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December 2013 corporate presentation
 

December 2013 corporate presentation

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    December 2013 corporate presentation December 2013 corporate presentation Presentation Transcript

    • Corporate Presentation October 7, 2013
    • Cautionary Notes Forward-looking Statements This document contains certain forward-looking information and forward-looking statements within the meaning of applicable securities legislation (collectively “forward-looking statements”). The use of any of the words “being”, “will”, “until”, “estimate”, “will be”, “is considering”, “will proceed”, “plans”, “reactivate”, “recommence”, “would be”, “could be”, “will bring”, “could bring”, “expected”, and similar expressions are intended to identify forward-looking statements. These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. Such forward-looking statements should not be unduly relied upon. The Company believes the expectations reflected in those forward-looking statements are reasonable, but no assurance can be given that these expectations will prove to be correct. This document contains forward-looking statements and assumptions pertaining to the following: business strategy, strength and focus; the granting of regulatory approvals; the timing for receipt of regulatory approvals; geological and engineering estimates relating to the resource potential of the Properties; the estimated quantity and quality of the Company’s oil and natural gas resources; supply and demand for oil and natural gas and the Company’s ability to market crude oil, natural gas and; expectations regarding the ability to raise capital and to continually add to reserves and resources through acquisitions and development; the Company’s ability to obtain qualified staff and equipment in a timely and cost-efficient manner; the ability of the Company to obtain the necessary approvals to conclude the acquisition of assets from Origin on schedule, or at all; the ability of the Company to conclude the TWN Joint Venture on schedule, or at all; the ability of the Company’s subsidiaries to obtain mining permits and access rights in respect of land and resource and environmental consents; the recoverability of the Company’s crude oil, natural gas reserves and resources; and future capital expenditures to be made by the Company. Actual results could differ materially from those anticipated in these forward-looking statements as a result of the risk factors set forth below and elsewhere in the document, such as the speculative nature of exploration, appraisal and development of oil and natural gas properties; uncertainties associated with estimating oil and natural gas resources; changes in the cost of operations, including costs of extracting and delivering oil and natural gas to market, that affect potential profitability of oil and natural gas exploration; operating hazards and risks inherent in oil and natural gas operations; volatility in market prices for oil and natural gas; market conditions that prevent the Company from raising the funds necessary for exploration and development on acceptable terms or at all; global financial market events that cause significant volatility in commodity prices; unexpected costs or liabilities for environmental matters; competition for, among other things, capital, acquisitions of resources, skilled personnel, and access to equipment and services required for exploration, development and production; changes in exchange rates, laws of New Zealand or laws of Canada affecting foreign trade, taxation and investment; failure to realize the anticipated benefits of acquisitions; and other factors. Readers are cautioned that the foregoing list of factors is not exhaustive. Statements relating to “reserves and resources” are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the resources described can be profitably produced in the future. The forward-looking statements contained in the document are expressly qualified by this cautionary statement. These statements speak only as of the date of this document and the Company does not undertake to update any forward-looking statements that are contained in this document, except in accordance with applicable securities laws. More information is available in the Company’s Annual Information Form for the year ended December 31, 2012, filed on June 17, 2013 on SEDAR at www.sedar.com. Reserve & Resource Estimates The oil and gas reserve and resource calculations and net present value projections were estimated in accordance with the Canadian Oil and Gas Evaluation Handbook (“COGEH”) and National Instrument 51-101 (“NI 51-101”). The term barrels of oil equivalent (“boe”) may be misleading, particularly if used in isolation. A boe conversion ratio of six Mcf: one bbl was used by NZEC. This conversion ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date, based on: the analysis of drilling, geological, geophysical, and engineering data; the use of established technology; and specified economic conditions, which are generally accepted as being reasonable. Reserves are classified according to the degree of certainty associated with the estimates. Proved Reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves. Probable Reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves. Possible Reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10% probability that the actual remaining quantities recovered will exceed the sum of the estimated proved plus probable plus possible reserves. Revenue projections presented are based in part on forecasts of market prices, current exchange rates, inflation, market demand and government policy which are subject to uncertainties and may in future differ materially from the forecasts above. Present values of future net revenues do not necessarily represent the fair market value of the reserves evaluated. Information concerning reserves may also be deemed to be forward looking as estimates imply that the reserves described can be profitably produced in the future. These statements are based on current expectations that involve a number of risks and uncertainties, which could cause the actual results to differ from those anticipated. Contingent resources are those quantities of oil and gas estimated on a given date to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political and regulatory matters, or a lack of markets. Prospective resources are those quantities of oil and gas estimated on a given date to be potentially recoverable from undiscovered accumulations. Undiscovered resources means those quantities of oil and gas estimated on a given date to be contained in accumulations yet to be discovered. The resources reported are estimates only and there is no certainty that any portion of the reported resources will be discovered