MD&A (NZ BOD 2025 11 30 NZEC MDA Q3 2025 Final)

(Expressed in Canadian Dollars)

This Management's Discussion and Analysis ("MD&A") is dated 1 December 2025, for the quarter ended 30 September 2025. It should be read in conjunction with the Unaudited Condensed Consolidated Financial statements for the quarter ended 30 September 2025 of New Zealand Energy Corp. ("NZEC" or the "Company") as publicly filed on the SEDAR+ website at https://www.sedarplus.ca.

NZEC reports in accordance with International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board ("IASB") and the associated Unaudited Condensed Consolidated Interim Financial statements, are presented in accordance with IFRS.

This MD&A includes certain statements which may be deemed "forward-looking statements" (see Forward-looking Information). All amounts are in Canadian dollars unless otherwise stated.

NZEC's shares are listed on the TSX Venture Exchange under the symbol "NZ". Additional information is available on

SEDAR+ and on the Company's website at https://www.newzealandenergy.com.

NZEC, through its subsidiaries (collectively the "Group") is engaged in the production, development, appraisal, and exploration for oil and natural gas, as well as the operation of midstream assets, in New Zealand. The Group's assets are located on New Zealand's North Island in the Taranaki Basin, New Zealand's only commercial oil and gas producing area.

Background

NZEC is the Operator of three Petroleum Mining Licences ("PMLs"), one Petroleum Mining Permit ("PMP") and one Petroleum Exploration Permit ("PEP") in each of which it has an interest. It holds a 50% interest in PML 38138 ("Tariki Licence"), PML 38140 ("Waihapa Licence") and PML 38141 ("Ngaere Licence") which are known collectively as the "TWN Petroleum Mining Licences". L&M Energy Limited ("L&M") holds the remaining 50% in these three licences.

NZEC holds a 100% interest in Mining Permit PMP 55491 ("Copper Moki") and Exploration Permit PEP 51150 (the "Eltham Permit").

NZEC also holds a 50% working interest (with New Dawn Energy Limited) in, and is Operator of, the Waihapa Production Station and associated gathering and sales infrastructure (known collectively as the "TWN Assets"). These provide a range of services to its own operated assets and to third parties including, oil handling and pipeline throughput, gas processing and transport, LPG storage and produced water handling and disposal.

The following are the operating highlights for the quarter:

1. Safety: Q3 of 2025 has been a quiet quarter. Intervention work was completed at Copper Moki on both Copper Moki 1 & 2 without incident. There was one incident at Waihapa which was due to Corrosion under Insulation (CUI). This was discovered during Planned Maintenance Inspection of the above ground pipework. The pipework was isolated and NDT completed to assure pipeline integrity. The incident was classified as a Near Miss. An ongoing effort by the operators has seen a positive volume of observation cards. Work continues on the Safety Case to ensure successful resubmission in the 1st Quarter 2026. All Waihapa Production Station HAZOP's have been reviewed and an action plan issued. Permit to Work audits were completed as per the PTW audit plan.
2. Copper Moki Workovers: The Copper Moki-2 and -1 wells were successfully worked over in late Q2 and early Q3 respectively. Copper Moki-2 production started in early July and has been producing 45 to 50 bopd consistently through the quarter. Copper Moki-1 commenced in late July and was initially 80% water-cut, due to both the completion fluids and the offset well Waitapu-2 having operated as a waterflood well. By the end of August Copper Moki-1 was at 40% water-cut and producing ~45 to 55 bopd. In mid September the Copper Moki-1 downhole pump locked up and efforts commenced to diagnose the fault. It is now confirmed via rod pulling that recently installed pump has broken apart at the top and will need a new pump installed. Plans for this are underway as the well has new tubing already, this will be completed in late Q4 2025 or early Q1 2026 without needing a rig.
3. Waihapa-Ngaere Production: The average rate (NZEC share) for Q3 2025 was 44 bopd (100% oil). This was an increase from the 18 bopd NZEC share (100% oil) in Q2 2025. At quarter end the Waihapa-Ngaere Field was averaging 40 bopd (NZEC share). See "2025 Outlook" and "Property Review and Outlook".
4. Production: Aggregate production for Q3 2025 was 8,975 boe (94% oil) (average 98 boe per day); compared to Q2 2025 when production was 1,685 boe (100% oil) (average 18 boe per day).
5. Sales (oil): Oil sales for Q3 2025 of 3,858 bbl realised $330,772 (with an average oil sale price of $85.75 per bbl) compared to the Q2 2025 sales of 1,342 bbl realised $119,678 (with an average oil sale price of $89.25 per bbl).
6. Processing revenue: The TWN Assets (NZEC share) generated $93,790 from processing fees for Q3, compared to $104,674 for the previous quarter, with several third-party customers accessing a range of services including site operations, oil processing and handling, oil and gas pipeline throughput services, water disposal and gas processing.
7. Tariki PML 38138: The primary focus for the Company remain maturation of the Tariki Field to a Gas Storage Project within the next 15 months. There are four workstreams associated with this work:

