An Overview of the National, State and Regional Modelling System

 National Economic Review

National Institute of Economic and Industry Research

No. 66 September 2011

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ISSN 0813-9474

An overview of the national, state and regional modelling system

Peter Brain, Executive Director, NIEIR

Ian Manning, Deputy Executive Director, NIEIR

Abstract

The present paper provides an overview of NIEIR’s national, state and regional modelling system. NIEIR’s forecasting methodology provides a strong and realistic basis for policy evaluation. An economic projection incorporating a policy change is compared with an otherwise similar ‘base case’ projection without the policy change.

Although using general equilibrium models is exceedingly fashionable in policy analysis, based as they are on a fundamental assumption that economies can usefully be divided into autonomous markets and analysed in terms of price-mediated balances of demand and supply in each market, NIEIR’s models are significantly closer to reality. They do not assume away mathematically inconvenient aspects of the economy and, hence, are less likely to deliver counter-productive advice.

 Introduction
The National Institute of Economic and Industry Research (NIEIR) originally entered the field of economic modelling as a forecaster. It maintains this role, preparing regular forecasts and checking them against actual forecast realisation, a process that results in learning from experience. However, NIEIR’s forecasting methodology provides a strong and realistic basis for policy evaluation. The concept is simple: an economic projection incorporating a policy change is compared with an otherwise similar ‘base case’ projection without the policy change.

After more than 25 years experience in economic forecasting and analysis, NIEIR has confirmed the value of dealing always in time sequences. This allows not only for the modelling of causation involving driver and driven variables but for the insertion of response lags and for the inclusion of lagged feedbacks. This time-driven structure of causation means that considerable complexity can be handled without major problems in ensuring analytical consistency.

A second benefit of experience is that NIEIR has developed a sense of relevance and used it to identify the drivers that have influenced the major forecast variables over the past six decades and more. These drivers have all been incorporated into the forecasting and analytical models in ways that reflect their perceived causative role. This is not to claim that a new wild card might not emerge (NIEIR continually scans the horizon in case one does) nor is it to claim that influences are constant in direction or strength, but it is to claim that the Institute has incorporated all historically-relevant drivers into its models and, furthermore, has endeavoured to ensure that their influence is determined by the data and not by assumption. Incorporation in the model is not the last word: historical behaviour is never completely replicated, especially the capricious historical behaviour of exchange rates and other variables strongly influenced by speculative financial markets. Again, although econometric relationships can provide evidence of the direction of causation, this evidence is never conclusive and the estimates of the strength of influence are not always stable. However, model specification emphasising lags and feedbacks provides a structure in which the complexities revealed by econometric analysis of historical experience can be formalised and brought into a logical relationship for forecasting purposes.

In the course of model development, NIEIR has learnt the benefit of a major simplifying device: the geographic layering of forecasting models. Some of the prices, flows and balance sheet values relevant to Australian forecasts are determined primarily on world markets, some are determined primarily at the all-Australia level, some at the level of large city-regions (which approximate to states in Australia) and some at the regional level. The Institute has thus evolved a tiered structure of models: the world is represented formally by the LINK models, to which NIEIR adds its own scenarios of world economic growth; the primary model is the National IMP model (from NIEIR’s IMP modelling suite), which is of particular importance in determining the values of variables influenced by imports, exports and the balance of payments and variables influenced by Commonwealth policy: broadly, the variables emphasised in the National Accounts.

It is also important as a means of ensuring that all-Australia markets add up; the state models include their own range of National Accounts variables and have their own city–region dynamics, but are individually constrained to national values for variables such as the exchange rate and inflation rate, and (subject to feedbacks) are constrained to national totals for a wide range of macroeconomic variables. Within these constraints there is scope for divergence from national trends, some brought about by differences in demography or by differences in industry mix, some by policy effects (particularly state government policies) and some by differences between states in the operation of markets, particularly such markets as housing; and the regional models again have their own dynamics, but are even more constrained by state and national values for variables, and state and national totals. When operated in ‘top down’ mode the regional models determine the local consequences of state and national forecasts. However, the modelling system can also be configured so that regional model results feed back to the state and national level.

All models are disaggregated by industry, with an emphasis on inter-industry relationships. Where a particular forecast or policy study emphasises a particular industry, the modelling of that industry is reviewed to ensure that the peculiarities of the industry are accurately represented. This can apply to industry modelling at national, state or regional levels.

The Institute originally developed two sets of models: annual models based on detailed annual data and projecting in 1-year increments, and stripped-down quarterly models. However, the modelling system has recently been rebuilt on a quarterly basis, this being the minimum time interval used in the National Accounts. Although this creates problems due to seasonality, it has major advantages in the treatment of causation.

The National (IMP) model

For operational and conceptual convenience, NIEIR’s integrated system of forecasting models is divided into modules. The most convenient point of entry to the system as a whole is the national model, because this model is most readily explained in relation to academic economics. It is also important to understand the national model because it determines many of the drivers that operate at the more detailed levels, and also guarantees the coherence of results at those levels.