and that, if discovered, it will be economically viable or technically feasible to produce. Private Placement On September 19, 2013, NZEC announced a non-brokered private placement (“Offering”) of up to $15 million to consist of up to 45.5 million Subscription Receipts at a price of $0.33 each. The Subscription Receipts will be convertible into Units consisting of one common share and one-half of one non-transferable share purchase warrant entitling the holder to acquire one share at a price of $0.45 for a period of 12 months following closing of the Offering. The proceeds from the sale of the Subscription Receipts will be used to compete the Acquisition of assets from Origin Energy and for general working capital. The funds will be held in escrow and released on closing of the Acquisition. If the Company is unable to close the Acquisition, the proceeds from the sale of the Subscription Receipts will be returned to the subscribers. NZEC will file a short form prospectus with the applicable regulatory authorities in each of the provinces of Canada where Subscription Receipts are sold. On October 1, 2013, NZEC announced that it had met the finance condition precedent for the Acquisition and would continue to raise up to $7.1 million in working capital through the sale of Subscription Receipts. See September 19 and October 1 press releases for more details. 2
    • Strategic Acquisition 1 TWN Assets in Taranaki Basin • Three new Petroleum Licences in the main production fairway • Full-cycle production facility central to NZEC’s permits and other oil/gas fields • Immediate value creation on closing with production from existing wells, followed by new exploration opportunities $33.5 million purchase price • $18.25 million purchase price contribution from L&M Energy to form 50/50 joint venture across TWN Assets • $15.25 million contribution by NZEC • NZEC moving through private placement to raise working capital 2 1. On September 30, 2013, NZEC met the financing condition precedent for the Acquisition and now awaits New Zealand government approval, the final condition required to close the Acquisition. 2. Reserves and Resources shown on 100% basis and will be attributable to NZEC on a 50% basis once the Acquisition and TWN Joint Venture are complete. See TWN Reserves and TWN Resources and Cautionary Notes. 2. See Private Placement in Cautionary Notes. 3
    • Asset Overview Permit Working Interest Net Acres 2P boe Reserves 1 Contingent Resource 2 Prospective Resource 2 Eltham 100% 93,166 708 M boe - 31.6 MM bbl Alton 65% 77,482 - - 45.0 MM bbl Manaia 60% 16,456 - - Early stage TWN 3 50% 11,525 1,072 M boe 581 M boe 11.78 MM boe Castlepoint 100% 551,045 - - 208.6 MM bbl Wairoa 4 80% 214,290 - - Under review Ranui 100% 223,087 East Cape 5 100% 1,067,495 Total 2,254,546 Considering relinquishment - - 2P Reserves 1,780 M boe 40.5 MM bbl 355.4 MM bbl Conventional Focus East Cape Conventional and Unconventional Targets TWN Manaia Eltham Wairoa Alton Castlepoint Ranui 1. Estimated by Deloitte LLP with an effective date of April 30, 2013. 2. Best estimate of contingent and prospective resources assuming 9% to 14% recovery for conventional oil resources and 50% for gas resources. Estimated 2% recovery for unconventional oil resources. See detailed Reserve and Resource tables and Cautionary Notes. 3. Acquisition of TWN Petroleum Licences and Waihapa Production Station, and TWN Joint Venture, pending. See Strategic Acquisition. 4. Acquisition of Wairoa Permit pending NZPAM approval. 5. Grant of East Cape Permit pending NZPAM approval. 6. TWN Reserves and Resources will not transfer to NZEC until the Acquisition is complete and NZEC files an updated reserve report. 4
    • 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
    • Understanding the Mt. Messenger Formation • Four successful NZEC Mt. Messenger wells drilled to date • 265,636 bbl produced to end of August 2013 • Initial production and decline rates varied - Results consistent with Mt. Messenger wells on adjacent permits • Engaged RPS, world leader in well evaluation, to complete independent reservoir study to better understand reservoir characteristics and declines - Used data from Copper Moki, Waitapu and other Mt. Messenger wells in region - Resulted in a better understanding of reservoir characteristics and concluded that declines are not related to wax buildup or mechanical issues • Allowed NZEC to develop a composite type curve for Mt. Messenger production • Proprietary merged 3D seismic provides better identification of targets • Go-forward exploitation strategy - Can more accurately estimate economic pool size with knowledge from RPS study - Reduce costs by drilling multiple wells from each pad - Prioritize targets close to Waihapa Production Station  expedited tie-in 6
    • TWN Joint Venture = 50/50 NZEC/L&M 1 2 3 3 3 2 1. On September 30, 2013, NZEC met the financing condition precedent for the Acquisition and now awaits New Zealand government approval, the final condition required to close the Acquisition. NZEC will become the operator of all permits and assets. 2. Total purchase consideration agreed with Origin amounts to ~$33.5 million, of which L&M will pay $18.25 million and NZEC will pay $15.25 million. 3. TWN reserves and resources shown at a 100% basis, of which 50% will be attributable to NZEC upon closing of the Acquisition and TWN Joint Venture. 7
    • Investment Highlights Post Acquisition Based on NZEC’s Mid-case Production and Financial Model Strategic Acquisition • Resulting in a fully integrated upstream/midstream company with cash flow, infrastructure and inventory to support long-term growth Accretive to Reserves, Production and Cash Flow • Additional 1.07 million boe 2P reserves 1 with estimated before tax NPV (10%) of $31.4 million ($13.84/boe acquisition cost) 2 • Forecast production of 2,300 boe/day exit 2014 (81% oil) 3 • Forecast cash flow from operations of $26.1 million from early Q4-2013 closing to exit 2014 3 Cornerstone Joint Venture Investment • $18.25 million from L&M Energy to form 50/50 JV for TWN Licences and Waihapa Production Station • NZEC is operator, L&M adds technical expertise and financial participation • L&M will pay 50% of all TWN and WPS costs  reduces NZEC’s capital spend and G&A Immediate Valuation Triggers • Reactivate six existing Tikorangi wells with gas lift  total initial production net to NZEC of 120 bbl/d (risked) 3 • Install high volume lift on six reactivated wells  total initial production net to NZEC of 810 bbl/d (risked) 3 • Uphole Mt. Messenger completions in two existing wells  total initial production of 300 bbl/d (risked) 3 • Large inventory of high-impact deeper targets and development opportunities across multiple horizons to access 88.96 million boe in resources 4 1. NZEC’s share of TWN Reserves. See TWN Reserve Estimate and Cautionary Notes. 2. Purchase Price = C$33.5M total - C$18.25M from L&M Energy = C$15.25M (not including transaction costs). 3. NZEC midcase forecast based on 50% ownership of TWN. See Assumptions. 4. NZEC’s share of Prospective Resources across Taranaki permits. See Resource Estimates and Cautionary Notes. Production, Reserves and Resources stated are NZEC’s share unless otherwise noted. 8
