gas and 66 million
bbl oil
• TWN Licences tested by four wells  all
encountered gas in the Kapuni Group
• Work program includes two Kapuni wells by end of
2014 with forecast total initial production of 1,216
boe/d (risked) (100% basis)  funded by farm-in
partner 1
2013 Deloitte Resource Estimate 2
• Contingent resource: 5.0 Bcf gas, 233,000 bbl NGL
(100% basis)
• Prospective resource: 95.8 Bcf gas, 4.5 million bbl
NGL (100% basis)
• Discovered PIIP: 13.8 Bcf gas (100% basis)
• Undiscovered PIIP: 261.1 Bcf gas (100% basis)
1. See Assumptions and Planned Post Acquisition Work Program. 2. Shown on a 100% basis. See
TWN Resource Estimate and Cautionary Notes. Resources will be attributable to NZEC on a 50%
basis when the Acquisition and TWN Joint Venture are complete.
18

19. Total Forecast Production and Cash Flow
Attributable to NZEC
2,300 BOE/d (exit 2014)
C$26.11 cumulative cash flow from operations (exit 2014)
3,000
C$ 25
2,500
Cumulative cash flows from operations (C$ millions)
Kapuni New Wells
Tikorangi New Wells
1,500
1,000
Daily production (BOE/day)
Tikorangi - High Volume Lift
2,000
C$ 30
Tikorangi - Gas Lift
Mt. Messenger - Uphole Completion in Existing Tikorangi Wells
Mt. Messenger - Development (incl. Horoi)
Waitapu - Artificial Lift
Copper Moki - Existing
Cumulative Operating Cash flows (C$)
500
-
C$ 20
C$ 15
C$ 10
C$ 5
C$ -
C$ (5)
T
T+1M
T+2M
T+3M
T+4M
T+5M
T+6M
T+7M
T+8M
T+9M
T+10M T+11M T+12M T+13M T+14M T+15M T+16M
NZEC’s share of production and cash flow from operations. See Planned Post Acquisition Work Program and Assumptions.
19

20. NZEC vs. International Producer Comps
• Attractive Cash Flow Netback metrics
CF Netback – 2014E ($/boe)
$53.75
Average = $33.04
$50.76
$44.37
$37.64
$40
$36.39
$36.70
$30.81
$26.81
$22.78
$20
$11.08
Valeura Energy
TransGlobe Energy
Petroamerica Oil
Niko Resources
Cub Energy
Coastal Energy
Caracal Energy
Canacol Energy
Bankers Petroleum
$0
New Zealand (PF)
CF Netback - 2014E ($/ boe)
$60
See Assumptions. Note: All comparables data per Canaccord Genuity Research.
20

21. Price Paid by NZEC vs. Transaction Precedents
• An attractive Purchase Price1 on a 2P reserve and boe Produced Daily basis
Transaction Precedents ($/boe 2P) 2
Transaction Precedents ($/boe Produced Daily) 3
$80,000
$15
$13.84
$14.12
Transaction Precedents
($/ boe Produced Daily)
Transaction Precedents
($/ boe 2P)
$20
$74,373
$60,000
$40,000
$20,000
$9,455
$0
$10
50% TWN
Transaction
Precedent
Average
50% TWN
Transaction
Precedent
Average
1. Purchase Price = C$33.5M total - C$18.25M from L&M Energy = C$15.25M (not including transaction costs). 2. Based on pre-transaction 2P
of 708.3 mboe and post-transaction 2P of 1,780.7 mboe. 3. Based on NZEC’s forecast 2014E boepd of 1,569 from the newly acquired
properties (total attributable 2014E is 1,801 boe/d). See Assumptions. Note: Precedent averages are from a Canaccord Genuity Research
International Light Oil transaction database (65 deals from Jan12 to present).
21

22. Full-cycle Production Station
22

23. Waihapa Production Station Assets
Full-cycle facility with gathering and sales pipeline infrastructure
Oil facility
• 25,000 bbl/d oil handling facility
• 7,800 bbl oil storage capacity
• 49-km 15,500 bbl/d oil sales pipeline from Waihapa to Shell’s Omata Tank Farm
Gas facility
• 45 mmcf/d separation and compression capacity
• 70 tonne/d LPG processing capacity
• 51-km 8-inch gas sales pipeline from Waihapa to New Plymouth
• Storage bullets for LPG
Water disposal operations
• 3,600 bbl water storage capacity
• 18,000 bbl/d water injection capacity
Includes 100 acres of land providing a buffer zone surrounding the facility
1. On September 30, 2013, NZEC met the financing condition precedent for the Acquisition and now awaits New Zealand
government approval, the final condition required to close the Acquisition.
23