Macroeconomics

The main data source at the macroeconomic level is the Australian Bureau of Statistics (ABS) System of National Accounts. The National Accounts comprise three main segments:

estimates of national income, expenditure and production;

financial or flow-of-funds accounts; and

the national balance sheet.

Although there is a tendency to regard the first of these as the most important, the other two provide information that is essential to forecasting growth in national income, expenditure and production. In particular, the national balance sheet includes important information on assets and liabilities.

The National Accounts are of fundamental importance for economic forecasting, for several reasons. They provide the following:

a guide for average or typical experience – if aggregate income is rising, individual incomes will also rise on average; consistency checks not only (by definition) within the National Accounts themselves, but checks useful in more detailed analysis, often expressed as column and row totals;

driver variables for more detailed analysis; a variable set within which a number of important dependant variables can be determined, particularly such variables as GDP, inflation, the exchange rate and the unemployment rate (these variables are also the subject of multiple feedbacks from the variables they drive: e.g. GDP drives energy use but any resulting changes in the efficiency of energy use feedback to GDP); and

a set of variables that is very attractive for econometric analysis, because data quality is high and virtually all the variables are the product of highly decentralised decision-making (the major variables affected by centralised decisions are government expenditure and taxation).

A disadvantage of the National Accounts is that they are published after a delay, and are subject to revision for many quarters after publication. This means that projections inevitably take off from a mixture of estimates of varying quality. NIEIR has tackled this problem and emphasises ‘lead indicators’ in its treatment of the latest published observations.

Forecasts of National Accounts variables provide invaluable background to forecasts at the industry and regional level and to policy-oriented analytical projections. NIEIR approaches the task of forecasting the National Accounts with the utmost seriousness. By longstanding practice, National Accounts forecasts have been ‘top down’; that is, the National Accounts variables, which are either aggregates or conceptually broad indices, are forecast in terms of other aggregates and indices, most of which also occur in the National Accounts or are easily related to the Accounts (e.g. national population). When forecasting in top-down mode, more detailed forecasts are largely driven by the national totals and, as a methodological principle, are reconciled to these totals, although not always completely: differences that can be highly significant at the industry and regional level are not always significant nationally, where they might lie within the acceptable range of forecast errors.

Although the top-down approach is standard, it is possible to move in the opposite direction, working from forecasts at the industry and regional level back to the national aggregates. and then down again to a further round of industry and regional detail.

Keynesian macroeconomics

National Accounts were first prepared after the Keynesian revolution and their basic structure continues to support Keynesian analysis. The familiar categories of aggregate demand are documented, including consumption, investment (fixed capital accumulation), government demand and net exports. Therefore, the National Accounts lend themselves to forecasting using the simplest of Keynesian models in which national income and GDP are determined by the sum total of consumption, investment and net export demand. As explained in university classes in elementary macroeconomics, this model is inherently dynamic. The consumption multiplier, which raises GDP following an exogenous increase in (say) investment demand, is usually explained as taking place in a series of steps, each step following one time period after its predecessor. This model is far too simple to yield useful forecasts, but it reveals two important points.

Demand is a very important underlying concept in economics. Marketed goods and services will not be produced unless they can be sold somewhere. Demand limits production.

Although the Keynesian multiplier can be explained as governing the transition from one steady state to another, it does not take much imagination to see it operating in conditions where exogenous shocks are occurring continuously. These do not prevent the multiplier from operating, but do prevent it from ever yielding a steady state.

Crude demand-dominated Keynesian models were common in the early days of National Accounting, in the 1950s and perhaps the 1960s. However, the

Institute’s forecasting model was never in this crude category. From the beginning it recognised the importance of Keynesian microeconomics and also the importance of explicit growth theory.

 

Keynesian microeconomics

Keynesian macroeconomics is founded on Keynesian microeconomics, summarised as import parity pricing for trade-exposed goods and services and cost-plus pricing for all others. Where market structure indicates that monopoly or oligopoly pricing are present, these can be handled by varying the cost-plus mark-up.

The microeconomics of import-parity and cost-plus is not standard economics as taught in first year courses. Economic doctrine privileges pricing at the equilibrium of demand (which increases as price falls) and supply (which reduces as price falls). The fundamental reason for teaching this doctrine is its association with the normative defence of competitive markets. This apart, the equilibrium theory of price formation has been variously defended, for example on the grounds that it follows from the logic of optimisation in conditions of diffused economic power, or that it is approximated in at least some markets. The reasons that it is not assumed in NIEIR’s models are as follows.

The demand/supply concept is closely bound up with the concept of perfectly competitive markets. In practice, very few, if any, Australian product and service markets meet the onerous conditions required if competition is to be perfect. Instead, competition is generally restricted to a limited number of firms, each of which has incentives to adopt strategic pricing behaviour. In these circumstances, cost-plus subject to an import-parity maximum provides a reasonably accurate approximation to actual price formation.

