NZEC has permits covering 1.93 million acres in New Zealand with conventional and unconventional oil and gas opportunities. Its near-term work program focuses on increasing production from existing wells in the Tikorangi and Mt. Messenger formations through low-cost reactivations and uphole completions, with three new wells also planned. This is expected to increase NZEC's production to over 2,300 boe/d by the end of 2014. NZEC also has multi-zone exploration potential across its acreage and will start drilling high-impact exploration wells later in 2014.

1. TSX-V: NZ
OTCQX: NZERF
Waihapa Production Station
Corporate Presentation
April 3, 2014

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”, “forecast”, “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’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. 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. More information is
available in the Company’s Form F1-101F1 Statement of Reserves Data and Other Oil and Gas Information dated April 2, 2014, which is filed on SEDAR at www.sedar.com.
2

3. Fully Integrated Upstream/Midstream Company
• 1.93 million acres of permits with both
conventional and unconventional opportunities
• Completed strategic acquisition in October 2013
- Three petroleum mining licenses with significant
production and exploration potential
- Full-cycle production facility central to NZEC’s permits
• Strategic JV partners: L&M Energy, New Zealand Oil
& Gas, Westech Energy
• Experienced team with New Zealand and Western
Canadian exploration and operations expertise
• Focused on increasing production and cash flow 2
- Advancing existing wells to production  low-cost
workovers, rapid tie-in using existing infrastructure
- March 2014 production averaged 233 bbl/d
- Three new wells expected to add to April production
- Continuing to identify additional near-term
production opportunities from existing wells
- Plan to drill new high-impact wells later in 2014
3
1. See Reserve and Resource tables in the Appendix, and Cautionary Notes. 2. Development and operating costs are to be funded initially
by existing working capital and cash flows from production. To carry out all of the planned development activities, the Company is
considering a number of options to increase its financial capacity, including additional joint arrangements, commercial arrangements, or
other financing alternatives. Development and exploration activities and timing of activities is subject to change as the Company continues
to review and refine its 2014 program.

4. Asset Overview
4
Permit Working
Interest
Net Acres 2P boe
Reserves 1
Contingent
Resource 1
Prospective
Resource 1
Eltham 2 100% 47,395 536,000 - 31.6 MM bbl
Alton 65% 38,717 - - 45.0 MM bbl
Manaia 60% 16,456 - - Early stage
TWN 50% 11,525 1,113,000 580 M boe 11.7 MM boe
Castlepoint 100% 551,045 - - 208.6 MM bbl
Wairoa 80% 214,290 - - Under review
East Cape 100% 1,048,406 - - 355.4 MM bbl
Total 1,927,834 1,649,000 boe 2P Reserves net to NZEC
$57.9 million NPV (after tax, 10% discount)
1. Reserves and resources estimated by Deloitte LLP. For effective dates and estimated recovery rates, see NZEC’s most recent annual
and interim reserve and resource reports filed on SEDAR in April 2014, the Reserve and Resource tables in the Appendix, and
Cautionary Notes. Reserves are updated annually. 2. Final configuration of Copper Moki mining license and Eltham exploration permit
subject to NZP&M approval.
Eltham
Alton
Castlepoint
East Cape
Conventional
Focus
Conventional and
Unconventional
Targets
Wairoa
TWN
Manaia