    • Significant Growth in Reserves Post Acquisition 1 Estimated Reserves Mboe 2500 2000 1500 1000 500 0 NZEC Reserves Proved TWN Reserves Probable Total NZEC Reserves Post Acquisition 1 Possible 1. Reserves estimated by Deloitte LLP. NZEC reserves have an effective date of December 31, 2012 and are restricted to the Eltham Permit. TWN Reserves have an effective date of April 30, 2013 and are restricted to the Tikorangi Formation on the Waihapa and Ngaere Permits. See detailed Reserve tables and Cautionary Notes. Reserves reflect NZEC’s 50% working interest upon completion of the TWN Joint Venture. The TWN Reserves will not be attributable to NZEC until the Acquisition closes and NZEC files an updated reserve report. 9
    • Planned Post Acquisition Work Program (Balance of 2013 and 2014) Balance of 2013 Existing Tikorangi Well Reactivations • Reactivate six Tikorangi wells with gas lift • High volume lift installation on two initial wells $2.1 million Mt. Messenger development • Waitapu artificial lift and tie-in • Two Mt. Messenger uphole completions in existing wells • Horoi exploration well (including surface infrastructure) $5.2 million 2013 Total (to be funded initially by existing working capital and cash flow from production) $7.3 million 2014 Existing Tikorangi Well Reactivations • Increase water handling capacity • High volume lift installation on four remaining wells $8.4 million New Tikorangi wells • Drill two new Tikorangi wells $7.9 million Mt. Messenger development • Three new Mt. Messenger wells (including surface infrastructure) $6.1 million Seismic acquisition, G&G studies and Other $2.0 million 2014 Total $24.4 million Expenditures reflect NZEC’s net working interest in its various permits. See Assumptions. 10
    • Near-term Work Program 11
    • Immediate Catalyst – Existing Tikorangi Well Reactivations Drill-proven formation • 23.6 million bbl historical production from 11 wells since 1992 1 • Remaining 2P reserves estimated at 1,852,700 bbl oil, 1.45 Bcf gas, 50,700 bbl NGL (100% basis) 2 • Fractured limestone reservoir oil recoveries can be as high as 65% of OOIP (OIIP range estimated at 25 to 100 million bbl) Recommence production from six existing wells • Proof of concept  Origin reactivated Ngaere-1 well intermittently in June and July • Gas lift system in place, standard technology • Permanent gas supply identified • Gathering systems in place to deliver product to market • NZEC operations team has hands-on experience with the assets Low cost, high reward • $400,000 (NZEC share) to reactivate gas lift • Forecast total forecast initial production of 120 bbl/d (risked) 3 • High volume lift on six wells adds total forecast initial production of 810 bbl/d (risked) 3 • Flush production not included in model = upside 1. See Historical Production – Tikorangi Formation. 2. Reserve estimate completed by Deloitte LLP with an effective date of April 30, 2013. Reserves restricted to the Tikorangi Formation on the Waihapa and Ngaere Permits. See Cautionary Note Regarding Reserve & Resource Estimates. Reserves will be attributable to NZEC on a 50% basis when the Acquisition and TWN Joint Venture are complete and NZEC files an updated reserve report. 3. NZEC mid-cases. See Assumptions and Planned Post Acquisition Work Program. 12
    • Tikorangi Reactivations Forecast Production and Cash Flow Attributable to NZEC 780 bbl/d from Tikorangi Reactivations (exit 2014) C$11.09 million additional cash flow from operations (exit 2014) 900 800 700 Tikorangi - Gas Lift (Gas lift replaced with High Volume Lift) 600 Daily production (bbl/day) Tikorangi - High Volume Lift 500 400 300 200 100 - T+1M T+2M T+3M T+4M T+5M T+6M T+7M T+8M T+9M T+10M T+11M T+12M T+13M T+14M T+15M T+16M NZEC’s share of production and cash flow from operations. See Planned Post Acquisition Work Program and Assumptions. 13
    • Tikorangi – Two New Wells in 2014 Drill new wells to access oil reserves • 410,300 bbl (100% Basis) 2P Undeveloped Reserves attributed to crestal well 1 - Crestal well planned for 2014 • NZEC study indicates higher productivity within 250 metre fault buffer zone • Two potential locations identified for second well to be drilled in 2014 • Forecast total initial production of 750 bbl/d (both wells, risked) 2 1. Reserve estimate completed by Deloitte LLP with an effective date of April 30, 2013. Reserves restricted to the Tikorangi Formation on the Waihapa and Ngaere Permits. See Cautionary Note Regarding Reserve & Resource Estimates. Reserves will be attributable to NZEC on a 50% basis when the Acquisition and TWN Joint Venture are complete and NZEC files an updated reserve report. 2. See Assumptions and Planned Post Acquisition Work Program. 14
    • New Tikorangi Wells Forecast Production and Cash Flow Attributable to NZEC 490 bbl/d from New Tikorangi Wells (exit 2014) C$8.46 million additional cash flow from operations (exit 2014) 800 700 600 Daily production (bbl/day) Tikorangi New Wells 500 400 300 200 100 T+7M T+8M T+9M T+10M T+11M T+12M T+13M T+14M T+15M T+16M NZEC’s share of production and cash flow from operations. See Planned Post Acquisition Work Program and Assumptions. 15
    • Mt. Messenger Work Program Two Uphole Completions, Four New Wells in 2013/2014 Drill-proven formation • Significant discoveries to the west (TAG: Cheal), south (NZEC: Copper Moki, Waitapu, Arakamu) and east (Kea: Puka) • Contingent resources: 88,000 bbl oil (100% basis) 1 • Prospective resources: 2,061,000 bbl oil (100% basis) 1 Low-cost production potential in existing wells • Well information shows uphole completion potential in six existing Tikorangi wells • Drill pads and gathering systems in place  reduced drilling expense, expedited tie-in • Work program includes two uphole completions in existing Tikorangi wells by end 2014 with forecast total initial production of 300 bbl/d (both wells, risked) 2 New exploration opportunities • More than 18 new Mt. Messenger leads identified on 3D seismic • Five targets at Waipapa site, permitting complete • Work program includes four new wells by end of 2014 with forecast total initial production of 330 bbl/d (risked) 2 1. Prospective resources for Mt. Messenger formation only, shown on a 100% basis. Additional ~880,000 bbl prospective resources estimated for Urenui and Moki formations. See TWN Resource Estimate and Cautionary Notes. Resources will be attributable to NZEC on a 50% basis when the Acquisition and TWN Joint Venture are complete. 2. See Assumptions and Planned Post Acquisition Work Program. Waipapa wellsite 16