   1. Sub-surface Reservoir Static and Dynamic modelling. The first versions of the new Static Models were made available for Reservoir Simulation at the end of Q3 and reservoir simulation and storage forecasting work has commenced and will be completed in Q4.

   2. Facility/Infrastructure - Concept Selection and Feasibility Studies have been completed with Worley's specialist engineering team during Q3. The project timelines and costs are now well understood, and the detailed engineering design was scoped during Q3 and will be commenced in Q4 2025.

   3. Commercial - Work to develop the framework for providing storage capacity rights and usage fees has progressed through Q3 along with further engagement with Genesis Energy Limited ("Genesis"), who have priority gas storage negotiation rights and the Company is in negotiations to have a commercial specialist retained to assist with this phase of the project.

   4. Tariki-5A Well Restart - The selected 1.666" velocity string was ordered in Q3 and will be in country by the end of Q4 for an early Q1 installation. In parallel, facilities studies to design and procure the restart site equipment commenced in Q3.

Key objectives for the year include:

1. Health and Safety: The Group's focus remains on keeping safety as an embedded component of everyday operations, zero harm to people and the environment remains foremost in planning and implementing all Group and contractor activities. The Group continues to work with regulators, other operators, local community businesses, communities and iwi to maintain safe operations and HSE performance.
2. Tariki: As in Q2 the primary focus for the Company remains the maturation of Tariki to a Gas Storage Project within the next 15 months. The four workstreams associated with this work will continue through Q4;

   1. Sub-surface -. The full static model rebuilds using the structural scenarios developed from the seismic volume in Q2 2025 commenced mid-August and are completed with dynamic modelling commencing at the end of Q3 2025 as planned. This second round of reservoir modelling using multiple scenarios will improve the reliability of the models and the associated performance forecasts. The results from the range of Gas Storage dynamic models in use were reviewed by external experts through Q3 and continue to Q4.

   2. Facility/Infrastructure - Concept Selection and Feasibility Studies completed with Worley's Facilities

      Engineering and delivered the first draft of their recommended concept(s) in late Q3.

   3. Commercial - Work to develop the framework for providing storage capacity rights and usage fees continues to progress in Q3 2025. Progress has been slow while the Company focusses on the reservoir modelling and the restart of Tariki gas production both of which have been encouraged by Genesis who have priority gas storage negotiation rights.

   4. Tariki-5A Well Restart - Equipment has been ordered and the site layout and equipment scoped and located. Due to the current lead times, it is anticipated to be restarting Tariki-5A in Q1 2026.

3. Waihapa-Ngaere Production: Production is back operating on cyclic well unloads without the use of gas-lift, from 5 wells. Ngaere 1 was restored to production in July 2025 and provided flush production through to early September. Since then, the well continues to be the best producer in the field and averages ~25 bopd.
4. Copper Moki: Production at Copper Moki has been restored with both Copper Moki wells being on production in the quarter. The two wells peaked at a combined oil rate of just over 100 bopd before the Copper Moki-1 pump failed in mid -September. Work to re-instate Copper Moki-1 is underway in Q4.
5. Eltham PEP 51150: Arakumu-2A is an oil discovery well that has produced minor volumes of oil to surface but has a viscous waxy low GOR oil, and hence no reservoir energy or drive. A trial of water injection into nearby offset wells was carried out through 2023/24 and a review of the data from this shows that no communication between these wells and Arakamu-2A was seen. Reservoir studies to evaluate alternative improved recovery technologies, i.e. heat and/or solvent injection are scheduled for Q3 2025 in order to meet the permit requirements.
6. Appraisal & Exploration: The Company's portfolio of appraisal and exploration activities has been prioritised, and further maturation has been on hold while the Company has focused on what has become the Tariki Gas Storage Project. The appraisal and exploration projects will be restarted in priority through 2026 after external review and as funding becomes available. These opportunities include accessing undeveloped discovered hydrocarbons in the Waihapa-Ngaere and Tariki permits, and exploration potential within the Waihapa/Ngaere and Tariki Licences and the Copper Moki and Arakamu Permits.
7. Third Party services: The Group continues to provide a number of services to third parties including disposal of oil processing and transportation, deep well waste fluids disposal, and storage of LPG, all of which provide a helpful source of additional revenue.

