The March 2015 corporate presentation for New Zealand Energy Corp. highlights forward-looking statements regarding the company's resource estimates, business strategy, and operational goals, while emphasizing the uncertainties and risks involved. Key points include a focus on increasing oil and gas production through existing wells and exploration opportunities in a politically and fiscally stable environment. The document also outlines significant assets and prospective resources, while affirming the company's commitment to safety and environmental management.

1. Corporate Presentation
March, 2015
New Zealand Energy Corp.

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. Safety is our first priority
Our Commitment
• Systematic approach to health, safety and environment management
• Operate with zero harm to our people
• Protect the environment
• Respect our neighbours and engage with our communities
• Training and safety leadership
• Compliance with all legislative requirements
Methods and tools to deliver our ZERO HARM goal
• NZEC operates a comprehensive health, safety and environment management system
• NZEC enforces 12 life saving rules to keep our people safe
• NZEC uses the New Zealand industry standard common permit to work system – the
benchmark for managing worksite safety across the New Zealand petroleum sector
3

4. Investment Highlights
 Highly prospective property portfolio
• 130,150 total acres on New Zealand’s North Island
• 1,146,036 net acres and a full-cycle production facility in the main Taranaki Basin production fairway
• 1,649,000 boe of 2P reserves with an NPV (10% discount) of $57.9 million1
 Focused in New Zealand, a politically and fiscally stable jurisdiction with a supportive government,
excellent tax and royalty regime, and Brent oil pricing
 Experienced New Zealand team with exploration and operations expertise
 Focused on increasing production and cash flow2
• Optimizing production from existing wells
• Opportunities to advance additional existing wells to production  low-cost workovers, rapid tie-in using
existing infrastructure
 Actively engaging in opportunities to increase financial capacity
 Actively seeking farm-in and joint venture partners to fund new drilling
• Significant exploration opportunities across multiple prospective formations
• 62.9mmboe of prospective conventional resources3
1. NZEC’s share of reserves. See detailed Reserve tables 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.
3. Resources estimated by Deloitte LLP. Best estimate. See Resource tables and Cautionary Notes.
4

5. Common shares outstanding at March 2015
Options outstanding (Exercisable at average $0.54)
Warrants issued in Oct 2013 Private Placement (Exercisable at $0.45 until Oct 2015)
Warrants issued in Dec 2014 Private Placement (Exercisable at $0.07 until Dec 2015)
Fully diluted shares outstanding
187,873,459
7,917,200
24,452,173
17,000,000
237,242,832
Insider ownership (fully diluted) [Directors and Officers]
52 Week High/Low
Average Volume (Q4-2014)
~19%
$0.255 / $0.025
~200,000 shares/day
Current market cap (March 5th , 2015)
2P Reserves 1,649,000 boe1
~$9.4 million
NPV $57.9 million1a
Financial Highlights2
Oil produced during nine-month period ended September 30, 2014
Pre-tax revenue during nine-month period ended September 30, 2014
Cumulative third-party revenue earned from Waihapa Production Station (Nov 26, 2014)
Average realized oil price for nine-month period ended September 30, 2014
Field netback for nine-month period ended September 30, 20143
Estimated working capital (November 26, 2014) (excluding materials and supplies of ~NZ$1.9 M)
57,436 bbl
$11.5 million
$2.3 million
$115.53 / bbl
$66.08 / bbl
$1.3 million
Corporate Profile
1. As at 31 December 2013, 1a After tax, 10% discount. 2. As per NZEC’s Q3-2014 interim financial statements, filed on November 26,
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.
5