24. Production Facility: Buy vs Build
Waihapa Production Station 1
Neighbouring Production Facility 4
Gas processing
45 MMcf/day
Gas processing
15 MMcf/day
Oil handling
25,000 bbl/day
Oil handling
5,000 bbl/day
Water handling
18,000 bbl/day
Water handling
None
LPG recovery
70 tonne/day
LPG recovery
None
Pipelines
8” 49-km oil sales line to Shell’s Omata Tank Farm
8” 51-km gas sales line to New Plymouth
Gas lift for Tikorangi wells
Pipelines
11-km gas line to New
Zealand’s open access
gas pipelines
Cost to buy
C$33.5 million (100% basis)
• Includes 23,049 acres of Petroleum Licences
estimated to host 2,144,700 boe of 2P reserves
with $62.9 million NPV (before tax, 10% discount,
Cost to expand
C$30 million
No exploration land
100% basis) 2
• Includes additional 1,162,000 boe contingent
resources, 23,541,000 boe prospective
resources (100% basis) 2
Cost to replace 3
+/- 30%
Oil plant: NZ$35.2 million, Gas plant: NZ$40.8 million
Gathering systems: NZ$70.6 million, Wellsite and satellite facilities: NZ$10.6 million
1. On September 30, 2013, NZEC met the financing condition precedent for the Acquisition and now awaits New Zealand government approval, the final condition required to close the Acquisition.
2. Reserves and resources reported on a 100% basis, of which 50% will be attributable to NZEC when the Acquisition closes and NZEC files an updated reserve report. See TWN Reserves and TWN
Resources and Cautionary Notes. 3. Cost to replace plant and pipelines estimated by Strive Engineering effective July 18, 2012. 4. Information regarding neighbouring production facility compiled
using publicly available information.
24

25. Waihapa Midstream Business Plan
* To be owned by TWN Limited, a 50/50 Limited Partnership of NZEC and L&M. Operated by NZEC Ngaere Limited as the General Partner.
Contact paying a monthly fee of C$165,000 to NZEC Ngaere Limited to operate the Ahuroa Gas Storage Facility.
25

26. NZEC’s TWN Management & Operational Experience
NZEC Position
Years Relevant
O&G Experience
Years Experience
with TWN Assets
Previous TWN Associated Roles
Chris Bush, NZ
Country Manager
30+
11
Country Manager (Origin), VP Facilities (Swift)
Mike Oakes, GM
Midstream Assets
35+
8
NZ Asset Manager (Origin), Plant Super &
Commissioning Supervisor (Fletcher Energy)
Newton Cockerill
5
5
Business Performance & Accounting Manager
(Origin)
Stewart Angelo,
Engineering &
Maintenance Manager
25+
15
Maintenance & Engineering Consultant (Origin),
Maintenance Superintendent (Fletcher
Challenge)
Peter Kingsnorth,
Plant Superintendent
25+
20
Shift Supervisor (Origin), Plant Operator (Fletcher
Challenge and Petrocorp)
Pono Cooper,
Field Superintendent
25+
5
Well Site Supervisor (Origin, Swift)
26

27. Drilling Inventory
27

28. De-risking Drilling Inventory
• RPS Mt. Messenger reservoir study
• Merged 3D seismic provides better
identification of targets
• New data from Mt. Messenger
recompletions and new wells drilled on
TWN and Horoi will provide additional
insight for Mt. Messenger exploitation
strategy
• New data collected from Tikorangi
reactivations and new Tikorangi wells will
solidify exploration model for deeper, highreward targets on all Taranaki permits
• Waihapa Production Station and
infrastructure expedites tie-in, reduces
production and processing costs
28

29. New Proprietary Merged 3D Seismic Database
Reprocessed datasets
• Combined five 3D surveys
• Total area covered (full fold) 552 km2
• Pre-stack merge and post-stack time
migration complete, pre-stack time
migration underway
• Greater geological understanding of
basin reduces drilling risk by providing
consistent interpretation of seismic
anomalies and the correlation with
production success and pool size
Volume
Vintage
Area (km2)
Kapuni
1989
305
Waihapa
1989
43
Eltham
2002
20
Brecon
2006
74
Rotokare
2012
110
29

30. Individual 3D Surveys = Mismatched Data
Kapuni 3D
1989
Rotokare 3D
2012
30

31. Proprietary Merged 3D Datasets Increase Chance
of Success
Kapuni 3D
Reprocessed and merged 2013
Rotokare 3D
31

32. Inventory of Taranaki Drilling Leads
NZEC’s Copper Moki area converting to long-term mining permit
Copper Moki
Wairere
Waitapu
Waipapa
site
Arakamu
Horoi
site
32