Note: The abbreviation bbl means barrel of oil.

This section reviews activities and developments during the reporting period in respect of the Group's assets (see map

following).

The Group produces petroleum from Waihapa and Ngaere wells in the TWN Petroleum Mining Licences and from the Copper Moki wells in the Copper Moki Mining Permit.

Waihapa/Ngaere

The Waihapa Ngaere wells produce oil and gas from the fractured Oligocene Tikorangi Limestone at a depth of ~2,700m. The field has been on production since 1988. It has produced up to 18,000 bopd in the past and has produced ~24 mmstb cumulative oil. Reservoir modelling indicates that there was initially ~44 mmstb Oil-In-Place and after ~24 mmstb cumulative oil production (i.e. recovery factor of ~55%) there remains ~20 mmtb Oil-In-Place in the field. The recovery factor in reservoirs of this type, where the connected porosity is entirely within open fracture networks, can be more than 80%.

The current focus is on assessing the opportunities for restoring production from wells which have had mechanical issues. Two of these wells have been prioritised, i.e. Waihapa H1 and Waihapa-6A, and work is progressing to implement these opportunities in mid 2025, with actual timing depending on the selected intervention methodology, Long Lead delivery times, and budget. Waihapa-H1 is a horizontal penetration of the crestal Tikorangi that produced well for ~6 weeks until the section of the open-hole close to the shoe collapsed. The well unloads ~70 bbls of oil that has seeped through the collapse every week. Waihapa-6A is the highest oil cut well in the field but has a poorly performing gas lift completion.

Tariki

Updated reservoir static and dynamic modelling began in Q2 and planned to be completed in Q4. In the meantime, the results of earlier reservoir studies and the Tariki-5/5A well are being used to support the following opportunities.

1. Tariki formation - gas production

   Deloitte has provided an independent evaluation confirming there are proved and probable reserves within Tariki, primarily up-dip of wells Tariki-5A and Tariki-1A. The Tariki Joint Venture is planning activity(ies) to access this gas and confirm its presence and size from performance analyses. The presence of economically recoverable reserves within Tariki is not essential to a Gas Storage project but would be of material benefit to the Joint Venture and any storage participants.

2. Tariki formation - gas storage

   Reservoir modelling, the results from Tariki-5/5A, and the subsequent re-interpretation of the structure supports the position that more than 20 PJ of gas can reliably be stored in the Tariki formation, and at pressures less than the initial reservoir pressure of 4620 psia.

   The achievable injection and extraction rates are in the range of 25TJ/day from a single well (and up to 75TJ/day from 3 wells). Discussions with counterparties are ongoing and concept/feasibility studies commenced late in Q2 2025.

   Following the end of the quarter, the Company signed an MOU with Genesis that reinforces both parties' commitment to advance the Tariki Gas Storage Project. The MOU provides a clear and coordinated framework for completing the remaining technical assessments, negotiating commercial terms, and preparing the project for a final gas storage services agreement. Management views the MOU as a key step toward demonstrating commercial viability and de-risking the project's development pathway. The Company will continue to advance the required technical work and commercial discussions, with the objective of moving the project toward a final investment decision in 2026. NZEC believes Tariki remains a strategically significant opportunity given the increasing need for gas storage flexibility within New Zealand's energy sector.

   The Company plans to be in a position to commit to Gas Storage Development and/or Tariki Storage Asset Sale within 12 months.