6. Asset Overview – New Zealand’s North Island
1. Reserves and resources estimated by Deloitte LLP. The term barrels of oil equivalent (“boe”) may be misleading.
A boe conversion ratio of six Mcf: one bbl was used by NZEC. 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 this presentation, and the Cautionary Notes. Reserves are updated annually.
Eltham
Alton
East Cape
TWN
Permit Working
Interest
Net Acres 2P boe
Reserves 1
Contingent
Resource 1
Prospective
Resource 1
Taranaki Basin – Conventional Targets
Copper Moki 100% 944 536,000 - -
Eltham 100% 46,444 - - 31.6 MM bbl
Alton 65% 38,813 - - 45.0 MM bbl
TWN 50% 11,525 1,113,000 580 M boe 11.7 MM boe
East Coast Basin – Conventional and Unconventional Targets
East Cape 100% 1,048,406 - - 355.4 MM bbl
Total 1,146,036 1,649,000 boe 2P Reserves net to NZEC (80% oil)
$57.9 million NPV (after tax, 10% discount)
6

7. Fully Integrated Upstream/Midstream Company
1. NZEC requires additional working capital or a funding partner to commence further production optimization and drilling new
exploration opportunities.
 97,726 net acres and a full-cycle production
facility in the main Taranaki Basin production
fairway
 Experienced New Zealand team with
exploration and operations expertise
 Focused on increasing production and cash
flow (Q4-2014 ave. 182 bbl/d)1
- Optimizing production from existing wells
- Advancing previously drilled wells to
production  low-cost workovers, rapid
tie-in using existing infrastructure
- New exploration opportunities across
multiple prospective formations
7

8. Multiple Prospective Formations in Taranaki Basin
Moki
Tikorangi
Kapuni
Mt Messenger
Kapuni Group
2,500 metres
3,000 metres
3,500 metres
4,000 metres
Approximate Depth
8

9. Inventory of Taranaki Leads
Waitapu
Copper Moki
Arakamu
Wairere
Horoi
site
9

10. NZEC Production & Development Wells (Status at Jan/Feb 2015)
Average Daily Oil Production During 2014/15 net to NZEC (bbl/d)
May Jun Jul Aug Sep Oct Nov Dec Jan
201 231 202 205 205 212 183 153 151
Well Name Permit Formation Notes
Producing Wells
Copper Moki-1 Copper Moki Mt. M Producing since Dec 2011
Copper Moki-2 Copper Moki Mt. M Producing since Apr 2012
Waitapu-2 Copper Moki Mt. M Producing since Dec 2012
Ngaere-1 TWN Tikorangi Oil prod. reactivated Nov 2013
Producing on rest/recovery
Ngaere-2A TWN Tikorangi Oil prod. reactivated Nov 2013
Producing on rest/recovery
Ngaere-3 TWN Tikorangi Oil prod. reactivated Nov 2013
Producing on rest/recovery
Waihapa-H1 TWN Tikorangi Oil prod. reactivated Nov 2013
Producing on rest/recovery
Waihapa-6A TWN Tikorangi Oil prod. Reactivated Nov 2013
Producing on rest/recovery
Toko-2B TWN Tikorangi Oil prod. Reactivated Nov 2013
ESP installed June 2014 producing on
rest/recovery
Waihapa-8 TWN Mt. M Commenced oil prod on gas lift .
Mar 2014
Waihapa-2 TWN Mt. M Commenced oil prod. Apr 2014
Recompleted as upper/lower sand
selective with jet pump Dec 2014
Producing wells current shut-in
Copper Moki-3 Copper Moki Mt. M Producing since Jul 2012, shut-in
pending down hole pump repair
Additional Opportunities
Waihapa-1B TWN Tikorangi Evaluating potential for productivity
enhancement of Tikorangi
Horoi Alton Mt. M Potential new exploration well
Mt. M = Mt. Messenger Formation
10

11. Waihapa Production Station Assets1
Full-cycle facility with gathering and sales pipeline infrastructure
Oil & Water
 25,000 bbl/d oil handling facility
 18,000 bbl/d water handling capacity
 7,800 bbl oil storage capacity
 49 km 15,500 bbl/d oil sales pipeline from Waihapa to Shell’s Omata Tank Farm
Gas & LPG
 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
 9,000 bbl/d water injection capacity
Includes 100 acres of land providing a buffer zone surrounding the facility
1. NZEC and L&M Energy formed a 50/50 joint venture to explore, develop and operate the TWN Licenses and Waihapa
Production Station.
11

