Nzecppt 201402 03

100 %
0 %
Information about Nzecppt 201402 03
Education

Published on February 4, 2014

Author: NZEnergy

Source: slideshare.net

TSX-V: NZ OTCQX: NZERF Waihapa Production Station Corporate Presentation February 3, 2014

Cautionary Notes Forward-looking Statements This document contains certain forward-looking information and forward-looking statements within the meaning of applicable securities legislation (collectively “forward-looking statements”). The use of any of the words “being”, “will”, “until”, “estimate”, “forecast”, “will be”, “is considering”, “will proceed”, “plans”, “reactivate”, “recommence”, “would be”, “could be”, “will bring”, “could bring”, “expected”, and similar expressions are intended to identify forward-looking statements. These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. Such forward-looking statements should not be unduly relied upon. The Company believes the expectations reflected in those forward-looking statements are reasonable, but no assurance can be given that these expectations will prove to be correct. This document contains forward-looking statements and assumptions pertaining to the following: business strategy, strength and focus; the granting of regulatory approvals; the timing for receipt of regulatory approvals; geological and engineering estimates relating to the resource potential of the Properties; the estimated quantity and quality of the Company’s oil and natural gas resources; supply and demand for oil and natural gas and the Company’s ability to market crude oil, natural gas and; expectations regarding the ability to raise capital and to continually add to reserves and resources through acquisitions and development; the Company’s ability to obtain qualified staff and equipment in a timely and cost-efficient manner; the ability of the Company’s subsidiaries to obtain mining permits and access rights in respect of land and resource and environmental consents; the recoverability of the Company’s crude oil, natural gas reserves and resources; and future capital expenditures to be made by the Company. Actual results could differ materially from those anticipated in these forward-looking statements as a result of the risk factors set forth below and elsewhere in the document, such as the speculative nature of exploration, appraisal and development of oil and natural gas properties; uncertainties associated with estimating oil and natural gas resources; changes in the cost of operations, including costs of extracting and delivering oil and natural gas to market, that affect potential profitability of oil and natural gas exploration; operating hazards and risks inherent in oil and natural gas operations; volatility in market prices for oil and natural gas; market conditions that prevent the Company from raising the funds necessary for exploration and development on acceptable terms or at all; global financial market events that cause significant volatility in commodity prices; unexpected costs or liabilities for environmental matters; competition for, among other things, capital, acquisitions of resources, skilled personnel, and access to equipment and services required for exploration, development and production; changes in exchange rates, laws of New Zealand or laws of Canada affecting foreign trade, taxation and investment; failure to realize the anticipated benefits of acquisitions; and other factors. Readers are cautioned that the foregoing list of factors is not exhaustive. Statements relating to “reserves and resources” are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the resources described can be profitably produced in the future. The forward-looking statements contained in the document are expressly qualified by this cautionary statement. These statements speak only as of the date of this document and the Company does not undertake to update any forward-looking statements that are contained in this document, except in accordance with applicable securities laws. More information is available in the Company’s Annual Information Form for the year ended December 31, 2012, filed on June 17, 2013 on SEDAR at www.sedar.com. Reserve & Resource Estimates The oil and gas reserve and resource calculations and net present value projections were estimated in accordance with the Canadian Oil and Gas Evaluation Handbook (“COGEH”) and National Instrument 51-101 (“NI 51-101”). The term barrels of oil equivalent (“boe”) may be misleading, particularly if used in isolation. A boe conversion ratio of six Mcf: one bbl was used by NZEC. This conversion ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date, based on: the analysis of drilling, geological, geophysical, and engineering data; the use of established technology; and specified economic conditions, which are generally accepted as being reasonable. Reserves are classified according to the degree of certainty associated with the estimates. Proved Reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves. Probable Reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves. Possible Reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10% probability that the actual remaining quantities recovered will exceed the sum of the estimated proved plus probable plus possible reserves. Revenue projections presented are based in part on forecasts of market prices, current exchange rates, inflation, market demand and government policy which are subject to uncertainties and may in future differ materially from the forecasts above. Present values of future net revenues do not necessarily represent the fair market value of the reserves evaluated. Information concerning reserves may also be deemed to be forward looking as estimates imply that the reserves described can be profitably produced in the future. These statements are based on current expectations that involve a number of risks and uncertainties, which could cause the actual results to differ from those anticipated. Contingent resources are those quantities of oil and gas estimated on a given date to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political and regulatory matters, or a lack of markets. Prospective resources are those quantities of oil and gas estimated on a given date to be potentially recoverable from undiscovered accumulations. Undiscovered resources means those quantities of oil and gas estimated on a given date to be contained in accumulations yet to be discovered. The resources reported are estimates only and there is no certainty that any portion of the reported resources will be discovered and that, if discovered, it will be economically viable or technically feasible to produce. More information is available in the Company’s Form F1-101F1 Statement of Reserves Data and Other Oil and Gas Information dated April 22, 2013, and in the Company’s Interim Statement of Reserves and Resources Data and Other Oil and Gas Information dated October 28, 2013, both of which are filed on SEDAR at www.sedar.com. 2

