MD&A (2025 Annual MDA NZEC)

(Expressed in Canadian Dollars)

This Management's Discussion and Analysis ("MD&A") is dated 3 July 2026, for the year ended 31 December 2025. It should be read in conjunction with the audited consolidated financial statements for the year ended 31 December 2025 of New Zealand Energy Corp. ("NZEC" or the "Group") as publicly filed on the System for Electronic Document Analysis and Retrieval Plus ("SEDAR+") website at https://www.sedarplus.ca.

NZEC reports in accordance with IFRS Accounting Standards ("IFRS") as issued by the International Accounting Standards Board ("IASB") and the associated consolidated 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 Group's website at https://www.newzealandenergy.com.

NZEC, through its subsidiaries (collectively "NZEC" or "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") (known collectively as the "TWN Licences"). L&M Energy Limited ("L&M") holds the remaining 50% in these licences.

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

NZEC 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. Copper Moki-1: Copper Moki-1 was successfully restored to production in Q3 of 2025. However, early in Q4 a pump failure occurred and the well has been shut in pending an intervention of restore production. Prior to the failure the Copper Moki-1 well was producing 45-55 bopd consistently.
2. Copper Moki-2: Copper Moki-2 produced consistently during Q4/2025 at a rate of 35-40 bopd with minor amounts of associated water.
3. Waihapa Production Station: Operations through Q4 focussed primarily on Waihapa-Ngaere and third-party oil, gas and water handling services, and production from Copper Moki.
4. Waihapa-Ngaere Production: The average rate (NZEC share) for Q4 2025 was 18 bopd (100% oil). This was a decrease from the 44 bopd NZEC share (100% oil) in Q3 2025. At quarter end the Waihapa and Ngaere Fields were producing 14 bopd. See "2026 Outlook" and "Property Review and Outlook".
5. Production: Aggregate production for Q4 2025 was 4,787 boe (100% oil) (average 52 boe per day); compared to Q3 2025 when production was 8,975 boe (98% oil) (average 92 boe per day).
6. Sales (oil): Oil sales for Q4 2025 of 8,172 bbl realised $665,676 (with an average oil sale price of $81.46 per bbl) compared to the Q3 2025 sales of 3,858 bbl which realised $330,772 (with an average oil sale price of

   $85.75 per bbl). Increased sales are a result of higher production and more lifting in the quarter.

7. Processing revenue: The TWN Assets (NZEC share) generated $103,218 from processing fees for Q4, compared to $93,790 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.
8. Tariki PML 38138: In November 2025 NZEC executed a non-binding Memorandum of Understanding ("MoU") with Genesis Energy Limited ("Genesis"). The MoU formalizes a framework that commits the parties to collaborate exclusively on a programme of technical studies, commercial negotiations, and project development milestones required to progress the Tariki Gas Storage Project to a final gas storage services agreement. This will then support moving towards a Final Investment Decision and ultimately project completion and commercial operations. Subsurface and engineering work to confirm the Tariki Gas Storage Project's parameters was conducted during Q4/2025 which included static and dynamic reservoir modelling to define the range of gas storage capacities, cushion-gas requirements, operating pressures, injection/withdrawal rates, and long-term storage behaviour. In addition, gas storage facility development concept studies are underway, including surface facilities, compression, pipelines and network connections, and operational configuration(s).

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 openly and collaboratively with regulators, other operators, local community businesses, communities and iwi to maintain safe operations and HSE performance.
2. Tariki: The primary focus for the Company in 2026 continues to be the maturation of the Tariki Field to a Gas Storage Project within the next 18-24 months. There are three workstreams associated with this work; technical (sub-surface and facility), commercial, and operational/implementation.

   1. The sub-surface technical work was largely completed in 2025 although injectivity and extraction testing is expected through H1/2026 to enhance the understanding of the gas storage facility parameters.

   2. Commercial discussions to develop the framework for providing storage capacity rights and usage fees have commenced. The Company is expected to continue to negotiate with Genesis Energy Limited ("Genesis") as per the MOU signed with Genesis in November 2025. Further, the Company is actively engaged in a submission to Kanoa (The Gas Security Fund) to secure funding for the development of the Tariki Gas Storage project.

   3. From an operational standpoint the Company plans to the flow both the Tariki 1A and Tariki 5A wells for extended production tests. The information gathered will be used to determine the remaining Gas-In-Place by performance and to advance the project toward a final investment decision, which is expected to occur during H2/2026.

