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• 5. Gas

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• 5.1 Summary of Key Issues: Gas Sector
  • 5.1.1 Gas as a Fuel Supply
• 5.2 Exploration and Production
  • 5.2.1 Background
  • 5.2.2 Gas Reserves and Production
  • 5.2.3 Key Commercial Interests in the Upstream Gas Sector
  • 5.2.4 Description of Key Production Assets
  • 5.2.5 Key Issues: Upstream Gas Assets
• 5.3 Transmission Infrastructure
  • a) NGC Transmission System
  • b) Maui Pipeline System
• 5.4 Distribution Infrastructure
  • a) Vector
  • b) Powerco
  • c) NGC
  • d) Wanganui Gas
• 5.5 Emissions
• 5.6 Demand/Supply Gaps
• 5.7 Gas Supply Pricing
• 5.8 Gas Investment Plans
  • 5.8.1 Exploration and Production
  • 5.8.2 Gas Processing Infrastructure
  • 5.8.3 Transmission
  • 5.8.4 Distribution
• 5.9 Demand Projections
  • 5.9.1 Pricing Impact
• 5.10 Gas Industry Development and Governance

Gas infrastructure is considered under the headings of Exploration and Production, Transmission and Distribution. In summary, at present New Zealand's gas infrastructure is in good condition and has excess capacity.

The key issues facing the Gas sector are not with current but rather with future production.

5.1 Summary of Key Issues: Gas Sector

1. Decreasing Gas Supplies
   Availability of gas is the key driver of the sector. At present, there is insufficient gas to meet demand requirements, with Methanex unable to secure sufficient gas to maintain full production at its methanol sites. In the medium term, shortages look likely to continue, particularly given the lead time between exploration and bringing any gas discoveries into production. In the longer term, supply is still likely to be tight, but the impact of further exploration and/or the importation of LNG is likely to ease shortfalls.
2. Demand patterns, particularly in the petrochemical and generation sectors, are already changing in response to gas shortages and price increases. As noted previously, Methanex has significantly reduced throughput at its methanol plants. In addition, gas fired generation at Huntly has reduced, and in medium term, new gas fired generation (such as Otahuhu C) has been put on hold.
3. Potential stranding of assets (particularly downstream assets) if gas volumes reduce significantly.
4. Price uncertainty and significant price increases in the post-Maui era.
5. In addition to a lack of gas supply, potential barriers to further development of the gas sector include:
   • Regulation
     The RMA can pose significant cost and timing issues on such projects, significantly reducing the industry's ability to respond rapidly to opportunities or changing demands (although we understand that the development of the Rimu field was not hindered by RMA requirements). In general however, the RMA is considered to be more of an inconvenience than a potential preventer of new developments.
   • Utility corridors are becoming crowded and authorities are restricting access to these, making it more difficult for distribution companies to access their system assets, or further develop their networks. Furthermore, there appears to be a lack of consistency of practices between roading control authorities governing corridor access. This is also an issue for urban electricity. We understand that progress has been made on addressing these issues through the New Zealand Utilities Advisory Group ("NZUAG").

5.1.1 Gas as a Fuel Supply

Gas is clearly a non-renewable, combustion fuel. As such, supplies cannot be replaced and pollution arises from its use. However, gas generally produces lower levels of pollution than other thermal generation fuel sources (both in terms of noxious pollutants and CO₂ per unit of energy produced). Whereas coal produces around 91kt CO₂ per PJ, gas (from Maui for example) produces almost half of this amount at 52kt CO₂ per PJ. Depending on the technology used, gas is generally a more efficient fuel. For example, coal fired thermal generation is generally has a transformation efficiency in the region of 35%, compared to modern combined cycle gas turbines which may have efficiency factors of greater than 50%.

Prima facie, this suggests that, in terms of its emissions impact and fuel-efficiency, gas would be strongly preferred to coal. Utilisation of gas as a direct fuel domestically or in industry is also more efficient than most electricity generation, given the transformation loss that arises in electricity generation and transmission.

However, the decreasing supply of gas suggests that it will not be possible to increase in the medium to long term the proportion of New Zealand's energy consumption produced from domestic gas sources. It may be possible to import gas in the form of LNG. However, this is likely to be expensive compared to other energy sources, and introduces a reliance on overseas fuel supplies.

5.2 Exploration and Production

5.2.1 Background

The Taranaki Basin has been and continues to be the focus of exploration and production. The first oil well was drilled in 1865 near Moturoa. In 1959, successful drilling of Kapuni-1 by the Shell-BP-Todd consortium kick-started widespread commercial development of the sector. Kapuni began production in 1970.

In 1969, the Shell-BP-Todd consortium discovered gas in the Maui gas-condensate field, which at the time of its discovery was one of the largest gas fields in the world. Maui was eight times the size of Kapuni, and a market for the off-take was required. The Government stepped in to secure 50% of the off-take, partly to secure fuel for increased electricity demand.

Over 70% of New Zealand's hydrocarbon production currently comes from the Kapuni and Maui fields.

The Government also set up the Petroleum Corporation of New Zealand (Petrocorp) to encourage additional exploration in New Zealand. Petrocorp undertook an aggressive exploration programme in the late 1970s, which resulted in the discovery of the McKee oil field in 1979, and the Tariki, Ahuroa, Waihapa and Ngaere fields ("the TAWN fields") in the mid-late 1980s.