3. Tikorangi formation

   The Tikorangi formation, from which over 24 mmstb oil has been produced at Waihapa/Ngaere, is present in the Tariki permit. Existing well Tariki-2C produced over 100,000 barrels of oil from the Tikorangi. The 2021 seismic data indicates the Tariki-2C well penetrated the Tikorangi formation approximately 200 metres down dip from the crest of the structure. Hydrocarbon shows were also seen in the Tikorangi section drilled near the crest in Tariki-5 and in the earlier 1996 Kupara-1 well, both drilled from the Tariki A site. Kupara-1/1A and Tariki-4A are being reviewed for possible use to access the Tikorangi in this vicinity.

   In addition, a restart of production from Tariki-2C is being investigated and this may be achievable in H1 2026.

4. Mt. Messenger formation

The 2021 3D seismic data identified AVO bright spots and anomalies in the Mt. Messenger formation. Oil has been produced from the Mt. Messenger formation in a number of fields within the onshore Taranaki Basin, including at Copper Moki to the south and Ngatoro to the north. Evaluation of these leads is continuing but is low priority.

Copper Moki-1: In Q3 2025 - 1,499 bbls Copper Moki-2: In Q3 2025 - 2,868 bbls.

A reservoir simulation study completed in Q1 2022 has provided technical assurance concerning the beneficial effects of water flood on the ultimate recovery in Copper Moki.

Water injection will be optimised once Copper Moki-1 is back on production in late 2025.

The PEP 51150 Appraisal Extension area includes the 2012 Arakamu-2 discovery well, which produced oil from the Miocene Moki and Mt. Messenger Formations when tested in Q1 2013. This well had oil produced to surface and is the target of the Appraisal Extension Work Program.

Reservoir studies to evaluate the use of improved recovery technologies in the Arakumu-2 reservoir are ongoing.

A number of third parties access services for oil, gas and water processing, handling and pipeline throughput and for storage of LPG.

See "NZEC's Business", "Property Review & Outlook" and "Results of Operations", for the activities to which this summary of quarterly results relates.

This section of the MD&A provides analysis of the Company's operations in respect of the third quarter of 2025 ("Three Month Period") compared to results achieved for the same period in 2024. See Operating & Financial Highlights and Property Review and Outlook for a summary of the second quarter 2025 operational events and activities.

Production is lower than achieved in 2024. This is the result of lower production in Waihapa/Ngaere.

Oil sales revenue is derived from oil sales volume, oil price and exchange rate. The realised price per barrel is based on the Brent crude oil price less contractual discounts and the exchange rate.

Processing revenue is lower as result of a decrease in water disposal services. Opportunities for increasing processing revenue are being pursued, including providing water disposal services for various third parties

Other Revenue relates mainly to LPG storage and interest.

Royalties paid are based on an ad valorem Crown royalty of 5% for Copper Moki and 10% (less allowable costs) for the TWN Petroleum Mining Licences.

Higher production has resulted in a lower production cost per bbl for three months. Workover costs have resulted in a higher production cost per bbl for the nine month period.

Depletion on oil and gas assets is calculated using the unit-of-production method i.e. the ratio of production during the respective periods to the total proved and probable reserves of oil and natural gas.

See further breakdown in Unaudited Condensed Consolidated Financial Statements - Note 13, General and Administrative Expenses.

Accretion reflects the expense associated with unwinding the discounting of the asset retirement obligations. Loan interest accrued, relates to accrual of interest on the convertible loan. See Unaudited Condensed Consolidated Interim Financial Statements - Note 8, Asset Retirement Obligations and note 10 Convertible Loan, for more information.

Abandonment provision movement arises from the change in estimate for the abandonment of wells which have previously been fully impaired.

Exchange differences arise from the translation of foreign operations and monetary items (largely based in NZD). The NZD exchange rate has weakened against the CAD over the three-month period to 30 September 2025.

The Company recognised the following additions in Oil and Gas assets during the three and nine month periods:

See details provided in Unaudited Condensed Consolidated Financial Statements - Note 16, Commitments.

See details provided in Unaudited Condensed Consolidated Financial Statements - Note 17, Permit Expenditure Plans.