A particular case where demand/supply pricing is inadequate is that of increasing returns to scale, which generate downward-sloping supply curves and indeterminate price. This is no small problem, because increasing returns to scale are endemic in manufacturing and possibly in other industries such as retailing. Once again, the import parity/cost plus theory yields determinate prices.

Even if competitive equilibrium provides a reasonably accurate account of price formation in some of the markets of an economy, the existence of cost-plus import-parity pricing in significant sectors is sufficient to generate Keynesian macroeconomic behaviour.

The fundamental reason for not using competitive equilibrium in forecasting models is that equilibrium is timeless and, therefore, unhelpful in a forecasting context.

Although the general import parity/cost plus approach remains, the disaggregation of the Institute’s modelling system by industry has made it possible to vary the approach to price formation by industry. For manufacturing industries, NIEIR’s developed models use the cost-plus approach with the mark-up a function of unit capital costs and export and import prices. Demand in relation to capacity is included as a short-period influence to allow for profit-taking during booms and price-cutting to generate cash flow during recessions.

Although NIEIR avoids the assumption that prices vary to bring markets into equilibrium, it respects the National Accounts identity: aggregate demand must equal aggregate supply. The difference is that this equality is generally unsatisfactory to the economic actors. It is a temporary accommodation rather than a lasting balance of forces.

 

Growth theory and inflation

In the 1950s, Keynesian macroeconomic theory was developed into a series of growth models (Harrod, Domar, Hicks and Robinson). These models recognised that investment (in the Keynesian sense of gross fixed capital formation) not only adds to current demand but also adds to the capital stock, resulting in increased productivity of labour and increased incomes for both workers and the owners of capital. Because the Institute forecasting model was designed to yield policy analysis over a time horizon of a couple of decades, it included these relationships, by contrast with a great many contemporary Keynesian forecasting models, which are limited to a time horizon of a few years.

This explicit treatment of the capital stock was of great importance in meeting the challenge of the 1970s: the failure of simple Keynesian models to predict the stagflation of those years. As Keynesian economics developed, it was quickly realised that demand was not the only determinant of GDP. There were also constraints on the supply side, and it was possible for ex-ante aggregate demand to exceed the aggregate supply capacity of the economy. Three relationships were posited

quick-working relationship by which demand which could not be satisfied due to limits to productive capacity spilled over into inflation,conventionally known as excess demand inflation;a quick-working relationship by which demand spilled over into imports and, less spectacularly, into reductions in exports (these relationships raised the whole question of the incorporation of international trade into economic analysis); and

a slow-working relationship by which excess demand for goods and services created additional demand for capacity-creating investment (this ‘accelerator’ relationship further increased capacity utilisation and initially worsened inflation, but to the extent that investment demand crowded out consumption it increased the capital stock, raised capacity and eventually dampened inflation).

Further investigation and experience transformed the accelerator into a relationship between investment and business retained surpluses: the greater the surplus, the greater the level of investment. Further investigation also transformed the account of the relationship between capacity and inflation. Current modelling allows for inflation resulting from the following:

excess-demand;

cost-push (fundamentally a result of incompatible income claims);

imports (reflecting the net effect of inflation overseas and movements in the exchange rate); and

monetary sources (fundamentally a result of lack of control in the financial sector, public and private).

Capacity was gradually transformed from a near-engineering concept to one much more closely related to levels of activity above which inflation was likely to accelerate, and which itself depended on such variables as workforce skills.

Although long-run growth analysis is conveniently carried out in values adjusted for inflation, it is still important to include the inflation rate in forecasts, partly because it is a policy target (hence, a determinant of RBA behaviour and in some policy eras of Treasury behaviour as well) and partly because of its influence on economic behaviour, for example the behaviour of firms when assessing investment in fixed capital. NIEIR keeps in mind the various types of inflation, and makes an assessment of the strength of each mechanism. In the immediate wake of the global financial crisis the following assessments applied:

excess demand inflation was reasonably under control, but could break out if there was a reduction in the supply of imports;

cost-push inflation was initially defeated by the 1980s Accord and the probability of recurrence was further reduced by the Commonwealth’s moves to weaken the unions and transfer wage bargaining to the enterprise level;

a break-out of imported inflation will accompany any devaluation of the Australian dollar but was not a threat at current exchange rates, given the world outlook; and

monetary inflation was not a threat, given that the banks were more likely to be trimming their balance sheets than expanding them.

However, with the world economy in turmoil nothing should be taken for granted.

 

The overseas sector

There is a sense in which the overseas sector fits neatly and naturally into the Keynesian variables of the National Accounts. Exports add to demand and imports add to supply. Australian export earnings can be modelled as essentially demand-driven, industry by industry, from projections of world growth. Allowance can also be made for domestic supply constraints. Imports can likewise be modelled, industry by industry, by estimating domestic supply at the world-parity price and calculating imports as domestic demand less domestic supply and exports.