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

6. Planned Work Program – Taranaki Basin
(Balance of 2013 and 2014) 1
6
November–December 2013
Existing Tikorangi Well Reactivations
 Reactivate oil production from six Tikorangi wells on TWN Licenses (achieved production in November)
Mt. Messenger development
 Install artificial lift in Waitapu-2 well on Eltham Permit
 Begin uphole recompletions in two existing wells on TWN Licenses
2014 1
Tikorangi development
 Optimize oil production from reactivated wells on TWN Licenses
• Install high-volume lift on select reactivated wells (first well expected to commence production in April)
• Determine potential to reactivate oil production from additional existing Tikorangi wells on TWN Licenses
• Drill new Tikorangi wells on TWN Licenses
Mt. Messenger development
 Recommence production from Waitapu-2 well on Eltham Permit (achieved production in March)
 Reactivate oil production from existing Mt. Messenger wells on TWN Licenses (achieved production in March)
• Multiple Mt. Messenger uphole completions on TWN Licenses (production from first well targeted for April)
• Drill Horoi exploration well on Alton Permit
• Drill new Mt. Messenger wells on TWN Licenses
Seismic acquisition, G&G studies and Other
1. Planned work program as at November 2013. See Assumptions. Development and operating costs are to be funded initially by existing
working capital and cash flows from production. In order to carry out all of the planned development activities, the Company is
considering a number of options to increase its financial capacity, including additional joint arrangements, commercial arrangements, or
other financing alternatives. 2. Decision to advance to commercial production contingent on flow test results from recompleted wells.

7. NZEC Production & Development Wells
Status at April 2, 2014
7

8. 8
Immediate Value from
Near-term Work Program

9. Immediate Catalyst – Existing Tikorangi Well Reactivations
Forecast impact: 780 bbl/d net to NZEC (exit 2014)
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)
Immediate production potential from existing wells
• Six wells reactivated in November  optimizing oil production
from Tikorangi formation
• Identified Tikorangi oil production potential from additional
existing wells
• Pipelines in place to deliver oil and gas production to Waihapa
Production Station, and on to market
• NZEC operations team has hands-on experience with the
properties and production station
Low cost, high reward
• $400,000 (NZEC share) to reactivate gas lift
• Achieved initial production forecast of net 20 bbl/d per well
(net 120 bbl/d all six wells, risked)3
• High volume lift adds forecast initial production of net 135 bbl/d
per well (risked) 3
9
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. Reserves attributable to NZEC at 50%. See Cautionary Note Regarding Reserve & Resource Estimates.
3. NZEC mid-cases. See Assumptions and Planned Work Program.

10. Mt. Messenger Work Program
Forecast impact: 575 bbl/d net to NZEC (exit 2014)
Drill-proven formation
• Significant discoveries to the west (TAG: Cheal), south
(NZEC: Copper Moki, Waitapu) 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 Mt. Messenger
completion potential in multiple Tikorangi wells
- First uphole completion expected to commence
commercial production in April 2014
• Forecast total initial production of net 150 bbl/d per well
(risked) 2
• Drill pads and gathering systems in place  reduced
drilling expense, expedited tie-in
New exploration opportunities
• More than 18 new Mt. Messenger leads identified on
3D seismic
• Work program includes four new wells (including Horoi
commitment well on Alton Permit) by end of 2014 with
forecast total initial production of net 80 bbl/d per well
(risked) 2
10
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. Resources attributable to NZEC at 50%. See TWN Resource Estimate and Cautionary Notes. 2.
See Assumptions and Planned Work Program. Development and operating costs are to be funded initially by existing working capital and
cash flows from production. To carry out all of the planned development activities, the Company is considering a number of options to
increase its financial capacity, including additional joint arrangements, commercial arrangements, or other financing alternatives.
Development and exploration activities and timing of activities subject to change as the Company reviews and refines its 2014 program.
Waipapa wellsite

11. Tikorangi – Two New Wells in 2014 1
Forecast impact: 570 bbl/d net to NZEC (exit 2014)
Drill new wells to access oil reserves
• 410,300 bbl (100% Basis) 2P Undeveloped
Reserves attributed to crestal well 2
- 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
net 375 bbl/d per well (risked) 3
11
1. Development and operating costs are to be funded initially by existing working capital and
cash flows from production. To carry out all of the planned development activities, the
Company is considering a number of options to increase its financial capacity, including
additional joint arrangements, commercial arrangements, or other financing alternatives.
Development and exploration activities and timing of activities is subject to change as the
Company continues to review and refine its 2014 program. 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, attributable to NZEC at 50%. See Cautionary
Note Regarding Reserve & Resource Estimates. 3. See Assumptions and Planned Work
Program.