As at 30 September 2025, the Company had cash and cash equivalents of $567,623 (31 December 2024: $1,131,605) and a working capital deficit of $(993,311) (31 December 2024: $(2,874,002)). Current liabilities include trade and other payables, the current portion of lease liabilities, and deferred revenue recorded in accordance with IFRS 15. The decrease in the working capital deficit during the period reflects the completion of the July 2025 private placement, the settlement and termination of the Company's outstanding convertible loan, and ongoing cost-management initiatives.

The Company continues to rely on external financing, operating cash flows from oil and gas production, and commercial arrangements to fund its ongoing operations and capital requirements. During the period, the Company completed a non-brokered private placement for gross proceeds of $2,718,640 and also completed the settlement and termination of the outstanding Arizona/Vliet loan through a combination of cash and the issuance of 1,000,000 common shares (see Note 10 to the Financial Statements). These transactions improved the Company's financial position but do not eliminate the need for additional future capital.

Included within trade and other payables is deferred revenue of $1,010,212, which includes a non-refundable payment of NZD $1,000,000 ($809,750) received from Genesis Energy under the Tariki Gas Storage Exclusivity and Assessment Agreement. This payment represents consideration received in advance for future deliverables under the agreement and is not repayable in cash. Although classified as a current liability under IFRS 15, the balance does not represent a cash outflow obligation and therefore does not increase the Company's short-term solvency risk.

The Company is pursuing alternatives to improve its financial capacity, including cash flows from oil and gas production, water disposal, potential credit facilities, strategic commercial arrangements, and other financing alternatives to support the advancement of the Tariki Gas Storage Project and other development activities. The timing and success of these initiatives depend on operational results, commodity prices, capital market conditions, and the Company's ability to secure partnerships and funding on acceptable terms.

The Company's ability to continue as a going concern is dependent on its capacity to raise additional capital, manage expenditures, generate positive operating cash flows, and advance its development plans. These factors, combined with the Company's working capital deficit and the need for continued financing, represent material uncertainties that may cast significant doubt on the Company's ability to continue as a going concern. Additional information is provided in Note 1 -Going Concern to the Unaudited Condensed Consolidated Financial Statements.

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Net Loss for the nine-month period was $1,886,151 (2024: Loss: $3,371,103). The more significant non-cash items included during the period were $769,179 in depreciation, depletion and accretion (2024: $616,972) and a change in working capital items of $289,366 (2024: $524,808).

The period also includes a non-cash gain on extinguishment of debt of $2,107,423 related to the settlement of the Arizona/Vliet convertible loan. This gain increased net income but did not impact cash flows and has been presented separately in the Statement of Comprehensive Loss in accordance with IFRS 9.

Investing activities were for the purchase of oil and gas properties.

See details provided in Unaudited Condensed Consolidated Interim Financial Statements - Note 14, Related Party Transactions.

The Company does not have any off-balance sheet arrangements.

The Company has used the same accounting policies and methods of computation as in the annual consolidated financial statements for the year ended 31 December 2024, refer Unaudited Condensed Consolidated Interim Financial Statements

- Note 2, Summary of Significant Accounting Policies.

NZEC uses certain terms for measurement within this MD&A which do not have standardized meanings prescribed by IFRS, and these measurements may differ from other companies' and accordingly may not be comparable to measures used by other companies. The term "field netback" is not a recognized measure under the applicable IFRSs. Management of the Company believes the measure is useful to provide shareholders and potential investors with additional information, in addition to profit and loss and cash flow from operating activities as defined by IFRS, for evaluating the Company's operating performance. Field netback is reconciled as follows to the Company's Consolidated Financial statements for the Three Month and Nine Month periods ended 30 September 2025 and 2024:

Exercise of Options - During the period the company issued 27,000 common shares at an exercise price of $0.84 for proceeds of $22,680.

On July 18, 2025, the Company closed a non-brokered private placement issuing 15,103,556 common shares at a price of $0.18 per share for gross proceeds of $2,718,640. The Company also issued:

• 1,666,667 common shares to Charlestown Energy Partners, LLC in settlement of $300,000 in outstanding indebtedness.

• 1,000,000 common shares to Vliet Financing B.V. in connection with the termination of the Company's outstanding

convertible loan.

