This corporate presentation from New Zealand Energy Corp outlines their plans to increase oil production and cash flow from their assets in the Taranaki Basin of New Zealand. Key points include: - Reactivating existing wells to produce from the proven Tikorangi formation, with an expected 780 bbl/d of net production to NZEC by the end of 2014. - Conducting uphole completions and drilling new wells in the Mt. Messenger formation, with an expected 575 bbl/d of net production to NZEC by the end of 2014. - Drilling two new wells in the Tikorangi formation, expected to add 570 bbl/d of net production

1. TSX-V: NZ
OTCQX: NZERF
Waihapa Production Station
Corporate Presentation
February 20, 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. 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. More information is available in the Company’s Form F1-101F1 Statement of Reserves Data and Other Oil and Gas Information dated April 22, 2013, and in the
Company’s Interim Statement of Reserves and Resources Data and Other Oil and Gas Information dated October 28, 2013, both of which are filed on SEDAR at www.sedar.com.
2

3. Fully Integrated Upstream/Midstream Company
• Strategic acquisition and private placement
complete
- Three Petroleum Mining Licenses with immediate
production potential
- 150% increase to NZEC’s reserves 1
- Full-cycle production facility central to NZEC’s
permits
• Increasing production and cash flow 2
 Reactivate oil production in existing Tikorangi wells
 Recomplete existing wells uphole in Mt. Messenger
formation (production pending)
- Drill new wells to Mt. Messenger and deeper
Tikorangi formation
• ~1.93 million acres of permits with both
conventional and unconventional opportunities
• Strategic JV partners: L&M Energy, New Zealand
Oil & Gas, Westech Energy
• Experienced team with New Zealand and Western
Canadian exploration and operations expertise
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.
3

4. Asset Overview
Permit
Working
Interest
Net Acres
2P boe
Reserves 1
Contingent
Resource 1
Prospective
Resource 1
Eltham 2
100%
47,395
708 M boe
-
31.6 MM bbl
Alton
65%
38,717
-
-
45.0 MM bbl
Manaia
60%
16,456
-
-
Early stage
TWN
50%
11,525
1,072 M boe
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
Conventional
Focus
East Cape
Conventional and
Unconventional
Targets
TWN
Alton
Manaia
Eltham
Wairoa
Castlepoint
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 filed on SEDAR in October 2013, the Reserve and Resource tables in the Appendix, and Cautionary
Notes. Reserves and resources are updated annually. 2. Final configuration of Copper Moki mining license and Eltham exploration
permit subject to NZP&M approval.
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. Planned Work Program – Taranaki Basin
(Balance of 2013 and 2014) 1
November–December 2013
Existing Tikorangi Well Reactivations
 Reactivate oil production from six Tikorangi wells on TWN Licenses
Mt. Messenger development
 Complete installation of Waitapu-2 artificial lift
 Begin uphole recompletions in two existing wells on TWN Licenses
2014 1
Tikorangi development
• Optimize oil production from reactivated wells on TWN Licenses, including installation of high-volume lift
on select wells
• Determine potential to reactivate oil production from additional existing Tikorangi wells on TWN Licenses
• Drill two new Tikorangi wells on TWN Licenses
Mt. Messenger development
 Recommence production from Copper Moki-3 well on Eltham Permit
• Recommence production from Waitapu-2 well on Eltham Permit
• Advance Mt. Messenger uphole completions on TWN Licenses to production 2
• Determine potential to reactivate oil production from existing Mt. Messenger wells on TWN Licenses
• Drill Horoi exploration well (including surface infrastructure) on Alton Permit
• Drill three new Mt. Messenger wells (including surface infrastructure) 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.
6