33. Advancing Unconventional Oil Shales
33

34. East Coast Basin Oil Shales
• Over 300 oil and gas seeps sourced back to two
oil shale formations: Whangai and Waipawa
- Whangai shale package estimated to be
300 – 600 metres thick
- Characteristics similar to Bakken shales
• Two commitment wells pending (one each on
Castlepoint and Ranui) 2
• Castlepoint Permit
- 54.5 million bbl of conventional prospective
resource 1
- 154.1 million bbl of unconventional prospective
resource 1
• Ranui Permit (considering relinquishment)
- 18.0 million bbl of conventional prospective
resource 1
- 22.5 million bbl of unconventional prospective
resource 1
• NZEC retained Core Laboratories as technical
advisor to develop East Coast strategy
1. See NZEC Resource Estimates and Cautionary Notes. Acquisition of Wairoa Permit and grant of East Cape Permit pending
Crown approval. 2. Work program assumes commitment wells are funded by a farm-in partner.
34

35. East Coast Strategy
• Results from technical work providing greater
insight into unlocking shale potential
- Drilled three stratigraphic wells
- Acquired 120 km of 2D seismic
- Results pending from unconventional test on
adjoining permit
• NZEC’s technical team has worked extensively on
the East Coast as consultants  positive
relationships with local communities
-
Seismic acquisition and interpretation
Wellsite geology and prospectivity evaluation
Permitting and land access agreements
Consultation with community members, local
government, local iwi, service providers
• Castlepoint Permit
Exploration wells drilled by Westech Energy New Zealand discovered
- Drill locations identified
oil and natural gas, but did not make a commercial discovery
- Consent and permitting process underway
• Wairoa Permit
- Log data from 16 wells and more than 500 km of 2D seismic shows both conventional and
unconventional opportunities
- Reviewing 50 km of 2D seismic acquired by NZEC in 2013 (NZ$3.5 million) to identify drilling locations
• Actively seeking a partner to fund drilling program
1. Acquisition of Wairoa Permit pending Crown approval. NZEC will own 80% and operate the permit, in partnership with Westech
Energy New Zealand.
35

36. Corporate Profile – Pre Private Placement 1
Common Shares Outstanding
Options (Exercisable at average $1.35)
Fully Diluted Shares Outstanding
Insider Ownership (fully diluted)
52 Week High / Low
Average Volume (Q3-2013)
Current market cap (October 7, 2013)
Financial Highlights 2
Oil sold – cumulative to August 26, 2013 (incl. pre-production testing)
Pre-tax oil sales (incl. pre-production testing) – cumulative to August 26, 2013
Cash flow from petroleum operations – cumulative to end Q2-2013
Average realized oil price (YTD June 30, 2013)
Average field netback (YTD June 30, 2013) 3
Substantial reduction in direct production costs at Copper Moki Site
following installation of permanent production facilities (June 2013)
122.0 million
9.8 million
131.8 million
~35%
$2.10 / $0.20
~353,000 shares/day
~$40 million
264,938 bbl
$28.5 million
$17.2 million
$107.27/bbl
$35.10/bbl
1. See Private Placement in Cautionary Notes. 2. As per NZEC’s Q2-2013 consolidated interim financial statements, unless otherwise
noted. 3. NZEC’s wells are producing light (~40 API), high-quality oil that sells at Brent pricing. NZEC calculates its netback as the oil sale
price less fixed and variable operating costs and a royalty. Waitapu-2 well was shut-in in May to gather critical data and to evaluate and
install artificial lift and surface equipment, but the Company continued to incur costs on the Waitapu Site during the period.
36

37. Value Drivers Next 18 Months
• Complete Acquisition and TWN Joint Venture
• Value increase from Acquisition
- Immediately book 150% net increase in 2P reserves to 1.78 million boe with total
estimated NPV of $54.05 million (before tax, 10% discount rate) 1
- Exploitation of existing Tikorangi wells and drilling of new wells results in 15x
increase in production to net 2,300 boe/day exit 2014 (81% oil) 2
- Cumulative cash flow from operations of $26.1 million exit 2014 2
- Reduce net general and administrative costs through joint ventures and third-party
processing 2
• Leverage Waihapa Production Station and infrastructure
- Generate cash flow from existing and new liquids rich natural gas production
- Expedite tie-in of new discoveries = additional incremental cash flow
• Resume drilling program
- De-risked Mt. Messenger targets with merged 3D seismic and new drilling and
reservoir information
- Initiate exploration of high-reward deeper formations
• Experienced team with business, operations and geological expertise to execute
development plan and deliver on targets
1. NZEC’s share of TWN Reserves plus NZEC’s existing reserves. See detailed Reserve tables and Cautionary Notes. 2. NZEC forecast based on 50%
ownership of TWN Assets and execution of the planned development program. See Assumptions and Planned Post Acquisition Work Program.
37

