New Zealand Energy Announces Second Quarter Results and Operational Update

VANCOUVER, BRITISH COLUMBIA--(Marketwired - Aug. 29, 2013) - New Zealand Energy Corp. ("NZEC" or the "Company") (TSX VENTURE:NZ)(OTCQX:NZERF) has released the results of its second quarter ended June 30, 2013. Details of the Company's financial results are described in the Unaudited Consolidated Financial Statements and Management's Discussion and Analysis which, together with further details on each of the Company's projects, will be available on the Company's website at www.newzealandenergy.com and on SEDAR at www.sedar.com. All amounts are in Canadian dollars unless otherwise stated.

HIGHLIGHTS

Production and Development

Announced development plans for the Taranaki Basin until the end of 2014, forecasting exit production rates of 2,300 BOE/day (applying mid-case assumptions)1 48,752 barrels of oil ("bbl") produced and 49,204 bbl sold during six-month period, generating pre-tax oil sales of $5.3 million Positive net cash flow from petroleum operations during six-month period of approximately $1.7 million Average field netback during six-month period of $35.10/bbl Substantial reduction to direct production costs at Copper Moki site during June 2013 as a result of the installation of permanent production facilities 56,717 bbl produced and 59,623 bbl sold year to date (August 26, 2013), generating pre-tax oil sales of approximately $6.4 million Cumulative production of 264,938 bbl since commencement of production, generating pre-tax oil sales (including sales from pre-production testing) of approximately $28.5 million Initiated installation of artificial lift at Waitapu-2 well Received results of RPS reservoir study, providing the Company with a better understanding of Mt. Messenger reservoir characteristics and declines Lodged an application for a petroleum mining permit that will encompass the Company's Copper Moki, Waitapu, Arakamu and Wairere sites in the Eltham Permit (18.73 km2)

Acquisition of TWN Licences and TWN Assets from Origin Energy

Amended deal terms related to the acquisition, resulting in a simplified sale and reduced purchase price Entered into a binding letter agreement with L&M Energy ("L&M") to explore and operate the TWN Licences and TWN Assets, securing $18.25 million from L&M to purchase a 50% interest in the assets Obtained an extension to secure remaining required funds ($9.25 million) until September 30, 2013 Settled the HSBC operating line of credit Announced 2P reserves of 1.07 million BOE attributed to the TWN Licences (NZEC's interest)2 1 Barrels of oil equivalent (BOE) may be misleading, particularly if used in isolation. The boe conversion ratio of 6 Mcf : 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. See Forward-looking Information for assumptions associated with production forecast.2 Reserves associated with the TWN Licences, as previously announced in an NZEC press release on June 17, 2013, will not be attributable to NZEC until the Company has completed the acquisition of assets from Origin and filed an updated Reserve report under NI 51-101. NZEC's shares of the TWN Reserves is 50%, as per the terms of the TWN Arrangement with L&M.

FINANCIAL SNAPSHOT

Six months
ended
June 30, 2013Three months
ended
June 30, 2013Six months
ended
June 30, 2012Three months
ended
June 30, 2012Total comprehensive income (loss)(Loss) earnings per share - basic and diluted

Note: The abbreviation bbl means barrel or barrels of oil.

Six-month Operating Results

During the six-month period ended June 30, 2013, the Company produced 48,752 barrels of oil and sold 49,204 barrels for total oil sales of $5,277,878, with an average oil sale price of $107.27 per barrel. Total recorded production revenue, net of a 5% royalty payable to the New Zealand Government (an average of $4.94 per barrel), was $5,034,958. Production costs during the six-month period ended June 30, 2013 totalled $3,307,876, or an average of $67.23 per barrel, generating an average field netback of $35.10 per barrel during the period. NZEC calculates the netback as the oil sale price less fixed and variable production costs and a 5% royalty. The notable reduction in netback during the six-month period ended June 30, 2013, is predominantly the result of decreased oil production. As previously announced, the Company had shut in the Waitapu-2 well during May 2013 in order to gather critical data for the Mt. Messenger reservoir study (see Reservoir Study) and to evaluate and install artificial lift.