7. NZEC Production & Development Wells
Well Name
Permit
Name
Target Notes
Formation
Copper Moki-1
Copper Moki-2
Copper Moki-3 1
Eltham
Eltham
Eltham
Mt. M
Mt. M
Mt. M
Producing since Dec 2011
Producing since Apr 2012
Producing since Jul 2012 1
Waitapu-2 2
Eltham
Mt. M
Producing since Dec 2012 2
Reactivated Tikorangi Wells
Toko-2B, Ngaere-3,
Ngaere-2A, Ngaere-1,
Waihapa-H1, Waihapa-6A
TWN
Tikorangi Existing wells drilled by previous operator
Oil production reactivated in Nov 2013
Potential Tikorangi Well
Waihapa-1B
Uphole Recompletions
Waihapa-2
Waihapa-1B
TWN
Tikorangi Tikorangi flow test scheduled for Feb 2014
Additional upside from Mt. M formation
Mt. M Waihapa-2 production targeted for Q2-2014
Waihapa-1B Mt. M recompletion contingent on results of
Tikorangi production test
Reactivated Mt. M Well
Waihapa-8
TWN
TWN
Mt. M
Production targeted for Q2-2014
1. Copper Moki-3 shut-in during December 2013 for maintenance, resumed production in Jan 2014.
2. Waitapu-2 shut in at end of May 2013 for installation of artificial lift and reservoir tests, expected to resume
production in Q1-2014.
7

8. Immediate Value from
Near-term Work Program
8

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 120 bbl/d (all six wells,
risked)3
• High volume lift adds forecast initial production of net 135 bbl/d
per well (risked) 3
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.
9

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 completion potential
in multiple Tikorangi wells
- First uphole completion commencing commercial
production in Q1-2014
- Additional uphole completions in Q1-2014
• 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
well) by end of 2014 with forecast total initial production
of net 80 bbl/d per well (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. 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
10

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
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.
11

12. Forecast Production Attributable to NZEC
2,300 boe/d (exit 2014) (81% oil)
Daily Production net to NZEC (boe/d)
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.
12

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)
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.
13

14. Full-cycle Production Station
14

15. 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. NZEC and L&M Energy have formed a 50/50 joint venture to explore, develop and operate the TWN Licenses and Waihapa
Production Station.
15

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,
Cost to expand
C$30 million
No exploration land
100% basis) 1
• Includes additional 1,162,000 boe contingent
resources, 23,541,000 boe prospective
resources (100% basis) 1
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
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.
16

17. Waihapa Production Station Generating
Third-Party Cash Flow
* 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.
17

18. NZEC’s TWN Management & Operational Experience
NZEC Position
Years Relevant
O&G Experience
Years Experience
with TWN Assets
Previous TWN Associated Roles
Mike Oakes,
GM Operations
35+
8
Derek Gardiner,
CFO
25
3
Commercial & Finance Manager
(Origin)
Newton Cockerill,
Controller
5
5
Business Performance & Accounting Manager
(Origin)
NZ Asset Manager (Origin), Plant Super &
Commissioning Supervisor (Fletcher Energy)
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)
18

19. Drilling Inventory
19

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, highreward 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
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
21

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

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

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

25. Advancing Unconventional Oil Shales
25

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
1. See NZEC Resource Estimates and Cautionary Notes. 2. Work program assumes commitment wells are funded by a farm-in
partner.
26

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

28. Corporate Profile
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
Insider ownership (fully diluted)
52 Week High / Low
Average Volume (Q4-2013)
170.9 million
11.1 million
24.5 million
3.0 million
209.4 million
~25%
$0.86 / $0.19
~370,000 shares/day
Current market cap (February 19, 2014)
~$43 million
Financial Highlights 2
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 3
Working capital (November 26, 2013)
63,852 bbl
$6.6 million
$108.84 / bbl
$58.90 / bbl
$6 million
Forecast production – exit 2014 4
2,300 boe/d
1. NZEC has applied to reprice 1.19 million options to $0.45. The incentive options were previous issued at exercise prices between $1 and $3.
Repricing is subject to shareholder approval. Director options are not being repriced. 2. As per NZEC’s Q3-2013 consolidated interim financial
statements, unless otherwise noted. 2. NZEC’s Q4-2013 financials will be released in the third week of April 2014. 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. 4. Assuming successful execution of planned work program. See Planned Work Program – Taranaki Basin and Assumptions.
28