12. Forecast Production Attributable to NZEC
12
Forecasts NZEC’s share of production from operations. See Planned Work Program and Assumptions. To carry out all of the planned
development activities, the Company is considering a number of options to increase its financial capacity, including additional joint
arrangements, commercial arrangements, or other financing alternatives. Development and exploration activities and timing of activities is
subject to change as the Company continues to review and refine its 2014 program.
2,300 boe/d (exit 2014) (81% oil)
DailyProductionnettoNZEC(boe/d)

13. Kapuni Group – High Impact Deep Targets
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 for 2015
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)
13
1. See Assumptions and Planned Work Program. Kapuni exploration contingent on finding
a funding partner. 2. Shown on a 100% basis, attributable to NZEC at 50%. See TWN
Resource Estimate and Cautionary Notes.

14. 14
Full-cycle Production Station

15. 15
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
Waihapa Production Station Assets
Full-cycle facility with gathering and sales pipeline infrastructure
1. NZEC and L&M Energy have formed a 50/50 joint venture to explore, develop and operate the TWN Licenses and Waihapa
Production Station.

16. Production Facility: Buy vs Build
Waihapa Production Station Neighbouring Production Facility 3
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,
100% basis) 1
• Includes additional 1,162,000 boe contingent
resources, 23,541,000 boe prospective
resources (100% basis) 1
Cost to expand C$30 million
No exploration land
Cost to replace 2
+/- 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
16
1. Reserves and resources reported on a 100% basis, attributable to NZEC on a 50% basis. See TWN Reserves and TWN Resources and Cautionary Notes. 2. Cost to replace plant and pipelines
estimated by Strive Engineering effective July 18, 2012. 3. Information regarding neighbouring production facility compiled using publicly available information.

17. Waihapa Production Station Generating
Third-Party Cash Flow
17
* Owned by TWN Limited, a 50/50 Limited Partnership of NZEC and L&M Energy. 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.

18. NZEC’s TWN Management & Operational Experience
18
NZEC Position Years Relevant
O&G Experience
Years Experience
with TWN Assets
Previous TWN Associated Roles
Mike Oakes,
GM Operations
35+ 8
NZ Asset Manager (Origin), Plant Super &
Commissioning Supervisor (Fletcher Energy)
Derek Gardiner,
CFO
25 3
Commercial & Finance Manager
(Origin)
Newton Cockerill,
Controller
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 Services Supervisor (Swift), Waihapa
Operations Superintendent (Origin)

19. 19
Drilling Inventory

20. 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, high-
reward targets on all Taranaki permits
• Waihapa Production Station and
infrastructure expedites tie-in, reduces
production and processing costs
20

21. New Proprietary Merged 3D Seismic
Database
21
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

22. Individual 3D Surveys = Mismatched Data
22
Kapuni 3D Rotokare 3D
1989 2012

23. Proprietary Merged 3D Datasets Increase Chance
of Success
23
Kapuni 3D Rotokare 3D
Reprocessed and merged 2013

24. Inventory of Taranaki Drilling Leads
NZEC’s Copper Moki area converted to long-term mining license
24
WaitapuCopper Moki
Arakamu
Wairere
Horoi
site
Waipapa
site

25. 25
Advancing Unconventional Oil Shales

26. 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
• Castlepoint Permit
- 54.5 million bbl of conventional prospective
resource 1
- 154.1 million bbl of unconventional prospective
resource 1
- Exploration well on Castlepoint in Q2-2014 2
• NZEC retained Core Laboratories as technical
advisor to develop East Coast strategy
26
1. See NZEC Resource Estimates and Cautionary Notes.
2. Work program assumes commitment wells are funded by a farm-in partner.