Fully Integrated Upstream/Midstream Company • Strategic acquisition and private placement complete - Three Petroleum Mining Licenses with immediate production potential - 150% increase to NZEC’s reserves 1 - Full-cycle production facility central to NZEC’s permits • Increasing production and cash flow 2  Reactivate oil production in existing Tikorangi wells  Recomplete existing wells uphole in Mt. Messenger formation (production pending) - Drill new wells to Mt. Messenger and deeper Tikorangi formation • ~1.95 million acres of permits with both conventional and unconventional opportunities • Strategic JV partners: L&M Energy, New Zealand Oil & Gas, Westech Energy • Experienced team with New Zealand and Western Canadian exploration and operations expertise 1. See Reserve and Resource tables in the Appendix, and Cautionary Notes. 2. Development and operating costs are to be funded initially by existing working capital and cash flows from production. To carry out all of the planned development activities, the Company is considering a number of options to increase its financial capacity, including additional joint arrangements, commercial arrangements, or other financing alternatives. Development and exploration activities and timing of activities is subject to change as the Company continues to review and refine its 2014 program. 3

Asset Overview Permit Working Interest Net Acres 2P boe Reserves 1 Contingent Resource 1 Prospective Resource 1 Eltham 2 100% 47,395 708 M boe - 31.6 MM bbl Alton 65% 38,717 - - 45.0 MM bbl Manaia 60% 16,456 - - Early stage TWN 50% 11,525 1,072 M boe 580 M boe 11.7 MM boe Castlepoint 100% 551,045 - - 208.6 MM bbl Wairoa 80% 214,290 - - Under review East Cape 100% 1,048,406 - - 355.4 MM bbl Total 1,927,834 Conventional Focus East Cape Conventional and Unconventional Targets TWN Alton Manaia Eltham Wairoa Castlepoint 1. Reserves and resources estimated by Deloitte LLP. For effective dates and estimated recovery rates, see NZEC’s most recent annual and interim reserve and resource filed on SEDAR in October 2013, the Reserve and Resource tables in the Appendix, and Cautionary Notes. Reserves and resources are updated annually. 2. Final configuration of Copper Moki mining license and Eltham exploration permit subject to NZP&M approval. 4

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

Planned Work Program – Taranaki Basin (Balance of 2013 and 2014) 1 November–December 2013 Existing Tikorangi Well Reactivations  Reactivate oil production from six Tikorangi wells on TWN Licenses Mt. Messenger development  Complete installation of Waitapu-2 artificial lift  Begin uphole recompletions in two existing wells on TWN Licenses 2014 1 Tikorangi development • Optimize oil production from reactivated wells on TWN Licenses, including installation of high-volume lift on select wells • Determine potential to reactivate oil production from additional existing Tikorangi wells on TWN Licenses • Drill two new Tikorangi wells on TWN Licenses Mt. Messenger development  Recommence production from Copper Moki-3 well on Eltham Permit • Recommence production from Waitapu-2 well on Eltham Permit • Advance Mt. Messenger uphole completions on TWN Licenses to production 2 • Determine potential to reactivate oil production from existing Mt. Messenger wells on TWN Licenses • Drill Horoi exploration well (including surface infrastructure) on Alton Permit • Drill three new Mt. Messenger wells (including surface infrastructure) on TWN Licenses Seismic acquisition, G&G studies and Other 1. Planned work program as at November 2013. See Assumptions. Development and operating costs are to be funded initially by existing working capital and cash flows from production. In order to carry out all of the planned development activities, the Company is considering a number of options to increase its financial capacity, including additional joint arrangements, commercial arrangements, or other financing alternatives. 2. Decision to advance to commercial production contingent on flow test results from recompleted wells. 6

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

Immediate Value from Near-term Work Program 8

Immediate Catalyst – Existing Tikorangi Well Reactivations Forecast impact: 780 bbl/d net to NZEC (exit 2014) Drill-proven formation • 23.6 million bbl historical production from 11 wells since 1992 1 • Remaining 2P reserves estimated at 1,852,700 bbl oil, 1.45 Bcf gas, 50,700 bbl NGL (100% basis) 2 • Fractured limestone reservoir oil recoveries can be as high as 65% of OOIP (OIIP range estimated at 25 to 100 million bbl) Immediate production potential from existing wells  Six wells reactivated in November  optimizing oil production from Tikorangi formation • Identified Tikorangi oil production potential from additional existing wells • Pipelines in place to deliver oil and gas production to Waihapa Production Station, and on to market • NZEC operations team has hands-on experience with the properties and production station Low cost, high reward • $400,000 (NZEC share) to reactivate gas lift • Achieved initial production forecast of net 120 bbl/d (all six wells, risked)3 • High volume lift adds forecast initial production of net 135 bbl/d per well (risked) 3 1. See Historical Production – Tikorangi Formation. 2. Reserve estimate completed by Deloitte LLP with an effective date of April 30, 2013. Reserves restricted to the Tikorangi Formation on the Waihapa and Ngaere Permits. Reserves attributable to NZEC at 50%. See Cautionary Note Regarding Reserve & Resource Estimates. 3. NZEC mid-cases. See Assumptions and Planned Work Program. 9

