Electricity: Supply and Demand Issues

Background

• Current electricity production is approximately 38,000 GWh/year from 8,600 MW of capacity.
• In a normal hydrology year, hydro provides around 63% of our generation, with the balance comprising gas (22%), geothermal (7%), coal (4%) and other (3%).
• In a 1 in 20 dry year, loss of hydro capacity can be over 15% (around 4000 GWh out of 24,000 GWh mean year capacity). This shortfall needs to be made up by increased thermal generation (gas and coal) and by demand reductions.
• The Government's policy objective for electricity is to ensure that it is delivered in an efficient, fair, reliable and environmentally sustainable manner to all classes of consumer.
• The Government Policy Statement on Electricity (GPS) of December 2000 requires an industry Electricity Governance Board (EGB) to make specific improvements to the efficiency and fairness of the market.
• The Electricity Amendment Act (passed in 2001) enables the government to regulate and set up a Government EGB if the industry EGB fails to deliver.
• There have been significant delays in setting up the industry EGB, but many of the objectives set out in the GPS are now being met (e.g. consumer complaints scheme, disclosure of hydro spill, generator offers and forward hedge prices, and real time pricing).
• The National Energy Efficiency and Conservation Strategy (NEECS), adopted in 2001, aims to improve energy efficiency by 20% by 2012 and increase the uptake of renewables (by 30PJ a year by 2012).
• The Government's climate change policies also aim to improve energy efficiency and reduce emissions from fossil fuels.
• The current market model applied to the electricity industry relies essentially on market participants responding to price signals to balance supply and demand over time. As supply tightens (and the probability of dry year shortages increases), average spot prices (and therefore hedge prices) will rise, signalling the need for and incentivising construction of new capacity and investment in demand side management. Commercial pressures are expected to ensure that capital is invested wisely and costs are minimised.

Current Issues

New Zealand faces the need to:

• build new generating capacity to meet growth in electricity demand
• improve our ability to deal with the risk of dry years, especially given the expected early depletion of the Maui gas field
• improve our demand-side management capability and energy efficiency.

We are experiencing a relatively fast change from:

• surplus generating capacity over the past few years to tighter supply and a requirement to build new capacity, and
• plentiful availability of cheap gas (a premium fuel for electricity) to a tighter gas supply situation from multiple and more expensive fields.

This change in circumstances was always going to occur, with continually increasing demand for electricity (currently around 2% pa) and the depletion of Maui around 2009. However, the expected early depletion of Maui (around 2007) has accelerated the need to address supply issues.

• At current electricity demand growth rates, new capacity is required at a rate of around 150 MW (800 GWh) a year. This is required as soon as possible (taking into account lead times) to minimise the risks of shortfalls in dry years.
• In aggregate, generators have public and confidential plans, covering the next ten years or so, to build this level of capacity.

New Generation Capacity

New Zealand has a considerable number of options for new generation capacity. These are set out in Table One. Chart One provides a "cost curve" for new generation (assuming that capacity is built approximately in "merit" order in terms of cost).

The following points should be noted from this material:

• costs are generally higher (at 6 to 6.5c/kWh) than current average wholesale market prices (which are around 5c/kWh). Thus, average wholesale prices may rise over the next few years, depending primarily on gas prices. Any increase in delivered electricity prices will be lower, as they include line and transmission prices that are not expected to rise.
• if significant new gas discoveries are made with favourable field development costs it is likely that gas fired stations will displace most other alternatives, except probably Project Aqua. While the introduction of carbon charges under climate change policies will increase the cost of gas plants, they are still likely to have competitive advantages (including location flexibility, and speed of construction).
• assuming no early and significant new gas discoveries, new capacity from around 2007 for the next 15 years is expected to comprise renewables.

Table Two shows publicly announced plans to build new capacity. In addition, the main generators have provided commercial-in-confidence information to the Minister of Energy on other proposals under active investigation.