In this context, NIEIR has benefited as the Australian representative of the United Nations LINK project. Under this project, NIEIR annually prepares forecasts of Australian economic activity, including exports and imports by commodity. Along with its colleagues in other countries (most UN members participate), NIEIR submits its forecasts to the LINK secretariat, which reconciles the national forecasts using the requirement that one country’s exports are another country’s imports. The revised estimates are published and contribute to NIEIR’s forecasts.

Turning to the financial components of the balance of payments, earnings on Australian overseas investments can be calculated from the value of these investments and the rate of return, which is influenced by world growth and monetary conditions. Likewise, the earnings of overseas investors in Australia can be calculated from the value of their investments and the rate of return, as influenced (for equity investments) by the profitability of businesses in Australia and (for debt) by the Australian interest rate. As a consequence of Australian net indebtedness to the rest of the world, Australian interest rates are reliably above world rates, a requirement that limits the RBA’s capacity to influence interest rates.

It is agreed by all analysts that imports and net debt servicing have to be paid for and the ultimate source of foreign exchange with which to pay is export revenue. However, imports can also be paid for from capital inflow, known as a deficit on the balance of trade. Capital inflow results in net debt servicing costs and the addition of these to the balance of trade yields the balance of payments. The question for forecasters contemplating the typical Australian balance of payments deficit is how long it can be sustained by continued capital inflow and how far it will blow out. This involves forecasting both overseas willingness to lend to Australia and Australian willingness to borrow on the terms offered by overseas lenders.

Analysing Australian experience up to 1990, NIEIR employed the concept of the balance of payments constraint to growth. When the balance of payments deficit threatened to become excessive, three mechanisms came into play. First, the high interest rates required to attract overseas loans cut into Australian demand, reducing incomes and so reducing imports. Second, when alarmed over the deficit, the Reserve Bank imposed credit squeezes: quantitative controls over borrowing that acted to reduce incomes and imports. If these were not enough, the Treasury would tighten fiscal policy, further reducing incomes and imports. In the era of exchange and interest rate controls, up to the 1980s, the Commonwealth institutions alternated between periods when they used ‘high’ interest rates to support a ‘high’ exchange rate in the hope that low-priced imports would curtail inflation and periods when they used ‘low’ interest rates to support a ‘low’ exchange rate to encourage export and import-competing industries.

At deregulation the Reserve Bank forswore the quantitative regulation of the banks and the Treasury forswore active fiscal policy. The balance of payments constraint seemed to evaporate as the banks demonstrated a hitherto unsuspected capacity to absorb overseas loans, which they on-lent to the household sector. Successive national balance sheets chronicled an increase in bank liabilities to overseas and in household liabilities to the banks. The policy authorities regarded the resulting balance of payments deficit as benign: it was incurred between private parties and imports of low-cost consumers’ goods were welcome because they kept inflation down. The question for economic analysts is how long this pattern of household and bank debt accumulation can last. There was a severe wobble during the global financial crisis and the indications are for a return to balance of payments constrained growth, but when, and with how much of a bump, is one of the current conundrums of forecasting.

When deregulation was being pursued, one of its expected benefits was that market determination of the exchange rate would ensure appropriate pricing of imports and exports and so equilibriate the balance of payments. In the event, since 1990, the AUD/USD exchange rate has fluctuated between parity to AUD2 for each USD without any commensurate relationship to economic fundamentals. The exchange rate matters for forecasting – it affects the AUD values of all entries in the balance of payments and so finds its way into GDP – but has turned out to be very difficult to forecast. This would not have surprised Keynes, who had sufficient experience of financial markets to know their speculative jitteriness. In its forecasts, NIEIR takes into account commodity prices (which seem to influence the exchange rate far more than their significance for the economy) and interest rate differentials.

 

Investment

In neoliberal economics, finance for fixed capital investment is distributed by a cool and rational finance sector. By contrast, in the macroeconomics of Keynes’ General Theory, investment depends largely on animal spirits. NIEIR makes use of the Flow of Funds statistics, which show that there is very little net flow of funds from Australian financial intermediaries to businesses making major investments in fixed capital: funding is generally from internal sources backed up by direct access to international equity markets. In these circumstances, the Taylor rule is generally appropriate: fixed capital accumulation depends on industry retained surpluses with inflationary expectations taken into account through a downward adjustment when the inflation rate rises. This rule has the technical advantage of ease of econometric estimation at the industry level. 

It has been argued in economics that forecasts of real capital accumulation should be forward-looking, emphasising the expectations of investors. For many years, NIEIR experimented with the data from surveys of investment expectations but found that realisation rates varied cyclically except for large-scale committed projects. NIEIR continues to use project lists to forecast expenditure for committed construction projects but otherwise argues that recent retained profits are as good a proxy as any for profit expectations. They accordingly exercise a strong influence on both the ability and willingness to invest.

Although based on the National Accounts and macroeconomic theory, NIEIR’s models have been extended from the world of Keynesian aggregates to include inter-industry accounting as pioneered by Leontief. As perceived by Leontief, the industries of any region take inputs and create outputs. The inputs comprise capital, labour and ‘materials’, the outputs of other industries in the region plus imports from other regions. The outputs of each industry are divided between inputs to other industries in the region, exports to other regions and consumption of final products by households in the region. This classification elaborates the Keynesian aggregates. For example, aggregate consumption is the total of industry outputs sold to consumers plus imports sold to consumers, while gross domestic product is the sum across all industries of the cost of capital and labour inputs. For this reason, it fits very neatly into NIEIR’s modelling system.