Offshore, drilling of the Kupe South-1 well in 1996 identified similar geological structural trends as the Kapuni Field. Kupe reserves are believed to be 16 million barrels ("mmbbl") of oil and 264 billion cubic feet ("bcf") of gas. In addition, oil was discovered in the Maui-B Field in 1993, and by the drilling of the Maari-1 well in 1998. Recoverable reserves have been assessed between 20 - 60 million barrels of oil equivalent ("mmboe").

Gas was also discovered in the Mangahewa Field in 1996 and more recently Rimu in 1999.

The Pohokura gas-condensate field was discovered offshore in 2000. At the time of its discovery estimates were made that this field could contain 1 trillion cubic feet ("tcf") of gas. This has subsequently been reassessed at 700-750 bcf.

5.2.2 Gas Reserves and Production

Table 8 below sets out current hydrocarbon reserves.

Notes:
* Reserves are estimated as "proven and probable" or P50 by the field operators.
** Excludes LPG for Kapuni, Maui, Tariki/Ahuroa and Rimu/Kauri and also reinjection for Kapuni. The figures here differ from those in Table E.2a in that own use, losses and flared are included here.
*** Includes information for Goldie well.

Source MEDEnergy Data File July 2003:

* As at 30 June 2002, total reserves were disclosed as 964 bcf. This has subsequently been revised to 700 - 750 bcf

Source: Crown Minerals

Figure 34 below illustrates historical gas production.

Figure 34: Gas Production

Source: MEDEnergy Data File July 2003

5.2.3 Key Commercial Interests in the Upstream Gas Sector

The key commercial interests in the upstream gas sector are:

• Shell Petroleum Mining Limited ("Shell") - 48% of Pohokura; 77.5% Maui
• Todd Energy ("Todd") - 26% of Pohokura; 100% of McKee and Mangahewa; 12.5% Maui
• OMV - 26% of Pohokura; 10% of Maui.
• Swift Energy New Zealand Limited ("Swift") - 100% of Rimu/Kauri; 100% of TAWN
• Greymouth Petroleum - 100% Kaimiro; 98% Moturoa
• Shell Todd Oil Services "STOS" - developer of the Pohokura gas field on behalf of the Pohokura joint venture; operator of the McKee/Mangahewa field for Todd; operator of the Omata Tank Farm for Shell; operator of the Kapuni field; operator of the Maui off-shore and on-shore facilities.

5.2.4 Description of Key Production Assets

a) Maui

Maui A Platform

• commissioned in 1979
• receives gas and condensate from 14 production wells
• after separation, gas and liquids are piped 33km to the onshore Oaonui plant

Maui B Platform

• built in early 1990s
• acts as a satellite platform 15km from Maui A, receives gas from four oil wells and six gas wells
• connected to Maui A by a single multi-phase pipeline which takes liquid and gases to the Maui A platform

Floating Production, Storage and Offloading Facility (FPSO)

• located close to Maui B and processes and stores crude from Maui B, to be offloaded to tankers
• gas is compressed and piped back to the Maui B platform before being piped to shore
• once oil storage capacity is reached, oil is released to shuttle tankers, taken to Marsden Point or exported.

Oaonui Production Station

• onshore production station built to process Maui gas and condensate
• gas and liquids separated into pipeline quality gas, LPG and stabilised condensate
• has been modified over time with further refrigeration being added in the 1990s
• decline in Maui production has freed up capacity in this plant
• processing capacity 700mmcfd (or in excess of 200PJ per annum)
• has been running at around 40% to 45% recently, with lower throughput during high hydro generation periods

b) Kapuni

The Kapuni field was discovered in 1959.

Kapuni Production Station

• owned by Shell and Todd
• well-stream from 14 wells is separated at well sites into gas and condensate, taken by gathering lines to the Kapuni production station
• most of this gas is then passed on to the Kapuni Gas Treatment Station

Kapuni Gas Treatment Station

• owned by NGC
• commissioned in 1970 due to the high CO₂ content of the Kapuni gas (approximately 42%)
• comprises three trains (two currently operational, one being refurbished)
• plant has been upgraded continuously with two of the processing trains refurbished in 1995, and cogeneration plant and north system expansion projects completed in 1998.

c) McKee

• owned by Todd
• discovered 1979 and commissioned in 1984
• 43 wells with oil and gas production facilities
• gas processing capacity 30 million cubic feet of gas per day ("mmcfd"). Oil processing capacity 27,000 barrels of oil per day ("bopd")
• currently producing 11 mmcfd

d) Mangahewa

• Owned by Todd
• commercially drilled in 1995 and came on line at McKee station in September 2001
• currently produces 450 barrels of condensate per day and 34 mmcfd
• gas processing capacity of 34 mmcfd
• currently fully utilised

e) TAWN

• Owned by Swift Energy
• Tariki and Ahuroa discovered 1986, production began 1988
• Waihapa and Ngaire discovered in 1988
• 8 oil and gas producers, 3 gas producers
• two processing plants, the Waihapa Production Station (WPS) and the Tariki Ahuroa Gas Plant (TAG) - solution gas gathered from the WPS (an oil facility) flows to TAG for processing
• the capacity of the processing facilities at year end 2002 was 40 mmcfd (oil 15,000 bopd).
• current utilisation of TAG is around 90%
• gas processing can be increased significantly with additional compression as needed

f) Rimu/Kauri

• Rimu Processing Station is a new plant (commercial production from May 2002)
• current plant capacity is 20 mmcfd
• current usage is less than 50% of capacity
• with minimal additional capital, the plant's capacity can be more than doubled to 8,250 barrels of oil and 20 mmcfd with options for even further expansion.