The Company intends to use the net proceeds from the private placement to (i) advance the Tariki Gas Storage Project,

(ii) fund the cash settlement of $500,000 payable to Vliet under the Loan Termination Agreement, and (iii) provide general working capital.

The Group's authorized share capital consists of an unlimited number of voting common shares. As at 30 September 2025, the Group had 38,370,186 common shares 1,348,000 options and 56,383 broker warrants outstanding.

As of the date of this MD&A and following the closing of the private placement and shares for debt, the Group's share

capitalization included 38,370,186 common shares, 1,348,000 options and no warrants.

On November 9, 2025, 56,383 broker warrants had expired unexercised.

On November 26, 2025, after the end of the quarter, the Company entered into an MOU with Genesis to advance the Tariki Gas Storage Project. The MOU formalizes a framework under which the parties will collaborate exclusively on the technical studies, commercial negotiations, and project development milestones required to progress the project toward a definitive gas storage services agreement.

On October 31, 2025, the Company appointed Barry MacNeil as Chief Financial Officer and Giuseppe (Pino) Perone as Corporate Secretary and General Counsel of the Company. Mr. MacNeil and Mr. Perone succeed Ketan Chhima, who voluntarily stepped down from his roles as Chief Financial Officer and Corporate Secretary effective the same date.

Natural resources exploration and development involve a number of risks and uncertainties, many of which are beyond management's control. The Company's business is subject to the risks normally encountered in the oil and natural gas industry such as the marketability of, and prices for, oil and natural gas, competition with companies having greater resources, acquisition, exploration and production risks, need for capital, fluctuations in the market price and demand for oil and natural gas, the regulation of the oil and natural gas industry by various levels of government and public protests. The success of further development and exploration projects cannot be assured. In addition, the Company's operations are outside of Canada and are subject to risks arising from foreign exchange and foreign regulatory regimes. The Company works to mitigate these risks through such mechanisms as its project and opportunity evaluation processes, engagement with joint venture parties and employing appropriately skilled staff. In addition, insurance policies, consistent with industry practice, are maintained to protect against loss of assets, well blowouts and third-party liability. The Company is committed to operating in accordance with all applicable laws and regulations, safely and with due regard to the environment.

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 "will", "objective", "plan", "seek", "expect", "potential", "pursue", "subject to", "can", "could", "hopeful", "contingent", "anticipate", "look forward", and similar expressions are intended to identify forward-looking statements. These statements involve known and unknown risks, uncertainties and other factors which 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 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 and natural gas; expectations regarding the Company's ability 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 Company's ability to raise capital on appropriate terms, or at all; the ability of the Company's subsidiaries to obtain mining permits and access rights in respect of land and resource and environmental consents; the recoverability of the Company's crude oil, natural gas reserves and resources; and future capital expenditures to be made by the Company.

Actual results could differ materially from those anticipated in these forward-looking statements as a result of the risk factors set forth below and elsewhere in the document, such as the speculative nature of exploration, appraisal and development of oil and natural gas properties; uncertainties associated with estimating oil and natural gas resources; changes in the cost of operations, including costs of extracting and delivering oil and natural gas to market, affecting the 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 which prevent the Company from raising the funds necessary for exploration and development on acceptable terms or at all; global financial market events which 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 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. This document includes references to management's forecasts of future development, probability of success, production and cash flows from such operations, which represent management's best estimates at the time. 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 contained in this document, except in accordance with applicable securities laws.

The oil and gas reserves calculations and income 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 which can be estimated with a high degree of certainty to be recoverable. It is likely the actual remaining quantities recovered will exceed the estimated proved reserves. Probable Reserves are those additional reserves which are less certain to be recovered than proved reserves. It is equally likely the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.

Revenue projections presented are based in part on forecasts of market prices, current exchange rates, inflation, market demand and government policy which are subject to uncertainties and may in future differ materially from the forecasts above. Present values of future net revenues do not necessarily represent the fair market value of the reserves evaluated. The report also contains forward-looking statements including expectations of future production and capital expenditures. Information concerning reserves may also be deemed to be forward looking as estimates imply the reserves described can be profitably produced in the future. These statements are based on current expectations which 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. The resources reported are estimates only and there is no certainty any portion of the reported resources will be discovered and, if discovered, will be economically viable or technically feasible to produce.