    • Mt. Messenger Development Program Forecast Production and Cash Flow Attributable to NZEC 540 bbl/d from Mt. Messenger Development (exit 2014) C$6.21 million additional cash flow from operations (exit 2014) Mt. Messenger - Uphole Completion in Existing Tikorangi Wells 700 600 Mt. Messenger - Development (incl. Horoi) 500 Daily production (bbl/day) Waitapu - Artificial Lift Copper Moki - Existing 400 300 200 100 T+1M T+2M T+3M T+4M T+5M T+6M T+7M T+8M T+9M T+10M T+11M T+12M T+13M T+14M T+15M T+16M NZEC’s share of production and cash flow from operations. See Planned Post Acquisition Work Program and Assumptions. 17
    • Kapuni Group – High Impact Deep Targets Two Kapuni Wells to be Drilled in 2014 Drill-proven formation • Kapuni Gas Field onshore oil/gas discovery (Shell) producing since 1969, estimated ultimate recovery of 1,365 billion cf (Bcf) natural gas and 66 million bbl oil • TWN Licences tested by four wells  all encountered gas in the Kapuni Group • Work program includes two Kapuni wells by end of 2014 with forecast total initial production of 1,216 boe/d (risked) (100% basis)  funded by farm-in partner 1 2013 Deloitte Resource Estimate 2 • Contingent resource: 5.0 Bcf gas, 233,000 bbl NGL (100% basis) • Prospective resource: 95.8 Bcf gas, 4.5 million bbl NGL (100% basis) • Discovered PIIP: 13.8 Bcf gas (100% basis) • Undiscovered PIIP: 261.1 Bcf gas (100% basis) 1. See Assumptions and Planned Post Acquisition Work Program. 2. Shown on a 100% basis. See TWN Resource Estimate and Cautionary Notes. Resources will be attributable to NZEC on a 50% basis when the Acquisition and TWN Joint Venture are complete. 18
    • Total Forecast Production and Cash Flow Attributable to NZEC 2,300 BOE/d (exit 2014) C$26.11 cumulative cash flow from operations (exit 2014) 3,000 C$ 25 2,500 Cumulative cash flows from operations (C$ millions) Kapuni New Wells Tikorangi New Wells 1,500 1,000 Daily production (BOE/day) Tikorangi - High Volume Lift 2,000 C$ 30 Tikorangi - Gas Lift Mt. Messenger - Uphole Completion in Existing Tikorangi Wells Mt. Messenger - Development (incl. Horoi) Waitapu - Artificial Lift Copper Moki - Existing Cumulative Operating Cash flows (C$) 500 - C$ 20 C$ 15 C$ 10 C$ 5 C$ - C$ (5) T T+1M T+2M T+3M T+4M T+5M T+6M T+7M T+8M T+9M T+10M T+11M T+12M T+13M T+14M T+15M T+16M NZEC’s share of production and cash flow from operations. See Planned Post Acquisition Work Program and Assumptions. 19
    • NZEC vs. International Producer Comps • Attractive Cash Flow Netback metrics CF Netback – 2014E ($/boe) $53.75 Average = $33.04 $50.76 $44.37 $37.64 $40 $36.39 $36.70 $30.81 $26.81 $22.78 $20 $11.08 Valeura Energy TransGlobe Energy Petroamerica Oil Niko Resources Cub Energy Coastal Energy Caracal Energy Canacol Energy Bankers Petroleum $0 New Zealand (PF) CF Netback - 2014E ($/ boe) $60 See Assumptions. Note: All comparables data per Canaccord Genuity Research. 20
    • Price Paid by NZEC vs. Transaction Precedents • An attractive Purchase Price1 on a 2P reserve and boe Produced Daily basis Transaction Precedents ($/boe 2P) 2 Transaction Precedents ($/boe Produced Daily) 3 $80,000 $15 $13.84 $14.12 Transaction Precedents ($/ boe Produced Daily) Transaction Precedents ($/ boe 2P) $20 $74,373 $60,000 $40,000 $20,000 $9,455 $0 $10 50% TWN Transaction Precedent Average 50% TWN Transaction Precedent Average 1. Purchase Price = C$33.5M total - C$18.25M from L&M Energy = C$15.25M (not including transaction costs). 2. Based on pre-transaction 2P of 708.3 mboe and post-transaction 2P of 1,780.7 mboe. 3. Based on NZEC’s forecast 2014E boepd of 1,569 from the newly acquired properties (total attributable 2014E is 1,801 boe/d). See Assumptions. Note: Precedent averages are from a Canaccord Genuity Research International Light Oil transaction database (65 deals from Jan12 to present). 21
    • Full-cycle Production Station 22
    • Waihapa Production Station Assets Full-cycle facility with gathering and sales pipeline infrastructure Oil facility • 25,000 bbl/d oil handling facility • 7,800 bbl oil storage capacity • 49-km 15,500 bbl/d oil sales pipeline from Waihapa to Shell’s Omata Tank Farm Gas facility • 45 mmcf/d separation and compression capacity • 70 tonne/d LPG processing capacity • 51-km 8-inch gas sales pipeline from Waihapa to New Plymouth • Storage bullets for LPG Water disposal operations • 3,600 bbl water storage capacity • 18,000 bbl/d water injection capacity Includes 100 acres of land providing a buffer zone surrounding the facility 1. On September 30, 2013, NZEC met the financing condition precedent for the Acquisition and now awaits New Zealand government approval, the final condition required to close the Acquisition. 23
    • Production Facility: Buy vs Build Waihapa Production Station 1 Neighbouring Production Facility 4 Gas processing 45 MMcf/day Gas processing 15 MMcf/day Oil handling 25,000 bbl/day Oil handling 5,000 bbl/day Water handling 18,000 bbl/day Water handling None LPG recovery 70 tonne/day LPG recovery None Pipelines 8” 49-km oil sales line to Shell’s Omata Tank Farm 8” 51-km gas sales line to New Plymouth Gas lift for Tikorangi wells Pipelines 11-km gas line to New Zealand’s open access gas pipelines Cost to buy C$33.5 million (100% basis) • Includes 23,049 acres of Petroleum Licences estimated to host 2,144,700 boe of 2P reserves with $62.9 million NPV (before tax, 10% discount, Cost to expand C$30 million No exploration land 100% basis) 2 • Includes additional 1,162,000 boe contingent resources, 23,541,000 boe prospective resources (100% basis) 2 Cost to replace 3 +/- 30% Oil plant: NZ$35.2 million, Gas plant: NZ$40.8 million Gathering systems: NZ$70.6 million, Wellsite and satellite facilities: NZ$10.6 million 1. On September 30, 2013, NZEC met the financing condition precedent for the Acquisition and now awaits New Zealand government approval, the final condition required to close the Acquisition. 2. Reserves and resources reported on a 100% basis, of which 50% will be attributable to NZEC when the Acquisition closes and NZEC files an updated reserve report. See TWN Reserves and TWN Resources and Cautionary Notes. 3. Cost to replace plant and pipelines estimated by Strive Engineering effective July 18, 2012. 4. Information regarding neighbouring production facility compiled using publicly available information. 24
    • Waihapa Midstream Business Plan * To be owned by TWN Limited, a 50/50 Limited Partnership of NZEC and L&M. Operated by NZEC Ngaere Limited as the General Partner. Contact paying a monthly fee of C$165,000 to NZEC Ngaere Limited to operate the Ahuroa Gas Storage Facility. 25