Mt. Messenger Work Program Forecast impact: 575 bbl/d net to NZEC (exit 2014) Drill-proven formation • Significant discoveries to the west (TAG: Cheal), south (NZEC: Copper Moki, Waitapu) and east (Kea: Puka) • Contingent resources: 88,000 bbl oil (100% basis) 1 • Prospective resources: 2,061,000 bbl oil (100% basis) 1 Low-cost production potential in existing wells • Well information shows uphole completion potential in multiple Tikorangi wells - First uphole completion commencing commercial production in Q1-2014 - Additional uphole completions in Q1-2014 • Forecast total initial production of net 150 bbl/d per well (risked) 2 • Drill pads and gathering systems in place  reduced drilling expense, expedited tie-in New exploration opportunities • More than 18 new Mt. Messenger leads identified on 3D seismic • Work program includes four new wells (including Horoi well) by end of 2014 with forecast total initial production of net 80 bbl/d per well (risked) 2 1. Prospective resources for Mt. Messenger formation only, shown on a 100% basis. Additional ~880,000 bbl prospective resources estimated for Urenui and Moki formations. Resources attributable to NZEC at 50%. See TWN Resource Estimate and Cautionary Notes. 2. See Assumptions and Planned Work Program. Development and operating costs are to be funded initially by existing working capital and cash flows from production. To carry out all of the planned development activities, the Company is considering a number of options to increase its financial capacity, including additional joint arrangements, commercial arrangements, or other financing alternatives. Development and exploration activities and timing of activities subject to change as the Company reviews and refines its 2014 program. Waipapa wellsite 10

Tikorangi – Two New Wells in 2014 1 Forecast impact: 570 bbl/d net to NZEC (exit 2014) Drill new wells to access oil reserves • 410,300 bbl (100% Basis) 2P Undeveloped Reserves attributed to crestal well 2 - Crestal well planned for 2014 • NZEC study indicates higher productivity within 250 metre fault buffer zone • Two potential locations identified for second well to be drilled in 2014 • Forecast total initial production of net 375 bbl/d per well (risked) 3 1. Development and operating costs are to be funded initially by existing working capital and cash flows from production. To carry out all of the planned development activities, the Company is considering a number of options to increase its financial capacity, including additional joint arrangements, commercial arrangements, or other financing alternatives. Development and exploration activities and timing of activities is subject to change as the Company continues to review and refine its 2014 program. 2. Reserve estimate completed by Deloitte LLP with an effective date of April 30, 2013. Reserves restricted to the Tikorangi Formation on the Waihapa and Ngaere Permits, attributable to NZEC at 50%. See Cautionary Note Regarding Reserve & Resource Estimates. 3. See Assumptions and Planned Work Program. 11

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

Kapuni Group – High Impact Deep Targets Drill-proven formation • Kapuni Gas Field onshore oil/gas discovery (Shell) producing since 1969, estimated ultimate recovery of 1,365 billion cf (Bcf) natural gas and 66 million bbl oil • TWN Licences tested by four wells  all encountered gas in the Kapuni Group • Work program includes two Kapuni wells by end of 2014 with forecast total initial production for 2015 of 1,216 boe/d (risked) (100% basis)  funded by farm-in partner 1 2013 Deloitte Resource Estimate 2 • Contingent resource: 5.0 Bcf gas, 233,000 bbl NGL (100% basis) • Prospective resource: 95.8 Bcf gas, 4.5 million bbl NGL (100% basis) • Discovered PIIP: 13.8 Bcf gas (100% basis) • Undiscovered PIIP: 261.1 Bcf gas (100% basis) 1. See Assumptions and Planned Work Program. Kapuni exploration contingent on finding a funding partner. 2. Shown on a 100% basis, attributable to NZEC at 50%. See TWN Resource Estimate and Cautionary Notes. 13

Full-cycle Production Station 14

Waihapa Production Station Assets Full-cycle facility with gathering and sales pipeline infrastructure Oil facility • 25,000 bbl/d oil handling facility • 7,800 bbl oil storage capacity • 49-km 15,500 bbl/d oil sales pipeline from Waihapa to Shell’s Omata Tank Farm Gas facility • 45 mmcf/d separation and compression capacity • 70 tonne/d LPG processing capacity • 51-km 8-inch gas sales pipeline from Waihapa to New Plymouth • Storage bullets for LPG Water disposal operations • 3,600 bbl water storage capacity • 18,000 bbl/d water injection capacity Includes 100 acres of land providing a buffer zone surrounding the facility 1. NZEC and L&M Energy have formed a 50/50 joint venture to explore, develop and operate the TWN Licenses and Waihapa Production Station. 15

Production Facility: Buy vs Build Waihapa Production Station Neighbouring Production Facility 3 Gas processing 45 MMcf/day Gas processing 15 MMcf/day Oil handling 25,000 bbl/day Oil handling 5,000 bbl/day Water handling 18,000 bbl/day Water handling None LPG recovery 70 tonne/day LPG recovery None Pipelines 8” 49-km oil sales line to Shell’s Omata Tank Farm 8” 51-km gas sales line to New Plymouth Gas lift for Tikorangi wells Pipelines 11-km gas line to New Zealand’s open access gas pipelines Cost to buy C$33.5 million (100% basis) • Includes 23,049 acres of Petroleum Licences estimated to host 2,144,700 boe of 2P reserves with $62.9 million NPV (before tax, 10% discount, Cost to expand C$30 million No exploration land 100% basis) 1 • Includes additional 1,162,000 boe contingent resources, 23,541,000 boe prospective resources (100% basis) 1 Cost to replace 2 +/- 30% Oil plant: NZ$35.2 million, Gas plant: NZ$40.8 million Gathering systems: NZ$70.6 million, Wellsite and satellite facilities: NZ$10.6 million 1. Reserves and resources reported on a 100% basis, attributable to NZEC on a 50% basis. See TWN Reserves and TWN Resources and Cautionary Notes. 2. Cost to replace plant and pipelines estimated by Strive Engineering effective July 18, 2012. 3. Information regarding neighbouring production facility compiled using publicly available information. 16