The Company undertook a number of reservoir and production tests with the objective of optimizing oil production, and these tests have added to production costs. During the six-month period ended June 30, 2013, fixed production costs represented approximately 84% of total production costs. Installation of the Copper Moki surface facilities was completed in May and, as expected, this resulted in a reduction in production costs for the Copper Moki site during the month of June 2013, as discussed under June Operating Results - Copper Moki Site Only. Although shutting in the Waitapu-2 well in May 2013 reduced some of the fixed operating costs, the Company continues to incur costs on that site.

Three-month Operating Results

During the three-month period ended June 30, 2013, the Company produced 18,573 barrels of oil and sold 21,958 barrels for total oil sales of $2,216,815, with an average oil sale price of $100.96 per barrel. Total recorded production revenue, net of a 5% royalty payable to the New Zealand Government (an average of $4.88 per barrel), was $2,109,700. Production costs during the three-month period ended June 30, 2013 totalled $1,616,471, or an average of $73.62 per barrel, generating an average field netback of $22.46 per barrel during the period.

As demonstrated in Six-month Operating Results, reduced production following the shut-in of Waitapu-2 greatly impacted the three-month netback results, although this was partially offset by reduced production costs related to the Copper Moki site following the commissioning of surface facilities (see June Operating Results - Copper Moki Site Only).

June Operating Results - Copper Moki Site Only

The Company is starting to see the positive effect on production costs of installation of surface facilities as reflected in reduced production costs related to the Copper Moki site during June 2013. Following the commissioning of surface facilities on the Copper Moki site in May 2013, the Company incurred direct production costs of approximately $165,000 to produce 4,740 barrels of oil, which amounted to $34.81 per barrel during the month of June 2013, a significantly lower production cost per barrel than the quarterly average of $73.62 per barrel. This is also comparable to management's estimate of well-site production costs of NZ$40 per barrel as assumed in management's forecast of cash flows from operations referenced in the Company's August 6, 2013 press release.

Considering the proportion of fixed production costs reported for the quarter ended June 30, 2013, as well as netbacks reported in prior periods, the direct production costs per barrel is reflective of the economies of scale. Thus, further savings should arise from higher production levels from future developments.

At August 26, 2013, the Company had an estimated $4.6 million in net working capital.

ACQUISITION OF INTEREST IN UPSTREAM AND MIDSTREAM ASSETS

As previously announced, the Company has entered into an agreement with Origin Energy Resources NZ (TAWN) Limited ("Origin") to acquire three (net) petroleum mining licences in the Taranaki Basin totalling 23,049 acres (93.3 km2) - the Tariki, Waihapa and Ngaere Licences (the "TWN Licences") - as well as the Waihapa Production Station and associated gathering and sales infrastructure (the "TWN Assets"). On August 12, the Company announced that Origin had agreed to extend the deadline for satisfying the financing condition precedent for the acquisition from August 14, 2013 to September 30, 2013, and to extend the deadline for obtaining the required government approvals from September 13, 2013 to October 14, 2013. In exchange, the Company agreed to increase its acquisition deposit to $6 million.

L&M Letter Agreement to Form Joint Arrangement

On July 30, 2013, the Company announced that it had entered into a binding agreement (the "L&M Letter Agreement") with L&M Energy ("L&M") to form a 50/50 joint arrangement to explore, develop and operate the TWN Licences and the TWN Assets. Once the joint arrangement is completed, the Company and L&M will each own 50% of the TWN Licences and will also hold a 50% interest in the TWN Assets (the "TWN Joint Arrangement"). The reserves and resources estimated for the TWN Licences, as announced on June 17, 2013, will be attributable to NZEC on a 50% basis upon closing of the acquisition and the TWN Joint Arrangement, and filing of an updated reserve report.

