Growth Through Acquisition and Exploration Corporate Update June 19, 2013 TSX-V: NZ OTCQX: NZERF

NZEC Board of Directors

2

John Greig Chairman

John Proust CEO

Bruce McIntyre Executive Director

Hamish Campbell

NZEC Executive Management Team

3

Chris Bush New Zealand

Country Manager

Ian Brown Chief Operating

Officer

Chris Ferguson Chief Financial

Officer

Gerrie van der Westhuizen

VP Finance

Celeste Curran

VP Corporate & Legal Affairs

Rhylin Bailie VP Investor Relations &

Communications

Mike Oakes, General Manager Midstream Operations Cliff Butchko, General Manager Upstream Operations Eileen Au, Corporate Secretary

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

4

Asset Overview

5

Permit Working Interest

Net Acres 2P BOE Reserves 1

Contingent Resource 2

Prospective Resource 2

Eltham 100% 93,166 708 Mboe - 31.6 MM bbl

Alton 65% 77,482 - - 45.0 MM bbl

Manaia 60% 16,456 - - Early stage

TWN 3 100% 23,049 2,145 Mboe 1,162 Mboe 23,541 Mboe

Ranui 100% 223,087 - - 40.5 MM bbl

Castlepoint 100% 551,045 - - 208.6 MM bbl

Wairoa 4 80% 214,290 - - Under review

East Cape 5 100% 1,067,495 - - 355.4 MM bbl

Total Acreage 2,266,070

1. Estimated by Deloitte LLP with an effective date of April 30, 2013. 2. Best estimate of contingent and prospective resources assuming 9% to 14% recovery for conventional oil resources and 50% for gas resources. Estimated 2% recovery for unconventional oil resources. See detailed Reserve and Resource tables and Cautionary Notes. 3. Acquisition of TWN Petroleum Licenses and Waihapa Production Station pending. See Strategic Acquisition. 4. Acquisition of Wairoa Permit pending NZPAM approval. 5. Grant of East Cape Permit pending NZPAM approval. 6. TWN Reserves and Resources will not transfer to NZEC until the Acquisition is complete and NZEC files an updated reserve report.

Eltham Alton

Ranui

Castlepoint

East Cape

Conventional Focus

Conventional and Unconventional Targets

Wairoa TWN

Manaia

Recent Milestones

6

• Increased North Island exploration portfolio by 250,000 acres to 2,028,730 acres 3

• Established partnerships with Westech Energy and New Zealand Oil & Gas 3

• Drilled nine wells on Eltham Permit four wells in production, two awaiting artificial lift evaluation, one pending completion 1

• Installed permanent facilities at Copper Moki site • Increased Eltham 2P reserve base by 151% 2

• Completed 100 km2 of 3D seismic in Taranaki Basin, merged five seismic datasets to compile seamless 3D coverage across main Taranaki production fairway

• Completed 120 km of 2D seismic on East Coast • Drilled three stratigraphic wells to collect core from

East Coast Basin oil shales • Recruited industry experts to leadership team • Continued to build strong community relationships • Launched acquisition for strategic upstream and

midstream assets • Finalized sale and purchase agreement for

acquisition

1. Copper Moki-1, -2, and -3 wells in production. Waitapu-2 temporarily shut in for down-hole tests and evaluation of artificial lift. Arakamu-2 and Copper Moki-4 awaiting artificial lift evaluation. Wairere-1A pending completion. 2. See NZEC Eltham Reserve Estimate and Cautionary Note Regarding Reserve and Resource Estimates. 3. Including permits pending. See Asset Overview and NZEC Resource Estimates.

Three new Petroleum Licences in the main production fairway

• Near-term production potential from existing wells

• New exploration opportunities • 2,144,700 boe 2P Reserves 2

(89% liquids)

• 1,162,000 boe Contingent Resources 2 (28% liquids)

• 23,541,000 boe Prospective Resources 2

(31% liquids) Full-cycle production facility central to NZEC’s permits and other oil/gas fields 1. Closing of the Acquisition is subject to meeting the financing condition precedent by August 14 and the government approval condition precedent by September 13, in order to close the Acquisition by September 20, 2013. 2. Resources are best estimate. The Petroleum Licences and attributable reserves and resources will not transfer to NZEC until the Acquisition is complete. See TWN Reserves and TWN Resources and Cautionary Notes.

