TSX-V: NZ OTCQX: NZERF Waihapa Production Station Corporate Presentation December 3, 2013
Jan 13, 2015
TSX-V: NZ OTCQX: NZERF
Waihapa Production Station Corporate Presentation
December 3, 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”, “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 Reactivate oil production from Tikorangi formation
in six existing wells - Recomplete existing wells uphole in Mt. Messenger
formation - Drill new wells to Mt. Messenger and Tikorangi
formation • More than 2 million acres of permits with both
conventional and unconventional opportunities • Strategic JV partners: L&M Energy, New Zealand
Oil & Gas, Westech • Experienced team with New Zealand and Western
Canadian exploration and operations expertise
3 1. See Reserve and Resource tables in the Appendix, and Cautionary Notes.
Asset Overview
4
Permit Working Interest
Net Acres 2P boe Reserves 1
Contingent Resource 1
Prospective Resource 1
Eltham 100% 93,166 708 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 2 80% 214,290 - - Under review
East Cape 100% 1,048,406 - - 355.4 MM bbl
Ranui 100% 223,087 Considering relinquishment 40.5 MM bbl
Total 2,196,692
1. Reserves and resources estimated by Deloitte LLP. For effective dates and estimated recovery rates, see NZEC’s annual and interim reserve and resource filings on SEDAR, the Reserve and Resource tables in the Appendix, and Cautionary Notes. 2. Acquisition of Wairoa Permit pending NZPAM approval.
Eltham Alton
Ranui
Castlepoint
East Cape
Conventional Focus
Conventional and Unconventional Targets
Wairoa TWN
Manaia
Multiple Prospective Conventional Formations in Taranaki Basin
5
Moki
Tikorangi
Kapuni
Mt Messenger
Kapuni Group
2,500 metres
3,000 metres
3,500 metres
4,000 metres
Approximate Depth
Dominant Exploration and Infrastructure Portfolio in Main Production Fairway 1
6
1. NZEC and L&M Energy have formed the 50/50 TWN Joint Arrangement to explore, develop and operate the TWN Licenses and Waihapa Production Station.
2. TWN reserves and resources shown at a 100% basis, of which 50% is attributable to NZEC. See Reserve and Resource estimate tables and Cautionary Notes.
• Currently producing oil and natural gas from nine wells
• Near-term potential to increase production from four additional wells
• Exploration planned for 2014 into three drill-proven formations
• Operator of open access midstream facility central to NZEC’s exploration / development inventory and third-party business opportunities
• 100 km of oil and gas gathering and sales pipelines
7
Immediate Value from Near-term Work Program
Planned Work Program – Taranaki Basin (Balance of 2013 and 2014)
8
Balance of 2013 Existing Tikorangi Well Reactivations Reactivate oil production from six Tikorangi wells on TWN Licenses
Mt. Messenger development • Waitapu-2 artificial lift and tie-in on Eltham Permit • Begin uphole recompletions in two existing wells on TWN Licenses
2014 Existing Tikorangi Well Reactivations
• High volume lift installation on two best-performing wells on TWN Licenses • Increase water handling capacity at Waihapa Production Station • High volume lift installation on remaining four reactivated wells on TWN Licenses
New Tikorangi wells • Drill two new Tikorangi wells on TWN Licenses
Mt. Messenger development • Complete Mt. Messenger uphole completions in existing wells on TWN Licenses • Horoi exploration well (including surface infrastructure) on Alton Permit • Drill three new Mt. Messenger wells (including surface infrastructure)
Seismic acquisition, G&G studies and Other
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.
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 • Six wells reactivated in November – oil production from
Tikorangi formation • 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 • Forecast total 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
9
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.
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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
Daily
pro
duct
ion
(bbl
/day
)
Tikorangi - High Volume Lift
Tikorangi - Gas Lift
Tikorangi Reactivations Forecast Production and Cash Flow Attributable to NZEC
10
T = October 28, 2013, the day the Acquisition closed. Daily production = NZEC’s share of production and cash flow from operations. See Planned Work Program and Assumptions.
780 bbl/d from Tikorangi Reactivations (exit 2014) C$11.09 million additional cash flow from operations (exit 2014)
(Gas lift replaced with High Volume Lift)
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
11 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.