For reasons of data availability, this scheme is most readily actualised at the national level. Data are required on the values, by industry, of output, labour inputs, capital inputs, inputs from each other industry, inputs from imports, outputs sold to each other industry, outputs sold as exports, outputs sold to consumers and taxes paid less subsidies received. Price series are also required for all inputs and outputs. At the national level, all of these values are either directly estimated by the ABS or can be derived from ABS data. The input–output matrix is a central element. Unfortunately, it is not produced as frequently as the other data but after allowing for this it is possible to develop time series for all the variables required to describe activity in Australian industries as classified by the ABS: over 100 in the input–output table.

A crucial element in the analysis of this plethora of data is the functional form of the relationship between inputs and output. Because there are several inputs, the functional form must be able to deal with the choice of inputs. Assuming standard qualities for each input, this amounts to the rate of substitution of input for input when the ratio of input prices changes. Leontief responded to this problem by letting the data speak for itself. He specified a relationship in which outputs increased with inputs, but inputs could be either substitutes or complements: substitutes when purchases increased when relative price fell; and complements when purchases increased when the relative price of the complementary input fell. Apart from these limited priors, Leontief allowed the data to determine the parameters, including lagged changes. Applying this approach to Australian manufacturing industry data, NIEIR found that the response to an increase in demand is indeed dynamic, with inputs tending to be harder worked initially followed by an adjustment as capacity was increased. The effect of working inputs harder shows up as a short-term increase in productivity, or returns to scale, and the effect of increasing capacity is to remove at least some of these economies of scale. However, even after 5 years of adjustment, there were many industries in which increasing returns to scale persisted. Similarly, industries were identified in which at least some inputs were complementary: most commonly capital and inputs purchased from other industries (‘material’ broadly defined to include services). All of these estimates, including the dynamics, were well suited to incorporation into the model outlined above. Incorporation allowed the drivers of many of the macroeconomic variables (demand for labour, capital accumulation, value of output, imports and exports) to be calculated by aggregation from the industry level, subject to consistency conditions (e.g. total sales of consumption goods must equal total demand for consumption goods as determined by household incomes, wealth and the like).

 

The generalised Leontief cost function

Underlying the generalised Leontief production function is a cost function that has the desirable property that it can be regarded as a second-order approximation in prices to any arbitrary cost (and, hence, production) function.

The general form of the desired factor input function can be derived from the generalised Leontief production function as follows:
i=1

+ bj,n+1 fj(Q) + exogenous variables}

(j,k = 1, 2, …, n)

where fj(Q) and f(Q) are unspecified, monotonically increasing functions in output. For the equation to describe an underlying production technology, the regularity condition summarised above must be satisfied, for which bj,1 … bj,a+1 must be zero or positive for all j.

The generalised Leontief cost function is comprehensive, because it describes all the types of production technology that produce positive outputs. There will be a variable elasticity of substitution between factors j and k if at least one bj,k, j ≠ k, is non-zero. The function also allows for complementarity between factors, which exists if bj,k is negative: if bj,k is positive, the traditional substitutability assumption applies.

Although this approach to the data is straightforward, it requires a certain amount of unlearning by those who have previously encountered input–output tables only in the context of equilibrium theories. The first difference is the introduction of dynamic instead of instantaneous adjustment, the second the unrestricted form of the relationships (hence, for example, increasing returns to scale can occur), while the third, and more subtle, difference is that changes in outputs and inputs are not so strongly driven by prices. Instead, quantity adjustments can occur, in the same way as they occur in the macroeconomic model.

As an example, the energy industries are identified in the national model complete with input–output relationships with other industries and with their own internal relationships by which inputs are transformed into outputs. In the energy industries, inputs of capital are particularly important, reflecting not only the capital-intensive nature of the industries but the importance of technology in governing the transformation of fuels and other energy sources into useful energy. At the broad level, the various transformation technologies are represented by coefficients that reflect the productivity of capital embodied in succeeding vintages of the various technologies employed. The system thus describes the changing sensitivity of costs to the prices of fuel and capital. This summary account of the energy industries is incorporated into the model at the national level; however, much more detailed modelling of the demand for energy is required when preparing forecasts for particular energy industries.

The national model is complemented by state and local models, to which we now turn.

 

The state and regional models
Australia is geographically a large country, and the growth rates of economic variables generally diverge regionally. A first step in analysing these divergences is to move from the national to the state and territory level.

State activity

The ABS estimates and publishes most of the National Accounts data at the state and territory level, so providing the basis for constructing similar models to the NIEIR national model at the state/territory level. The main differences are as follows:

A number of drivers are determined at the national level and applied across the board to the states. These include the exchange rate, financial variables, such as the interest rate, and variables reflecting Commonwealth policy.