    • NZEC’s TWN Management & Operational Experience NZEC Position Years Relevant O&G Experience Years Experience with TWN Assets Previous TWN Associated Roles Chris Bush, NZ Country Manager 30+ 11 Country Manager (Origin), VP Facilities (Swift) Mike Oakes, GM Midstream Assets 35+ 8 NZ Asset Manager (Origin), Plant Super & Commissioning Supervisor (Fletcher Energy) Newton Cockerill 5 5 Business Performance & Accounting Manager (Origin) Stewart Angelo, Engineering & Maintenance Manager 25+ 15 Maintenance & Engineering Consultant (Origin), Maintenance Superintendent (Fletcher Challenge) Peter Kingsnorth, Plant Superintendent 25+ 20 Shift Supervisor (Origin), Plant Operator (Fletcher Challenge and Petrocorp) Pono Cooper, Field Superintendent 25+ 5 Well Site Supervisor (Origin, Swift) 26
    • Drilling Inventory 27
    • De-risking Drilling Inventory • RPS Mt. Messenger reservoir study • Merged 3D seismic provides better identification of targets • New data from Mt. Messenger recompletions and new wells drilled on TWN and Horoi will provide additional insight for Mt. Messenger exploitation strategy • New data collected from Tikorangi reactivations and new Tikorangi wells will solidify exploration model for deeper, highreward targets on all Taranaki permits • Waihapa Production Station and infrastructure expedites tie-in, reduces production and processing costs 28
    • New Proprietary Merged 3D Seismic Database Reprocessed datasets • Combined five 3D surveys • Total area covered (full fold) 552 km2 • Pre-stack merge and post-stack time migration complete, pre-stack time migration underway • Greater geological understanding of basin reduces drilling risk by providing consistent interpretation of seismic anomalies and the correlation with production success and pool size Volume Vintage Area (km2) Kapuni 1989 305 Waihapa 1989 43 Eltham 2002 20 Brecon 2006 74 Rotokare 2012 110 29
    • Individual 3D Surveys = Mismatched Data Kapuni 3D 1989 Rotokare 3D 2012 30
    • Proprietary Merged 3D Datasets Increase Chance of Success Kapuni 3D Reprocessed and merged 2013 Rotokare 3D 31
    • Inventory of Taranaki Drilling Leads NZEC’s Copper Moki area converting to long-term mining permit Copper Moki Wairere Waitapu Waipapa site Arakamu Horoi site 32
    • Advancing Unconventional Oil Shales 33
    • East Coast Basin Oil Shales • Over 300 oil and gas seeps sourced back to two oil shale formations: Whangai and Waipawa - Whangai shale package estimated to be 300 – 600 metres thick - Characteristics similar to Bakken shales • Two commitment wells pending (one each on Castlepoint and Ranui) 2 • Castlepoint Permit - 54.5 million bbl of conventional prospective resource 1 - 154.1 million bbl of unconventional prospective resource 1 • Ranui Permit (considering relinquishment) - 18.0 million bbl of conventional prospective resource 1 - 22.5 million bbl of unconventional prospective resource 1 • NZEC retained Core Laboratories as technical advisor to develop East Coast strategy 1. See NZEC Resource Estimates and Cautionary Notes. Acquisition of Wairoa Permit and grant of East Cape Permit pending Crown approval. 2. Work program assumes commitment wells are funded by a farm-in partner. 34
    • East Coast Strategy • Results from technical work providing greater insight into unlocking shale potential - Drilled three stratigraphic wells - Acquired 120 km of 2D seismic - Results pending from unconventional test on adjoining permit • NZEC’s technical team has worked extensively on the East Coast as consultants  positive relationships with local communities - Seismic acquisition and interpretation Wellsite geology and prospectivity evaluation Permitting and land access agreements Consultation with community members, local government, local iwi, service providers • Castlepoint Permit Exploration wells drilled by Westech Energy New Zealand discovered - Drill locations identified oil and natural gas, but did not make a commercial discovery - Consent and permitting process underway • Wairoa Permit - Log data from 16 wells and more than 500 km of 2D seismic shows both conventional and unconventional opportunities - Reviewing 50 km of 2D seismic acquired by NZEC in 2013 (NZ$3.5 million) to identify drilling locations • Actively seeking a partner to fund drilling program 1. Acquisition of Wairoa Permit pending Crown approval. NZEC will own 80% and operate the permit, in partnership with Westech Energy New Zealand. 35
    • Corporate Profile – Pre Private Placement 1 Common Shares Outstanding Options (Exercisable at average $1.35) Fully Diluted Shares Outstanding Insider Ownership (fully diluted) 52 Week High / Low Average Volume (Q3-2013) Current market cap (October 7, 2013) Financial Highlights 2 Oil sold – cumulative to August 26, 2013 (incl. pre-production testing) Pre-tax oil sales (incl. pre-production testing) – cumulative to August 26, 2013 Cash flow from petroleum operations – cumulative to end Q2-2013 Average realized oil price (YTD June 30, 2013) Average field netback (YTD June 30, 2013) 3 Substantial reduction in direct production costs at Copper Moki Site following installation of permanent production facilities (June 2013) 122.0 million 9.8 million 131.8 million ~35% $2.10 / $0.20 ~353,000 shares/day ~$40 million 264,938 bbl $28.5 million $17.2 million $107.27/bbl $35.10/bbl 1. See Private Placement in Cautionary Notes. 2. As per NZEC’s Q2-2013 consolidated interim financial statements, unless otherwise noted. 3. NZEC’s wells are producing light (~40 API), high-quality oil that sells at Brent pricing. NZEC calculates its netback as the oil sale price less fixed and variable operating costs and a royalty. Waitapu-2 well was shut-in in May to gather critical data and to evaluate and install artificial lift and surface equipment, but the Company continued to incur costs on the Waitapu Site during the period. 36
    • Value Drivers Next 18 Months • Complete Acquisition and TWN Joint Venture • Value increase from Acquisition - Immediately book 150% net increase in 2P reserves to 1.78 million boe with total estimated NPV of $54.05 million (before tax, 10% discount rate) 1 - Exploitation of existing Tikorangi wells and drilling of new wells results in 15x increase in production to net 2,300 boe/day exit 2014 (81% oil) 2 - Cumulative cash flow from operations of $26.1 million exit 2014 2 - Reduce net general and administrative costs through joint ventures and third-party processing 2 • Leverage Waihapa Production Station and infrastructure - Generate cash flow from existing and new liquids rich natural gas production - Expedite tie-in of new discoveries = additional incremental cash flow • Resume drilling program - De-risked Mt. Messenger targets with merged 3D seismic and new drilling and reservoir information - Initiate exploration of high-reward deeper formations • Experienced team with business, operations and geological expertise to execute development plan and deliver on targets 1. NZEC’s share of TWN Reserves plus NZEC’s existing reserves. See detailed Reserve tables and Cautionary Notes. 2. NZEC forecast based on 50% ownership of TWN Assets and execution of the planned development program. See Assumptions and Planned Post Acquisition Work Program. 37