Waipapa wellsite
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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
Daily
pro
duct
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(bbl
/day
)
Mt. Messenger - Uphole Completion in Existing Tikorangi Wells
Mt. Messenger - Development (incl. Horoi)
Waitapu - Artificial Lift
Copper Moki - Existing
Mt. Messenger Development Program Forecast Production and Cash Flow Attributable to NZEC
12
T = October 28, 2013, the day the Acquisition closed. Daily production = NZEC’s share of production and cash flow from operations. See Planned Work Program and Assumptions.
540 bbl/d from Mt. Messenger Development (exit 2014) C$6.21 million additional cash flow from operations (exit 2014)
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
13
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, attributable to NZEC at 50%. See Cautionary Note Regarding Reserve & Resource Estimates. 2. See Assumptions and Planned Work Program.
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T+7M T+8M T+9M T+10M T+11M T+12M T+13M T+14M T+15M T+16M
Daily
pro
duct
ion
(bbl
/day
)
Tikorangi New Wells
New Tikorangi Wells Forecast Production and Cash Flow Attributable to NZEC
14
T = October 28, 2013, the day the Acquisition closed. Daily production = NZEC’s share of production and cash flow from operations. See Planned Work Program and Assumptions.
490 bbl/d from New Tikorangi Wells (exit 2014) C$8.46 million additional cash flow from operations (exit 2014)
Kapuni Group – High Impact Deep Targets Two Kapuni Wells to be Drilled in 2014
Drill-proven formation • Kapuni Gas Field onshore oil/gas discovery (Shell)
producing since 1969, estimated ultimate recovery of 1,365 billion cf (Bcf) natural gas and 66 million bbl oil
• TWN Licences tested by four wells all encountered gas in the Kapuni Group
• Work program includes two Kapuni wells by end of 2014 with forecast total initial production of 1,216 boe/d (risked) (100% basis) funded by farm-in partner 1
2013 Deloitte Resource Estimate 2
• Contingent resource: 5.0 Bcf gas, 233,000 bbl NGL (100% basis)
• Prospective resource: 95.8 Bcf gas, 4.5 million bbl NGL (100% basis)
• Discovered PIIP: 13.8 Bcf gas (100% basis)
• Undiscovered PIIP: 261.1 Bcf gas (100% basis)
15
1. See Assumptions and Planned Work Program. 2. Shown on a 100% basis, attributable to NZEC at 50%. See TWN Resource Estimate and Cautionary Notes.
C$ (5)
C$ -
C$ 5
C$ 10
C$ 15
C$ 20
C$ 25
C$ 30
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500
1,000
1,500
2,000
2,500
3,000
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
Cum
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cash
flow
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om o
pera
tions
(C$
mill
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)
Daily
pro
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ion
(BO
E/da
y)
Kapuni New Wells
Tikorangi New Wells
Tikorangi - High Volume Lift
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$)
Total Forecast Production and Cash Flow Attributable to NZEC
16
T = October 28, 2013, the day the Acquisition closed. Daily production = NZEC’s share of production and cash flow from operations. See Planned Work Program and Assumptions.
2,300 BOE/d (exit 2014) C$26.11 cumulative cash flow from operations (exit 2014)
17
Full-cycle Production Station
18
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
Waihapa Production Station Assets Full-cycle facility with gathering and sales pipeline infrastructure
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.
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$33.7 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, 100% basis) 1
• Includes additional 1,162,000 boe contingent resources, 23,541,000 boe prospective resources (100% basis) 1
Cost to expand C$30 million No exploration land
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
19
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.
Waihapa Midstream Business Plan
20 * Owned by TWN Limited Partnership, 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.