Waihapa Production Station Generating Third-Party Cash Flow * Owned by TWN Limited, a 50/50 Limited Partnership of NZEC and L&M Energy. Operated by NZEC Ngaere Limited as the General Partner. Contact paying a monthly fee of C$165,000 to NZEC Ngaere Limited to operate the Ahuroa Gas Storage Facility. 17

NZEC’s TWN Management & Operational Experience NZEC Position Years Relevant O&G Experience Years Experience with TWN Assets Previous TWN Associated Roles Mike Oakes, GM Operations 35+ 8 Derek Gardiner, CFO 25 3 Commercial & Finance Manager (Origin) Newton Cockerill, Controller 5 5 Business Performance & Accounting Manager (Origin) NZ Asset Manager (Origin), Plant Super & Commissioning Supervisor (Fletcher Energy) Stewart Angelo, Engineering & Maintenance Manager 25+ 15 Maintenance & Engineering Consultant (Origin), Maintenance Superintendent (Fletcher Challenge) Peter Kingsnorth, Plant Superintendent 25+ 20 Shift Supervisor (Origin), Plant Operator (Fletcher Challenge and Petrocorp) Pono Cooper, Field Superintendent 25+ 5 Well Services Supervisor (Swift), Waihapa Operations Superintendent (Origin) 18

Drilling Inventory 19

De-risking Drilling Inventory • RPS Mt. Messenger reservoir study • Merged 3D seismic provides better identification of targets • New data from Mt. Messenger recompletions and new wells drilled on TWN and Horoi will provide additional insight for Mt. Messenger exploitation strategy • New data collected from Tikorangi reactivations and new Tikorangi wells will solidify exploration model for deeper, highreward targets on all Taranaki permits • Waihapa Production Station and infrastructure expedites tie-in, reduces production and processing costs 20

New Proprietary Merged 3D Seismic Database Reprocessed datasets • Combined five 3D surveys • Total area covered (full fold) 552 km2 • Pre-stack merge and post-stack time migration complete, pre-stack time migration underway • Greater geological understanding of basin reduces drilling risk by providing consistent interpretation of seismic anomalies and the correlation with production success and pool size Volume Vintage Area (km2) Kapuni 1989 305 Waihapa 1989 43 Eltham 2002 20 Brecon 2006 74 Rotokare 2012 110 21

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

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

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

Advancing Unconventional Oil Shales 25

East Coast Basin Oil Shales • Over 300 oil and gas seeps sourced back to two oil shale formations: Whangai and Waipawa - Whangai shale package estimated to be 300 – 600 metres thick - Characteristics similar to Bakken shales • Castlepoint Permit - 54.5 million bbl of conventional prospective resource 1 - 154.1 million bbl of unconventional prospective resource 1 - Exploration well on Castlepoint in Q2-2014 2 • NZEC retained Core Laboratories as technical advisor to develop East Coast strategy 1. See NZEC Resource Estimates and Cautionary Notes. 2. Work program assumes commitment wells are funded by a farm-in partner. 26

East Coast Strategy • Results from technical work providing greater insight into unlocking shale potential - Drilled three stratigraphic wells - Acquired 120 km of 2D seismic - Results pending from unconventional test on adjoining permit • NZEC’s technical team has worked extensively on the East Coast as consultants  positive relationships with local communities - Seismic acquisition and interpretation Wellsite geology and prospectivity evaluation Permitting and land access agreements Consultation with community members, local government, local iwi, service providers • Castlepoint Permit Exploration wells drilled by Westech Energy New Zealand discovered - Drill locations identified, consent and permitting oil and natural gas, but did not make a commercial discovery 1 process underway • Wairoa Permit - Log data from 16 wells and 2D seismic shows both conventional and unconventional opportunities - Reviewing 50 km of 2D seismic acquired by NZEC in 2013 (NZ$3.5 million) to identify drilling locations • Actively seeking a partner to fund drilling program 1. Work program assumes commitment wells are funded by a farm-in partner. 27

Corporate Profile Common shares outstanding at January 2014 Options outstanding at January 2014 (Exercisable at average $0.67) 1 Warrants issued in Oct 2013 Private Placement (Exercisable at $0.45 until Oct 2014) Finder’s Warrants issued in Private Placement (Exercisable at $0.33 until Oct 2014) Fully diluted shares outstanding Insider ownership (fully diluted) 52 Week High / Low Average Volume (Q4-2013) 170.9 million 11.1 million 24.5 million 3.0 million 209.4 million ~25% $0.86 / $0.19 ~370,000 shares/day Current market cap (January 31, 2014) ~$50 million Financial Highlights 1 Oil sold during nine-month period Pre-tax oil sales during nine-month period Average realized oil price for Q3-2013 Field netback for Q3-2013 2 Working capital (November 26, 2013) 63,852 bbl $6.6 million $108.84 / bbl $58.90 / bbl $6 million Forecast production – exit 2014 3 2,300 boe/d 1. NZEC has applied to reprice 1.19 million options to $0.45. The incentive options were previous issued at exercise prices between $1 and $3. Repricing is subject to shareholder approval. Director options are not being repriced. 2. As per NZEC’s Q3-2013 consolidated interim financial statements, unless otherwise noted. 2. NZEC’s 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. 3. Assuming successful execution of planned work program. See Planned Work Program – Taranaki Basin and Assumptions. 28