12. Full-cycle Production Station
12

13. Proprietary Merged 3D Seismic
Database
Reprocessed datasets
 Combined five 3D surveys
 Total area covered (full fold) 555 km2
 Processing includes pre-stack merge, post-stack
time migration, and pre-stack time migration
 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
ELTHAM ALTON
WAIHAPA
NGAERE
TARIKI
13

14. Individual 3D Surveys = Mismatched Data
Kapuni 3D Rotokare 3D
1989 2012
14

15. Proprietary Merged 3D Datasets
Increased Chance of Success
Kapuni 3D Rotokare 3D
Reprocessed and merged 2013-2014
15

16. Mt. Messenger Opportunities
Drill-proven formation
 Significant discoveries to the west (TAG: Cheal), south (NZEC:
Copper Moki, Waitapu) and east (Kea: Puka)
 Prospective resources: 2,061,000 bbl oil (100% basis)1
 Miocene oil and gas shows across TWN acreage
Low-cost production potential in existing wells 2
 Copper Moki water flood (see separate slide)
 Waihapa 2 Jet Pump project successfully completed in
December 2014
New exploration opportunities 2
 More than 18 new Mt. Messenger leads identified on
3D seismic on TWN Licenses
 None of these leads intersected by existing wells
 Drill pads and gathering systems in place  reduced drilling
expense, expedited tie-in, reduced opex
 Additional drill targets on Eltham and Alton permits
1. Prospective resources for Mt. Messenger formation only, shown on a 100% basis. Additional ~640,000
bbl prospective resources estimated for Urenui and Moki formations. Resources attributable to NZEC at
50%. See TWN Resource Estimate and Cautionary Notes.
2. To carry out 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. NZEC requires additional working capital or a funding partner to commence
drilling new exploration opportunities.
16

17. Copper Moki/Waitapu Development
Current Status
• Copper Moki-1, Copper Moki-2 and Waitapu-2
producing on rod pump.
• Copper Moki-3 shut-in (sand) - pending down hole
pump repair
• Jan-2015 average rates were 27, 47 and 20 bopd for
CM-1, CM-2 and W-2 respectively. No significant water.
Observations
• Copper Moki-1 and Waitapu-2 in good pressure
communication. No clear evidence of communication
with Copper Moki-2 or Copper Moki-3.
• Expected recovery from existing depletion drive
mechanisms 10-15% of OOIP. Implementing water
flood could increase recovery to 25-40% of OOIP.
• Assuming CM-1/W-2 15% primary recovery of 230,000
bbls the incremental oil associated with a water flood
could be 150,000 – 380,000 bbls.
17

18. Copper Moki Water Flood Proposal
Strategy
 Increase oil production rate and recovery factor by introducing a water flood to the
Copper Moki 1 /Waitapu-2 reservoir;
• Expect recovery factor to increase by 10-30%
• Increase production from Copper Moki with gas piped by existing pipeline to WPS
• Eliminates requirement to install Waitapu-2 gas pipeline (~$800,000 savings)
Proposed Work Program
 Workover and complete Waitapu-2 for water injection
 Install water injection facility at Waitapu
Estimated cost to undertake this exercise1
 NZ$0.5m
18
1. To carry out 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. NZEC requires additional working capital or a
funding partner to commence drilling new exploration opportunities.

19. Copper Moki Performance
Combined CM-1/W-2
decline trend
Projected recovery
through depletion
drive mechanisms
~230,000 bbls
(estimated at 15%
recovery)
Rebuilding pressure
expected to increase
production and total
hydrocarbon recovery
19

20. TWN Tikorangi Limestone Upside Potential
Current Status
• Intermittent flow due to ineffective artificial lift
mechanisms.
• Jan 15 average 105 bopd with 256 bwpd
• Six wells available for production
(N-1,N-2A,N-3,T-2B,WH-1,W-6A)
• One well available for water disposal (W-7A)
Observations
• Complex fractured reservoir system
• Long standing belief that by-passed oil exists in low
permeability fracture systems. Un-swept oil could exist
in pockets or be distributed across the whole structure.
• Up-dip oil may exist but structural uncertainty,
possibility of a gas cap and rapid water breakthrough
changes risk profile.
• Drilling option appropriate if targeting up-dip oil but of
little or no value in targeting by-passed oil.
• Oil recovery has been almost entirely associated with
aquifer movement. If aquifer can be “out run”, depletion
drive mechanism is expected to mobilize stranded oil.
20