38. Appendix
38
38

39. Comparison of Final and Original Acquisition Terms 1
Final Terms
Original Terms
Purchase price
• C$33.5 million ($18,250,000 L&M, $15,250,000 NZEC)
• 50/50 ownership by NZEC and L&M = TWN Joint Venture
• No additional adjustments to purchase price
Purchase price
• C$42 million
• Additional C$9 million in adjustments at closing
(NZEC internal estimate)
Petroleum Licences
• Ultimate NZEC ownership of 50% interest in three Petroleum Licences:
Tariki, Waihapa and Ngaere (“TWN Licences”). The Ahuroa Licence will be
transferred to Contact Energy. Net NZEC acreage: 11,525 acres (46.6 km2)
Petroleum Licences
• NZEC purchasing four Petroleum Licences: Tariki,
Ahuroa, Waihapa and Ngaere. Total acreage:
26,907 acres (108.9 km2)
Royalty payable to Origin 2
• 9% net revenue royalty payable to Origin on all future hydrocarbon
production on the Licences
• TWN Joint Venture retains the ability to buy back up to 4% of the royalty
at any time for C$4.25 million per percentage point
Royalty payable to Origin
• 5% net revenue royalty payable to Origin on all
future hydrocarbon production on the Petroleum
Licences
Commitments to Origin
Commitments to Origin
• Simplified sale agreement
• NZEC responsible for 100% of costs associated
- NZEC retains 50% of production from all existing and new wells on the
with drilling a well to the crestal interval of the
TWN Licences in all formations, subject to the Origin Royalty (and a
Tikorangi formation, with profits to be shared
10% royalty payable to the NZ Government)
50/50 with Origin
- Origin relinquishes all other rights and encumbrances on the TWN
• Origin retained rights to eight “option wells” for
Licences
gas storage
1. On September 30, 2013, NZEC met the financing condition precedent for the Acquisition and now awaits New Zealand government approval, the final condition required to close the
Acquisition. 2. The Origin royalty is payable at 9% of net revenue (hydrocarbon sales less operating expenses incurred between the point of valuation and the point of sale). TWN Joint Venture
may buy back at any time and from time to time up to 4% of the Origin royalty by paying C$4.25 million per percentage point. The TWN Licences are also subject to a government royalty payable
at 10% of net revenue as they are “grandfathered” under the 1937 Petroleum Act.
39

40. L&M Energy and Geoff Loudon
Mr. Loudon is a New Zealand based international investor with family roots going back to
the Hokitika, NZ gold fields in 1875. He was the former Chairman of L&M Energy (ASX,
NZX), which he privatized in January 2013 through a NZ$48 million takeover bid by his
company, New Dawn Energy Limited. L&M Energy holds a number of petroleum
exploration permits on the North and South Islands of New Zealand, including a 35%
interest in NZEC’s Alton Permit.
Mr. Loudon is Chairman of Nautilus Minerals Inc. (TSX), a Canadian based seabed minerals
exploration company; was a founding director from 1995 to 2010 of Lihir Gold Limited
(ASX, TSX, NASDAQ), a PNG gold miner; and a founder and investor in Peru Copper Inc.
(TSX, AMEX).
Mr. Loudon is a mining professional with qualifications in geology, engineering and
international finance. He started his career as a geologist with the NSW Geological Survey
Australia, then worked with Placer Dome in Canada in operations, development and
exploration before starting a finance career with Kleinwort Benson, a UK merchant bank.
He then founded Niugini Mining which developed gold and copper mines in PNG, Chile
and Australia and discovered the Lihir gold deposit in PNG.
Mr. Loudon is a Fellow of the Australasian Institute of Mining & Metallurgy (AIMM), a
Member of the Canadian Institute of Mining (CIM) and a Member of the American
Institute of Mining Engineers (AIME).
40

41. Historical Production – Tikorangi Formation
23.6 million bbl of historical production 1
Well name 1
Max bbl/d
Total bbl produced
Ngaere-1
7,537
4,337,084
Ngaere-2
3,658
1,002,565
Ngaere-3
8,652
1,089,505
Toko-2B
298
126,286
Waihapa H-1
1,953
45,349
Waihapa-1B
4,804
4,909,317
Waihapa-2
3,182
4,798,752
Waihapa-4
2,674
2,990,189
Waihapa-5
979
91,055
Waihapa-6A
4,674
4,262,707
1. Select production data using publicly available information regarding wells that produced
oil on the TWN Licences.
41