Value Drivers Next 18 Months • Value increase from Acquisition - Immediately booked 150% net increase in 2P reserves 1 - Reactivated oil production from six existing Tikorangi wells  optimizing oil production - Recompleting existing wells uphole in Mt. Messenger  low-cost production opportunities - Additional exploration and development opportunities in 2014 • Increasing production and cash flow - Forecast production of 2,300 boe/day exit 2014 (81% oil) 2 - Reduce net general and administrative costs through joint ventures and third-party processing • Leverage Waihapa Production Station and infrastructure - Generating cash flow from existing and new liquids rich natural gas production - Expedite tie-in of new discoveries = additional incremental cash flow • Resume drilling program - Initiate exploration of high-reward deeper Tikorangi and Kapuni formations - De-risked Mt. Messenger targets with merged 3D seismic and new reservoir information • Experienced team with business, operations and geological expertise to execute development plan and deliver on targets 1. NZEC’s share of TWN Reserves plus NZEC’s existing reserves. See detailed Reserve tables and Cautionary Notes. 2. NZEC forecast based on 50% ownership of TWN Assets and execution of the planned development program. See Assumptions and Planned Work Program – Taranaki Basin. Development and operating costs are to be funded initially by existing working capital and cash flows from production. To carry out all of the planned development activities, the Company is considering a number of options to increase its financial capacity, including additional joint arrangements, commercial arrangements, or other financing alternatives. Development and exploration activities and timing of activities is subject to change as the Company continues to review and refine its 2014 program. 29

Appendix 30 30

NZEC Production / Exploration Wells Drilling / Production Report Card Well Name Permit Name Target Formation Total Depth Notes Total Oil Prod (net, end Dec 2013) Copper Moki-1 Copper Moki-2 Copper Moki-3 1 Copper Moki-4 Eltham Eltham Eltham Eltham Mt. M Mt. M Mt. M / Moki Mt. M / Urenui 2,220 m 2,084 m 3,167 m 2,125 m Producing since December 2011 Producing since April 2012 Producing from Mt. Messenger since July 2012 1 Urenui oil discovery, shut in pending further testing 112,585 bbl 100,320 bbl 46,558 bbl Waitapu-1 Waitapu-2 2 Eltham Eltham Mt. M Mt. M 2,213 m 2,084 m Shut in pending further testing or sidetrack Producing since December 2012 2 Arakamu-1A Arakamu-2 Eltham Eltham Moki Mt. M 2,900 m 2,380 m Suspended, pending further evaluation Oil discovery in April 2013, awaiting artificial lift Wairere-1 Wairere-1A Eltham Eltham Mt. M Mt. M 1,971 m 2,152 m Plugged back for sidetrack Completion pending Six Reactivated Wells (Toko-2B, Ngaere-3, Ngaere-2A, Ngaere-1, Waihapa-H1, Waihapa-6A) TWN Tikorangi Existing wells drilled by previous operator Oil production reactivated in November 2013 Uphole Recompletions (Waihapa-2, Waihapa-1, Waihapa-8) TWN Mt. M WH-2 commencing production in Q1-2014 WH-1 and WH-8 testing underway in Q1-2014 Tikorangi Crestal Wells 3 (Tik-1, Tik-2) TWN Tikorangi ~3,000 m Two new wells, drilling in Q2-Q4 2014 3 New Mt. Messenger Wells 3 (New-1, New-2, New-3) TWN Mt. M ~2,000 m Three new wells, drilling in Q2-Q4 2014 3 Horoi 3 Alton Mt. M ~2,000 m New exploration well, drilling in Q2-2014 3 18,790 bbl 7,430 bbl 1. Copper Moki-3 shut-in during December 2013 for maintenance, resumed production in Jan 2014. 2. Waitapu-2 shut in at end of May 2013 for analysis of artificial lift and reservoir tests, expected to resume production in Q1-2014. 3. Development and operating costs are to be funded initially by existing working capital and cash flows from production. To carry out all of the planned development activities, the Company is considering a number of options to increase its financial capacity, including additional joint arrangements, commercial arrangements, or other financing alternatives. Development and exploration activities and timing of activities is subject to change as the Company continues to review and refine its 2014 program. 31