Clearly, not all this capacity will be built, and plans will change in response to changing market conditions. At the same time, other proposals are unknown (for example, cogeneration proposals by industry, new renewables proposals by lines companies and a likely multiplicity of distributed generation developments). A reasonable assessment is that there appears to be strong interest in building new capacity at the level required to meet demand.

Electricity Demand

A major determinant of future supply security is demand growth rates. Over the past 10 years, demand growth has averaged 1.8% pa. Higher economic growth rates, rising population and the prospect of more energy intensive projects, such as wood processing, will put upward pressure on demand. However, downward pressure is expected to come from:

• the National Energy Efficiency and Conservation Strategy, which aims to improve energy efficiency by 20% by 2012. EECA considers that this could lower demand growth rates by 1 percent pa (e.g. from 2% to 1% pa) although in the next five years it considers that a 0.5% reduction in annual demand growth rates is more achievable.
• higher prices with the depletion of Maui
• climate change policy, including Negotiated Greenhouse Agreements (NGAs) and carbon charges
• market improvements required by the GPS, including real time pricing and publication of a forward hedge price index.

Additional steps that might improve demand side responsiveness, and which are being explored, include:

• improved tradability of hedge contracts
• greater uptake of fixed price, fixed volume contracts by businesses
• introduction of a "day ahead" market to enable the demand side to secure short term hedges.

Availability of Gas

Gas is a critical fuel for electricity generation. It currently fuels 22% of our electricity in a normal hydrology year, rising significantly in a dry year (for example in 2001, it rose to about 30%). Gas is likely to be the preferred fuel for new generating capacity if it is available on a long-term basis. This holds true even if there are significant price increases over current Maui prices.

There are uncertainties over the volume of gas likely to be available in future. These include:

• residual volumes in Maui that are "economically recoverable" at current contracted prices. The current redetermination process is expected to be completed by the end of the year.
• additional recoverable reserves from Maui at higher prices. The Maui partners are currently seeking to establish this
• offtake (post-redetermination) by Methanex (which currently uses around 40 percent of gas production).
• the volume and timing of gas from Pohokura
• the timing, size, location and cost of new gas discoveries.

Over the last 30 years gas discoveries averaging around 90PJ/pa have been made, excluding Maui. If this rate of discoveries continues, New Zealand will have good supplies of gas at projected usage rates (excluding petrochemicals) for decades. However new discoveries are likely to take 5 to 10 years to bring on stream, depending critically on location and accessibility (especially whether on or offshore, and if offshore, whether in shallow or deep water) and the quality of the field.

Information on projected availability of gas from existing fields (provided by Shell, which dominates oil and gas production in New Zealand) suggests reserves are sufficient to met demand (at a wellhead price of $4/GJ) until 2010. This appears to be conservative, since much of the surplus available prior to 2010 is likely to be carried over to post 2010.

The information from Shell (Chart Two) does not include any allowance for new discoveries, and excludes the Kupe field. Note that:

• technical feasibility is not proven in all instances
• the demand curve at $4/GJ does not include Methanex, which requires cheaper gas to be economic.

Exploration activity, particularly in the Taranaki area, is currently high, and projected to increase. Key determinants of the level of exploration, in rough order of importance, are oil and gas prices, prospectivity, the cost and availability of petroleum infrastructure, the general business environment and the royalty and permitting regime.

New Zealand's current royalty and permitting regime is considered internationally attractive. It is scheduled for review during 2003.

The Crown Minerals group in the Ministry actively promotes New Zealand to international petroleum explorers. It is currently promoting a privately funded seismic survey of deep-water Taranaki, with exploration permits to be available from September 2003.

Exploration will also be facilitated by ensuring access to the Maui pipeline for non-Maui gas and by the establishment of better market institutions for gas trading.

Source: Energy Modelling and Statistics Unit

Chart One: Cost of New Generation 2005-2025⁴ (excluding Cogeneration)

Source: Energy Modelling and Statistics Unit

Chart Two: Demand and Potential Gas Supply (Unrisked) at $4.00/GJ Ex-Field

Source: Shell New Zealand

Chart Three: Projected Demand and Generation Capacity

Source: Transpower

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