Capacity constraints are a little more flexible. For example, a state that is growing faster than the others will be better able to attract skilled labour, allowing its skilled labour supply to grow more rapidly than the national total.

Some of the statistical detail used in the estimation of the national model is not available at the state level, and has to be estimated. This is particularly true of the input–output table, which NIEIR estimates at the state level using a methodology similar to that used by the ABS for the national table, subject to national-level constraints.

At the state level, particular construction and investment projects increase in prominence in relation to the general flow of economic activity. Because they result from individual decisions, these are unsuited to econometric modelling. Instead, NIEIR maintains project lists and decides on the basis of such information as is available when listed projects are likely to be undertaken. Care is taken to avoid double counting.

When preparing general economic forecasts, which to a large degree are driven by world and all-Australia trends, NIEIR runs the national model and then estimates state impacts using the state models. This involves operating the state models in top-down mode, in which state estimates of macroeconomic variables are derived from the national estimates by applying ‘shift-share’ functions. These functions might be simple

(e.g. allocation by state in proportion to a single driver) or sophisticated (multiple drivers, feedbacks or lags). The simplifying assumption underlying this methodology is that national trends are experienced pro-rata by the states, without any interaction between the states. If interaction is expected, it is necessary to go to much more detailed modelling that covers the dynamics of each state and its effects on the other states and territories.

Although state models remain relevant to the assessment of state-level policies, their main role is to provide control totals for the regional modelling system. These align the regional models with National Accounts data, the state being the smallest jurisdiction for which these data are published.

 

Regional models

Reflecting the structure of Australian governments, NIEIR generally defines local regions as local government areas (LGAs). However, other definitions are possible: virtually any geographic area can be defined as a region for modelling purposes.

As at the state level, reasonably accurate business-as-usual forecasts can be prepared with relatively little effort using top-down methods, applying shift-share functions to allocate national and state totals to LGAs. Similar methods are appropriate for most policy changes at the Commonwealth level, such as the effect on regional incomes of a change in tax rates. It is even appropriate to use top-down methods in the case of major investment projects that impact particular LGAs, one or a small number, provided there is no direct impact on their neighbours. In this case, the projects can be added to the LGAs concerned, to the state concerned and to the national total. The revised national forecast, excluding the effect on the directly affected LGAs, can then be allocated to the remaining LGAs by shift-share.

This approach is inadequate for the assessment of developments where regions interact with each other.

Interaction can only be described using ‘bottom-up’ modelling, in which each region is modelled in its own right as though it represents a country in a world model. This requires replication of the structure of the national model for each region. The national model then disappears from forecasting, national totals being calculated by summing the regional totals.

Replication of the national model at the regional level requires that each region should have its own household sector, its own industries and its own inter-industry relationships, all joined to other regions by explicit trade links (imports and exports) and explicit financial flows (including transfer incomes and commuter incomes and expenditures). The data requirements for this approach are very large, because for each region the following datasets are needed:

– aggregate household income and expenditure accounts showing income received, income outflows, savings and aggregate housing and consumption expenditures;

– basic aggregate household balance sheets, including property values and debt;

– input–output tables or inter-industry flows for industries operating within the region;

– foreign trade flows showing how each industry in a given region allocates exports to overseas markets and purchases imports from overseas;

– inter-regional trade flows showing how each industry in a given region sells goods and services to, and buys them from, industries in each other region in Australia;

– income flows showing how incomes flow between regions due to commuting, property incomes, government benefits and government-financed services; and

– expenditure flows showing how expenditures flow between regions due to taxes, superannuation contributions and out-of-region shopping.

 

The main problems in estimating models at the LGA level are due to data availability. Therefore, we name the major sources:

at 5-yearly intervals the Census provides detailed information on household demography, incomes, occupations, industry of employment and even basic information on asset ownership and indebtedness;

the Census also provides detailed information on the location of employment by industry and occupation. This is derived from the Census

‘journey to work’ question, and requires manipulation before it can be reconciled with Census data on employment by place of residence;

the Taxation Office provides detailed information on taxpayer characteristics by postcode, which NIEIR converts to LGA using a concordance produced by the ABS;

Centrelink likewise provides postcode data on the take-up of pensions and benefits;

at a variety of time intervals (generally getting longer) the ABS has conducted censuses of tourist accommodation, retail activity, manufacturing, mining and agriculture. For many years the ABS conducted a very basic census of businesses, known as the business register. This has been partially replaced by data from Dun and Bradstreet; sample surveys rarely yield valid data at LGA level, the partial exception being the labour force surveys of employment and unemployment produced by the Commonwealth Department of Education Employment and Workforce Relations. However, data from a variety of ABS surveys have been incorporated into NIEIR’s regional modelling; building approvals data are a source; the Real Estate and Stock Institute provides data on dwelling sales and values; and various other sources, mostly administrative data from state and local governments, are relevant from time to time.

Many of these data are costly and their use is limited by agreements to safeguard privacy and commercial confidentiality.