42. Oil in Tikorangi Formation
• 23.6 million bbl produced to date
• Numerous independent estimates of original oil in place (OOIP) ranging from
25 mmbbl (P90) to 100 mmbbl (P10) 1
• Fractured limestone oil recoveries can be as high as 65% of OOIP
• NZEC commissioned independent petroleum reservoir engineering study that concluded remaining
oil (100% basis) contained in:
- Low permeability network fractures (est. 1.5 million bbl from reactivation)
- Attic oil trapped up-dip of existing wells (est. 0.95 million bbl from new well)
- Laterally trapped oil in existing fracture system (est. 2.05 million bbl from new wells)
• Range of well productivity from existing wells, EUR = 400,000 bbl (P50)
Cum Oil (mbbl)
EUR for a new well = 400 mbbl
1. NZEC collation of independent
consultancy assessments.
42

43. TWN Reserve Estimate (100% basis) 1
Reserve Category
Light &
Medium Oil
(Mbbl)
Natural
Gas
(MMcf)
Natural Gas
Liquids
(Mbbl)
Barrels of Oil
Equivalent
(Mboe)
NPV, Before
Tax (10%)
Proved Developed
(Non-producing)
983.7
762.0
26.7
1,137.4
$36,142,000
Proved Undeveloped
258.1
206.5
7.2
299.8
$7,340,000
1,241.8
968.5
33.9
1,437.1
$43,482,000
610.9
479.3
16.8
707.6
$19,393,000
1,852.7
1,447.8
50.7
2,144.7
$62,875,000
Total Proved
Probable
Proved + Probable (2P)
1. Reserve estimate completed by Deloitte LLP with an effective date of April 30, 2013. Reserves restricted to the Tikorangi Formation on
the Waihapa and Ngaere Permits. See Cautionary Note Regarding Reserve & Resource Estimates. Reserves will be attributable to NZEC
on a 50% basis when the Acquisition and TWN Joint Venture are complete and NZEC files an updated reserve report.
43

44. TWN Resource Estimate (100% basis) 1
Formation
Product Type
Low
Best
High
Contingent Resources
Miocene Sands (Mt. Messenger)
Eocene Sands (Kapuni Group)
Total
Oil (Mbbl)
35
88
203
2,513
5,036
10,336
NGL (Mbbl)
101
233
525
BOE (Mboe)
567
1,162
2,426
Gas (MMcf – sales)
Prospective Resources
Miocene Sands (Urenui, Mt. Messenger, Moki)
Eocene Sands (Kapuni Group)
Total
Oil (Mbbl)
1,606
2,941
5,732
Gas (MMcf – sales)
42,833
95,837
226,424
NGL (Mbbl)
1,909
4,498
11,375
BOE (Mboe)
10,825
23,541
54,368
Discovered PIIP
Miocene Sands (Mt. Messenger)
Eocene Sands (Kapuni Group)
Total
Oil (Mbbl)
327
681
1,400
Gas (MMcf – raw)
7,211
13,770
26,935
BOE (Mboe)
1,529
2,976
5,889
Undiscovered PIIP
Miocene Sands (Urenui, Mt. Messenger, Moki)
Eocene Sands (Kapuni Group)
Total
Oil (Mbbl)
11,315
20,442
37,804
Gas (MMcf – raw)
118,981
261,080
605,860
BOE (Mboe)
31,145
63,955
138,781
1. Resources estimated by Deloitte with an effective date of April 30, 2013 assuming 9 to 14% recovery for oil resources and 50% for gas resources. See Cautionary Note
Regarding Reserve and Resource Estimates. Resources will be attributable to NZEC on a 50% basis when the Acquisition and TWN Joint Venture are complete.
44

45. NZEC Eltham Reserve Estimate
Marketable Oil and Gas Reserves
As at December 31, 2012
Forecast Prices and Costs
Reserves Category
Proved Developed Producing
Light & Medium Natural Gas
Oil (Mbbl)
(MMcf)
Natural Gas
Liquids (Mbbl)
Barrels Oil
NPV, Before Tax
Equivalent (Mboe)
(10%)
307.8
594.9
38.7
445.7
$14,400,000
20.6
31.9
2.0
27.9
$893,000
Total Proved
328.4
626.8
40.7
473.6
$15,293,000
Probable
158.3
329.6
21.5
234.7
$7,320,000
Proved + Probable
486.7
956.4
62.2
708.3
$22,613,000
Possible
195.6
398.1
25.8
287.8
$7,549,000
Proved + Probable + Possible
682.3
1354.5
88.0
996.1
$30,162,000
Proved Undeveloped
Notes: Gross reserves before the deduction of royalty obligations payable to the New Zealand government. Numbers may not sum due to
rounding. Reserve estimates calculated by Deloitte. Mbbl – thousand barrels of oil. MMcf – million cubic feet of natural gas. Mboe –
thousand barrels of oil equivalent using a conversion ratio of 6 Mcf : 1 bbl. Barrels of oil equivalent (boe) may be misleading, particularly if
used in isolation. The boe conversion ratio is based on an energy equivalency conversion method primarily applicable at the burner tip
and does not represent a value equivalency at the wellhead. Possible reserves are those additional reserves that are less certain to be
recovered than probable reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of
proved plus probable plus possible reserves. See Cautionary Note Regarding Reserve and Resource Estimates.
45