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Strategic Acquisition 1

Shell

Gas Storage Facility

Power Station

Strategic Acquisition – Results of Extended Negotiation

• Reduced purchase price and simplified sale agreement 1

• NZEC retains 100% of production from existing and new wells in all formations subject to a 9% royalty payable to Origin 2

• Quantified reserves and resources on the TWN Licences will add 2,144,700 boe of 2P reserves to NZEC’s inventory (300% increase) plus substantial resources 3

• Identified potential gas supply adequate to run Waihapa Production Station and reactivate gas lift on Tikorangi wells 4

• Identified opportunities to use Waihapa Production Station to full capacity

8

1. See Comparison of Final and Original Acquisition Terms. Closing of the Acquisition is subject to meeting the financing condition precedent by August 14 and the government approval condition precedent by September 13, in order to close the Acquisition by September 20, 2013 2. The Origin royalty is payable at 9% of net revenue (hydrocarbon sales less operating expenses incurred between the point of valuation and the point of sale). NZEC may buy back at any time and from time to time up to 4% of the Origin royalty by paying C$4.25 million per percentage point. The TWN Licences are also subject to a government royalty payable at 10% of net revenue as they are “grandfathered” under the 1937 Petroleum Act. 3. See TWN Reserves and Cautionary Notes. Reserves and resources will not transfer to NZEC until the Acquisition is complete. 4. Gas supply dependent on outcome of NZEC/Contact gas throughput study and gas looping trial.

9

Comparison of Final and Original Acquisition Terms 1

Final Terms Original Terms Purchase price • C$33.5 million • No additional adjustments to purchase price

Purchase price • C$42 million • Additional C$9 million in adjustments at closing

(NZEC internal estimate)

Petroleum Licences • Ultimate ownership of three Petroleum Licences: Tariki, Waihapa and

Ngaere (“TWN Licences”). The Ahuroa Licence will be transferred to Contact Energy. Total acreage: 23,049 acres (93.3 km2)

Petroleum Licences • NZEC purchasing four Petroleum Licences: Tariki,

Ahuroa, Waihapa and Ngaere. Total acreage: 26,907 acres (108.9 km2)

Royalty payable to Origin 2

• 9% net revenue royalty payable to Origin on all future hydrocarbon production on the Licences

• NZEC retains the ability to buy back up to 4% of the royalty at any time for C$4.25 million per point

Royalty payable to Origin • 5% net revenue royalty payable to Origin on all

future hydrocarbon production on the Petroleum Licences

Commitments to Origin • Simplified sale agreement

- NZEC retains 100% of production from all existing and new wells on the TWN Licences in all formations, subject to the Origin Royalty (and a 10% royalty payable to the NZ Government)

- Origin relinquishes all other rights and encumbrances on the TWN Licences

Commitments to Origin • NZEC responsible for 100% of costs associated with

drilling a well to the crestal interval of the Tikorangi formation, with profits to be shared 50/50 with Origin

• Origin retained rights to eight “option wells” for gas storage

1. Closing of the Acquisition is subject to meeting the financing condition precedent by August 14 and the government approval condition precedent by September 13, in order to close the Acquisition by September 20, 2013. 2. The Origin royalty is payable at 9% of net revenue (hydrocarbon sales less operating expenses incurred between the point of valuation and the point of sale). NZEC may buy back at any time and from time to time up to 4% of the Origin royalty by paying C$4.25 million per percentage point. The TWN Licences are also subject to a government royalty payable at 10% of net revenue as they are “grandfathered” under the 1937 Petroleum Act.

Significant Growth in Reserves Post Acquisition 1

10

0

500

1000

1500

2000

2500

3000

3500

NZEC Reserves TWN Reserves Total NZEC ReservesPost Acquisition

Estim

ated

Res

erve

s M

boe

Proved Probable Possible

1. Reserves estimated by Deloitte LLP. NZEC reserves have an effective date of December 31, 2012 and are restricted to the Eltham Permit. TWN Reserves have an effective date of April 30, 2013 and are restricted to the Tikorangi Formation on the Waihapa and Ngaere Permits. See detailed Reserve tables and Cautionary Notes. The TWN Reserves will not be attributable to NZEC until the Acquisition closes and NZEC files an updated reserve report. See Strategic Acquisition.