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

TWN Reserve Estimate (NZEC’s 50% Interest) 1 Reserve Category Light & Medium Oil (Mbbl) Natural Gas (MMcf) Natural Gas Liquids (Mbbl) Barrels of Oil Equivalent (Mboe) NPV, Before Tax (10%) Proved Developed (Non-producing) 491.85 381.00 13.35 568.70 $18,071,000 Proved Undeveloped 129.05 103.25 3.60 149.90 $3,670,000 Total Proved 620.90 484.25 16.95 718.55 $21,741,000 Probable 305.45 239.65 8.40 353.80 $9,696,500 Proved + Probable (2P) 926.35 723.90 25.35 1,072.35 $31,437,500 - - - - - 926.35 723.90 25.35 1,072.35 $31,437,500 Possible Proved + Probable + Possible (3P) 1. NZEC’s 50% interest in TWN Reserves, as estimated by Deloitte LLP with an effective date of April 30, 2013. Reserves restricted to the Tikorangi Formation on the Waihapa and Ngaere Permits. Gross reserves before the deduction of any royalty obligations. See Cautionary Note Regarding Reserve & Resource Estimates. Mbbl – thousand of barrels. MMcf – millions of cubic feet. Mboe – thousand barrels of oil equivalent using a conversion ratio of 6 Mcf : 1 bbl. NPV – net present value. 33

Eltham Reserve Estimate (NZEC 100%) 1 Marketable Oil and Gas Reserves As at December 31, 2012 Forecast Prices and Costs Reserves Category Proved Developed Producing Light & Medium Natural Gas Oil (Mbbl) (MMcf) Natural Gas Liquids (Mbbl) Barrels Oil NPV, Before Tax Equivalent (Mboe) (10%) 307.8 594.9 38.7 445.7 $14,400,000 20.6 31.9 2.0 27.9 $893,000 Total Proved 328.4 626.8 40.7 473.6 $15,293,000 Probable 158.3 329.6 21.5 234.7 $7,320,000 Proved + Probable 486.7 956.4 62.2 708.3 $22,613,000 Possible 195.6 398.1 25.8 287.8 $7,549,000 Proved + Probable + Possible 682.3 1354.5 88.0 996.1 $30,162,000 Proved Undeveloped 1. Gross reserves before the deduction of royalty obligations payable to the New Zealand government. Numbers may not sum due to rounding. Reserve estimates calculated by Deloitte. Mbbl – thousand barrels. MMcf – million cubic feet. Mboe – thousand barrels of oil equivalent using a conversion ratio of 6 Mcf : 1 bbl. NPV – net present value. See Cautionary Note Regarding Reserve and Resource Estimates. 34

TWN Resource Estimate (NZEC’s 50% Interest) 1 Formation Product Type Low Best High Contingent Resources Miocene Sands (Mt. Messenger) Eocene Sands (Kapuni Group) Total Oil (Mbbl) 17 44 101 1,257 2,518 5,168 NGL (Mbbl) 51 117 263 BOE (Mboe) 277 580 1,225 Gas (MMcf – sales) Prospective Resources Miocene Sands (Urenui, Mt. Messenger, Moki) Eocene Sands (Kapuni Group) Total Oil (Mbbl) 803 1,471 2,866 21,417 47,919 113,212 NGL (Mbbl) 955 2,249 5,688 BOE (Mboe) 5,327 11,706 27,422 Gas (MMcf – sales) Discovered PIIP Miocene Sands (Mt. Messenger) Eocene Sands (Kapuni Group) Total Oil (Mbbl) Gas (MMcf – raw) BOE (Mboe) 164 341 700 3,606 6,885 13,468 764 1,488 2,945 Undiscovered PIIP Miocene Sands (Urenui, Mt. Messenger, Moki) Eocene Sands (Kapuni Group) Total Oil (Mbbl) 5,658 10,221 18,902 Gas (MMcf – raw) 59,491 130,540 302,930 BOE (Mboe) 15,573 31,978 69,390 1. NZEC’s 50% share of TWN Resources as estimated by Deloitte with an effective date of April 30, 2013 assuming 9 to 14% recovery for oil resources and 50% for gas resources. See Cautionary Note Regarding Reserve and Resource Estimates. 35

Taranaki and East Coast Resource Estimates 36

Historical Production – Tikorangi Formation 23.6 million bbl of historical production 1 Well name 1 Max bbl/d Total bbl produced Ngaere-1 7,537 4,337,084 Ngaere-2 3,658 1,002,565 Ngaere-3 8,652 1,089,505 Toko-2B 298 126,286 Waihapa H-1 1,953 45,349 Waihapa-1B 4,804 4,909,317 Waihapa-2 3,182 4,798,752 Waihapa-4 2,674 2,990,189 Waihapa-5 979 91,055 Waihapa-6A 4,674 4,262,707 1. Select production data using publicly available information regarding wells that produced oil on the TWN Licences. 37

Oil in Tikorangi Formation • 23.6 million bbl produced to date • Numerous independent estimates of original oil in place (OOIP) ranging from 25 mmbbl (P90) to 100 mmbbl (P10) 1 • Fractured limestone oil recoveries can be as high as 65% of OOIP • NZEC commissioned independent petroleum reservoir engineering study that concluded remaining oil (100% basis) contained in: - Low permeability network fractures (est. 1.5 million bbl from reactivation) - Attic oil trapped up-dip of existing wells (est. 0.95 million bbl from new well) - Laterally trapped oil in existing fracture system (est. 2.05 million bbl from new wells) • Range of well productivity from existing wells, EUR = 400,000 bbl (P50) Cum Oil (mbbl) EUR for a new well = 400 mbbl 1. NZEC collation of independent consultancy assessments. 38