g) Kaimiro

• owned by Greymouth Petroleum
• deep gas field discovered 1981, shallow oil field discovered 1988,
• production began 1984
• oil and gas treatment facilities for 2,000 bopd of oil and 8 mmcfd of gas

5.2.5 Key Issues: Upstream Gas Assets

The key issues for upstream gas assets may be summarised as:

• Production and processing infrastructure has been built to meet the requirements and location of specific fields. However, the dynamics of production are now changing as fields reach the end of their economic lives and new fields come on line (e.g. NGC are looking to utilise the Kapuni gas treatment station further by processing the gas from many of the smaller fields in the Taranaki region).
• Asset owners undertake maintenance and refurbishment regularly to ensure that the infrastructure is adequate to support the expected production from the relevant fields.
• Exploration and production assets are currently able to meet the demands placed upon them, in terms of the volumes of gas being produced in the Taranaki region.
• There is now excess processing capacity, particularly given the reduction in production volumes from the Maui field.
• We do not expect, in the short term, that asset stranding will be an issue, given that there are ongoing gas supplies from the Taranaki region.

5.2.5.1 Gas Infrastructure Efficiency: Transmission Losses

The following tables indicate the level of transmission losses as a percentage of total gas production since 1993.

*Estimate

Source: Energy Data File July 2003

Generally, transmission losses are relatively low as a proportion of overall energy consumption, particularly when compared with losses in electricity transmission and distribution. As noted previously, electricity transmission losses for Transpower over the last five years have averaged 3.9%, while for electricity distribution businesses average losses for the same period were an additional 6.0%. Total electricity losses within the transmission system are therefore of the order of 10% of input electricity; for gas the figure is less than 0.5%.

In addition to transmission losses, gas is also flared or consumed as part of the production or transportation processes. The following table indicates recent trends in gas flaring, production losses and own use.

Source: Energy Data File July 2003

5.3 Transmission Infrastructure

The main gas transmission system in New Zealand (the NGC system) was developed to serve the Kapuni field. With the discovery of the Maui field, an additional transmission line was developed (the Maui pipeline) solely for the transportation of Maui gas. Further detail on these assets is provided below.

a) NGC Transmission System

The NGC Transmission System consists of four major sub-systems:

• Kapuni to Wellington pipeline ("South") built in 1968, substantially reinforced/looped in the 1980s due to demand growth in Wellington and the Hutt Valley. This pipeline now has a capacity far greater than the demands placed upon it.
• Kapuni to Huntly pipeline ("Central") built in 1969, bypassed by the Maui pipeline decade later. At present, this pipeline is the only access to Northern gas markets for non-Maui gas and is therefore well utilised.
• Gisborne pipeline ("Bay of Plenty") built in 1984 on the back of demand from four large consumers (the Hospital, Watties, Gisborne Refrigeration and Advanced Meats) of whom two have since closed or moved. This pipeline operates at only approximately 50% of capacity.
• Northland pipeline ("North") built in 1985. This asset has also been affected by reduced demand

NGC System Capacity and Utilisation

Pursuant to the Gas (Information Disclosure) Regulations 1997, NGC publishes a report⁹ that provides information available on NGC's transmission pipeline capacity. The report summarises the main pipeline segments of each system, and in particular gives information for each pipeline on utilisation during peak periods, the amount of excess capacity available during peak periods and options for (and costs of) increasing capacity at peak points.

This report therefore provides an indicative assessment of the excess capacity available.

NGC System Asset Age and Condition

Given that the pipelines were constructed in the late 1960s, at the earliest, the pipeline system in New Zealand is relatively young (by contrast, some US systems are reaching 70-80 years old, although not necessarily high pressure pipelines).

For the purpose of calculating the Optimised Deprival Value ("ODV") of the pipelines, NGC use a theoretical pipeline life of 65 years for transmission and 50 years for distribution. The average remaining life of the transmission pipelines, determined for the purpose of undertaking the ODV calculation, is 42 years (based on a useful life of 65 years), as at 31 December 2002. NGC management state that the large pipelines are all intelligently "pigged" (checked for corrosion internally and externally), with very few instances of even pin-hole corrosion noted during the checking process. There is little evidence of internal corrosion (the processed gas is quite dry, therefore providing little cause of corrosion). External coatings also provide a good level of protection, further backed up by cathodic¹⁰ protection. If current maintenance practices are maintained (and adapted to any emerging problems in the future) we believe that the remaining life of the pipeline (i.e. the need to replace) is unlikely to be a constraint on the ability to deliver gas.

b) Maui Pipeline System

The Maui pipeline, which runs from Oaonui to the Huntly Power Station, is effectively operated as part of the Maui gas supply system (as a wholesale pipeline). It is not currently an open access pipeline, meaning that only Maui gas is transmitted. The pipeline also supplies gas to the Methanex Waitara Valley and Motunui plants and provides connections to NGC's transmission system.

In the Gas Industry Government Policy Statement, the government iterated its expectation that the gas industry develop open access regimes are established across all high-pressure transmission pipelines on reasonable terms and conditions.