29. Value Drivers Next 18 Months
• Value increase from Acquisition
- Immediately booked 150% net increase in 2P reserves 1
- Reactivated oil production from six existing Tikorangi wells  optimizing oil production
- Recompleting existing wells uphole in Mt. Messenger  low-cost production
opportunities
- Additional exploration and development opportunities in 2014
• Increasing production and cash flow
- Forecast production of 2,300 boe/day exit 2014 (81% oil) 2
- Reduce net general and administrative costs through joint ventures and third-party
processing
• Leverage Waihapa Production Station and infrastructure
- Generating cash flow from existing and new liquids rich natural gas 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
• 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 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.
29

30. Appendix
30
30

31. NZEC Production / Exploration Wells
Drilling / Production Report Card
Well
Name
Permit
Name
Target
Formation
Total
Depth
Notes
Total Oil Prod
(net, end Dec 2013)
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
112,585 bbl
100,320 bbl
46,558 bbl
Waitapu-1
Waitapu-2 2
Eltham
Eltham
Mt. M
Mt. M
2,213 m
2,084 m
Shut in pending further testing or sidetrack
Producing since December 2012 2
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
Six Reactivated Wells
(Toko-2B, Ngaere-3, Ngaere-2A,
Ngaere-1, Waihapa-H1, Waihapa-6A)
TWN
Tikorangi
Existing wells drilled by previous operator
Oil production reactivated in November 2013
Uphole Recompletions
(Waihapa-2, Waihapa-1, Waihapa-8)
TWN
Mt. M
WH-2 commencing production in Q1-2014
WH-1 and WH-8 testing underway in Q1-2014
Tikorangi Crestal Wells 3
(Tik-1, Tik-2)
TWN
Tikorangi
~3,000 m
Two new wells, drilling in Q2-Q4 2014 3
New Mt. Messenger Wells 3
(New-1, New-2, New-3)
TWN
Mt. M
~2,000 m
Three new wells, drilling in Q2-Q4 2014 3
Horoi 3
Alton
Mt. M
~2,000 m
New exploration well, drilling in Q2-2014 3
18,790 bbl
7,430 bbl
1. Copper Moki-3 shut-in during December 2013 for maintenance, resumed production in Jan 2014. 2. Waitapu-2 shut in at end of May 2013 for analysis of artificial lift and reservoir tests, expected to resume
production in Q1-2014. 3. 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.
31

32. Taranaki Activity: NZEC’s Property Portfolio
Strategically Located in Main Production Fairway
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.
32

33. TWN Reserve Estimate (NZEC’s 50% Interest) 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)
491.85
381.00
13.35
568.70
$18,071,000
Proved Undeveloped
129.05
103.25
3.60
149.90
$3,670,000
Total Proved
620.90
484.25
16.95
718.55
$21,741,000
Probable
305.45
239.65
8.40
353.80
$9,696,500
Proved + Probable (2P)
926.35
723.90
25.35
1,072.35
$31,437,500
-
-
-
-
-
926.35
723.90
25.35
1,072.35
$31,437,500
Possible
Proved + Probable +
Possible (3P)
1. NZEC’s 50% interest in TWN Reserves, as estimated by Deloitte LLP with an effective date of April 30, 2013. Reserves restricted
to the Tikorangi Formation on the Waihapa and Ngaere Permits. Gross reserves before the deduction of any royalty obligations.
See Cautionary Note Regarding Reserve & Resource Estimates. Mbbl – thousand of barrels. MMcf – millions of cubic feet. Mboe –
thousand barrels of oil equivalent using a conversion ratio of 6 Mcf : 1 bbl. NPV – net present value.
33

34. Eltham Reserve Estimate (NZEC 100%) 1
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
1. 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. MMcf – million cubic feet. Mboe – thousand barrels of oil
equivalent using a conversion ratio of 6 Mcf : 1 bbl. NPV – net present value. See Cautionary Note Regarding Reserve and Resource
Estimates.
34