27. 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
- Drill locations identified, consent and permitting
process underway 1
• Wairoa Permit
27
Exploration wells drilled by Westech Energy New Zealand discovered
oil and natural gas, but did not make a commercial discovery
1. Work program assumes commitment wells are funded by a farm-in partner.
- Log data from 16 wells and 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

28. Common shares outstanding at January 2014
Options outstanding at January 2014 (Exercisable at average $0.67) 1
Warrants issued in Oct 2013 Private Placement (Exercisable at $0.45 until Oct 2014)
Finder’s warrants issued in Private Placement (Exercisable at $0.33 until Oct 2014)
Fully diluted shares outstanding
170.9 million
11.1 million
24.5 million
3.0 million
209.4 million
Insider ownership (fully diluted)
52 Week High / Low
Average Volume (Q1-2014)
~25%
$0.53 / $0.19
~270,000 shares/day
Current market cap (April 2, 2014)
2P Reserves 1,649,000 boe
~$37 million
NPV $57.9 million 2
Financial Highlights 3
Oil sold during nine-month period
Pre-tax oil sales during nine-month period
Average realized oil price for Q3-2013
Field netback for Q3-2013 4
Working capital (November 26, 2013)
63,852 bbl
$6.6 million
$108.84 / bbl
$58.90 / bbl
$6 million
Forecast production – exit 2014 5 2,300 boe/d
Corporate Profile
28
1. NZEC has applied to re-price 1.19 million options to $0.45. The incentive options were previous issued at exercise prices between $1 and $3. Re-pricing
is subject to shareholder approval. Director options are not being re-priced. 2. As per NZEC’s Q3-2013 consolidated interim financial statements, unless
otherwise noted. 2. After tax, 10% discount. 3. NZEC’s Q4-2013 financials will be released on April 29, 2014. 4. 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. 5. Assuming
successful execution of planned work program. See Planned Work Program – Taranaki Basin and Assumptions.

29. Value Drivers Next 12 Months
• Increase production and cash flow
- Reactivating oil production from existing Tikorangi and Mt. Messenger wells
- Recompleting existing wells uphole in Mt. Messenger
- Continuing to review 3D seismic, well logs and drilling data to identify new production
opportunities on the TWN Licenses
- Forecast production of 2,300 boe/day exit 2014 (81% oil) 1
• Leverage Waihapa Production Station and infrastructure
- Generating cash flow by processing third-party oil, gas and water production
- Expedite tie-in of new discoveries = additional incremental cash flow
• Resume drilling program
- Initiate exploration of high-reward deeper Tikorangi and Kapuni formations
- De-risked Mt. Messenger targets with merged 3D seismic and new reservoir information
• Identify funding partner to advance East Coast permits
29
1. NZEC forecast based on 50% ownership of TWN Assets and execution of the planned development program. See Assumptions and Planned Work
Program – Taranaki Basin. Development and operating costs are to be funded initially by existing working capital and cash flows from production. To
carry out all of the planned development activities, the Company is considering a number of options to increase its financial capacity, including
additional joint arrangements, commercial arrangements, or other financing alternatives. Development and exploration activities and timing of
activities is subject to change as the Company continues to review and refine its 2014 program.