An open access regime is currently being developed by the partners in Maui Developments Limited, although there are a number of contractual hurdles that need to be overcome before such a regime can be implemented. We understand that the process is still underway.

Pipeline Capacity and Utilisation

The Maui pipeline, operated by NGC, is significantly larger than the NGC pipeline that follows a similar northern route (Nominal Bore of 30-34 inches, compared to 8 inches) and has a capacity of around ten times the NGC pipeline. While historically it has run close to capacity on occasions (at around 245TJ per day), the recent ramping down of Maui production (currently at around 40% to 45% of capacity) has increased the unutilised capacity in the pipeline.

Pipeline Asset Age and Condition

The pipeline, built in 1979 is 24 years old. The Maui pipeline is subject to the same checks on its integrity as the NGC pipelines. Age and quality are not currently an issue.

In summary, the gas transmission pipelines are currently able to meet the demands placed upon them and do not represent a constraint on the delivery of gas, particularly in the light of the declining Maui volumes.

5.4 Distribution Infrastructure

Natural gas is currently only reticulated in the North Island.¹¹ In summary, the networks are not currently constrained in their ability to meet customer demands, or act as a constraint on distribution. The network owners are generally willing to roll out the distribution infrastructure where commercially viable. The impact of lower gas volumes could impact infrastructure roll out, although the impact is more likely to be felt by large users than those in the reticulated market.

The owners of the distribution infrastructure may be generally more reactive in terms of maintenance and forward-looking investment than for transmission systems. The networks can be reinforced more easily and are often meshed (i.e. pipelines within a distribution network are interconnected) so have more flexibility and security.

A brief summary of the distribution network characteristics is provided below.

a) Vector

• The Auckland network is supplied by two NGC pipelines so there is good security of supply
• We are not aware of any significant capacity constraints on this network
• Incremental growth can be accommodated. The main growth in Auckland is likely to be in electricity generation, which will access gas direct from the transmission grid

b) Powerco

• Owns and manages networks in Taranaki, Wellington, Hutt Valley, Porirua, Manawatu and Hawke's Bay
• We are not aware of any significant capacity constraints on this network

c) NGC

• Owns and operates networks in Hamilton, Mt Maunganui, Tauranga and Gisborne
• A winter gauging programme has been undertaken to monitor pressure in high demand areas
• We are not aware of any significant capacity constraints on this network

d) Wanganui Gas

• Owns and operates networks in Wanganui and Marton
• We are not aware of any significant capacity constraints on this network

Gas pipeline businesses are required to disclose certain information under the Gas (Information Disclosure) Regulations 1997. The table below indicates the load factors disclosed for NGC, Powerco, UnitedNetworks and Wanganui Gas, and the year end to which the disclosures relate. On 1 November 2002, Vector and Powerco acquired the gas assets of UnitedNetworks. Vector has yet to make its disclosures under these regulations. We have therefore included the load factor of UnitedNetworks in the table below.

* includes the gas networks acquired from UnitedNetworks on 1 November 2002 on a time weighted basis.

On the basis of the information gathered, we conclude that the distribution networks can currently meet the demands placed upon them, and are in reasonable condition commensurate with their age. While there are pockets of old assets within the distribution networks, these are monitored and replaced as necessary and do not impact significantly on network performance.

The gas distributors are currently subject to review by the Commerce Commission of pricing and whether pricing controls should be imposed. In general, gas distributors are of the view that price controls are not required, given that reticulated gas can be viewed as a competitive, easily substitutable fuel source.

5.5 Emissions

The following table highlights the volume of emissions resulting from fuel combustion, in the oil and gas extraction and processing sector.

Source: Energy Greenhouse Gas Emissions 1990-2002

The following table indicates the level of fugitive emissions from the oil and natural gas sector. Whereas the table above considers emissions from fuel combustion in the oil and gas extraction process, the table below considers emissions from non-combustion sources. The main source of CO₂ emissions from production and processing is the Kapuni Gas Treatment station, with relatively small volumes of CO₂ released in transmission and distribution.

However, when the energy content of all emissions from the sector are considered, transmission and distribution account for a significantly higher value of losses. The bulk of these losses are attributable to local gas distribution systems.

* emissions which do to come from the combustion of fuel to produce useful heat.

5.6 Demand/Supply Gaps

The Centre for Advanced Engineering ("CAE") estimates that gas consumption (excluding methanol manufacture) has grown at a compound rate of 6% per annum. Figure 35 below provides a sectoral breakdown of usage for the year ended March 2003, whilst Table 15 provides the breakdown for the last three years.

Figure 35: Gas Use by Sector - Year Ended 31 March 2003

Source: MEDEnergy Data File July 2003

*Excludes electricity generation but includes cogeneration
**Estimated from July 2000 to March 2003

Source: Energy Data File July 2003

The gas market is currently very tight. Long-term contracts underpin the majority of gas supply arrangements, and with reduced Maui output, and in the absence of a spot-market, very little un-contracted gas can be accessed in the short-term.

• Methanex estimated that its New Zealand operations would produce 1 million tonnes of methanol in the year to 31 December 2003, which is approximately 40% of its plant capacity (2.4 million tonnes). This reduction in volumes is a direct result of its inability to access gas supplies. In the quarter ended 31 March 2003, production fell to 356,000 tonnes or 59% of the capacity for the quarter due to lack of gas feedstock, and Methanex have indicated that its planning assumption for 2004 is that the methanol plant will produce somewhere between 500,000 and 1 million metric tons. Methanex has had its share of the remaining Maui reserves reduced significantly following the redetermination process, and must now seek gas supplies outside its existing Maui contractual offtake arrangements.
• Uncertainty in gas supply is already leading to delays by electricity generators in undertaking further investment in the power generation sector.
• Gas availability is currently adequate for the reticulated market, including industrial use (but excluding Methanex at full production levels).