    • Appendix 38 38
    • Comparison of Final and Original Acquisition Terms 1 Final Terms Original Terms Purchase price • C$33.5 million ($18,250,000 L&M, $15,250,000 NZEC) • 50/50 ownership by NZEC and L&M = TWN Joint Venture • No additional adjustments to purchase price Purchase price • C$42 million • Additional C$9 million in adjustments at closing (NZEC internal estimate) Petroleum Licences • Ultimate NZEC ownership of 50% interest in three Petroleum Licences: Tariki, Waihapa and Ngaere (“TWN Licences”). The Ahuroa Licence will be transferred to Contact Energy. Net NZEC acreage: 11,525 acres (46.6 km2) Petroleum Licences • NZEC purchasing four Petroleum Licences: Tariki, Ahuroa, Waihapa and Ngaere. Total acreage: 26,907 acres (108.9 km2) Royalty payable to Origin 2 • 9% net revenue royalty payable to Origin on all future hydrocarbon production on the Licences • TWN Joint Venture retains the ability to buy back up to 4% of the royalty at any time for C$4.25 million per percentage point Royalty payable to Origin • 5% net revenue royalty payable to Origin on all future hydrocarbon production on the Petroleum Licences Commitments to Origin Commitments to Origin • Simplified sale agreement • NZEC responsible for 100% of costs associated - NZEC retains 50% of production from all existing and new wells on the with drilling a well to the crestal interval of the TWN Licences in all formations, subject to the Origin Royalty (and a Tikorangi formation, with profits to be shared 10% royalty payable to the NZ Government) 50/50 with Origin - Origin relinquishes all other rights and encumbrances on the TWN • Origin retained rights to eight “option wells” for Licences gas storage 1. On September 30, 2013, NZEC met the financing condition precedent for the Acquisition and now awaits New Zealand government approval, the final condition required to close the Acquisition. 2. The Origin royalty is payable at 9% of net revenue (hydrocarbon sales less operating expenses incurred between the point of valuation and the point of sale). TWN Joint Venture may buy back at any time and from time to time up to 4% of the Origin royalty by paying C$4.25 million per percentage point. The TWN Licences are also subject to a government royalty payable at 10% of net revenue as they are “grandfathered” under the 1937 Petroleum Act. 39
    • L&M Energy and Geoff Loudon Mr. Loudon is a New Zealand based international investor with family roots going back to the Hokitika, NZ gold fields in 1875. He was the former Chairman of L&M Energy (ASX, NZX), which he privatized in January 2013 through a NZ$48 million takeover bid by his company, New Dawn Energy Limited. L&M Energy holds a number of petroleum exploration permits on the North and South Islands of New Zealand, including a 35% interest in NZEC’s Alton Permit. Mr. Loudon is Chairman of Nautilus Minerals Inc. (TSX), a Canadian based seabed minerals exploration company; was a founding director from 1995 to 2010 of Lihir Gold Limited (ASX, TSX, NASDAQ), a PNG gold miner; and a founder and investor in Peru Copper Inc. (TSX, AMEX). Mr. Loudon is a mining professional with qualifications in geology, engineering and international finance. He started his career as a geologist with the NSW Geological Survey Australia, then worked with Placer Dome in Canada in operations, development and exploration before starting a finance career with Kleinwort Benson, a UK merchant bank. He then founded Niugini Mining which developed gold and copper mines in PNG, Chile and Australia and discovered the Lihir gold deposit in PNG. Mr. Loudon is a Fellow of the Australasian Institute of Mining & Metallurgy (AIMM), a Member of the Canadian Institute of Mining (CIM) and a Member of the American Institute of Mining Engineers (AIME). 40
    • Historical Production – Tikorangi Formation 23.6 million bbl of historical production 1 Well name 1 Max bbl/d Total bbl produced Ngaere-1 7,537 4,337,084 Ngaere-2 3,658 1,002,565 Ngaere-3 8,652 1,089,505 Toko-2B 298 126,286 Waihapa H-1 1,953 45,349 Waihapa-1B 4,804 4,909,317 Waihapa-2 3,182 4,798,752 Waihapa-4 2,674 2,990,189 Waihapa-5 979 91,055 Waihapa-6A 4,674 4,262,707 1. Select production data using publicly available information regarding wells that produced oil on the TWN Licences. 41
    • Oil in Tikorangi Formation • 23.6 million bbl produced to date • Numerous independent estimates of original oil in place (OOIP) ranging from 25 mmbbl (P90) to 100 mmbbl (P10) 1 • Fractured limestone oil recoveries can be as high as 65% of OOIP • NZEC commissioned independent petroleum reservoir engineering study that concluded remaining oil (100% basis) contained in: - Low permeability network fractures (est. 1.5 million bbl from reactivation) - Attic oil trapped up-dip of existing wells (est. 0.95 million bbl from new well) - Laterally trapped oil in existing fracture system (est. 2.05 million bbl from new wells) • Range of well productivity from existing wells, EUR = 400,000 bbl (P50) Cum Oil (mbbl) EUR for a new well = 400 mbbl 1. NZEC collation of independent consultancy assessments. 42
    • TWN Reserve Estimate (100% basis) 1 Reserve Category Light & Medium Oil (Mbbl) Natural Gas (MMcf) Natural Gas Liquids (Mbbl) Barrels of Oil Equivalent (Mboe) NPV, Before Tax (10%) Proved Developed (Non-producing) 983.7 762.0 26.7 1,137.4 $36,142,000 Proved Undeveloped 258.1 206.5 7.2 299.8 $7,340,000 1,241.8 968.5 33.9 1,437.1 $43,482,000 610.9 479.3 16.8 707.6 $19,393,000 1,852.7 1,447.8 50.7 2,144.7 $62,875,000 Total Proved Probable Proved + Probable (2P) 1. Reserve estimate completed by Deloitte LLP with an effective date of April 30, 2013. Reserves restricted to the Tikorangi Formation on the Waihapa and Ngaere Permits. See Cautionary Note Regarding Reserve & Resource Estimates. Reserves will be attributable to NZEC on a 50% basis when the Acquisition and TWN Joint Venture are complete and NZEC files an updated reserve report. 43
    • TWN Resource Estimate (100% basis) 1 Formation Product Type Low Best High Contingent Resources Miocene Sands (Mt. Messenger) Eocene Sands (Kapuni Group) Total Oil (Mbbl) 35 88 203 2,513 5,036 10,336 NGL (Mbbl) 101 233 525 BOE (Mboe) 567 1,162 2,426 Gas (MMcf – sales) Prospective Resources Miocene Sands (Urenui, Mt. Messenger, Moki) Eocene Sands (Kapuni Group) Total Oil (Mbbl) 1,606 2,941 5,732 Gas (MMcf – sales) 42,833 95,837 226,424 NGL (Mbbl) 1,909 4,498 11,375 BOE (Mboe) 10,825 23,541 54,368 Discovered PIIP Miocene Sands (Mt. Messenger) Eocene Sands (Kapuni Group) Total Oil (Mbbl) 327 681 1,400 Gas (MMcf – raw) 7,211 13,770 26,935 BOE (Mboe) 1,529 2,976 5,889 Undiscovered PIIP Miocene Sands (Urenui, Mt. Messenger, Moki) Eocene Sands (Kapuni Group) Total Oil (Mbbl) 11,315 20,442 37,804 Gas (MMcf – raw) 118,981 261,080 605,860 BOE (Mboe) 31,145 63,955 138,781 1. Resources estimated by Deloitte with an effective date of April 30, 2013 assuming 9 to 14% recovery for oil resources and 50% for gas resources. See Cautionary Note Regarding Reserve and Resource Estimates. Resources will be attributable to NZEC on a 50% basis when the Acquisition and TWN Joint Venture are complete. 44