Under the terms of the L&M Letter Agreement, L&M will contribute $18.25 million towards the approximately $33.5 million purchase consideration agreed to under the Origin Sale and Purchase Agreement, in order to obtain a 50% interest in the TWN Joint Arrangement. L&M will also contribute 50% of all future development and operating expenditures.

The Company will become the operator of the TWN Joint Arrangement, and decisions regarding exploration, development and operations of the TWN Joint Arrangement will be made by management committees with equal representation from both the Company and L&M.

The Company will be responsible for funding the $15.25 million balance of the $33.5 million purchase consideration agreed to under the Origin Sale and Purchase Agreement. The Company has paid a $6 million acquisition deposit to Origin, leaving $9.25 million to be funded to complete the acquisition.

The concurrent completion of the acquisition and the L&M Letter Agreement is subject to the Company placing the remainder of the purchase price into an escrow account by September 30, 2013, Origin and Contact consenting to L&M becoming a party to the definitive agreements, as well as receiving the relevant government approvals.

PROPERTY REVIEW

Taranaki Basin

The Taranaki Basin is situated on the west coast of the North Island and is currently New Zealand's only oil and gas producing basin, with total production of approximately 130,000 barrels of oil equivalent per day ("boe/d") from 18 fields. Within the Taranaki Basin, NZEC holds a 100% interest in the Eltham Permit, a 65% interest in the Alton Permit in joint arrangement with L&M, and a 60% interest in the Manaia Permit in joint arrangement with New Zealand Oil & Gas ("NZOG"). The Eltham Permit covers approximately 93,166 acres (377 km2) of which approximately 31,877 acres (129 km2) are offshore in shallow water. The Alton Permit covers approximately 119,204 onshore acres (482 km2). The Manaia Permit covers approximately 27,426 onshore acres (111 km2) and was granted to NZEC and NZOG in December 2012 as part of the annual New Zealand block offer for exploration permits.

NZEC also expects to acquire 50% of the three TWN Licences and to hold a 50% interest in the TWN Assets upon completion of the acquisition of assets from Origin, as outlined in Acquisition of Interest in Upstream and Midstream Assets.

Production

At the date of this MD&A, three of the Company's four commercially producing wells are in active production. The Waitapu-2 well is currently shut in and installation of artificial lift and surface facilities is underway. During the quarter, the Company also temporarily shut-in its Copper Moki-3 well to replace the down-hole pump, which seized as a result of fines settling in the pump during commissioning of the Copper Moki surface facilities. The wells are producing light oil that is trucked to the Shell-operated Omata Tank Farm and sold at Brent pricing. Cumulatively, as of the date of this report, the Company has produced approximately 264,938 barrels of oil, with cumulative pre-tax oil sales of approximately $28.5 million, including sales from oil produced during testing (net results of operations are discussed under Results of Operations). The wells have consistently produced between 123 bbl/d and 162 bbl/d since July 1, 2013, with an average production rate of 144 bbl/d, indicating that oil production from the Copper Moki wells appears to have stabilized. Over 26 production days in August 2013, the wells have collectively produced oil at an average rate of 139 bbl/d and extracted gas at an average rate of 490 mcf/d. The Company is not yet generating cash flows from extracted gas.

Copper Moki-1 has been producing since December 10, 2011, Copper Moki-2 since April 1, 2012 and Copper Moki-3 since July 2, 2012. All three wells produce ~41° API oil from the Mt. Messenger formation and flowed from natural reservoir pressure until October 2012, when NZEC installed artificial lift (pump jacks) to stabilize production rates.

Waitapu-2 commenced production on December 20, 2012 and was shut-in in May 2013 as described above. The well produces ~40° API oil from the Mt. Messenger formation and flowed from natural reservoir pressure until shut-in. Installation of artificial lift is currently underway. In addition to installation of artificial lift, during the period the Company ran down-hole gauges into Waitapu-2 that measures the bottom hole temperature and pressure of the reservoir. These data were critical to the recently completed Mt. Messenger reservoir study (see below).