3. Waihapa-Ngaere Production: Following the successful well perforations into the Ngaere-1, Ngaere-2 and Waihapa H1 Mt Messenger formations (the Miocene) during Q1 of 2026, following which production rates peaked at over 600 bopd (100%) cand continues through the balance of Q1 at more than 300 bopd (100%), it is expected that 2026 production from the Waihapa-Ngaere fields will remain elevated considerably above historic production rates. The Company has commenced multiple 'de-bottlenecking' activities to enable higher production rates of this new oil reservoir going forward. The facility constraints will be largely removed during H2/2026. Several additional well interventions are planned during 2H/2026 to both stabilize and enhance production in the field. These activities will include putting the wells on pump, further perforations, and investigating workovers on additional wells in the fields.
4. Copper Moki: Production at Copper Moki is expected to continue with the Copper Moki-2 well currently online. Work to re-instate Copper Moki-1 and fix the defective pump will commence in Q2/2026. It is expected that the Copper Moki-1 well will return to production at a similar rate (30-50 b/d) to what it was producing prior to the pump failure. Pressure support will be then be re-instated at Waitapu-2 o assist in maintaining reservoir pressure and improving oil recovery.
5. Appraisal & Exploration: The Company's portfolio of appraisal and exploration activities continues to be refined and prioritised with a renewed focus on the Miocene (Mt Messenger) targets across its existing acreage following on from the discovery of the Mt Messenger oil pool immediately NE of and below the Waihapa Production Station by wells Ngaere-1, Ngaere-2 and Waihapa-H1 in Q1/2026.. These opportunities include accessing undeveloped discovered hydrocarbons elsewhere in the Waihapa-Ngaere and Tariki permits, and exploration potential within the Waihapa/Ngaere and Tariki Licences, and the Copper Moki Permit.
6. Third Party services: The Group continues to provide a number of services to third parties including oil processing and transportation, deep well waste fluids disposal, produced water disposal by deep well injection, 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 Tariki, 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 ~2700m. 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 in excess of 80%.

The current focus is on assessing the opportunities for restoring production from wells which have had mechanical issues and also targeting the Mount Messenger bypassed oil play (see 2026 Outlook item 3.).

Mechanical issues; Two wells have been prioritised, i.e. Waihapa H1 and Waihapa-6A, and work is progressing to investigate production from the Tikorangi from these opportunities in H2/2026. Waihapa-H1 is a horizontal penetration of the crestal Tikorangi that produced well for ~6 weeks until the section of the open-hole at the shoe collapsed. The well has previously unloaded ~70 bbls of oil that has seeped through the collapse every week until 2024 when the collapsed section effectively sealed. Waihapa-6A is the highest oil cut well in the field but has a poorly performing gas lift completion due to known holes in the production tubing.

Bypassed pay; Subsequent to year-end 2025 NZEC successfully perforated three separate wells (Ngaere-1, Ngaere-2 and Waihapa H1) at the Miocene level (Mount Messenger sands). All three perforations were successuful and combined the wells produced at rates exceeding 300 bopd net. Further work will be completed in 2026 to enhance production and ensure long term stable flow rates from these wells. In addition opportunities to access the same reservoir sands in offset wells have been identified and will be developed through the balance of 2026. One of these is likely to become a water-injection well to maximise the Mt Messenger reservoir oil recovery.

Tariki

Following completion of the updated reservoir modelling and the signed MOU with Genesis, a number of opportunities are being progressed at the Tariki Field outside of the Tariki Gas Storage project including:

1. Tariki formation - gas production

   In H1 2026, strong initial production results occurred from both the Tariki 1A well and Tariki 5A well flow testing. The Tariki 1A well delivered a stabilized flow rate of approximately 3 mmcf/d over a 96-hour period and continued to flow gas naturally at a stabilized flow rate of approximately 1.5 mmcf/d over a subsequent 48- hour period until the well was shut-in for a pressure build-up and to move the test equipment to Tariki-1A. Tariki-1A was also successfully restrted to natural flow in mid Q2/2026 and has been flowing at rates of 2.2. to 2.5 mmscf/d and ~30 to 40 stb/.d condensate until the end of Q2/2026. This gas has been sold to market via the Matahio operated Cheal Production Station. Work is progressing at the Tariki-A site to eneable both wells to be on production simultaneously and is planned to be completed early in Q3/2026.

2. Mt Messenger formation

The 2021 Tariki 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 and the Waihapa-Ngaere Fields. Evaluation of these leads is continuing but is lower priority for the company across its Tariki assets.