    • NZEC Eltham Reserve Estimate Marketable Oil and Gas Reserves As at December 31, 2012 Forecast Prices and Costs Reserves Category Proved Developed Producing Light & Medium Natural Gas Oil (Mbbl) (MMcf) Natural Gas Liquids (Mbbl) Barrels Oil NPV, Before Tax Equivalent (Mboe) (10%) 307.8 594.9 38.7 445.7 $14,400,000 20.6 31.9 2.0 27.9 $893,000 Total Proved 328.4 626.8 40.7 473.6 $15,293,000 Probable 158.3 329.6 21.5 234.7 $7,320,000 Proved + Probable 486.7 956.4 62.2 708.3 $22,613,000 Possible 195.6 398.1 25.8 287.8 $7,549,000 Proved + Probable + Possible 682.3 1354.5 88.0 996.1 $30,162,000 Proved Undeveloped Notes: Gross reserves before the deduction of royalty obligations payable to the New Zealand government. Numbers may not sum due to rounding. Reserve estimates calculated by Deloitte. Mbbl – thousand barrels of oil. MMcf – million cubic feet of natural gas. Mboe – thousand barrels of oil equivalent using a conversion ratio of 6 Mcf : 1 bbl. Barrels of oil equivalent (boe) may be misleading, particularly if used in isolation. The boe conversion ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves. See Cautionary Note Regarding Reserve and Resource Estimates. 45
    • NZEC Resource Estimates (Current Permits) Net Permit Area Net Permit Acreage 377.0 Net Unrisked Prospective Recoverable (MM barrels of oil) Low Best High 93,166.1 TARANAKI BASIN Eltham (PEP 51150) 100% NZEC Conventional 231.4 313.6 Manaia (PEP 54867) 60% NZEC / 40% NZOG Conventional 66.6 EAST COAST BASIN Castlepoint (PEP 52694) 100% NZEC Conventional Unconventional Ranui (PEP 38342) 100% NZEC Conventional Unconventional East Cape (PEP 52976) 100% NZEC 1 Conventional Unconventional Wairoa (PEP 38346) 80% NZEC / 20% Westech Conventional Unconventional Total Conventional Unconventional Grant of permit pending. 346.8 578.8 19.7 31.6 56.9 224.8 Alton (PEP 51151) 65% NZEC / 35% L&M Conventional 1 Net Unrisked Undiscovered Petroleum (MM barrels of oil) Low Best High 493.7 1,229.7 18.9 45.0 116.9 77,482.4 16,455.7 Early stage 2,230.0 Early stage 551,045.0 349.0 2,958.2 867.2 30.3 56.2 54.5 154.1 102.0 458.5 198.3 969.0 435.0 2,252.5 8.1 8.6 18.0 22.5 42.0 65.2 189.8 5,747.2 4,320.0 1,053.1 16,190.7 94.3 440.4 902.8 586.3 6,743.0 615.7 13,148.1 1,997.4 31,838.3 14.6 110.3 53.3 302.1 195.4 906.3 223,086.7 1,067,495.2 214,289.8 Estimate pending 9,077.2 2,243,020.9 10,235.1 1,089.3 9,145.8 23,100.9 2,240.8 20,860.1 Estimate pending 55,575.5 5,294.0 50,281.5 Source: Deloitte LLP, effective date February 1, 2011. 266.7 91.6 175.1 681.1 202.4 478.7 1,943.2 513.2 1,430.0 46
    • Drilling / Production Report Card Drilling / Production Report Card Well Name Target Formation Total Depth Status Total Oil Prod (end Aug 2013) Mt. M Mt. M Mt. M / Moki Mt. M / Urenui 2,220 m 2,084 m 3,167 m 2,125 m Producing since December 2011 Producing since April 2012 Producing from Mt. Messenger since July 2012 Urenui oil discovery, shut in pending further testing 110,483 bbl 91,812 bbl 44,550 bbl Waitapu-1 Waitapu-2 Mt. M Mt. M 2,213 m 2,084 m Shut in pending further testing or sidetrack Producing since December 2012 1 Arakamu-1A Arakamu-2 Moki Mt. M 2,900 m 2,380 m Suspended, pending further evaluation Oil discovery in April 2013, awaiting artificial lift Wairere-1 Wairere-1A Mt. M Mt. M 1,971 m 2,152 m Plugged back for sidetrack Completion pending Copper Moki-1 Copper Moki-2 Copper Moki-3 Copper Moki-4 18,790 bbl • Engaged RPS, world-recognized leader in geological and reservoir evaluation, to undertake comprehensive reservoir study to assist in optimizing production and go-forward strategy 1. Waitapu-2 was temporarily shut in at the end of May to allow the Company to analyze artificial lift options and perform tests related to the Copper Moki reservoir study. 47
    • Assumptions in NZEC’s Mid-case Financial Model (as at July 31, 2013) Other Assumptions Oil sales price/bbl = US$99 Natural gas sales price/GJ = NZ$4.50 LPG sales price/tonne = NZ$500 USD/NZD exchange rate = 0.79 CAD/NZD exchange rate = 0.82 Development program includes the following: Six Tikorangi reactivations - wells placed on gas lift, subsequently on high volume lift Two Mt. Messenger uphole completions in existing Tikorangi wells Four New Mt Messenger wells on Alton/TWN permits Two New Tikorangi appraisal wells Two New Kapuni wells to be funded by new JV partner Existing Tikorangi Wells (gas lift  high volume lift) Reserves (unrisked, 100%) Working interest Probability of success IP rate Decline Capital cost (incl. surface equipment) Operating expenditure 150,000 – 448,000 bbls/well 50% 100% 49 BOE/day – 365 BOE/day 2% – 0.5% per month C$0.07 – C$0.8 million per well (WI) C$15,000 per month/well (WI) Mt. Messenger – Uphole Completion in Existing Tikorangi Wells Expected Ultimate Recovery (unrisked, 100%) Working interest Probability of success IP rate Decline Capital cost (incl. surface equipment) Operating expenditure 123,000 bbls/well 50% 100% 365 BOE/day 3% – 9% per month C$0.6 million per well (WI) C$10,000 per month/well (WI) Kapuni New Wells Expected Ultimate Recovery (unrisked, 100%) Working interest Probability of success IP rate Decline Capital cost (incl. surface equipment) Operating expenditure 7.91 Bcf 25% 60% 1,103 BOE/day 1% per month C$nil funded by new JV partner C$10,000 per month/well (WI) 1. Deloitte LLP has ascribed 2P reserves of 410,300 bbl to one Tikorangi new well. WI = based on Working Interest. Tikorangi New Wells Expected Ultimate Recovery (unrisked , 100%) 1 Working interest Probability of success IP rate Decline Capital cost (incl. surface equipment) Operating expenditure 561,000 bbls/well 50% 50% 1,824BOE/day 5% – 12% per month C$3.95million per well (WI) C$10,000 per month/well (WI) Mt. Messenger Development Wells (incl. Horoi) Expected Ultimate Recovery (unrisked, 100%) Working interest Probability of success IP rate Decline Capital cost (incl. surface equipment) Operating expenditure (not incl. royalty) 502,000 bbls/well 50% – 65% 35% – 40% 420 BOE/day – 511 BOE/day 2% per month C$1.7 – C$3.4 million per well (WI) N$40/bbl Waihapa Production Station Working Interest Operating expenditure (fixed) Operating expenditure (variable) Capital cost (in addition to purchase price) 50% N$0.4 million per month (WI) N$10/bbl $7.1 million, including increasing water handling capacity 48