21. Tikorangi Development Proposal
Strategy
 Increase total liquid production to 12-16,000 bpd with objectives being;
• Restore normal decline trend for primary oil recovery.
• Attempt to outrun aquifer, reduce reservoir pressure below historic low and mobilise stranded oil.
Work Program stage one1
 Run ESP in Waihapa-6A (based on Schlumberger gas lift analysis, pressure available for gas lift is
insufficient to make good use of existing mandrels).
 Recomplete an existing well to Matemateaonga formation for 2nd water disposal well.
Work Program stage two
 Ngaere-1 and Ngaere-2A artificial lift to be finalised which could include a further ESP or jet
pumps.
1. Work programme based on current technical analysis. Subject to ongoing evaluation and engineering review and funding.
21

22. Normal decline
trend established
pre-1998 with total
liquid production
>10,000bpd
Success case
expects 400-500
bopd
Estimated cost to
undertake this
exercise – NZEC
share ~NZ$1.5m1
Future Tikorangi Development Proposal
Increasing production to restore original decline trend
Without
effective
artificial lift total
liquid
production fell
High volume
artificial lift
ceased in 1998
Production now
based on
intermittent
flow.
Returning to the
established trend
could result in
2MMbbl
depending on
economic limit
22
1. Work programme based on current technical analysis. Subject to ongoing evaluation and engineering review and funding.

23. TWN Kapuni Group
Drill-proven formation
 Kapuni Gas Field onshore oil/gas discovery (Shell/Todd)
producing since 1969
• Estimated ultimate recovery of 1,365 billion cf (Bcf)
natural gas and 66 million bbl condensate
 TWN Licences tested by four wells  all encountered gas in the
Kapuni Group
 Two potential Kapuni well locations identified1
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. 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. Effective
date 30 April 2013.
23

24. East Coast Basin Oil Shales
Advancing unconventional oil shales
 Over 300 oil and gas seeps sourced back to
two oil shale formations
 NZEC has drilled three wells to take core
samples from the Waipawa Black Shale1
• Late Paleocene
• 10-50 metres thick
• TOC typically 2-6%, up to 12%
• S2 typically 5-20 kg HC/t rock
• Kerogen Type II + III
• Shale porosity 5-10%
• Quartz 46-56%
• Clay 28-38%
• Carbonate 0-4%
NZEC’s East Cape Permit
 1,048,406 acres
 Exploration period granted to Dec 2018
 Estimated prospective resources2
• Conventional: 53.3 million bbl oil
• Unconventional: 302.1 million bbl oil
1. Technical data for Waipawa Black Shale gleaned from both NZEC’s work and other technical work in the region. 2.
Resource estimate completed by Deloitte LLP with an effective date of February 1, 2011. Best estimate assuming 9%
recovery for conventional resources and 2% recovery for unconventional resources. See Taranaki and East Coast
Resource Estimates and Cautionary Note Regarding Reserve & Resource Estimates.
24

25. East Coast Geology
 Complex fold and thrust belt, NZEC block contains intact and over thrust strata
 Poor to good source rock characteristics
 Poor to marginal thermal maturity from outcrop and well samples
PEP 52976
25

26. Board of Directors
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.
David Robinson, B.A,
G.C.M
Director,
Chief Executive Officer
• More than 20 years management experience
in the oil and gas industry across commercial,
operations, health and safety and governance.
• CEO, Petroleum Exploration & Production Assoc. of New
Zealand
• Commercial General Manager, Z Energy
• Director, other downstream commercial positions, Shell
John Proust, C.Dir
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.
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
26