NZEC’s TWN Management & Operational Experience
21
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 Operations 35+ 8 NZ Asset Manager (Origin), Plant Super &
Commissioning Supervisor (Fletcher Energy)
Newton Cockerill Controller 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 Services Supervisor (Swift), Waihapa
Operations Superintendent (Origin)
22
Drilling Inventory
Drilling / Production Report Card
23
Well Name
Target Formation
Total Depth
Status Total Oil Prod (end Oct 2013)
Copper Moki-1 Copper Moki-2 Copper Moki-3 Copper Moki-4
Mt. M Mt. M
Mt. M / Moki Mt. M / Urenui
2,220 m 2,084 m 3,167 m 2,125 m
Producing since December 2011 Producing since April 2012
Producing from Mt. Messenger since July 2012 Urenui oil discovery, shut in pending further testing
111,205 bbl 96,417 bbl 46,337 bbl
Waitapu-1 Waitapu-2
Mt. M Mt. M
2,213 m 2,084 m
Shut in pending further testing or sidetrack Producing since December 2012 1
18,790 bbl
Arakamu-1A Arakamu-2
Moki Mt. M
2,900 m 2,380 m
Suspended, pending further evaluation Oil discovery in April 2013, awaiting artificial lift
Wairere-1 Wairere-1A
Mt. M Mt. M
1,971 m 2,152 m
Plugged back for sidetrack Completion pending
TWN Existing Well Reactivations
Tikorangi Six wells reactivated in November
Drilling / Production Report Card
1. Waitapu-2 was temporarily shut in at the end of May to allow the Company to analyze artificial lift options and perform tests related to the Copper Moki reservoir study. Installation of artificial lift is underway and Waitapu-2 is expected to recommence production in December 2013.
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, high-reward targets on all Taranaki permits
• Waihapa Production Station and infrastructure expedites tie-in, reduces production and processing costs
24
New Proprietary Merged 3D Seismic Database
25
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
Individual 3D Surveys = Mismatched Data
26
Kapuni 3D Rotokare 3D
1989 2012
Proprietary Merged 3D Datasets Increase Chance of Success
27
Kapuni 3D Rotokare 3D
Reprocessed and merged 2013
Inventory of Taranaki Drilling Leads NZEC’s Copper Moki area converting to long-term mining permit
28
Waitapu Copper Moki
Arakamu
Wairere
Horoi site
Waipapa site
29
Advancing Unconventional Oil Shales
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
• Exploration well on Castlepoint in Q2-2014
• 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
30
1. See NZEC Resource Estimates and Cautionary Notes. Acquisition of Wairoa Permit pending Crown approval. 2. Work program assumes commitment wells are funded by a farm-in partner.
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
- Drill locations identified, consent and permitting process underway
• Wairoa Permit
31
Exploration wells drilled by Westech Energy New Zealand discovered oil and natural gas, but did not make a commercial discovery
1. Acquisition of Wairoa Permit pending Crown approval. NZEC will own 80% and operate the permit, in partnership with Westech Energy New Zealand.
- 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
Common shares outstanding at September 2013 Shares issued in Private Placement Options outstanding at September 2013 (Exercisable at average $1.35) Warrants issued in 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
122.0 million 48.9 million
9.6 million 24.5 million
3.0 million 208.0 million
Insider ownership (fully diluted) 52 Week High / Low Average Volume (Q3-2013)
~23% $1.75 / $0.19
~353,000 shares/day
Current market cap (November 29, 2013) ~$54 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
Corporate Profile
32
1. 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.
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 optimizing oil production - Additional exploration and development opportunities results in forecast 15x increase
in production to net 2,300 boe/day exit 2014 (81% oil) 2
- Forecast 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 - Initiate exploration of high-reward deeper Tikorangi and Kapuni formations - De-risked Mt. Messenger targets with merged 3D seismic and new drilling and
reservoir information • Experienced team with business, operations and geological expertise to execute
development plan and deliver on targets
33
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.
34
Appendix 34
TWN Reserve Estimate (NZEC’s 50% Interest) 1
35
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
Possible - - - - -
Proved + Probable + Possible (3P)
926.35
723.90
25.35
1,072.35
$31,437,500
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.
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.