46. NZEC Resource Estimates (Current Permits)
Net Permit
Area
Net Permit
Acreage
377.0
Net Unrisked Prospective Recoverable
(MM barrels of oil)
Low
Best
High
93,166.1
TARANAKI BASIN
Eltham (PEP 51150)
100% NZEC
Conventional
231.4
313.6
Manaia (PEP 54867)
60% NZEC / 40% NZOG
Conventional
66.6
EAST COAST BASIN
Castlepoint (PEP 52694)
100% NZEC
Conventional
Unconventional
Ranui (PEP 38342)
100% NZEC
Conventional
Unconventional
East Cape (PEP 52976)
100% NZEC 1
Conventional
Unconventional
Wairoa (PEP 38346)
80% NZEC / 20% Westech
Conventional
Unconventional
Total
Conventional
Unconventional
Grant of permit pending.
346.8
578.8
19.7
31.6
56.9
224.8
Alton (PEP 51151)
65% NZEC / 35% L&M
Conventional
1
Net Unrisked Undiscovered Petroleum
(MM barrels of oil)
Low
Best
High
493.7
1,229.7
18.9
45.0
116.9
77,482.4
16,455.7
Early stage
2,230.0
Early stage
551,045.0
349.0
2,958.2
867.2
30.3
56.2
54.5
154.1
102.0
458.5
198.3
969.0
435.0
2,252.5
8.1
8.6
18.0
22.5
42.0
65.2
189.8
5,747.2
4,320.0
1,053.1
16,190.7
94.3
440.4
902.8
586.3
6,743.0
615.7
13,148.1
1,997.4
31,838.3
14.6
110.3
53.3
302.1
195.4
906.3
223,086.7
1,067,495.2
214,289.8
Estimate pending
9,077.2
2,243,020.9
10,235.1
1,089.3
9,145.8
23,100.9
2,240.8
20,860.1
Estimate pending
55,575.5
5,294.0
50,281.5
Source: Deloitte LLP, effective date February 1, 2011.
266.7
91.6
175.1
681.1
202.4
478.7
1,943.2
513.2
1,430.0
46

47. Drilling / Production Report Card
Drilling / Production Report Card
Well
Name
Target
Formation
Total
Depth
Status
Total Oil Prod
(end Aug 2013)
Mt. M
Mt. M
Mt. M / Moki
Mt. M / Urenui
2,220 m
2,084 m
3,167 m
2,125 m
Producing since December 2011
Producing since April 2012
Producing from Mt. Messenger since July 2012
Urenui oil discovery, shut in pending further testing
110,483 bbl
91,812 bbl
44,550 bbl
Waitapu-1
Waitapu-2
Mt. M
Mt. M
2,213 m
2,084 m
Shut in pending further testing or sidetrack
Producing since December 2012 1
Arakamu-1A
Arakamu-2
Moki
Mt. M
2,900 m
2,380 m
Suspended, pending further evaluation
Oil discovery in April 2013, awaiting artificial lift
Wairere-1
Wairere-1A
Mt. M
Mt. M
1,971 m
2,152 m
Plugged back for sidetrack
Completion pending
Copper Moki-1
Copper Moki-2
Copper Moki-3
Copper Moki-4
18,790 bbl
• Engaged RPS, world-recognized leader in geological and reservoir evaluation, to undertake
comprehensive reservoir study to assist in optimizing production and go-forward strategy
1. Waitapu-2 was temporarily shut in at the end of May to allow the Company to analyze artificial lift options and perform tests related to the Copper Moki reservoir study.
47