The model estimated for each LGA is structurally similar to those estimated at the national and state levels. However, the small size of LGAs results in a number of differences:

projects undertaken and decisions made by large employers (e.g. plant closure, plant upgrading) can completely dominate local economies and leave them open to idiosyncratic business and investment decisions. Where this is known to be the case, data on the particular project or employer decision is substituted for model-based forecasts; and LGAs, being small, are particularly open economies. Typically, a large proportion of total output is exported (to other LGAs, to overseas) while a large proportion of total supply is imported.

The lack of self-containment of LGAs also expresses itself in the flow of incomes from outside the LGA. These include commuter incomes (earnings of residents who work outside the LGA), private asset incomes and government pensions and benefits. LGA residents also contribute to taxation, and receive health, education and other publicly-financed services. These, in turn, generate employment, which is located at the discretion of governments. Although fixed capital capacity constraints apply strongly at the LGA level, labour can be imported readily, subject only to national constraints. However, labour imports may require incentive payments, particularly if the regional housing market is tight.

The household sector in the National Accounts includes households in their domestic activities plus family businesses and not-for-profit organisations. The incomes of the household sector are estimated from a combination of sources, including the Census, the Taxation Office and Centrelink, plus Institute calculations for the activities of unincorporated business. Consumption expenditures are estimated through microsimulation by matching the Household Expenditure Survey with the characteristics of local households. Consumption expenditures are initially classified by consumption item as in the Expenditure Survey, but these are translated into industry outputs (including imports from overseas by industry). Balance sheets are estimated by microsimulation from the balance sheet portion of the Household Expenditure Survey coupled with the limited Census data on assets and debts and data from other sources on dwelling prices and household debt. 

Estimates of the quantum of agricultural output are available by LGA. For modelling purposes, past agricultural production is normalised to standard weather patterns, after which the quantum can be converted to a value by application of price indices (which themselves might require normalisation for weather). For other industries the value of output is estimated primarily from employment data by industry multiplied by regional labour productivity differentials based on postcode income tax data. The estimates for knowledge-based industries are further modified to take into account the productivity effects of regional industry clusters.

A separate input–output table is estimated for each LGA by matching industry input requirements to industry outputs in the same LGA, given the total outputs of each and the patterns revealed in the national input–output table, which, incidentally, restricts disaggregation to 106 industries.

The first step in the estimation of trade flows is the construction of household accounts for each region. On the income side, regional household income is known reasonably accurately from the Census, taxation and social security data. Microsimulation models are used in conjunction with information about house prices, rents, mortgages and survey data to estimate total financial assets, financial liabilities, savings and consumption expenditure of households resident in each region. Microsimulation modelling involves matching survey data at unit record level, principally the ABS Household Expenditure Survey, to Census and regional activity data (such as retail sales) to estimate household consumption expenditure by region. The estimates are highly disaggregated. Expenditures are constrained so that the sum of expenditures by commodity equals the total regional household expenditure estimate. This process ensures that income and socio-demographic factors are reflected in the estimates of regional expenditure patterns.
Households do not necessarily spend their incomes in their LGA of residence. Expenditures are accordingly allocated to local and nearby retailers by a gravity model. Similarly, households do not necessarily earn their incomes in their LGA of residence. The Census ‘journey to work’ question allows accurate allocation of work incomes received in each LGA to the LGAs in which they were generated.

The foundation for production estimates is the Census estimate of four-digit Australian and New Zealand Standard Industrial Classification employment in each LGA. Given the employment base, the value of production can be estimated by multiplying employment for each industry by regional productivity differentials based on postcode income tax data. Farm income is also checked from agricultural output data. The estimates are checked for consistency with state-wide industry output data and the National Accounts state-level estimates.

Aggregate demand in each region totals net consumption (after allowance for sales to residents of nearby regions balanced against cross-border purchases by residents of the region), government expenditure, tourist expenditure (estimated from employment structure), investment expenditure and industry demand. Investment expenditure by households is mainly on housing and is modelled with reference to household formation, the supply of dwellings and household balance sheets (which document the capacity to borrow). Business investment covers both construction and equipment and is modelled (as in the national model) on the basis of business cash flow. Industry demand comprises investment demand and the demand for business inputs, which are calculated from regional input–output relationships.

 

Regional input–output

At the national level, the ABS publishes input–output tables that represent the flow of goods and services between industries. This information for the Australian economy as a whole can be adapted for regional use by taking four steps.

A national indirect allocation of imports table is prepared, showing the overseas import content of supply in each industry, the destination of supply (either inputs into various industries or final demands) and the mark-up between import costs and the prices charged to purchasers.

The information already described on industry output and consumption expenditure spent in the region is gathered. From the national input–output table, the region’s input requirements by industry are estimated given its industry outputs and consumption. How much of this input requirement is likely to be sourced locally is determined. This requires not only that local supply be available but that it be competitive with outside suppliers. The indicator used to assess likely local competitiveness is the import share in national supply as estimated in step 1.