1

TWN Reserve Estimate 1

11

Reserve Category Light & Medium Oil

(Mbbl)

Natural Gas

(MMcf)

Natural Gas Liquids (Mbbl)

Barrels of Oil Equivalent

(Mboe)

NPV, Before Tax (10%)

Proved Developed (Non-producing)

983.7

762.0

26.7

1,137.4

$36,142,000

Proved Undeveloped

258.1

206.5

7.2

299.8

$7,340,000

Total Proved

1,241.8

968.5

33.9

1,437.1

$43,482,000

Probable

610.9

479.3

16.8

707.6

$19,393,000

Proved + Probable (2P)

1,852.7

1,447.8

50.7

2,144.7

$62,875,000

1. Reserve estimate completed by Deloitte LLP with an effective date of April 30, 2013. Reserves restricted to the Tikorangi Formation on the Waihapa and Ngaere Permits. See Cautionary Note Regarding Reserve & Resource Estimates. Reserves will not be attributable to NZEC until the Acquisition is complete and NZEC files an updated reserve report.

TWN Resource Estimate 1

Formation Product Type Low Best High

Contingent Resources

Miocene Sands (Mt. Messenger) Oil (Mbbl) 35 88 203

Eocene Sands (Kapuni Group) Gas (MMcf – sales) 2,513 5,036 10,336

NGL (Mbbl) 101 233 525

Total BOE (Mboe) 567 1,162 2,426

Prospective Resources

Miocene Sands (Urenui, Mt. Messenger, Moki) Oil (Mbbl) 1,606 2,941 5,732

Eocene Sands (Kapuni Group) Gas (MMcf – sales) 42,833 95,837 226,424

NGL (Mbbl) 1,909 4,498 11,375

Total BOE (Mboe) 10,825 23,541 54,368

Discovered PIIP

Miocene Sands (Mt. Messenger) Oil (Mbbl) 327 681 1,400

Eocene Sands (Kapuni Group) Gas (MMcf – raw) 7,211 13,770 26,935

Total BOE (Mboe) 1,529 2,976 5,889

Undiscovered PIIP

Miocene Sands (Urenui, Mt. Messenger, Moki) Oil (Mbbl) 11,315 20,442 37,804

Eocene Sands (Kapuni Group) Gas (MMcf – raw) 118,981 261,080 605,860

Total BOE (Mboe) 31,145 63,955 138,781

1. Resources estimated by Deloitte with an effective date of April 30, 2013 assuming 9 to 14% recovery for oil resources and 50% for gas resources. See Cautionary Note Regarding Reserve and Resource Estimates. Resources will not be attributable to NZEC until the Acquisition is complete. 12

Valuable Upstream Assets

13

• Tariki, Waihapa and Ngaere petroleum licences covering 23,049 acres, contiguous with Eltham and Alton permits

• 23 MM bbl historical production from the Tikorangi formation 2,144,700 boe 2P Tikorangi reserves remaining 1

• Additional contingent and prospective resources from other formations 1

• 16 established drill sites with oil and gas gathering systems in place

Technical Data • Well information from 27 existing wells • 3D seismic covering southern half of the TWN

Licences • 585 km 2D seismic • TWN seismic has been merged with NZEC’s

existing seismic, providing seamless coverage across TWN, Eltham and Alton permits

1. Reserve estimate completed by Deloitte LLP with an effective date of April 30, 2013. Reserves restricted to the Tikorangi Formation on the Waihapa and Ngaere Permits. See Cautionary Note Regarding Reserve & Resource Estimates. Reserves and resources will not be attributable to NZEC until the Acquisition is complete and NZEC files an updated reserve report.

Waihapa Production

Station

Waipapa site

TARIKI LICENCE

NGAERE LICENCE

WAIHAPA LICENCE

Multiple Prospective Formations

14

Moki

Tikorangi

Kapuni

Mt Messenger

Historical Production – Tikorangi Formation

1. Select production data using publicly available information regarding wells that produced oil on the TWN Licences.

Waihapa Production

Station

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 million bbl of historical production 1

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Tikorangi Formation

Drill-proven formation • 23 million bbl historical production from 17 wells 1

• Remaining 2P reserves estimated at 1,852,700 bbl oil, 1.45 Bcf gas, 50,700 bbl NGL 2

Recommence production from existing wells • Six wells with reactivation potential • Gas lift system in place, potential gas supply identified 3

• Gathering systems in place • Near-term production potential, low cost

Drill crestal well into remaining reserves • Significant opportunity to drill new wells to access

further identified oil accumulations in the Tikorangi

16

1. See History of TAWN Permits. 2. Reserve estimate completed by Deloitte LLP with an effective date of April 30, 2013. Reserves restricted to the Tikorangi Formation on the Waihapa and Ngaere Permits. See Cautionary Note Regarding Reserve & Resource Estimates. Reserves will not be attributable to NZEC until the Acquisition closes and NZEC files an updated reserve report. 3. Gas supply dependent on outcome of NZEC/Contact gas throughput study and gas looping trial.