Copper Moki-1: In Q4 2025 - restored in Q3, shut in early Q4 due to pump failure.

Copper Moki-2: In Q4 2025 - produced consistently during Q4.

Copper Moki 1 & 2 had a combined production of 3,122 for Q4 compared to 4,368 for Q3.

A reservoir simulation study completed in Q1 2022 provided technical assurance concerning the beneficial effects of water flood on the ultimate recovery in Copper Moki. Restarting the Waitapu-2 water injection is being considered pending the successful reactivation on Copper Moki-1 in mid 2026..

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.

Following the identification of a relevant new well technology, an application to the regulator to extend the permit duration and/or modify the work program is in progress.

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

As required under National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities, the Group commissioned Deloitte LLP to prepare year-end oil and gas reserve estimates and economic evaluations with an effective date of December 31, 2025.

NZEC's Proved + Probable ("2P") reserves, reflecting the Group's 100% interest in the Copper Moki Permit and its 50% interest in the Waihapa, Tariki and Ngaere PMLs, are estimated at 252,000 barrels of light/medium crude oil (417,100 barrels of oil equivalent, including associated gas) on a gross working-interest basis. Net of royalty obligations payable to the New Zealand Government, 2P reserves are estimated at 208,000 barrels of light/medium crude oil (355,000 barrels of oil equivalent). The after-tax net present value of future net revenue discounted at 10% is estimated at C$3.5 million using Deloitte December 31, 2025 forecast pricing and costs.

The change in 2P working-interest reserves from December 31, 2024 to December 31, 2025 reflects 2025 production of

13.4 Mstb of oil and 7.5 MMcf of gas, drilling extensions of 57.6 Mstb of oil and 22.8 MMcf of gas, technical revisions reducing reserves by 343.9 Mstb of oil and 2,572.6 MMcf of gas, and economic factors reducing reserves by 2.0 Mstb of oil and 23.5 MMcf of gas.

• Copper Moki - 2P working-interest reserves of 73 Mbbl of oil (73 Mboe); before-tax NPV discounted at 10% of C$(1.3) million.

• Waihapa/Ngaere - 2P working-interest reserves of 152 Mbbl of oil and 58 MMcf of gas (162 Mboe); before-tax NPV discounted at 10% of C$2.5 million.

• Tariki - 2P working-interest reserves of 27 Mbbl of oil and 932 MMcf of gas (182 Mboe); before-tax NPV discounted at 10% of C$3.2 million.

See the Group's Form 51-101F1 Statement of Reserves Data for full information on the Group reserves, and in particular, Part 4 Reconciliation of Changes in Reserves.

1. Mstb - Thousand barrels; MMcf - Million cubic feet; Mboe - Thousand barrels of oil equivalent using a conversion ratio of 6 Mcf:1 bbl. Barrels of oil equivalent (boe) may be misleading, particularly if used in isolation. The boe conversion ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

2. Gross reserves are the Group's working-interest share before the deduction of royalty obligations payable to the New Zealand Government.

3. Net reserves are the Group's working-interest share after deduction of royalty obligations payable to the New Zealand Government.

1. Net present value of future net revenue to NZEC after deduction of royalty obligations payable to the New Zealand Government. Numbers may not sum due to rounding.

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 Group's operations in respect of the fourth quarter of 2025 ("Three Month Period") and the full year ("Year Ended" or "Twelve Month Period") compared to results achieved for the same periods in 2024. See Operating & Financial Highlights and Property Review and Outlook for a summary of the fourth quarter and full year 2025 operational events and activities.

Production is higher than achieved in 2024. This is the result of higher production in Copper Moki and Waihapa/Ngaere.

Note. 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: Revenue for Q4 increased to a near average level for the quarter. 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.

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

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).

See further breakdown in the Consolidated Financial Statements - Note 16, General and Administrative Expenses and Finance expenses

Accretion reflects the expense associated with asset retirement obligations. See the Consolidated Financial Statements -Note 9, Asset Retirement Obligations and Note 16, General and Administration expenses and Finance expenses, for more information.

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

During 2025, the Group incurred additions to property, plant and equipment of $1,573,825, including $1,571,732 of additions to oil and gas properties and $2,093 of other property, plant and equipment. This compares with 2024 additions of $5,852,054, including $5,782,672 of oil and gas property additions. The 2025 additions primarily relate to oil and gas property development activities, while the significant 2024 additions related primarily to Tariki drilling and related development activity. See Note 7 to the Consolidated Financial Statements.