30. 30
Appendix
30

31. Drilling / Production Report Card
31
Well Name Permit Formation Depth Notes Total Net Oil Prod *
Copper Moki-1
Copper Moki-2
Copper Moki-3 1
Copper Moki-4
Eltham
Eltham
Eltham
Eltham
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 1
Urenui oil discovery, shut in pending further testing
113,780 bbl
103,353 bbl
47,750 bbl
Waitapu-1
Waitapu-2
Eltham
Eltham
Mt. M
Mt. M
2,213 m
2,084 m
Shut in pending further testing or sidetrack
Produced Dec 2012 – May 2013, recommenced Mar 2014 18,790 bbl
Arakamu-1A
Arakamu-2
Eltham
Eltham
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
Eltham
Eltham
Mt. M
Mt. M
1,971 m
2,152 m
Plugged back for sidetrack
Completion pending
Reactivated Tikorangi Wells
(Toko-2B, Ngaere-3, Ngaere-2A,
Ngaere-1, Waihapa-H1, Waihapa-6A)
TWN Tikorangi Existing wells drilled and produced by previous operator
Oil production reactivated in November 2013
Toko-2B shut-in Mar 2014 to install high-volume lift (ESP)
13,441 bbl
Reactivated Mt. Messenger Well
(Waihapa-8)
TWN Mt. M Existing well drilled and produced by previous operator
Oil production reactivated March 29, 2014
Potential Tikorangi Reactivation or
Mt. M Uphole Completion (Waihapa-1)
TWN Tikorangi Evaluating potential to reactivate Tikorangi production
Additional upside from Mt. M recompletion
Potential Uphole Recompletions
(Waihapa-1, Waihapa-2, Waihapa-3,
Waihapa-4, Waihapa-5)
TWN Mt. M WH-2 production targeted for Apr 2014
WH-3, WH-4 and WH-5 are new uphole completion
opportunities identified in March. Evaluation underway
New Tikorangi Wells 2
(Tik-1, Tik-2)
TWN Tikorangi ~3,000 m Three potential drill locations identified 2
New Mt. Messenger Wells 2
(New-1, New-2, New-3)
TWN Mt. M ~2,000 m Multiple drill targets and locations identified 2
Horoi 3 Alton Mt. M ~2,000 m New exploration well, drilling targeted for Q3-2014 2 * Prod. to end Feb 2014
NZEC Production / Exploration Wells
1. CM-3 shut-in Mar 2013 for installation of new pump. 2. Development and operating costs are to be funded initially by existing working capital and cash flows from production. To carry out all of the planned development activities, the
Company is considering a number of options to increase its financial capacity, including additional joint arrangements, commercial arrangements, or other financing alternatives. Development and exploration activities and timing of
activities is subject to change as the Company continues to review and refine its 2014 program.

32. Taranaki Activity: NZEC’s Property Portfolio
Strategically Located in Main Production Fairway
32
1. NZEC owns 100% of the Eltham Permit. 2. NZEC and L&M Energy have formed a 50/50 joint arrangement to explore, develop and operate the TWN
Licenses and Waihapa Production Station, and a 65/35 joint arrangement to explore and develop the Alton Permit, with NZEC as the operator of both
permits. 3. NZEC and New Zealand Oil & Gas have formed a 60/40 joint arrangement to explore and develop the Manaia permit, with NZEC as the operator.

33. NZEC Reserve Estimate (net to NZEC) 1
33
1. Reserves on NZEC’s Copper Moki Permit are restricted to the Mt. Messenger Formation. NZEC’s on the TWN Licenses are
restricted to the Tikorangi Formation in the Waihapa and Ngaere permits. See NZEC’s Form 51-101 Statement of Reserves Data
dated April 2, 2014, filed on SEDAR at www.sedar.com.
Proved Developed Producing 517,000 935,000 40,000 713,000 $18,452,900
Proved Developed Non-producing 181,000 554,000 27,000 301,000 $19,574,600
Proved Undeveloped 111,000 88,000 3,000 129,000 $3,806,300
Total Proved 809,000 1,576,000 71,000 1,143,000 $41,833,800
Probable 359,000 683,000 34,000 506,000 $16,072,000
Proved + Probable 1,168,000 2,260,000 104,000 1,649,000 $57,905,800
Notes:
1. Reserve estimates calculated by Deloitte LLP with an effective date of December 31, 2013.
2. bbl – barrels. Mcf – thousand cubic feet of natural gas. boe – barrels of oil equivalent
3. Reserves net to NZEC after deduction of royalty obligations to the New Zealand government and Origin Energy Resources NZ (TAWN) Limited.
4. See Cautionary Note Regarding Reserve and Resource Estimates.
3. Barrels of oil equivalent (boe) may be misleading, particularly if used in isolation. The boe conversion ratio of 6 Mcf : 1 bbl is based on an energy
equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
Marketable Oil and Gas Reserves
As at December 31, 2013
Forecast Prices and Costs
Reserves Category
Light & Medium Oil
(bbl)
Natural Gas
(Mcf)
Natural Gas
Liquids (bbl)
Barrels Oil
Equivalent (boe)
NPV, After Tax
(10% Discount)