Mt. Messenger Formation (Miocene Sands)

Drill-proven formation • Significant discoveries to the west (TAG:

Cheal), south (NZEC: Copper Moki, Waitapu, Arakamu) and east (Kea: Puka)

• Contingent resources: 88,000 bbl oil 1

• Prospective resources: 2,061,000 bbl oil 1

Low-cost production potential in existing wells • Well information shows uphole completion

potential in six existing wells • 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 • Five high-priority targets at Waipapa site,

permitting complete

17

1. Prospective resources for Mt. Messenger formation only. Additional ~880,000 bbl prospective resources estimated for Urenui and Moki formations. Resources estimated by Deloitte with an effective date of April 30, 2013 assuming 9 to 14% recovery for P50 resources. See Cautionary Note Regarding Reserve and Resource Estimates. Resources will not be attributable to NZEC until the Acquisition closes.

Waipapa wellsite

Kapuni Group (Eocene Sands)

Drill-proven formation • Kapuni Gas Field onshore oil/gas discovery

(Shell) producing since 1969, estimated ultimate recovery of 1,365 Bcf natural gas and 66 million bbl oil

• TWN Licences tested by four wells all encountered gas in the Kapuni Group

2013 Deloitte Resource Estimate 1

• Contingent resource: 5.0 Bcf gas, 233,000 bbl NGL 1

• Prospective resource: 95.8 Bcf gas, 4.5 million bbl NGL 1

• Discovered PIIP: 13.8 Bcf gas 1 • Undiscovered PIIP: 261.1 Bcf gas 1

18

1. Resources estimated by Deloitte with an effective date of April 30, 2013 assuming 50% recovery for P50 gas resources. See Cautionary Note Regarding Reserve and Resource Estimates. Resources will not be attributable to NZEC until the Acquisition closes.

History of TAWN Petroleum Licences 1 Tariki, Ahuroa, Waihapa and Ngaere Petroleum Mining Licences (“PMLs”)

• 1978 – Petroleum Corporation of New Zealand formed for NZ Government’s petroleum exploration activities

• 1987 – Petrocorp publicly listed, Fletcher Challenge buys 15%, government retains 70%, TAWN Permits granted to Petrocorp

• March 1988 – Fletcher Challenge buys remaining 70% of Petrocorp, assumes ownership of TAWN Permits, becomes Fletcher Energy

• 1988-1998 – Petrocorp drills a number of wells, including 14 that produce oil and gas, converts permits to PMLs

• October 2000 – Shell and Apache buy Fletcher Energy, Shell gets TAWN PMLs • January 2002 – Swift Energy acquires TAWN PMLs and Waihapa Production

Station • 2002-2006 – Swift Energy drills a number of wells, including three producers • June 2008 – Origin Energy acquires Swift Energy’s NZ assets, sells inset permit

within Ahuroa PML to Contact Energy for gas storage usage (Origin owns 53% of Contact)

• May 2012 – NZEC agrees to acquire TAWN assets • June 2013 – NZEC / Origin / Contact finalize agreements for acquisition 2

19

1. Based on publicly available information. 2. Closing of the Acquisition is subject to meeting the financing condition precedent by August 14 and the government approval condition precedent by September 13, in order to close the Acquisition by September 20, 2013

20

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 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

Waihapa Production Station Assets Full-cycle facility with gathering and sales pipeline infrastructure

Includes 100 acres of fields surrounding the facility

1. Closing of the Acquisition is subject to meeting the financing condition precedent by August 14 and the government approval condition precedent by September 13, in order to close the Acquisition by September 20, 2013

Production Facility: Buy vs Build Waihapa Production Station 1 Neighbouring Production Facility 4