5.7 Gas Supply Pricing

Prices have historically been underpinned by the Maui Contract, at a price that will not be sustainable in the future. The Maui Contract incorporated a below-inflation price escalation factor, providing a cheap and plentiful gas supply. With the reduction in supply from Maui, prices are now going through a step-change that will likely lead to a much closer reflection of the underlying economics of field discovery and development. Consideration of future gas prices is provided in section 5.9.1 below.

5.8 Gas Investment Plans

5.8.1 Exploration and Production

Figure 36 and Figure 37 below present two views of historical and projected demand growth. The graphs also depict the existing source of supply to satisfy that demand and illustrate clearly the potential gap between supply of gas and demand.

However, neither of these graphs incorporate the potential for new gas discoveries. For example, the MED in the Energy Outlook, assume that the rate of new discoveries will be close to the average annual rate of past discoveries (excluding Maui as a result of its large size). On this basis, new discoveries of 35PJ per annum are assumed to become available from 2010, and 60PJ per annum from 2014. Table 15 above presents the primary energy supply of gas prepared by the Ministry of Economic Development, incorporating new discoveries.

What these graphs and our discussions with industry participants indicate, is the high level of uncertainty, not only in regard to future discoveries of gas, but also the level of reserves in producing, and known fields.

Figure 36: New Zealand Gas Market 1970-2020

Source: Geosphere Consulting

Figure 37: Gas Utilisation by Source and Usage

→ Larger Version of Figure 37 [56KB GIF]

Source: CAE/Sinclair Knight Merz

The impact of the decline of Maui completely changes the dynamics of the gas supply market, from a market dominated by one large field with a high level of flexibility, to an integrated, multi field supply structure. Prices will move from the low Maui prices toward a market price, that recognises the cost of developing new fields, amongst other things. While there are differing views on the rate of decline of Maui, there is a general consensus that New Zealand faces a significant decline in supply. In this context, the Pohokura and Kupe fields are very important to bridge the medium term shortfall, although both are currently undeveloped.

Looking further ahead, it is very difficult at this stage to determine the likely future position as this will depend on the rate of discovery and commercialisation of new sources of supply. Views in the industry on the deliverability of gas from the Kapuni field over time also differ, and this will be driven somewhat by the level of development that the field owners undertake.

Some commentary on the major production sources is provided below.

a) Existing Production Sources

Maui

It is expected that Maui will end its economically productive life in 2007. However, views on the profile of the "tail" differ (how much and for how long). The actual level of production will also be influenced by the resolution of the future entitlements to Maui gas, as a result of the redetermination process. In 2001/2002, the field produced approximately 200PJ, but this year the figure is more likely to be in the region of 115PJ. There is some potential for the field to continue to deliver gas at low rates until 2012 (maybe 25PJ per annum) although the current contractual arrangements end in 2009.

The Oaonui plant will have significant excess processing capacity as Maui production runs down. The Oaonui plant is also relatively isolated. It is likely that additional pipeline infrastructure would be required for the plant to process gas from other fields.

Kapuni

STOS is confident that Kapuni's field life can be extended for another 15-20 years. We also understand from our consultation process that there may be potential to increase the output of Kapuni (up to 50PJ per annum). This would require significant capital expenditure to drill and develop additional wells. We have not been able to establish what current plans for development of the field are.

McKee/Mangahewa

Todd Energy, as owner of the McKee and Mangahewa fields, has announced its intention to auction 100PJ of gas which is 88% of these fields' proven and probable reserves as at 30 June 2003.

Other existing sources are relatively minor in quantum

a) Known Potential Production Sources

Pohokura

Pohokura is operated by STOS, owned by Shell, Todd and OMV and is expected to be producing in 2006. Gas reserves were recently reassessed at 700-750 bcf (but subject to high degree of uncertainty).

Commerce Commission approval has been given to joint-sale of natural gas,¹² so long as certain conditions are met (a minimum of 60PJ per annum is produced and production must start by June 2006). The partners have indicated that they anticipate a market for the gas at $6 GJ.

STOS's base-case scenario, drawn up for use in applying for resource consents, involves:

• up to three unmanned platforms;
• about 20 production wells;
• a 70,000 cubic metre (m³) LPG storage facility;
• onshore production plant adjacent to the Methanex Motunui industrial complex (separating condensate at the production station and piping it to the Omata Tank Farm near Port Taranaki; LPG piped either to an LPG storage facility at the Omata Tank Farm and or dispatched from the onshore production station. There will also be a new tie-in to the Maui gas pipeline near Waitara in Taranaki.)

All new field developments contain an element of risk. Much of this risk is associated with the underlying field characteristics, which can not be gauged with any complete certainty even once the field is producing. In particular, the key risks include the recoverable level of reserves (i.e. the amount of hydrocarbons that can be extracted from the field), and field deliverability (i.e. the rate at which hydrocarbons can be extracted). In addition, the value of the field is dependent upon the price that can be realised for the hydrocarbons.