34. TWN Resource Estimate (NZEC’s 50% Interest) 1
Formation Product Type Low Best High
Contingent Resources
Miocene Sands (Mt. Messenger) Oil (Mbbl) 17 44 101
Eocene Sands (Kapuni Group)
Gas (MMcf – sales) 1,257 2,518 5,168
NGL (Mbbl) 51 117 263
Total BOE (Mboe) 277 580 1,225
Prospective Resources
Miocene Sands (Urenui, Mt. Messenger, Moki) Oil (Mbbl) 803 1,471 2,866
Eocene Sands (Kapuni Group)
Gas (MMcf – sales) 21,417 47,919 113,212
NGL (Mbbl) 955 2,249 5,688
Total BOE (Mboe) 5,327 11,706 27,422
Discovered PIIP
Miocene Sands (Mt. Messenger) Oil (Mbbl) 164 341 700
Eocene Sands (Kapuni Group) Gas (MMcf – raw) 3,606 6,885 13,468
Total BOE (Mboe) 764 1,488 2,945
Undiscovered PIIP
Miocene Sands (Urenui, Mt. Messenger, Moki) Oil (Mbbl) 5,658 10,221 18,902
Eocene Sands (Kapuni Group) Gas (MMcf – raw) 59,491 130,540 302,930
Total BOE (Mboe) 15,573 31,978 69,390
1. NZEC’s 50% share of TWN Resources as 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. 34

35. Taranaki and East Coast Resource Estimates
35
Low Best High Low Best High
TARANAKI BASIN
Eltham (PEP 51150) and 191.8 47,394.8
Copper Moki PML *
100% NZEC
Conventional 1
231.4 346.8 578.8 19.7 31.6 56.9
Alton (PEP 51151) 156.7 38,717.4
65% NZEC / 35% L&M
Conventional 1
224.8 493.7 1,229.7 18.9 45.0 116.9
Manaia (PEP 54867) 66.6 16,455.7
60% NZEC / 40% NZOG
Conventional
EAST COAST BASIN
Castlepoint (PEP 52694) 2,230.0 551,045.0
100% NZEC
Conventional 1
349.0 586.3 1,053.1 30.3 54.5 102.0
Unconventional 2
2,958.2 6,743.0 16,190.7 56.2 154.1 458.5
East Cape (PEP 52976) 4,320.0 1,048,406.3
100% NZEC
Conventional 1
189.8 615.7 1,997.4 14.6 53.3 195.4
Unconventional 2
5,747.2 13,148.1 31,838.3 110.3 302.1 906.3
Wairoa (PEP 38346) 867.2 214,289.8
80% NZEC / 20% Westech
Conventional
Unconventional
Total 7,832.3 1,916,309.0 9,700.4 21,933.6 52,888.0 250.0 640.6 1,836.0
Conventional 1
995.0 2,042.5 4,859.0 83.5 184.4 471.2
Unconventional 2
8,705.4 19,891.1 48,029.0 166.5 456.2 1,364.8
Resources estimated by Deloitte LLP. Eltham Resources effective date December 31, 2011. Other resources effective date February 1, 2011.
1
Assumes 9% recovery. 2
Assumes 2% recovery. * Configuration of Eltham PEP and Copper Moki PML pending NZP&M approval.
Estimate pending Estimate pending
(MM barrels of oil)
Early stage Early stage
Net Permit
Area
Net Permit
Acreage
Net Unrisked Undiscovered Petroleum
(MM barrels of oil)
Net Unrisked Prospective Recoverable

36. Historical Production – Tikorangi Formation
1. Select production data using publicly available information regarding wells that produced
oil on the TWN Licences.
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
23.6 million bbl of historical production 1
36

37. EUR for a new well = 400 mbbl
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)
37
CumOil(mbbl)
1. NZEC collation of independent
consultancy assessments.