See details provided in the Consolidated Financial Statements - Note 20, Commitments.

The Group undertakes oil and gas production, development and exploration activities and has plans to complete certain exploration activities. Certain permits and licences held by the Group require various work obligations to be performed in order to maintain the permits or licences in good standing. The Group and, where relevant, its co-venturers in a permit, may apply to alter the work programs, request extensions, reject development costs, relinquish certain permits or farm out an interest in permits. The permit expenditure plans include those required to maintain its permits in good standing during the current permit term, prior to the Group committing to the next stage of the permit term, where additional expenditure would be required.

Maintaining the permits in good standing during the permit term is based on the fulfilment of the work program and is not based on a specific expenditure level. The anticipated cost of the works planned are set out below and relate to the following permits/licences (in the Taranaki Basin):

The Group continues to pursue options to improve its financial capacity, including cash flow from oil and gas production, credit facilities, commercial arrangements or other financing alternatives to enable it to undertake operations required to further exploit the permits and licences it holds and increase petroleum production. Its ability to improve its financial capacity, including its ability to maintain financing facilities it currently has in place, cannot be assured. See the Consolidated Financial Statements - Note 1, Going Concern.

Net loss for the year was ($7,100,770) (2024: Loss: $8,071,050). The more significant non-cash items included in the net loss during the year included $638,624 in depreciation and depletion (2024: $336,053), $5,804,261 in impairment (2024:

$2,956,000) and a change in working capital items of ($536,097) (2024: $1,175,114) all contributing to cash used in operating activities of ($2,974,441) (2024: Used $1,962,125).

Investing activity cash outflows were primarily for oil and gas property expenditures. Financing activity cash inflows primarily related to private placement offerings.

Refer to the Consolidated Financial Statements - Note 18, Related Party Transactions and Note 11, Loans.

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

The Group has used the same accounting policies and methods of computation as in the annual consolidated financial statements for the year ended 31 December 2024.

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 Group 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 Group's operating performance. Field netback is reconciled as follows to the Group's consolidated financial statements for the Three and Twelve Month periods ended 31 December 2025 and 2024:

Exercise of Options - During the year, 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, a related party through common shareholdings and directors, as settlement of the Company's outstanding term loan.

• 1,000,000 common shares to Vliet Financing B.V., a related party controlled by a director of the Company, in connection with the extinguishment of the Company's outstanding convertible loan.

On November 9, 2025, 56,383 Broker Warrants expired unexercised.

The Group's authorized share capital consists of an unlimited number of voting common shares. As at 31 December 2025, the Group had 38,370,187 common shares, 1,050,000 stock options and no broker warrants outstanding.

As of the date of this MD&A and following the closing of the private placement subsequent to year end, the Group's share capitalization included 55,870,187 common shares, 4,300,000 stock options and no broker warrants outstanding.

On 12 January, 2026, the Company entered into a Funding Agreement for Additional Projects under which a third party agreed to advance funds for the purpose of conducting workovers on various properties held under the Company's Waihapa Petroleum Mining Permit. Once various milestones have been met, the third party will earn a 75% royalty interest in the net receipts from the properties until the advanced funds are recovered, at which point the royalty will convert to 25% of net receipts in perpetuity.

On 9 February 2026, the Company closed a non-brokered private placement of 17,500,000 common shares at a price of

$0.20 per share for gross proceeds of $3,500,000. The net proceeds are intended to be used to fund the advancement of the Company's gas storage business and for general corporate purposes.

On 25 February 2026, the Company granted stock options to certain directors, officers and employees to acquire up to 3,250,000 common shares at an exercise price of $0.45 per share for a term of five years. The options vested immediately on grant.

Natural resources exploration and development involves a number of risks and uncertainties, many of which are beyond management's control. The Group'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 Group's operations are outside of Canada and are subject to risks arising from foreign exchange and foreign regulatory regimes. The Group 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 Group 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 Group 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 Group's oil and natural gas resources; supply and demand for oil and natural gas and the Group's ability to market crude oil and natural gas; expectations regarding the Group's ability to continually add to reserves and resources through acquisitions and development; the Group's ability to obtain qualified staff and equipment in a timely and cost-efficient manner; the Group's ability to raise capital on appropriate terms, or at all; the ability of the Group's subsidiaries to obtain mining permits and access rights in respect of land and resource and environmental consents; the recoverability of the Group's crude oil, natural gas reserves and resources; and future capital expenditures to be made by the Group.

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 Group 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 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 Group 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.