Gas processing 45 MMcf/day Gas processing 15 MMcf/day

Oil handling 25,000 bbl/day Oil handling 5,000 bbl/day

Water handling 18,000 bbl/day Water handling None

NGL recovery 70 tonne/day NGL recovery None

Pipelines 8” 49-km oil sales line to 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 • 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) 2

• Includes additional 1,162,000 boe contingent resources, 23,541,000 boe prospective resources 2

Cost to expand C$30 million No exploration land

Cost to replace 3

+/- 30% Oil plant: NZ$35.2 million, Gas plant: NZ$40.8 million Gathering systems: NZ$70.6 million, Wellsite and satellite facilities: NZ$10.6 million

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1. Closing of the Acquisition is subject to meeting the financing condition precedent by August 14 and the government approval condition precedent by September 13, in order to close the Acquisition by September 20, 2013. 2. Reserves and resources will not be attributable to NZEC until the Acquisition closes and NZEC files an updated reserve report. See TWN Reserves and TWN Resources and Cautionary Notes. 3. Cost to replace NZEC plant and pipelines estimated by Strive Engineering effective July 18, 2012. 4. Information regarding neighbouring production facility compiled using publicly available information.

Waihapa Production Station Expedited tie-in of discoveries, midstream commercial opportunities

22

• Central to NZEC’s inventory of exploration prospects - Expedites tie-in of natural gas and liquids - Reduces NZEC’s processing and transportation costs - Gathering capacity in place to service NZEC’s oil and

gas production - Sales pipelines in place to deliver NZEC production

to market • Only open-access midstream facility in Taranaki

Basin business opportunities for processing and handling third-party gas, liquids, oil and water

• NZEC / Contact study underway regarding gas looping

• If successful, 6-month trial will commence to achieve the following1: - Blend NZEC’s liquid-rich gas for delivery to market - Activate gas lift for Tikorangi wells to extract

additional oil and gas production - Test economics of natural gas liquids extraction

1. Gas supply dependent on outcome of NZEC/Contact gas throughput study and gas looping trial. There can be no certainty as to the tenure of the arrangement or that the gas throughput trial will be successful.

Shell

Gas Storage Facility

Power Station

23

Taranaki Basin – Existing Permits 23

Taranaki Basin Conventional Focus

24

• NZEC controls three permits with extensive 3D-identified leads and prospects

• Four wells in production, two wells awaiting artificial lift, results pending from one additional well 4

• Acquisition of assets from Origin will add three new petroleum licences, new drilling leads and near-term production opportunities 5

• 2D seismic database: 73,364 km • 3D seismic database: 6,835 km2

187,104 Net acres

843 Million Barrels OOIP 3

77.1 Million Barrels conventional prospective resource 2

996,000 Barrels oil equivalent 3P reserves 1

1. Reserves estimate by AJM Deloitte based on reservoir and production data from three Copper Moki wells and Waitapu well with a December 31, 2012 effective date. See Reserve Estimates and Cautionary Note Regarding Reserve & Resource Estimates. 2. Net Prospective Resource as identified by AJM Petroleum Consultants (best estimate) assuming 9% recovery. See Resource Estimates and Cautionary Note Regarding Reserve & Resource Estimates. 3. Net Undiscovered Petroleum Initially in Place (OOIP) as identified by AJM Petroleum Consultants. See Cautionary Note Regarding Reserve & Resource Estimates.

Building Inventory of Drilling Leads 3D seismic identified new targets in deeper formations

25

Waitapu wells

Copper Moki wells

Arakamu wells

Eltham Permit

Alton Permit

Wairere wells

Horoi site

Drilling / Production Report Card

26

Well Name

Target Formation

Total Depth

Status Total Oil Prod (end May 2013)

Copper Moki-1 Copper Moki-2 Copper Moki-3 Copper Moki-4

Mt. M Mt. M

Mt. M / Moki Mt. M / Urenui

2,220 m 2,084 m 3,167 m 2,125 m

Producing since December 2011 Producing since April 2012

Producing from Mt. Messenger since July 2012 Urenui oil discovery, shut in pending further testing

107,499 bbl 84,568 bbl 41,490 bbl

Waitapu-1 Waitapu-2

Mt. M Mt. M

2,213 m 2,084 m

Shut in pending further testing or sidetrack Producing since December 2012 1

18,790 bbl

Arakamu-1A Arakamu-2

Moki Mt. M

2,900 m 2,380 m

Suspended, pending further evaluation Oil discovery in April 2013, awaiting artificial lift

Wairere-1 Wairere-1A

Mt. M Mt. M

1,971 m 2,152 m

Plugged back for sidetrack Completion pending

Drilling / Production Report Card

1. Waitapu-2 was temporarily shut in at the end of May to allow the Company to analyze artificial lift options and perform tests related to the Copper Moki reservoir study.