Eltham Reserve Estimate (NZEC 100%) 1
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Proved Developed Producing 307.8 594.9 38.7 445.7 $14,400,000
Proved Undeveloped 20.6 31.9 2.0 27.9 $893,000
Total Proved 328.4 626.8 40.7 473.6 $15,293,000
Probable 158.3 329.6 21.5 234.7 $7,320,000
Proved + Probable 486.7 956.4 62.2 708.3 $22,613,000
Possible 195.6 398.1 25.8 287.8 $7,549,000
Proved + Probable + Possible 682.3 1354.5 88.0 996.1 $30,162,000
NPV, Before Tax (10%)
Marketable Oil and Gas ReservesAs at December 31, 2012Forecast Prices and Costs
Reserves Category Natural Gas Liquids (Mbbl)
Barrels Oil Equivalent (Mboe)
Natural Gas (MMcf)
Light & Medium Oil (Mbbl)
TWN Resource Estimate (NZEC’s 50% Interest) 1
Formation Product Type Low Best High
Contingent Resources
Miocene Sands (Mt. Messenger) Oil (Mbbl) 17 44 101
Eocene Sands (Kapuni Group) Gas (MMcf – sales) 1,257 2,518 5,168
NGL (Mbbl) 51 117 263
Total BOE (Mboe) 277 580 1,225
Prospective Resources
Miocene Sands (Urenui, Mt. Messenger, Moki) Oil (Mbbl) 803 1,471 2,866
Eocene Sands (Kapuni Group) Gas (MMcf – sales) 21,417 47,919 113,212
NGL (Mbbl) 955 2,249 5,688
Total BOE (Mboe) 5,327 11,706 27,422
Discovered PIIP
Miocene Sands (Mt. Messenger) Oil (Mbbl) 164 341 700
Eocene Sands (Kapuni Group) Gas (MMcf – raw) 3,606 6,885 13,468
Total BOE (Mboe) 764 1,488 2,945
Undiscovered PIIP
Miocene Sands (Urenui, Mt. Messenger, Moki) Oil (Mbbl) 5,658 10,221 18,902
Eocene Sands (Kapuni Group) Gas (MMcf – raw) 59,491 130,540 302,930
Total BOE (Mboe) 15,573 31,978 69,390
1. NZEC’s 50% share of TWN Resources as estimated by Deloitte with an effective date of April 30, 2013 assuming 9 to 14% recovery for oil resources and 50% for gas resources. See Cautionary Note Regarding Reserve and Resource Estimates. 37
Taranaki and East Coast Resource Estimates
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Low Best High Low Best High
TARANAKI BASINEltham (PEP 51150) 377.0 93,166.1 100% NZECConventional 1 231.4 346.8 578.8 19.7 31.6 56.9
Alton (PEP 51151) 156.7 38,717.4 65% NZEC / 35% L&MConventional 1 224.8 493.7 1,229.7 18.9 45.0 116.9
Manaia (PEP 54867) 66.6 16,455.7 60% NZEC / 40% NZOGConventional
EAST COAST BASINCastlepoint (PEP 52694) 2,230.0 551,045.0 100% NZECConventional 1 349.0 586.3 1,053.1 30.3 54.5 102.0 Unconventional 2 2,958.2 6,743.0 16,190.7 56.2 154.1 458.5
Ranui (PEP 38342) 902.8 223,086.7 100% NZECConventional 1 94.3 198.3 435.0 8.1 18.0 42.0 Unconventional 2 440.4 969.0 2,252.5 8.6 22.5 65.2
East Cape (PEP 52976) 4,320.0 1,067,495.2 100% NZEC Conventional 1 189.8 615.7 1,997.4 14.6 53.3 195.4 Unconventional 2 5,747.2 13,148.1 31,838.3 110.3 302.1 906.3
Wairoa (PEP 38346) 867.2 214,289.8 80% NZEC / 20% Westech 3
ConventionalUnconventional
Total 8,920.3 2,204,255.9 10,235.1 23,100.9 55,575.5 266.7 681.1 1,943.2 Conventional 1 1,089.3 2,240.8 5,294.0 91.6 202.4 513.2 Unconventional 2 9,145.8 20,860.1 50,281.5 175.1 478.7 1,430.0
Resources estimated by Deloitte LLP. Eltham Resources effective date December 31, 2011. Other resources effective date February 1, 2011.1 Assumes 9% recovery. 2 Assumes 2% recovery. 3 Grant of 80% interest pending approval.
Net Permit Area
Net Permit Acreage
Net Unrisked Undiscovered Petroleum (MM barrels of oil)
Net Unrisked Prospective Recoverable
Estimate pending Estimate pending
(MM barrels of oil)