Kupe

Kupe is owned by Genesis (70%), the Crown (11%) and NZOG (19%), although the Crown has indicated that it will sell its share to Genesis in the near future. Five exploration/appraisal wells have been drilled and reserves are estimated at 264 bcf gas and 16 mmbbls oil. Genesis Power has announced its intention to sell part of its majority stake to an operator to pave the way for development of Kupe as a commercial field (and have appointed a local company to undertake an initial engineering study).

Kupe is considered to be technically challenging and expensive to develop and will be likely to have a low flow rate and inflexible delivery. Production is expected from 2007. As for Pohokura, field developments are not without risk and Kupe faces similar risks as Pohokura. Given the more challenging technical nature of the field, these risks may potentially be higher than on Pohokura.

b) Other Potential Production Sources

Taranaki

A number of other gas opportunities are currently being assessed onshore in Taranaki, but these are generally smaller fields, with incremental volumes only. Offshore Taranaki has the potential for larger discoveries, but is currently not being extensively explored, with little drilling being undertaken. However, a recent bidding round for nine offshore blocks and eight onshore blocks has received twenty three bids, although no announcement has yet been made as to which blocks have been bid for. We consider the reasons why this is the case below.

East Coast - Upper Wairoa

Westech Energy are planning a further appraisal to revisit reserves discovered near Wairoa.

Reserves would need to be large to be commercially viable. The field is not located near the existing NGC transmission system and Westech would need to construct a pipeline out either to the North or to Hastings. Processing infrastructure would also be required and, if connected to the existing transmission system, upgrades to this may be required.

An alternative would be to utilise the gas as a generation fuel in the region providing underwrite for development (but upgrades to the electricity transmission system may be required).

Offshore Wairarapa

Westech are looking for partners to assist with undertaking exploratory drilling of a potential field, in the Wairarapa area, 12 miles offshore.

Partners would need to be large and would be likely to be international players, therefore facing internal financing hurdle issues with allocating capital to New Zealand as opposed to other international opportunities.

Significant issues arise if any discoveries are commercially viable, including how to get the gas to market (what production, processing, storage and gas transmission would need to be built). If connected to the NGC transmission system, it may need to be reinforced. Again, an option would be to build electricity generating capacity onshore, or on the pipeline route to underpin a basic support load.

Canterbury and Great South Basins

These offshore basins are barely explored but both have shown potential, with both Galleon-1 and Clipper-1 showing significant hydrocarbon shows in the Canterbury Basin, as did Kawau-1 and Toroa-1 in the Great South Basin.

However, discoveries in these areas would be difficult to monetise given the lack of gas infrastructure and limited access to a market for the gas

In general, where significant volumes of gas are found outside of Taranaki, investment will be required in some or all of:

• Further pipelines and processing facilities;
• Gas fired power generation (factoring related transmission costs); and/or
• Dedicated major users.

The need for such extensive investment clearly affects the economics of the fields and therefore the likelihood of investment proceeding.

5.8.1.1 Gas Exploration Issues

At present, it appears that a number of small fields will replace large fields (such as Maui) in providing the bulk of the gas. Exploration is increasing, but there is industry consensus that activity still needs to be dramatically increased. One industry commentator has suggested that exploration needs to increase threefold in order to deliver sustainable reserves.

Incentivising gas exploration remains a key issue. Explorers are generally looking for oil, which is a more saleable commodity than gas.

Attracting capital to the sector is an issue. Although potentially offering high returns, exploration remains a high risk activity. Exploration costs are high. New Zealand's geographic location, coupled with low exploration activity, makes the cost of rig mobilisation high, particularly for offshore drilling. The cost of drilling offshore wells is very expensive (NZ$20-40million) and then further costs are required to appraise and develop. A recent round of tenders for deepwater offshore exploration permits resulted in the receipt of only one application although a combined onshore and offshore round in October attracted 23 bids for 17 blocks.

Ultimately, New Zealand competes in an international market against bigger markets with less market risk, lower exploration costs and potentially better reserves.

A longer term solution for gas exploration could involve collaborative activity between major gas consumers who have access to capital, looking to fund upstream investment. Any arrangement is likely to require funding by large consumers, the involvement of a large multinational oil and gas exploration company, and potentially the involvement of Government (although not necessarily through an equity interest).

Other hurdles for exploration activity in the gas sector include:

• lack of skilled people;
• explorers searching for oil rather than gas;
• smaller onshore plays are less risky and are more appealing to the smaller market participants;
• explorers are reluctant to explore outside Taranaki (in other gas prone areas), where there is an absence of established infrastructure.

One characteristic of the New Zealand gas industry is that it is cyclical around the life of large developed fields. Maui captured a dominant market share, but also underpinned the exploration activity and assessment of other fields. It also provided the scale of activity that enabled construction of the necessary supporting infrastructure (particularly transmission systems). Another large field could again change the market dynamics significantly.

Without significant increases in exploration and commercialisation, in the medium term, the options for the New Zealand gas sector are:

• Reduced consumption with migration to other forms of energy; or
• Importing gas (LNG).

5.8.1.2 Other Source Options: LNG

Liquefied Natural Gas ("LNG") is being considered as a replacement option by certain players in the sector (Contact and Genesis have recently announced a joint feasibility study). Introducing LNG will require significant investment in regasification plant and depending upon the location, potentially additional gas pipelines. Initial indications from Contact and Genesis indicate that the required infrastructure could cost up to NZ$1 billion.