35. TWN Resource Estimate (NZEC’s 50% Interest) 1
Formation
Product Type
Low
Best
High
Contingent Resources
Miocene Sands (Mt. Messenger)
Eocene Sands (Kapuni Group)
Total
Oil (Mbbl)
17
44
101
1,257
2,518
5,168
NGL (Mbbl)
51
117
263
BOE (Mboe)
277
580
1,225
Gas (MMcf – sales)
Prospective Resources
Miocene Sands (Urenui, Mt. Messenger, Moki)
Eocene Sands (Kapuni Group)
Total
Oil (Mbbl)
803
1,471
2,866
21,417
47,919
113,212
NGL (Mbbl)
955
2,249
5,688
BOE (Mboe)
5,327
11,706
27,422
Gas (MMcf – sales)
Discovered PIIP
Miocene Sands (Mt. Messenger)
Eocene Sands (Kapuni Group)
Total
Oil (Mbbl)
Gas (MMcf – raw)
BOE (Mboe)
164
341
700
3,606
6,885
13,468
764
1,488
2,945
Undiscovered PIIP
Miocene Sands (Urenui, Mt. Messenger, Moki)
Eocene Sands (Kapuni Group)
Total
Oil (Mbbl)
5,658
10,221
18,902
Gas (MMcf – raw)
59,491
130,540
302,930
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.
35

36. Taranaki and East Coast Resource Estimates
Net Permit
Area
TARANAKI BASIN
Eltham (PEP 51150) and
Copper Moki PML *
100% NZEC
Conventional 1
Net Permit
Acreage
191.8
231.4
Manaia (PEP 54867)
60% NZEC / 40% NZOG
Conventional
66.6
Wairoa (PEP 38346)
80% NZEC / 20% Westech
Conventional
Unconventional
Total
Conventional 1
Unconventional 2
346.8
578.8
19.7
31.6
56.9
224.8
156.7
East Cape (PEP 52976)
100% NZEC
Conventional 1
Unconventional 2
Net Unrisked Prospective Recoverable
(MM barrels of oil)
Low
Best
High
47,394.8
Alton (PEP 51151)
65% NZEC / 35% L&M
Conventional 1
EAST COAST BASIN
Castlepoint (PEP 52694)
100% NZEC
Conventional 1
Unconventional 2
Net Unrisked Undiscovered Petroleum
(MM barrels of oil)
Low
Best
High
493.7
1,229.7
18.9
45.0
116.9
38,717.4
16,455.7
Early stage
2,230.0
Early stage
551,045.0
349.0
2,958.2
867.2
1,053.1
16,190.7
30.3
56.2
54.5
154.1
102.0
458.5
189.8
5,747.2
4,320.0
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
1,048,406.3
214,289.8
Estimate pending
7,832.3
1,916,309.0
9,700.4
995.0
8,705.4
21,933.6
2,042.5
19,891.1
Estimate pending
52,888.0
4,859.0
48,029.0
250.0
83.5
166.5
640.6
184.4
456.2
1,836.0
471.2
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.
36

37. 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.
37

38. 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.
38

39. 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)
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)
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.
50%
N$0.4 million per month (WI)
N$10/bbl
C$7.1 million, including increasing water
handling capacity
39

40. 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,
Acting GM Exploration
• 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
40

41. 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.
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.
• 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,
Acting GM Exploration
Eileen Au, B.Sc
Corporate Secretary
41

42. Operations Team – New Zealand
Name
Expertise
Derek Gardiner
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
• 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
• Mechanical engineer with 30 years of experience
• Drilling and completion work, design, approval and
implementation of drilling programs
James Watchorn, B.Sc
Operations Manager
Stewart Angelo
Engineering & Maintenance
Manager
Toka Walden
Land Manager
Dan MacDonald
Drilling Manager
Experience
42

43. Technical Team – New Zealand
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.
Professional geological engineer, government and community relations
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
43

44. 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).
44

45. 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
M Partners
David Buma
416-603-7381
45

46. Contact NZEC
Corporate Head Office
John Proust, Chief Executive Officer
Bruce McIntyre, Director, GM Exploration
Rhylin Bailie, VP Investor Relations
North America Toll-free: 1-855-630-8997
Phone: + 604-630-8997
info@newzealandenergy.com
www.NewZealandEnergy.com
46