Early stage Early stage
Historical Production – Tikorangi Formation
1. Select production data using publicly available information regarding wells that produced oil on the TWN Licences.
Well name 1 Max bbl/d Total bbl produced
Ngaere-1 7,537 4,337,084
Ngaere-2 3,658 1,002,565
Ngaere-3 8,652 1,089,505
Toko-2B 298 126,286
Waihapa H-1 1,953 45,349
Waihapa-1B 4,804 4,909,317
Waihapa-2 3,182 4,798,752
Waihapa-4 2,674 2,990,189
Waihapa-5 979 91,055
Waihapa-6A 4,674 4,262,707
23.6 million bbl of historical production 1
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EUR for a new well = 400 mbbl
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)
40
Cum
Oil
(mbb
l)
1. NZEC collation of independent consultancy assessments.
Assumptions in NZEC’s Mid-case Financial Model (as at July 31, 2013)
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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
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
Existing Tikorangi Wells (gas lift high volume lift)
Tikorangi New Wells
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)
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 – Uphole Completion in Existing Tikorangi Wells
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
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)
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$40/bbl
Kapuni New Wells Waihapa Production Station
Expected Ultimate Recovery (unrisked, 100%) Working interest Probability of success IP rate Decline Capital cost (incl. surface equipment) Operating expenditure
7.91 Bcf 25% 60% 1,103 BOE/day 1% per month C$nil funded by new JV partner C$10,000 per month/well (WI)
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
1. Deloitte LLP has ascribed 2P reserves of 410,300 bbl to one Tikorangi new well. WI = based on Working Interest.
Board of Directors
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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
Corporate Office – Canada
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Name Expertise Experience
John G. Proust, C.Dir Chief Executive Officer
• Proven track record of building companies from grass roots to advanced development. Specializes in identifying undervalued assets on a global basis
• Chairman, 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.
Gerrie van der Westhuizen, CA Interim CFO
• 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.
Eileen Au, B.Sc Corporate Secretary
• More than 16 years of experience overseeing corporate governance and corporate affairs for publicly-listed resource companies
• Corporate Secretary for various public and private resource companies
• Director of Charlotte Resources
Operations Team – New Plymouth, NZ
44
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
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
James Watchorn, B.Sc Operations Manager
• Mechanical engineer with more than 15 years of experience in all aspects of drilling, completions and production, and facility and wellsite construction
• Production and Facilities Manager, TAG Oil • Senior Petroleum Engineer, Origin Energy • Operations Engineer, Iteration Energy/Chinook Energy
Stewart Angelo Engineering & Maintenance
Manager
• 25 years in oil and gas midstream assets focused around development and implementation of procedures and processes for asset management systems
• Engineering Officer with New Zealand Merchant Navy • Maintenance Engineer, Fletcher Challenge • Director of Productive Maintenance
Toka Walden Land Manager • Senior Manager, New Zealand Dept. of Conservation
• Negotiating access provisions and facilitating resource consent process, assisting with community relationship building
Dan MacDonald Drilling Manager • Mechanical engineer with 30 years of experience • Drilling and completion work, design, approval and
implementation of drilling programs
Technical Team – Wellington, NZ
45
Name Qualifications Expertise
Dr. Ian Brown B.Sc (Hons), M.Phil, D.Eng, MIPENZ, C.P.Eng Professional geological engineer, government and community relations
June Cahill B.Sc,
B. Applied Econ. Acquisition, management, and analysis of complex geoscience data
Bill Leask B.Sc (Hons) M.Sc (Hons)
Petroleum geology related to the East Coast and other New Zealand basins
Dr. Simon Ward B.Sc (Hons)
Ph.D Petroleum geology related to the Taranaki and other New Zealand basins
Ian Calman B.Sc (Hons) Seismic data acquisition, processing, and interpretation
Gareth Reynolds B.Sc (Hons) Geology Geoscientist with experience in New Zealand Basin analysis
Dr. Richard Kellett B.Sc (Hons), Ph.D, P.Geoph Geoscientist with worldwide exploration and business development experience
Monmoyuri Sarma B.Sc (Hons), M.Sc
(Petroleum Geosciences), M.Sc (Applied Geology)
Geoscientist with experience with reservoir modelling and petroleum system analysis
Peter Wood B.E (Hons), B.Sc ,
M.Comp.Sci Management and development of computing resources for geoscience applications
Sam Pryde B.Sc
Post.Grad.Dip. Geological investigations in the East Coast basin area
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).
46
Analyst Coverage
47
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
Contact NZEC
48
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 [email protected]
New Zealand Office Chris Bush, New Zealand Country Manager Tel: + 64-6-757-4470 New Zealand Toll-free: 0800-469-363 www.NewZealandEnergy.com