The initial views are that, with a moderate carbon tax of $15 CO₂/t, the cost of coal, gas-fired and LNG-produced electricity would be comparable at 7-8c/kWh. Other commentators indicate that prices in the range of 8c/kWh to 10c/kWh for LNG produced electricity are more likely. The introduction of LNG and its infrastructure investment will require sufficient offtake contracts to provide the necessary economies of scale and certainty over base load demand. The impact of LNG on the New Zealand market, and particularly on natural gas exploration activity is highly uncertain. If gas customers contract with the LNG provider to take committed volumes of LNG over long periods of time, the incentive to invest in exploration and commercialisation of new natural gas fields is reduced, as demand is already catered for through LNG contracts. If LNG is relatively highly priced, the economics of domestic gas exploration and production are improved (and the potential competition from domestic gas could in the long run assist with keeping LNG prices down).

Gas customers may be reluctant to commit to long term LNG offtake agreements while local exploration has the opportunity to still discover further (cheaper) reserves. However, as indicated above, if sufficient demand for LNG could be secured, it could spell the demise of local exploration activity if there is little remaining demand to service through domestic production (although higher prices may incentivise further exploration if un-contracted demand exists).

One advantage of LNG is that it is a global product with substantial established supplies, bringing a degree of supply certainty. Offsetting this certainty is a greater dependence on international markets and trends. LNG could also provide support for the reserve generation market, as deliveries are flexible, and a "spot" market for LNG cargos effectively exists.

It is useful to note, that if LNG imports become commercially viable, the flow on effects of increased energy costs will have a significant impact on energy intensive industries through increased costs in direct use (and from electricity generation), which will impact New Zealand's competitiveness in certain sectors, particularly processing industries (e.g. wood processing and dairy product processing).

The benefits of utilising indigenous reserves could be lost if LNG is required to underpin the local gas industry.

Other technical options, such as gas hydrates, do exist but are not believed to be technically and economically feasible at this stage.

5.8.2 Gas Processing Infrastructure

Development of gas fields is likely to drive development of processing capacity which is generally built as an integral part of the infrastructure required to bring gas on-stream. With the throughput from Maui at Oaonui expected to decline significantly in the next few years, we expect processing capacity to become available at this site (although this may require additional transmission infrastructure to transport gas from fields to the plant). Existing facilities are likely to be able to cover smaller fields (e.g. NGC have indicated that they intend to convert the Low Temperature Separator ("LTS") pipeline which currently carries high CO₂ gas to Methanex's plants, into a gas gathering line for Kapuni (after Methanex exits the market).

Additional processing capacity will be developed for Pohokura and potentially for Kupe. As noted previously, specific production plant has been planned for Pohokura by the Pohokura JV partners, while it is unclear at this stage what the infrastructure for Kupe will be, but processing is likely to be onshore, and will either consist of a greenfield processing development, or utilise expanded existing facilities in close proximity to Kupe (such as the Rimu Production Station, Kapuni or Oaonui).

The Kapuni Gas Treatment Station is in the process of being upgraded to return it to full processing capacity, recommissioning one of the plant's three process trains, adding additional LPG storage and installing a new absorber column to improve the plant's flexibility.

In summary, processing assets are not a constraint on the gas sector although, as noted above, if other big reserves are discovered outside of Taranaki, specific new infrastructure will be required.

5.8.3 Transmission

Transmission economics could change depending upon future gas supply scenarios - the following comments are in relation to expected volumes from known or expected gas production sources, which will be significantly lower than volumes historically transported under the Maui dominated regime

a) NGC System

Central

The general northward shift of demand is likely to continue. Huntly power station is likely to run on lower gas volumes (with higher coal consumption), as Maui output declines. Generally, there is sufficient transmission capacity between Taranaki and the northern markets for projected volumes. Capacity issues may however arise if additional gas-fired generating capacity is required north of Rotowaro.

The Huntly to Auckland 14-inch pipeline was built on the back of aggressive growth projections and was originally under-utilised. Capacity was subsequently increased to cope with Southdown and Otahuhu B power stations by increasing pressure and upgrading the Rotowaro compression facility. Gas requirements for the proposed Otahuhu C would necessitate further capacity. NGC has begun the process of obtaining designations for new a pipeline. Rotowaro is also likely to need upgrading, however this is not expected to be a constraint as the lead time for additional compression is generally less than that required for the construction of the new generation plant. New compression facilities may be subject to more constraints, including easements etc, although as these stations are generally located in rural areas, they are often non-notified under RMA.

South

While not looped over its full length, the system is not capacity constrained. Additional compression capability can be added relatively easily. Kaitoke compression is currently only used in winter and further compression could be added.

Gisborne/Bay of Plenty

There is a potential constraint at the Pokuru Compression Station if demand increases significantly, but additional compression could be added at Pokuru to cope with this. It should not be necessary to construct additional pipelines

b) Maui Pipeline

Lack of third party access to this pipeline is a potential impediment, as is the price and terms under which access will be offered. These access issues need to be resolved quickly in order to reduce uncertainty about the availability of gas in the Northern region. As previously noted, the government has indicated in the GPS that it expects the gas industry to establish open access to all transmission lines on reasonable terms and conditions.

[Summary]

In summary, unless significant additional gas reserves are discovered and brought into production, the combination of the existing Maui pipeline and the NGC system will be adequate to ensure existing gas reserves are able to be delivered to existing markets. There is plenty of excess capacity at the moment on existing routes, particularly on the Maui pipeline.