48. Assumptions in NZEC’s Mid-case Financial Model
(as at July 31, 2013)
Other Assumptions
Oil sales price/bbl = US$99
Natural gas sales price/GJ = NZ$4.50
LPG sales price/tonne = NZ$500
USD/NZD exchange rate = 0.79
CAD/NZD exchange rate = 0.82
Development program includes the following:
Six Tikorangi reactivations - wells placed on gas lift, subsequently on high volume lift
Two Mt. Messenger uphole completions in existing Tikorangi wells
Four New Mt Messenger wells on Alton/TWN permits
Two New Tikorangi appraisal wells
Two New Kapuni wells to be funded by new JV partner
Existing Tikorangi Wells (gas lift  high volume lift)
Reserves (unrisked, 100%)
Working interest
Probability of success
IP rate
Decline
Capital cost
(incl. surface equipment)
Operating expenditure
150,000 – 448,000 bbls/well
50%
100%
49 BOE/day – 365 BOE/day
2% – 0.5% per month
C$0.07 – C$0.8 million per well (WI)
C$15,000 per month/well (WI)
Mt. Messenger – Uphole Completion in Existing Tikorangi Wells
Expected Ultimate Recovery (unrisked, 100%)
Working interest
Probability of success
IP rate
Decline
Capital cost (incl. surface equipment)
Operating expenditure
123,000 bbls/well
50%
100%
365 BOE/day
3% – 9% per month
C$0.6 million per well (WI)
C$10,000 per month/well (WI)
Kapuni New Wells
Expected Ultimate Recovery (unrisked, 100%)
Working interest
Probability of success
IP rate
Decline
Capital cost (incl. surface equipment)
Operating expenditure
7.91 Bcf
25%
60%
1,103 BOE/day
1% per month
C$nil funded by new JV partner
C$10,000 per month/well (WI)
1. Deloitte LLP has ascribed 2P reserves of 410,300 bbl to one Tikorangi new well.
WI = based on Working Interest.
Tikorangi New Wells
Expected Ultimate Recovery (unrisked , 100%) 1
Working interest
Probability of success
IP rate
Decline
Capital cost (incl. surface equipment)
Operating expenditure
561,000 bbls/well
50%
50%
1,824BOE/day
5% – 12% per month
C$3.95million per well (WI)
C$10,000 per month/well (WI)
Mt. Messenger Development Wells (incl. Horoi)
Expected Ultimate Recovery (unrisked, 100%)
Working interest
Probability of success
IP rate
Decline
Capital cost (incl. surface equipment)
Operating expenditure (not incl. royalty)
502,000 bbls/well
50% – 65%
35% – 40%
420 BOE/day – 511 BOE/day
2% per month
C$1.7 – C$3.4 million per well (WI)
N$40/bbl
Waihapa Production Station
Working Interest
Operating expenditure (fixed)
Operating expenditure (variable)
Capital cost (in addition to purchase price)
50%
N$0.4 million per month (WI)
N$10/bbl
$7.1 million, including increasing water
handling capacity
48

49. Board of Directors
Name
Expertise
Experience
John A. Greig,
M.Sc, P.Geo
Chairman
• Founder and financier of numerous mining
and oil and gas companies. Specializing in
recognizing undervalued geological assets
• Founder, Director & Officer Sutton Resources, Cumberland
Resources Ltd., Eurozinc Mining Corp., Crown Resources Corp.
John G. Proust, C.Dir
CEO
Director
• Proven track record of building companies
from grass roots to advanced development.
Specializes in identifying undervalued assets
on a global basis
• Chairman, Director & CEO, Southern Arc Minerals Inc.
• Chairman, Director & Interim CEO, Eagle Hill Exploration Corp.
• Chairman, Canada Energy Partners Inc.
Bruce G. McIntyre,
P.Geol
Executive Director
• Professional petroleum geologist with over
30 years of proven exploration and
development oriented value creation
• President, CEO Sebring Energy Inc.
• President, CEO TriQuest Energy Corp.
• President, CEO BXL Energy Ltd.,
• Exploration Manager Gascan Resources Ltd.
Hamish J. Campbell
B.Sc (Geology),
FAusIMM
Director
• Professional geologist with 30 years of
experience managing exploration programs,
evaluation and assessment of joint ventures
and acquisitions
• Director of a number of New Zealand limited liability mineral
and petroleum companies
• Principal Indonesian mining service company
49

50. Corporate Office – Canada
Name
Expertise
Experience
• Proven track record of building companies from grass
roots to advanced development. Specializes in
identifying undervalued assets on a global basis
• Chairman, Director & CEO, Southern Arc Minerals Inc.
• Chairman, Director & Interim CEO, Eagle Hill Exploration Corp.
• Chairman, Canada Energy Partners Inc.
• Professional petroleum geologist with over 30 years of
proven exploration and development oriented value
creation
• President, CEO Sebring Energy Inc.
• President, CEO TriQuest Energy Corp.
• President, CEO BXL Energy Ltd.,
• Exploration Manager Gascan Resources Ltd.
• Chartered Accountant with expertise in financial
reporting and controls, equity offerings, treasury
management and debt structures, tax compliance
• Progressively senior positions with publicly-traded natural
resource companies
• Audit Manager, Mining Group, PricewaterhouseCoopers
Celeste M. Curran,
B.A. (Hon), L.L.B.
VP Corporate & Legal Affairs
• Over 20 years of legal and negotiating experience
specializing in major projects
• VP, Corporate & Legal Affairs, J. Proust & Associates
• Lead counsel for City of Vancouver and City of Richmond for
the 2010 Olympic and Paralympic Winter Games
• Senior Solicitor, City of Vancouver
Rhylin Bailie, B.ES
VP Communications & Investor
Relations
• More than 18 years of experience in the resource
industry, in both finance and investor relations
• Professional writer and editor
• Director Communications & Investor Relations, NovaGold
Resources Inc.
• Supervisor Treasury Administration, Placer Dome Inc.
• More than 16 years of experience overseeing
corporate governance and corporate affairs for
publicly-listed resource companies
• Corporate Secretary for various public and private resource
companies
• Director of Charlotte Resources
John G. Proust, C.Dir
Chief Executive Officer
Bruce G. McIntyre, P.Geol
Executive Director
Gerrie van der Westhuizen, CA
Interim CFO
Eileen Au, B.Sc
Corporate Secretary
50