Reservoir Study

Production declines from the Copper Moki wells have been greater than expected and this prompted the Company to initiate an independent reservoir study through RPS Group PLC, a world leader in well evaluation. The study provided the Company with a better understanding of reservoir characteristics and declines, based on data from Waitapu-2, the three Copper Moki wells, and other Mt. Messenger wells in the region.

The RPS study concluded that declines are not related to wax buildup or mechanical issues. Information from the study and from a proprietary database merging five 3D seismic surveys has allowed the Company to refine its Mt. Messenger exploitation strategy, which includes:

Choosing optimally sized targets based on interpretation of the merged 3D dataset, Reducing costs by drilling multiple wells from each pad, and Prioritization of targets close to the Waihapa Production Station to expedite tie-in.

The Mt. Messenger formation remains an integral part of the Company's development plans, as described in the Outlook section. These development plans include the Horoi-1 well, which is expected to be drilled later this year on the Alton Permit.

Application for Eltham Petroleum Mining Permit

During the quarter ended June 30, 2013, the Company lodged an application for a petroleum mining permit that will have an initial duration of 15 years. This petroleum mining permit will cover 18.73 km2 within the area currently included under the Company's Eltham Permit and includes all sites on which the Company had previously drilled its ten exploration wells (i.e. the Copper Moki site, Waitapu site, Arakamu site, and the Wairere site). A successful application for the petroleum mining permit will extend the duration that the Company is able to operate within the area covered by the permit, and will also reduce the surface area within the existing Eltham Permit that will be subject to relinquishment in September 2013 when the Eltham Permit is due for extension.

East Coast Basin

The East Coast Basin of New Zealand's North Island hosts two prospective oil shale formations, the Waipawa and Whangai, which are the source of more than 300 oil and gas seeps. Within the East Coast Basin, NZEC holds a 100% interest in the Castlepoint Permit, which covers approximately 551,042 onshore acres (2,230 km2), and a 100% interest in the Ranui Permit, which covers approximately 223,087 onshore acres (903 km2) and is adjacent to the Castlepoint Permit. NZEC is considering relinquishing the Ranui Permit but has not yet made a definitive decision in this regard. On September 3, 2010, NZEC applied to the Minister of Energy to obtain a 100% interest in the East Cape Permit. The application is uncontested and the Company expects the East Cape Permit to be granted to NZEC upon completion of New Zealand Petroleum & Minerals' ("NZPAM") review of the application. The East Cape Permit covers approximately 1,067,495 onshore acres (4,320 km2) on the northeast tip of the North Island. In addition, NZEC has entered into a binding agreement with Westech to acquire 80% ownership and become operator of the Wairoa Permit, which covers approximately 267,862 onshore acres (1,084 km2) south of the East Cape Permit. Preliminary approval of transfer of ownership was obtained from NZPAM on December 20, 2012 and formation of a joint arrangement with Westech is subject to final NZPAM approval.

The Company has completed the coring of two test holes on the Castlepoint Permit. The Orui (125 metres total depth) and Te Mai (195 metres total depth) collected core data across the Waipawa and Whangai shales. NZEC also completed a test hole on the Ranui Permit. Ranui-2 was drilled to 1,440 metres, coring the Whangai shale across several intervals. In Q2-2012, NZEC completed 70 line km of 2D seismic data across the Castlepoint and Ranui permits to further its technical understanding of the area and identify targets for exploration in 2013.

The Wairoa Permit has been actively explored for many years, with extensive 2D seismic data across the permit and log data from more than 15 wells drilled on the property. Historical exploration focused on the conventional Miocene sands. NZEC's technical team has identified conventional opportunities as well as potential in the unconventional oil shales that underlie the property. NZEC's team knows the property well and provided extensive consulting services (through the consulting company Ian R Brown Associates) to previous permit holders, assisting with seismic acquisition and interpretation, well-site geology and regional prospectivity evaluation. In addition, NZEC's team assisted with permitting and land access agreements and worked extensively with local district council, local service providers, land owners and iwi groups, allowing the team to establish an excellent relationship with local communities. During Q1-2013 the Company completed a 50 km 2D seismic program on the property, the results of which are currently being processed and reviewed and will help to identify exploration targets on the permit.