    • Board of Directors Name Expertise Experience John A. Greig, M.Sc, P.Geo Chairman • Founder and financier of numerous mining and oil and gas companies. Specializing in recognizing undervalued geological assets • Founder, Director & Officer Sutton Resources, Cumberland Resources Ltd., Eurozinc Mining Corp., Crown Resources Corp. John G. Proust, C.Dir CEO Director • Proven track record of building companies from grass roots to advanced development. Specializes in identifying undervalued assets on a global basis • Chairman, Director & CEO, Southern Arc Minerals Inc. • Chairman, Director & Interim CEO, Eagle Hill Exploration Corp. • Chairman, Canada Energy Partners Inc. Bruce G. McIntyre, P.Geol Executive Director • Professional petroleum geologist with over 30 years of proven exploration and development oriented value creation • President, CEO Sebring Energy Inc. • President, CEO TriQuest Energy Corp. • President, CEO BXL Energy Ltd., • Exploration Manager Gascan Resources Ltd. Hamish J. Campbell B.Sc (Geology), FAusIMM Director • Professional geologist with 30 years of experience managing exploration programs, evaluation and assessment of joint ventures and acquisitions • Director of a number of New Zealand limited liability mineral and petroleum companies • Principal Indonesian mining service company 49
    • Corporate Office – Canada Name Expertise Experience • Proven track record of building companies from grass roots to advanced development. Specializes in identifying undervalued assets on a global basis • Chairman, Director & CEO, Southern Arc Minerals Inc. • Chairman, Director & Interim CEO, Eagle Hill Exploration Corp. • Chairman, Canada Energy Partners Inc. • Professional petroleum geologist with over 30 years of proven exploration and development oriented value creation • President, CEO Sebring Energy Inc. • President, CEO TriQuest Energy Corp. • President, CEO BXL Energy Ltd., • Exploration Manager Gascan Resources Ltd. • Chartered Accountant with expertise in financial reporting and controls, equity offerings, treasury management and debt structures, tax compliance • Progressively senior positions with publicly-traded natural resource companies • Audit Manager, Mining Group, PricewaterhouseCoopers Celeste M. Curran, B.A. (Hon), L.L.B. VP Corporate & Legal Affairs • Over 20 years of legal and negotiating experience specializing in major projects • VP, Corporate & Legal Affairs, J. Proust & Associates • Lead counsel for City of Vancouver and City of Richmond for the 2010 Olympic and Paralympic Winter Games • Senior Solicitor, City of Vancouver Rhylin Bailie, B.ES VP Communications & Investor Relations • More than 18 years of experience in the resource industry, in both finance and investor relations • Professional writer and editor • Director Communications & Investor Relations, NovaGold Resources Inc. • Supervisor Treasury Administration, Placer Dome Inc. • More than 16 years of experience overseeing corporate governance and corporate affairs for publicly-listed resource companies • Corporate Secretary for various public and private resource companies • Director of Charlotte Resources John G. Proust, C.Dir Chief Executive Officer Bruce G. McIntyre, P.Geol Executive Director Gerrie van der Westhuizen, CA Interim CFO Eileen Au, B.Sc Corporate Secretary 50
    • Operations Team – New Plymouth, NZ Name Expertise Experience Chris Bush, B.E (Hon) New Zealand Country Manager • Chemical engineer with more than 30 years in both upstream and downstream oil and gas experience internationally • New Zealand Country Manager/Director, Origin Energy • Chairman of Petroleum Exploration and Producers Association of New Zealand Mike Oakes General Manager Midstream Operations • More than 30 years of international oil and gas experience overseeing design, commissioning and start up, staffing and operation of oil and gas fields and production facilities • Operations Manager, Asset Manager and Operational Excellence Advisor, Origin Energy • Technical Advisor, Total E&P Borneo Cliff Butchko P.Eng, MBA (Hon) General Manager Upstream Operations • Professional engineer with over 30 years experience evaluating and managing oil and gas resources • President Omni Oil and Gas Inc. • Vice President Lexoil Inc. • Partner and Co-founder TIFF advisory group • Senior technical positions in several resource companies James Watchorn, B.Sc Operations Manager • Mechanical engineer with more than 15 years of experience in all aspects of drilling, completions and production, and facility and wellsite construction • Production and Facilities Manager, TAG Oil • Senior Petroleum Engineer, Origin Energy • Operations Engineer, Iteration Energy/Chinook Energy • 25 years in oil and gas midstream assets focused around development and implementation of procedures and processes for asset management systems • Engineering Officer with New Zealand Merchant Navy • Maintenance Engineer, Fletcher Challenge • Director of Productive Maintenance • Senior Manager, New Zealand Dept. of Conservation • Negotiating access provisions and facilitating resource consent process, assisting with community relationship building Stewart Angelo Engineering & Maintenance Manager Toka Walden Land Manager 51
    • Technical Team – Wellington, NZ Name Qualifications Expertise Dr. Ian Brown B.Sc (Hons), M.Phil, D.Eng, MIPENZ, C.P.Eng June Cahill B.Sc, B. Applied Econ. Bill Leask B.Sc (Hons) M.Sc (Hons) Petroleum geology related to the East Coast and other New Zealand basins Dr. Simon Ward B.Sc (Hons) Ph.D Petroleum geology related to the Taranaki and other New Zealand basins Ian Calman B.Sc (Hons) Seismic data acquisition, processing, and interpretation Gareth Reynolds B.Sc (Hons) Geology Dr. Richard Kellett B.Sc (Hons), Ph.D, P.Geoph Monmoyuri Sarma B.Sc (Hons), M.Sc (Petroleum Geosciences), M.Sc (Applied Geology) Peter Wood B.E (Hons), B.Sc , M.Comp.Sci Sam Pryde B.Sc Post.Grad.Dip. Chief Operating Officer; professional geological engineer Acquisition, management, and analysis of complex geoscience data Geoscientist with experience in New Zealand Basin analysis Geoscientist with worldwide exploration and business development experience Geoscientist with experience with reservoir modelling and petroleum system analysis Management and development of computing resources for geoscience applications Geological investigations in the East Coast basin area 52
    • Analyst Coverage Company Analyst Contact Canaccord Genuity Christopher Brown 403-508-3858 Credit Suisse David Phung 403-476-6023 Dundee Capital Markets David Dudlyke 44-203-440-6870 Haywood Securities Alan Knowles 403-509-1931 Mackie Research Bill Newman 403-750-1297 Macquarie Equities Research Dave Popowich 403-539-8529 M Partners David Buma 416-603-7381 53
    • Contact NZEC Corporate Head Office John Proust, Chief Executive Officer Bruce McIntyre, Executive Director Rhylin Bailie, VP Investor Relations North America Toll-free: 1-855-630-8997 info@newzealandenergy.com New Zealand Office Chris Bush, New Zealand Country Manager Tel: + 64-6-757-4470 New Zealand Toll-free: 0800-469-363 www.NewZealandEnergy.com 54