51. Operations Team – New Plymouth, NZ
Name
Expertise
Experience
Chris Bush, B.E (Hon)
New Zealand
Country Manager
• Chemical engineer with more than 30 years in both upstream and
downstream oil and gas experience internationally
• New Zealand Country Manager/Director, Origin Energy
• Chairman of Petroleum Exploration and Producers Association
of New Zealand
Mike Oakes
General Manager
Midstream Operations
• More than 30 years of international oil and gas experience
overseeing design, commissioning and start up, staffing and
operation of oil and gas fields and production facilities
• Operations Manager, Asset Manager and Operational
Excellence Advisor, Origin Energy
• Technical Advisor, Total E&P Borneo
Cliff Butchko
P.Eng, MBA (Hon)
General Manager
Upstream Operations
• Professional engineer with over 30 years experience evaluating
and managing oil and gas resources
• President Omni Oil and Gas Inc.
• Vice President Lexoil Inc.
• Partner and Co-founder TIFF advisory group
• Senior technical positions in several resource companies
James Watchorn, B.Sc
Operations Manager
• Mechanical engineer with more than 15 years of experience in all
aspects of drilling, completions and production, and facility and
wellsite construction
• Production and Facilities Manager, TAG Oil
• Senior Petroleum Engineer, Origin Energy
• Operations Engineer, Iteration Energy/Chinook Energy
• 25 years in oil and gas midstream assets focused around
development and implementation of procedures and processes for
asset management systems
• Engineering Officer with New Zealand Merchant Navy
• Maintenance Engineer, Fletcher Challenge
• Director of Productive Maintenance
• Senior Manager, New Zealand Dept. of Conservation
• Negotiating access provisions and facilitating resource
consent process, assisting with community relationship
building
Stewart Angelo
Engineering & Maintenance
Manager
Toka Walden
Land Manager
51

52. Technical Team – Wellington, NZ
Name
Qualifications
Expertise
Dr. Ian Brown
B.Sc (Hons), M.Phil,
D.Eng, MIPENZ, C.P.Eng
June Cahill
B.Sc,
B. Applied Econ.
Bill Leask
B.Sc (Hons)
M.Sc (Hons)
Petroleum geology related to the East Coast and other New Zealand basins
Dr. Simon Ward
B.Sc (Hons)
Ph.D
Petroleum geology related to the Taranaki and other New Zealand basins
Ian Calman
B.Sc (Hons)
Seismic data acquisition, processing, and interpretation
Gareth Reynolds
B.Sc (Hons) Geology
Dr. Richard Kellett
B.Sc (Hons), Ph.D,
P.Geoph
Monmoyuri Sarma
B.Sc (Hons), M.Sc
(Petroleum Geosciences),
M.Sc (Applied Geology)
Peter Wood
B.E (Hons), B.Sc ,
M.Comp.Sci
Sam Pryde
B.Sc
Post.Grad.Dip.
Chief Operating Officer; professional geological engineer
Acquisition, management, and analysis of complex geoscience data
Geoscientist with experience in New Zealand Basin analysis
Geoscientist with worldwide exploration and business development experience
Geoscientist with experience with reservoir modelling and petroleum system
analysis
Management and development of computing resources for geoscience
applications
Geological investigations in the East Coast basin area
52

53. Analyst Coverage
Company
Analyst
Contact
Canaccord Genuity
Christopher Brown
403-508-3858
Credit Suisse
David Phung
403-476-6023
Dundee Capital Markets
David Dudlyke
44-203-440-6870
Haywood Securities
Alan Knowles
403-509-1931
Mackie Research
Bill Newman
403-750-1297
Macquarie Equities Research
Dave Popowich
403-539-8529
M Partners
David Buma
416-603-7381
53

54. Contact NZEC
Corporate Head Office
John Proust, Chief Executive Officer
Bruce McIntyre, Executive Director
Rhylin Bailie, VP Investor Relations
North America Toll-free: 1-855-630-8997
info@newzealandenergy.com
New Zealand Office
Chris Bush, New Zealand Country Manager
Tel: + 64-6-757-4470
New Zealand Toll-free: 0800-469-363
www.NewZealandEnergy.com
54