OUTLOOK

On August 6, 2013, the Company announced its updated plans to develop its oil and gas assets in the Taranaki Basin, including its plans for exploration and development of the TWN Licences and integration of the TWN Assets. Completing the acquisition of the TWN Licences and TWN Assets will be transformative for NZEC, resulting in a fully integrated upstream/midstream company with the cash flow, infrastructure and inventory to support long-term growth.

Taranaki Basin

Owning 50% of the TWN Assets and TWN Licences will allow NZEC to optimize development of its existing permits. The gas supply that NZEC has identified to reactivate gas lift and production from existing Tikorangi wells on the TWN Licences will provide the blending gas required to deliver NZEC's Copper Moki gas to market, bringing additional cash flow to NZEC from the Copper Moki wells. The Company also plans to build a pipeline to connect the Waitapu-2 well to the Copper Moki site and is currently evaluating the economics of this initiative. The pipeline would effectively tie in the Waitapu gas production (and associated liquefied petroleum gas or "LPG") into the Waihapa Production Station via the Copper Moki pipeline.

As NZEC continues to explore the Eltham and Alton permits, the Company will focus on drill targets that are close to the Waihapa Production Station and associated pipelines, allowing for rapid and cost effective tie-in of both oil and gas production.

NZEC has prepared a detailed financial and production model outlining the exploration and development program for its Taranaki assets that has allowed the Company to forecast the impact of those activities on its production and cash flow. NZEC's activities planned to the end of 2014 in the Taranaki Basin are outlined in the table below:

PLANNED POST ACQUISITION WORK PROGRAMProduction Impact
(Exit 2014)Tikorangi well reactivations
-- Reactivate six existing Tikorangi wells with gas lift
-- High volume lift installation on two initial wellsIncluded in 2014
production belowMt. Messenger development
-- Waitapu artificial lift and tie-inTwo Mt. Messenger uphole completions in existing wells
-- Horoi exploration well (including surface infrastructure)Included in 2014
production belowTikorangi Well Reactivations
-- Increase water handling capacity at Waihapa Production Station
-- High volume lift installation on four remaining wellsNew Tikorangi wells
-- Drill two new Tikorangi wellsMt. Messenger development
-- Three new Mt. Messenger wells (including surface infrastructure)Kapuni development (cost to be funded by new JV partner)
-- Two new Kapuni wellsSeismic acquisition, G&G studies and OtherExit 2,300 boe/day
(including production from
existing wells)

The forecast on which the above information is based reflects management's mid-case production assumptions, while capital costs indicate management's net share of the capital cost to be incurred by the TWN Joint Arrangement.

Development and operating costs in the first 12 months following the date of this report are to be funded initially by existing working capital and cash flows from production. However, in order to carry out all of the planned development activities, the Company is considering a number of options to increase its financial capacity. These options include increasing cash flow from oil production, additional joint arrangements, commercial arrangements or other financing alternatives. For the assumptions related to the production forecast, refer to the full Management's Discussion & Analysis filed on the Company's website and on SEDAR.

East Coast Basin

NZEC has drilled two stratigraphic holes on its 100% working interest Castlepoint Permit and one stratigraphic hole on its 100% working interest Ranui Permit. These three stratigraphic test wells have advanced NZEC's understanding of the Waipawa and Whangai formations. A review of the geochemical and physical properties of the two shale packages, coupled with information from seismic data, has focused NZEC's exploration strategy for the area. The Company is actively seeking a joint venture partner for its East Coast permits. The Company is currently considering its plans for the Ranui Permit, including possible relinquishment of the permit.