27. NZEC – Key Personnel
Name Expertise Experience
David Robinson, Director,
Chief Executive Officer
• More than 20 years management experience in the oil and gas industry
across commercial, operations, health and safety and governance.
• CEO, Petroleum Exploration & Production Assoc. of New Zealand
• Commercial General Manager, Z Energy
• Director, other downstream commercial 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
Derek Gardiner, MBS CA ACIS
Chief Financial Officer
• More than 25 years international financial management, governance and
joint venture experience in the oil and gas industry.
• Commercial and Finance Manager, Origin Energy, NZ
• CFO, Austral Pacific
• Finance Director, Shell Development Australia
• Senior Manager Business Planning, Sarawak Shell Bhd
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
Peter Kingsnorth,
Operations Manager
• Mechanic and Fitter Turner with over 25 years of experience in oil and gas
plant commissioning and start up, staffing and operation of oil and gas
fields and production facilities
• Mechanical Supervisor, Fitzroy Engineering
• Project Operations Lead, Ahuroa Gas Storage Facility
• Operations Team Leader, Origin Energy
Simon Ward, BSc (Hons), PhD
Geoscience and Compliance
Manager
• 13 years experience as geological consultant based in Wellington New
Zealand, and 4 years experience with NZEC. Specialist in petroleum
geology related to Taranaki and other New Zealand basins
• Drilling risk assessment and well design
• Well site and operations geology
• Production analysis, modeling and report
• Regulatory compliance and Resource Consent applications
Newton Cockerill, B.Com
Financial Controller
• Accountant with 20 years of finance experience, including 7 years in the oil
and gas industry
• Expertise in budgeting, forecasting, strategic planning, financial reporting,
consolidation and control
• Progressively senior positions within private sector
• Recent roles include 5 years with Origin Energy as Business Performance
and Accounting Manager, and 5 years with Orange Plc in the UK as Senior
Consolidation Analyst
Jason Rowe,
Health & Safety Manager
• 13 years health, safety and environmental experience within the oil, gas
and construction industry advancing safety cultures, compliance and HSE
management systems
• HSE CNPC Chuanqing Drilling Engineering Company - Kapuni Tight Gas
Project (STOS) and Cheal C (TAG)
• HSE Kaefer Integrated Services – NP Power Station Project for Contact
Energy
• HSE Chain Resources – Drilling for Origin Energy
David Hoke, BSc
Petroleum Engineer
• 38 years experience working for major and independent oil companies
around the world. Most recent experience has focused on reservoir
management, production optimization and new filed exploration
• Reservoir Engineering Specialist BP (ARCO Indonesia)
• Reservoir/Production Engineer, Swift Energy New Zealand
• Consulting Reservoir Engineer Murphy Oil Malaysia
• Reservoir Engineer Team Leader ROC Oil Beijing China
27

28. Contact NZEC
Corporate Head Office
David Robinson, Chief Executive Officer
119-125 Devon Street East
New Plymouth
New Zealand
Phone: + 646-757-4470
info@newzealandenergy.com
www.NewZealandEnergy.com
28

29. Appendix
29

30. NZEC Reserve Estimate (net to NZEC)1
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)
30

31. 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.
31

32. Copper Moki Performance
Original reservoir
pressure depicted by
Copper Moki 1 in
Sept-2011.
Waitapu-2 completion
encounters ~1000 psi
depletion in Dec-2012.
Decline in production
rate associated with
pressure depletion.
32

33. 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 1874 194,737
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 production1
33

34. Future Tikorangi Development Proposal
Increasing production to initiate depletion drive mechanisms
Strategy is to
mobilise oil by
reducing reservoir
pressure below
historic low
(~1994).
Enhanced recovery
potential depends
on level of
pressure depletion
achieved.
34

35. Analyst Coverage
Company Analyst Contact
Dundee Capital Markets Jessica Lindskog +44-203-440-6872
Mackie Research Bill Newman +1-403-750-1297
M Partners David Buma +1-416-603-7381
Prosdocimi Dorian Prosdocimi +44-207-199-3000
35