Assumptions in NZEC’s Mid-case Financial Model (as at July 31, 2013) Other Assumptions Oil sales price/bbl = US$99 Natural gas sales price/GJ = NZ$4.50 LPG sales price/tonne = NZ$500 USD/NZD exchange rate = 0.79 CAD/NZD exchange rate = 0.82 Development program includes the following: Six Tikorangi reactivations - wells placed on gas lift, subsequently on high volume lift Two Mt. Messenger uphole completions in existing Tikorangi wells Four New Mt Messenger wells on Alton/TWN permits Two New Tikorangi appraisal wells Two New Kapuni wells to be funded by new JV partner Existing Tikorangi Wells (gas lift  high volume lift) Reserves (unrisked, 100%) Working interest Probability of success IP rate Decline Capital cost (incl. surface equipment) Operating expenditure 150,000 – 448,000 bbls/well 50% 100% 49 BOE/day – 365 BOE/day 2% – 0.5% per month C$0.07 – C$0.8 million per well (WI) C$15,000 per month/well (WI) Mt. Messenger – Uphole Completion in Existing Tikorangi Wells Expected Ultimate Recovery (unrisked, 100%) Working interest Probability of success IP rate Decline Capital cost (incl. surface equipment) Operating expenditure 123,000 bbls/well 50% 100% 365 BOE/day 3% – 9% per month C$0.6 million per well (WI) C$10,000 per month/well (WI) Kapuni New Wells Expected Ultimate Recovery (unrisked, 100%) Working interest Probability of success IP rate Decline Capital cost (incl. surface equipment) Operating expenditure 7.91 Bcf 25% 60% 1,103 BOE/day 1% per month C$nil funded by new JV partner C$10,000 per month/well (WI) Tikorangi New Wells Expected Ultimate Recovery (unrisked , 100%) 1 Working interest Probability of success IP rate Decline Capital cost (incl. surface equipment) Operating expenditure 561,000 bbls/well 50% 50% 1,824BOE/day 5% – 12% per month C$3.95million per well (WI) C$10,000 per month/well (WI) Mt. Messenger Development Wells (incl. Horoi) Expected Ultimate Recovery (unrisked, 100%) Working interest Probability of success IP rate Decline Capital cost (incl. surface equipment) Operating expenditure (not incl. royalty) 502,000 bbls/well 50% – 65% 35% – 40% 420 BOE/day – 511 BOE/day 2% per month C$1.7 – C$3.4 million per well (WI) N$40/bbl Waihapa Production Station Working Interest Operating expenditure (fixed) Operating expenditure (variable) Capital cost (in addition to purchase price) 1. Deloitte LLP has ascribed 2P reserves of 410,300 bbl to one Tikorangi new well. WI = based on Working Interest. Capital costs and operating costs were estimated using the exchange rate assumptions noted above. Actual costs will fluctuate with exchange rate fluctuations. 50% N$0.4 million per month (WI) N$10/bbl C$7.1 million, including increasing water handling capacity 39

Board of Directors Name Expertise Experience John A. Greig, M.Sc, P.Geo Chairman • Founder and financier of numerous mining and oil and gas companies. Specializing in recognizing undervalued geological assets • Founder, Director & Officer Sutton Resources, Cumberland Resources Ltd., Eurozinc Mining Corp., Crown Resources Corp. John G. Proust, C.Dir CEO Director • Proven track record of building companies from grass roots to advanced development. Specializes in identifying undervalued assets on a global basis • Chairman, Director & CEO, Southern Arc Minerals Inc. • Chairman, Director & Interim CEO, Eagle Hill Exploration Corp. • Chairman, Canada Energy Partners Inc. Bruce G. McIntyre, P.Geol Executive Director, Acting GM Exploration • Professional petroleum geologist with over 30 years of proven exploration and development oriented value creation • President, CEO Sebring Energy Inc. • President, CEO TriQuest Energy Corp. • President, CEO BXL Energy Ltd., • Exploration Manager Gascan Resources Ltd. Hamish J. Campbell B.Sc (Geology), FAusIMM Director • Professional geologist with 30 years of experience managing exploration programs, evaluation and assessment of joint ventures and acquisitions • Director of a number of New Zealand limited liability mineral and petroleum companies • Principal Indonesian mining service company 40

Corporate Office – Canada Name Expertise Experience • Proven track record of building companies from grass roots to advanced development. Specializes in identifying undervalued assets on a global basis • Chairman, Director & CEO, Southern Arc Minerals Inc. • Chairman, Director & Interim CEO, Eagle Hill Exploration Corp. • Chairman, Canada Energy Partners Inc. • Professional petroleum geologist with over 30 years of proven exploration and development oriented value creation • President, CEO Sebring Energy Inc. • President, CEO TriQuest Energy Corp. • President, CEO BXL Energy Ltd., • Exploration Manager Gascan Resources Ltd. Gerrie van der Westhuizen, CA Vice President Finance • Chartered Accountant with expertise in financial reporting and controls, equity offerings, treasury management and debt structures, tax compliance • Progressively senior positions with publicly-traded natural resource companies • Audit Manager, Mining Group, PricewaterhouseCoopers Rhylin Bailie, B.ES VP Communications & Investor Relations • More than 18 years of experience in the resource industry, in both finance and investor relations • Professional writer and editor • Director Communications & Investor Relations, NovaGold Resources Inc. • Supervisor Treasury Administration, Placer Dome Inc. • More than 16 years of experience overseeing corporate governance and corporate affairs for publicly-listed resource companies • Corporate Secretary for various public and private resource companies • Director of Charlotte Resources John G. Proust, C.Dir Chief Executive Officer Bruce G. McIntyre, P.Geol Executive Director, Acting GM Exploration Eileen Au, B.Sc Corporate Secretary 41