NZEC has applied to NZPAM to extend the deadline for drilling the exploration well on the Castlepoint Permit to Q2-2014, while the Company continues to work towards obtaining the requisite consents and land access agreements for the Castlepoint Permit drill locations. The Company has met regularly with local communities to discuss its exploration plans.

NZEC completed a 50-km 2D seismic survey on the Wairoa Permit in Q2-2013 and is currently processing the data. The Company will finalize its exploration plans for the permit after reviewing all of the seismic and well log data.

The Company's application for the East Cape Permit is uncontested and NZEC expects the permit to be granted upon completion of NZPAM's review of the application.

SUMMARY OF QUARTERLY RESULTS

Exploration and evaluation assetsTotal comprehensive income (loss)Basic (loss) earnings per shareDiluted (loss) earnings per shareExploration and evaluation assetsTotal comprehensive income (loss)Basic (loss) earnings per shareDiluted (loss) earnings per share

On behalf of the Board of Directors

John Proust, Chief Executive Officer & Director

About New Zealand Energy Corp.

NZEC is an oil and natural gas company engaged in the production, development and exploration of petroleum and natural gas assets in New Zealand. NZEC's property portfolio collectively covers approximately 2.25 million acres (including permits and acquisitions pending) of conventional and unconventional prospects in the Taranaki Basin and East Coast Basin of New Zealand's North Island. The Company's management team has extensive experience exploring and developing oil and natural gas fields in New Zealand and Canada. NZEC plans to add shareholder value by executing a technically disciplined exploration and development program focused on the onshore and offshore oil and natural gas resources in the politically and fiscally stable country of New Zealand. NZEC is listed on the TSX Venture Exchange under the symbol "NZ" and on the OTCQX International under the symbol "NZERF". More information is available at www.newzealandenergy.com or by emailing info@newzealandenergy.com.

Neither the TSX Venture Exchange nor its Regulation Services Provider (as such term is defined in the policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this release.

FORWARD-LOOKING INFORMATION

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", "intend", "objective", "become", "transforming", "potential", "continuing", "pursue", "subject to", "look forward", "unlocking" 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 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 to obtain the necessary approvals and secure the necessary financing to conclude the acquisition of assets from Origin on schedule, or at all; the ability of the Company to obtain the necessary approvals to conclude the TWN Joint Arrangement on schedule, or at all; the ability of the Company's subsidiaries to obtain mining permits and access rights in respect of land and resource and environmental consents; the recoverability of the Company's crude oil, natural gas reserves and resources; and future capital expenditures to be made by the Company.

Actual results could differ materially from those anticipated in these forward-looking statements as a result of the risk factors set forth below and elsewhere in the document, such as the speculative nature of exploration, appraisal and development of oil and natural gas properties; uncertainties associated with estimating oil and natural gas resources; changes in the cost of operations, including costs of extracting and delivering oil and natural gas to market, that affect potential profitability of oil and natural gas exploration; operating hazards and risks inherent in oil and natural gas operations; volatility in market prices for oil and natural gas; market conditions that prevent the Company from raising the funds necessary for exploration and development on acceptable terms or at all; global financial market events that cause significant volatility in commodity prices; unexpected costs or liabilities for environmental matters; competition for, among other things, capital, acquisitions of resources, skilled personnel, and access to equipment and services required for exploration, development and production; changes in exchange rates, laws of New Zealand or laws of Canada affecting foreign trade, taxation and investment; failure to realize the anticipated benefits of acquisitions; and other factors. Readers are cautioned that the foregoing list of factors is not exhaustive. Statements relating to "reserves and resources" are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the resources described can be profitably produced in the future. This document includes references to management's forecasts of future development, production and cash flows from such operations. The major assumptions applied by management are outlined in the MD&A, published on the Company's website and on SEDAR. 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.

CAUTIONARY NOTE REGARDING RESERVE ESTIMATES

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 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. 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 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.

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