If new pipelines were required, these would be subject to a number of potential constraints:

• RMA requirements;
• The need to negotiate easements for new pipelines;
• Urban encroachment: area classifications may change requirements (such as pipeline thickness) and may require reductions in pressure.

Given the expected fall in gas production, there should be little requirement for substantial investment in transmission infrastructure. These constraints are therefore unlikely to matter.

5.8.4 Distribution

The distribution networks are expected to be able to meet the demands placed on them in the medium term.

Expansion of these networks can be achieved relatively simply when compared to the transmission system and we do not anticipate significant capacity constraints.

There are fewer restrictions on further development of distribution systems, compared to those in the transmission sector. Access to existing pipelines, and the laying of new pipelines is less of an issue, given existing rights to open streets, and fewer land owner consent issues as pipelines generally utilise existing roads.

5.9 Demand Projections

Table 16 and Table 17 below, from the MEDEnergy Outlook August 2003 provide an indication of future demand for energy in the New Zealand economy, and the relative percentage of gas in each of these sectors.

Source: MEDEnergy Outlook to 2025

Source: MEDEnergy Outlook to 2025

These tables highlight the impact that the reduction in production has on the gas sector. While industrial and commercial volume reduces significantly, mainly as a result of less gas available to supply Methanex's demand, residential demand remains relatively stable over the period of the forecasts, with little impact of supply shortages being experienced.

MED projects that primary energy supply of gas as follows:

Source: MEDEnergy Outlook to 2025

These projections are based on the following assumptions:

• The rate of new discoveries will be close to the average annual rate of past discoveries (excluding Maui);
• 35PJpa of gas becomes available from new discoveries from 2010, and 60PJpa from 2014;
• As noted previously, the Energy Outlook forecasts differ from those gas supply forecasts above, although the short-term impact of reduced Maui volumes is easily observable in all of these forecasts.

Under these assumptions, demand for gas cannot be met indefinitely, even after the closure of the methanol plants.

• Gas supply to Methanex methanol plants ceases prior to 2005;
• Primary energy supply of gas decreases by 42% between 2000 and 2005, principally as a result of the reduction of gas use in the production of petrochemicals;
• Even if Methanex takes no further gas there is a possibility, shortages could arise from 2006 onward depending upon when Pohokura and Kupe may come on stream;
• A similar impact is reflected in Figure 4 where Methanex demand reduces significantly, followed by the electricity generation, industrial and commercial customers.

The loss of such a large consumer as Methanex is significant:

• During the last nine months of 2003, Methanex estimated that it would be able to produce 600,000 tonnes of methanol
• Methanex aim to produce 500,000 tonnes to 1,000,000 tonnes of methanol at the Taranaki plant in 2004 and would require between 20PJ and 40PJ for that. Methanex had its entitlement to Maui gas cut to less than 10PJ a under the Maui redetermination.
• Complete withdrawal of Methanex on the one hand liberates gas supplies for other uses, but also removes a large amount of foreign exchange earnings for the country, and a substantial base load demand, thus weakening the business case for further exploration and production.

5.9.1 Pricing Impact

The reduction in gas supplies is expected to have a significant impact on the wholesale price for gas. Historically, NGC, Contact and Methanex have had contracts for Maui gas in the range of $2/GJ to $3/GJ. Forward-looking pricing indications at the moment include:

• Press commentary suggests that Methanex may be paying $5.50 for the 15PJ it recently secured from Mangahewa and McKee;
• Todd have indicated that they anticipate receiving $6/GJ for the 100PJ of gas being auctioned from McKee and Mangahewa;
• The cost of Kupe gas is unknown but likely to be $6+/GJ given the technically challenging nature of this field;
• The cost of Pohokura gas is also unknown but Shell have indicated that they will be looking for prices around $6/GJ. The Commerce Commission in the Pohukura gas joint selling determination assumed a price of $4/GJ but indicated that this was a conservative figure.

LNG has been considered by some to be available at $7-8/GJ. Some commentators think that this is optimistic - more likely to be $8-$9/GJ, or higher on a long run marginal cost basis given the high plant costs.

5.10 Gas Industry Development and Governance

In March 2003, the government released the Government Policy Statement: Development of New Zealand's Gas Industry, which set out the government's policy for the development of New Zealand's gas industry. The overall policy objective for gas is: To ensure that gas is delivered to existing and new customers in a safe, efficient, fair, reliable and environmentally sustainable manner.

The key arrangements that the government expects the industry to address include:

• the development of protocols, standards and conventions for wholesale gas trading, secondary gas markets, and capacity trading arrangements;
• the establishment of open access regimes on all high-pressure transmission pipelines;
• upgrading protocols for customer switching, development of effective arrangements for customer complaints, and development of model consumer contracts; and
• the establishment of effective safety standards

The government indicated that it favoured industry lead solutions where possible, but would be prepared to use regulatory solutions where necessary.

⁹Pipeline Capacity Disclosure of NGC New Zealand Limited.

¹⁰A technique for protecting pipelines from corrosion. Specifically: by making the structure the cathode in a cell, either by applying an electromotive force directly or by putting it into contact with a more electropositive metal.

¹¹Rockgas has developed two small LPG reticulation networks in the Christchurch and Queenstown CBDs.

¹²Excluding liquefied petroleum gas.