38. Assumptions in NZEC’s Mid-case Financial Model
(as at July 31, 2013)
38
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
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
Existing Tikorangi Wells (gas lift  high volume lift) Tikorangi New Wells
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)
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 – Uphole Completion in Existing Tikorangi Wells 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
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)
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$40/bbl
Kapuni New Wells Waihapa Production Station
Expected Ultimate Recovery (unrisked, 100%)
Working interest
Probability of success
IP rate
Decline
Capital cost (incl. surface equipment)
Operating expenditure
7.91 Bcf
25%
60%
1,103 BOE/day
1% per month
C$nil funded by new JV partner
C$10,000 per month/well (WI)
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
C$7.1 million, including increasing water
handling capacity
1. Deloitte LLP has ascribed 2P reserves of 410,300 bbl to one Tikorangi new well.
WI = based on Working Interest.
Capital costs and operating costs were estimated using the exchange rate assumptions noted above. Actual costs will fluctuate with exchange rate fluctuations.

39. Board of Directors
39
Name Expertise Experience
John 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 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 McIntyre, P.Geol
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 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
David Robinson, B.A, G.C.M
Director starting
March 31, 2014
• Significant business and management experience
in New Zealand’s oil and gas industry
• CEO, Petroleum Exploration & Production Assoc. of New Zealand
• Commercial General Manager, Z Energy
• Director, other downstream commercial positions, Shell

40. Corporate Office – Canada
40
Name Expertise Experience
John Proust, C.Dir
Chief Executive Officer
• 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.
Gerrie van der Westhuizen, CA
Vice President Finance
• 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
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.
Eileen Au, B.Sc
Corporate Secretary
• 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

41. Operations Team – New Zealand
41
Name Expertise Experience
Derek Gardiner, CA
Chief Financial Officer
• Chartered Accountant and Chartered Corporate Secretary with more
than 25 years of experience in the New Zealand oil gas industry with
senior financial, business planning and accounting positions
• Commercial and Finance Manager, Origin Energy
• Chief Financial Officer, Austral Pacific Energy
• Numerous senior positions, Shell
Mike Oakes
General Manager
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
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
Stewart Angelo
Engineering & Maintenance
Manager
• 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
Toka Walden
Land Manager
• Senior Manager, New Zealand Dept. of Conservation
• Negotiating access provisions and facilitating resource
consent process, assisting with community relationship
building
Dan MacDonald, B.Sc
Drilling Manager
• Mechanical engineer with 30 years of experience
• Drilling and completion work, design, approval and
implementation of drilling programs

42. Technical Team – New Zealand
42
Name Qualifications Expertise
Dr. Ian Brown
B.Sc (Hons), M.Phil,
D.Eng, MIPENZ, C.P.Eng
Advisor – Professional geological engineer, government and community relations
June Cahill
B.Sc,
B. Applied Econ.
Acquisition, management, and analysis of complex geoscience data
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 Geoscientist with experience in New Zealand Basin analysis
Dr. Richard Kellett
B.Sc (Hons), Ph.D,
P.Geoph
Geoscientist with worldwide exploration and business development experience
Monmoyuri Sarma
B.Sc (Hons), M.Sc
(Petroleum Geosciences),
M.Sc (Applied Geology)
Geoscientist with experience with reservoir modelling and petroleum system
analysis
Peter Wood
B.E (Hons), B.Sc ,
M.Comp.Sci
Management and development of computing resources for geoscience
applications
Sam Pryde
B.Sc
Post.Grad.Dip.
Geological investigations in the East Coast basin area

43. Analyst Coverage
43
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
M Partners David Buma 416-603-7381

44. Contact NZEC
44
Corporate Head Office
John Proust, Chief Executive Officer
Bruce McIntyre, Director
Rhylin Bailie, VP Investor Relations
North America Toll-free: 1-855-630-8997
Phone: + 604-630-8997
New Zealand Operations Office
Phone: + 646-757-4470
info@newzealandenergy.com
www.NewZealandEnergy.com