Operations Team – New Zealand Name Expertise Derek Gardiner Chief Financial Officer • Chartered Accountant and Chartered Corporate Secretary with more than 25 years of experience in the New Zealand oil gas industry with senior financial, business planning and accounting positions • Commercial and Finance Manager, Origin Energy • Chief Financial Officer, Austral Pacific Energy • Numerous senior positions, Shell Mike Oakes General Manager Operations • More than 30 years of international oil and gas experience overseeing design, commissioning and start up, staffing and operation of oil and gas fields and production facilities • Operations Manager, Asset Manager and Operational Excellence Advisor, Origin Energy • Technical Advisor, Total E&P Borneo • Mechanical engineer with more than 15 years of experience in all aspects of drilling, completions and production, and facility and wellsite construction • Production and Facilities Manager, TAG Oil • Senior Petroleum Engineer, Origin Energy • Operations Engineer, Iteration Energy/Chinook Energy • 25 years in oil and gas midstream assets focused around development and implementation of procedures and processes for asset management systems • Engineering Officer with New Zealand Merchant Navy • Maintenance Engineer, Fletcher Challenge • Director of Productive Maintenance • Senior Manager, New Zealand Dept. of Conservation • Negotiating access provisions and facilitating resource consent process, assisting with community relationship building • Mechanical engineer with 30 years of experience • Drilling and completion work, design, approval and implementation of drilling programs James Watchorn, B.Sc Operations Manager Stewart Angelo Engineering & Maintenance Manager Toka Walden Land Manager Dan MacDonald Drilling Manager Experience 42

Technical Team – New Zealand Name Qualifications Expertise Dr. Ian Brown B.Sc (Hons), M.Phil, D.Eng, MIPENZ, C.P.Eng June Cahill B.Sc, B. Applied Econ. Bill Leask B.Sc (Hons) M.Sc (Hons) Petroleum geology related to the East Coast and other New Zealand basins Dr. Simon Ward B.Sc (Hons) Ph.D Petroleum geology related to the Taranaki and other New Zealand basins Ian Calman B.Sc (Hons) Seismic data acquisition, processing, and interpretation Gareth Reynolds B.Sc (Hons) Geology Dr. Richard Kellett B.Sc (Hons), Ph.D, P.Geoph Monmoyuri Sarma B.Sc (Hons), M.Sc (Petroleum Geosciences), M.Sc (Applied Geology) Peter Wood B.E (Hons), B.Sc , M.Comp.Sci Sam Pryde B.Sc Post.Grad.Dip. Professional geological engineer, government and community relations Acquisition, management, and analysis of complex geoscience data Geoscientist with experience in New Zealand Basin analysis Geoscientist with worldwide exploration and business development experience Geoscientist with experience with reservoir modelling and petroleum system analysis Management and development of computing resources for geoscience applications Geological investigations in the East Coast basin area 43

L&M Energy and Geoff Loudon Mr. Loudon is a New Zealand based international investor with family roots going back to the Hokitika, NZ gold fields in 1875. He was the former Chairman of L&M Energy (ASX, NZX), which he privatized in January 2013 through a NZ$48 million takeover bid by his company, New Dawn Energy Limited. L&M Energy holds a number of petroleum exploration permits on the North and South Islands of New Zealand, including a 35% interest in NZEC’s Alton Permit. Mr. Loudon is Chairman of Nautilus Minerals Inc. (TSX), a Canadian based seabed minerals exploration company; was a founding director from 1995 to 2010 of Lihir Gold Limited (ASX, TSX, NASDAQ), a PNG gold miner; and a founder and investor in Peru Copper Inc. (TSX, AMEX). Mr. Loudon is a mining professional with qualifications in geology, engineering and international finance. He started his career as a geologist with the NSW Geological Survey Australia, then worked with Placer Dome in Canada in operations, development and exploration before starting a finance career with Kleinwort Benson, a UK merchant bank. He then founded Niugini Mining which developed gold and copper mines in PNG, Chile and Australia and discovered the Lihir gold deposit in PNG. Mr. Loudon is a Fellow of the Australasian Institute of Mining & Metallurgy (AIMM), a Member of the Canadian Institute of Mining (CIM) and a Member of the American Institute of Mining Engineers (AIME). 44

Analyst Coverage Company Analyst Contact Canaccord Genuity Christopher Brown 403-508-3858 Credit Suisse David Phung 403-476-6023 Dundee Capital Markets David Dudlyke 44-203-440-6870 Haywood Securities Alan Knowles 403-509-1931 Mackie Research Bill Newman 403-750-1297 M Partners David Buma 416-603-7381 45

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

Add a comment

Related presentations

Related pages

TSX-V: NZ OTCQX: NZERF - New Zealand Energy Corp.

TSX-V: NZ . OTCQX: NZERF . Waihapa Production Station Corporate Presentation February 3, 2014
Read more

Taller No.1 2014-02 - Documents

Nzecppt 201402 03 AGOF internet facts 2014-02 Kernergebnisse der AGOF internet facts 2014-02 Springer India 2014-02 India workshop given by Edanz Senior ...
Read more