• Engaged RPS, world-recognized leader in geological and reservoir evaluation, to undertake comprehensive reservoir study to assist in optimizing production and go-forward strategy

Notes: Gross reserves before the deduction of royalty obligations payable to the New Zealand government. Numbers may not sum due to rounding. Reserve estimates calculated by Deloitte. Mbbl – thousand barrels of oil. MMcf – million cubic feet of natural gas. Mboe – thousand barrels of oil equivalent using a conversion ratio of 6 Mcf : 1 bbl. Barrels of oil equivalent (boe) may be misleading, particularly if used in isolation. The boe conversion ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves. See Cautionary Note Regarding Reserve and Resource Estimates.

NZEC Eltham Reserve Estimate

27

Proved Developed Producing 307.8 594.9 38.7 445.7 $14,400,000

Proved Undeveloped 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

NPV, Before Tax (10%)

Marketable Oil and Gas ReservesAs at December 31, 2012Forecast Prices and Costs

Reserves Category Natural Gas Liquids (Mbbl)

Barrels Oil Equivalent (Mboe)

Natural Gas (MMcf)

Light & Medium Oil (Mbbl)

28

East Coast Basin

28

East Coast Basin Unconventional Opportunity

29

• World-class resource potential in two oil shale packages

• 2 permits issued, 2 permits pending 1

• Seeking partnerships to advance permits

• 1.4 B bbl conventional PIIP 3

• 20.9 B bbl unconventional PIIP 3

• 2D seismic database: 9,479 km • 3D seismic database: 662 km2

2.06 Million Net acres 1

125.8 Million Barrels conventional prospective resource 2

478.7 Million Barrels unconventional prospective resource 2

1. Grant of East Cape Permit (100% ownership) pending Crown approval. Acquisition of Wairoa Permit (80% ownership) pending Crown approval. 2. Net Prospective Resource as identified by AJM Petroleum Consultants (best estimate) assuming 9% recovery for conventional resources and 2% recovery for unconventional resources. Does not include resource estimate for Wairoa Permit, which is under evaluation. See Resource Estimates and Cautionary Note Regarding Reserve & Resource Estimates. 3. Net Undiscovered Petroleum Initially in Place (PIIP) as identified by AJM Petroleum Consultants. See Resource Estimates and Cautionary Note Regarding Reserve & Resource Estimates.

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 • Advancing technical understanding of shale

targets - Wairoa acquisition adds 214,290 acres to

NZEC’s portfolio - NZEC analyzing results from three stratigraphic

wells and 70 km of 2D seismic on Ranui and Castlepoint permits

• Two commitment wells required in Q4-2013 (one each on Ranui and Castlepoint)

• Retained Core Laboratories as technical advisor to develop East Coast strategy

30

1. Acquisition of Wairoa Permit and grant of East Cape Permit pending Crown approval. Acquisition of TWN Petroleum Licenses and Waihapa Production Station (in Taranaki Basin) pending. See Strategic Acquisition.

TAG pilot hole

Expanded East Coast Acreage – Wairoa Permit

• Wairoa Permit and surrounding area is most-explored region of East Coast

• Log data from 16 wells and more than 500 km of 2D seismic shows both conventional and unconventional opportunities

• NZEC’s technical team has worked extensively on the property (as consultants) - Seismic acquisition and interpretation - Wellsite geology and prospectivity evaluation - Permitting and land access agreements - Consultation with community members, local

government, local iwi, service providers • Established relationships with local communities • Successfully acquired 50-km of 2D seismic,

technical studies and seismic processing underway

31

Exploration wells drilled by Westech Energy New Zealand discovered oil and natural gas, but did not make a commercial discovery

1. Acquisition of Wairoa Permit pending Crown approval. NZEC will own 80% and operate the permit, in partnership with Westech Energy New Zealand.

Corporate Profile

32

1. As per NZEC’s year-end 2012 financial results, released on April 25, 2013. NZEC’s Q1-2013 results will be released in the last week of May.

2. 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.

Common Shares Outstanding Options (Exercisable at average $1.37) Fully Diluted Shares Outstanding

122.0 million 9.9 million

131.9 million

Insider Ownership (fully diluted) 52 Week High / Low Average Volume (Q1-2013)

~35% $2.39 / $0.30

~450,000 shares/day

Current market cap (June 18, 2013) ~$50 million

Financial Highlights 1

Oil sold – during the period (incl. pre-production testing) Oil sold – cumulative (incl. pre-production testing) Cash flow from petroleum operations Average realized oil price Average netback 2

Cash invested in property, plant and equipment

Q1-2013 30,179 bbl

235,992 bbl $1.2 million $112.35/bbl

$45.29/bbl $12.0 million

12 Months 2012 187,643 bbl 205,813 bbl

$13.8 million $106.71/bbl

$70.08/bbl $40.7 million

Estimated net working capital of $12 million (May 22, 2013)

Six Month Go-forward Plan

33

• Complete the TWN acquisition - Reactivate six existing Tikorangi oil wells - Install high-volume downhole electric submersible pumps (ESPs) in two of the reactivation wells - Come uphole in two existing wells and complete Mt. Messenger formation - Commence six-month “looping” trial with Contact Energy based upon results of current study - Develop plans to drill Tikorangi and Kapuni targets

• Drill Horoi South commitment well on the Alton Permit • Optimize Mt. Messenger strategy including all permits and TWN Petroleum Licences by

end of Q3-2013 (RPS evaluation) drilling program to follow • Apply for mining permit for Copper Moki area • Apply for second five-year term on Eltham and Alton permits, high-grading and retaining

50% of the permit area • Continue to seek partners for East Coast properties to advance Wairoa, Castlepoint and

Ranui permits two commitment wells required by year-end (Castlepoint and Ranui) • Finalize definition with NZPAM on what constitutes a “discovery” for unconventional

shales • Progress East Coast strategy with technical input from Core Laboratories (Houston) • Continue iwi engagement in advance of East Cape Permit award

34

Appendix

Board of Directors

35

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, CEO & Director, Southern Arc Minerals Inc. •Chairman, Canada Energy Partners Inc.

Bruce G. McIntyre, P.Geol

Executive Director

•Professional petroleum geologist with over 30 years of proven exploration and development oriented value creation

•President, CEO Sebring Energy Inc. •President, CEO TriQuest Energy Corp. •President, CEO BXL Energy Ltd., • Exploration Manager Gascan Resources Ltd.

Hamish J. Campbell B.Sc (Geology),

FAusIMM Director

•Professional geologist with 30 years of experience managing exploration programs, evaluation and assessment of joint ventures and acquisitions

•Director of a number of New Zealand limited liability mineral and petroleum companies

•Principal Indonesian mining service company

Corporate Office – Canada

36

Name Expertise Experience

John G. 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, CEO & Director, Southern Arc Minerals Inc. • Chairman, Canada Energy Partners Inc.

Bruce G. McIntyre, P.Geol Executive Director

• Professional petroleum geologist with over 30 years of proven exploration and development oriented value creation

• President, CEO Sebring Energy Inc. • President, CEO TriQuest Energy Corp. • President, CEO BXL Energy Ltd., • Exploration Manager Gascan Resources Ltd.

Celeste M. Curran, B.A. (Hon), L.L.B.

VP Corporate & Legal Affairs

• Over 20 years of legal and negotiating experience specializing in major projects

• VP, Corporate & Legal Affairs, J. Proust & Associates • Lead counsel for City of Vancouver and City of Richmond

for the 2010 Olympic and Paralympic Winter Games • Senior Solicitor, City of Vancouver

Rhylin Bailie, B.ES VP Communications &

Investor Relations

• More than 17 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.

Gerrie van der Westhuizen, CA

VP 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

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 Bryant Resources and Charlotte Resources

Operations Team – New Plymouth, NZ

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Name Expertise Experience

Chris Bush, B.E (Hon) New Zealand

Country Manager

• Chemical engineer with more than 30 years in both upstream and downstream oil and gas experience internationally

• New Zealand Country Manager/Director, Origin Energy • Chairman of Petroleum Exploration and Producers Association

of New Zealand

Chris Ferguson, CA Chief Financial Officer

• Chartered accountant with 18 years of financial, accounting and operational experience

• New Zealand reporting, SEC reporting, SOX 404 compliance

• Finance and Planning Manager, Origin Energy • 13 years of oil and gas experience within the Taranaki Basin

Mike Oakes General Manager

Midstream Operations

• More than 30 years of international oil and gas experience overseeing design, commissioning and start up, staffing and operation of oil and gas fields and production facilities

• Operations Manager, Asset Manager and Operational Excellence Advisor, Origin Energy

• Technical Advisor, Total E&P Borneo

Cliff Butchko P.Eng, MBA (Hon) General Manager

Upstream Operations

• Professional engineer with over 30 years experience evaluating and managing oil and gas resources

• President Omni Oil and Gas Inc. • Vice President Lexoil Inc. • Partner and Co-founder TIFF advisory group • Senior technical positions in several resource companies

James Watchorn, B.Sc Operations Manager

• Mechanical engineer with more than 15 years of experience in all aspects of drilling, completions and production, and facility and wellsite construction

• Production and Facilities Manager, TAG Oil • Senior Petroleum Engineer, Origin Energy • Operations Engineer, Iteration Energy/Chinook Energy

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

Technical Team – Wellington, NZ

38

Name Qualifications Expertise

Dr. Ian Brown B.Sc (Hons), M.Phil, D.Eng, MIPENZ, C.P.Eng Chief Operating Officer; professional geological engineer

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

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

NZEC Resource Estimates (Current Permits)

39

Low Best High Low Best High

TARANAKI BASINEltham (PEP 51150) 377.0 93,166.1 100% NZECConventional 231.4 346.8 578.8 19.7 31.6 56.9

Alton (PEP 51151) 313.6 77,482.4 65% NZEC / 35% L&MConventional 224.8 493.7 1,229.7 18.9 45.0 116.9

Manaia (PEP 54867) 66.6 16,455.7 60% NZEC / 40% NZOGConventional

EAST COAST BASINCastlepoint (PEP 52694) 2,230.0 551,045.0 100% NZECConventional 349.0 586.3 1,053.1 30.3 54.5 102.0 Unconventional 2,958.2 6,743.0 16,190.7 56.2 154.1 458.5

Ranui (PEP 38342) 902.8 223,086.7 100% NZECConventional 94.3 198.3 435.0 8.1 18.0 42.0 Unconventional 440.4 969.0 2,252.5 8.6 22.5 65.2

East Cape (PEP 52976) 4,320.0 1,067,495.2 100% NZEC 1

Conventional 189.8 615.7 1,997.4 14.6 53.3 195.4 Unconventional 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% WestechConventionalUnconventional

Total 9,077.2 2,243,020.9 10,235.1 23,100.9 55,575.5 266.7 681.1 1,943.2 Conventional 1,089.3 2,240.8 5,294.0 91.6 202.4 513.2 Unconventional 9,145.8 20,860.1 50,281.5 175.1 478.7 1,430.0 1 Grant of permit pending. Source: Deloitte LLP, effective date February 1, 2011.

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

New Zealand Advantage

• Proactive Government approach to exploration and development

• Favorable tax and royalty structure 28% corporate tax, royalty higher of 5% of net revenue or 20% of net accounting profits 1

• Brent pricing environment • Proven hydrocarbon systems with

multi-zone potential • Established infrastructure with

capacity • New Zealand Government goal of

energy self sufficiency by 2030 significant in-country demand for both oil and gas

40

1. The Company’s permits and licences are subject to the following Government royalties: (1) exploration permits: 5% of net revenue (hydrocarbon sales less operating expenses incurred between point of valuation and point of sale); (2) mining permits: greater of 5% of net revenue or 20% of net accounting profits (including deductions for capital costs); (3) TWN Licences: “grandfathered” under 1937 Petroleum Act, 10% of net revenue.

Contact NZEC

41

Corporate Head Office John Proust, Chief Executive Officer Bruce McIntyre, Executive Director Rhylin Bailie, VP Investor Relations North America Toll-free: 1-855-630-8997 info@newzealandenergy.com

New Zealand Office Chris Bush, New Zealand Country Manager Tel: + 64-6-757-4470 New Zealand Toll-free: 0800-469-363 www.NewZealandEnergy.com