For each industry, an increase in sales to other regions (exports) will yield increases in demand for the outputs of local industries, either directly as purchases of inputs or indirectly through the generation of household incomes which are spent locally. Dividing the resulting increase in local production by the increase in exports yields an estimate of the Type 1 multiplier: the increase in local output as a result of increased local sales, all other factors held constant. In further analysis there might be feedbacks: for example, increases in local wage rates that cause wage-sensitive local production to be curtailed, thus offsetting the initial stimulus. Whether or not this or other offsets occur depends strongly on local circumstances.

In addition to this basic analysis, regional input–output estimates can be strengthened by the addition of data, including details on employment, incomes and the extent to which profits generated in the region are retained within the region.

 

Freight flows

For each industry, data on overseas exports and imports is available by port and by state of origin/destination in both dollar value and tonnes. Given these constraints, a cost minimisation algorithm is used to allocate international exports and imports by port to the industries of each region. This assignment is iterated until a consistent balance is achieved across all regions and ports. Once international imports and exports by industry have been allocated by region, inter-regional exports and imports can be estimated as a residual. This is done using a gravity model. The gravity factors in the model are adjusted for variations in the substitutability of the items included in the output of each industry in a given location. The lower the substitutability, the greater will be the tendency of production in a given location to sell to the national market. Over time, increasing specialisation in production will tend to lower the degree of substitutability between plants in the same industry in different locations. The substitutability factors for each industry were estimated on the basis of differentials in net interstate imports by industry and by state.

A similar gravity model approach is taken with services, on the grounds that many services involve physical travel, which causes friction of distance, as with freight.

Although the basic unit of calculation is monetary values, trade flows in industries with physical outputs (as distinct from services) can be converted to tonnes using estimates of $/tonne. These can be compared to data on truck movements and reviewed if necessary.

Regional forecasting and analysis using the integrated regional model structure

Forecasts are prepared at the LGA level for the major economic indicators: population (including migration as a result of economic incentives), business value-added (or gross regional product, by industry), employment, income (by source) and consumption (by good or service purchased). The main factors driving the forecasts in each LGA include the following:

the dynamics internal to the LGA, including local demography, local holdings of wealth and debt, dwelling prices, local productive capacities of both capital and labour and local accumulation of capital and skills;

the effect of specific local changes, such as investment projects where the decision lies outside the forecasting model proper;

the local effect of changes in other LGAs through inter-LGA trade and income transfer mechanisms (these include the local effect of changes driven at the national, and occasionally state, levels, and these drivers are applied in each LGA-level model); and

in practice, and depending on judgement concerning the closeness of LGA relationships, changes in peripheral LGAs might be estimated by calculating a national total then cascading down from the national and state models through the effect of drivers determined in these models (e.g. interest rates and prices) and through the pro-rating process.

 

The regional modelling system is updated annually (with a special update after every Census). The update involves calculation of variables, such as regional value-added, which are not otherwise published. NIEIR groups Australia’s LGAs into 67 regions, and values for these regions along with short-term forecasts for each region are published annually in the ‘State of the Regions’ report for the Australian Local Government Association.

 

Modelling in practice

The NIEIR modelling system comprises a family of interacting, mutually-compatible econometric models adapted for both forecasting and analysis. Forecasting and analytical tasks are carried out using appropriate subsets of the family of models.

Because they are inherently dynamic, the models by their nature generate forecasts. These forecasts are driven partly by relationships internal to the models, but also by factors treated as exogenous, of which the most significant are world trade and finance. Exogenous variables become less and less reliable as they recede into the future, and so do endogenous relationships embedded in the models; therefore, beyond a decade or so, projections should not be regarded as forecasts, but rather as exploratory scenarios: business as usual perhaps, but not really business as expected.

Because the models cover all industries and all parts of the country, they can be used to prepare detailed forecasts for quite specific variables. A major area of forecasting expertise concerns energy demand, where the usual economic drivers have been supplemented by meteorological probability functions to predict peak electricity demand.

The models have also turned out to be powerful for policy analysis, using the simple methodology of dual projection: a business-as-usual or base case compared with a policy case. Welfare judgements can be made by a variety of variables, such as the effect on GDP, the effect on disposable income, the effect on sustainable consumption and the effect on the distribution of disposable income. Policies modelled can involve changes to prices, changes to technology, particular project investments variously financed, and changes to taxes, regulations and expenditures at all three levels of government. There is no difficulty in accommodating differences in timing.

Despite this general usefulness, when analysing particular proposals it has usually proved desirable to review and if necessary reconstruct the parts of the model(s) directly relevant to the proposal. This can include detailed attention to the local economy of an LGA, detailed review of the economics of an industry or perhaps detailed work on skills or finance. In these studies the general modelling provides background to the sector or region examined in detail. Lessons learnt at these detailed levels are fed back into the general modelling.

In the construction of forecasting models, the general methodology used by NIEIR has no serious competitors. However, in policy analysis it has been fashionable to resort to general equilibrium models, which claim to cover the whole ground of relationships relevant to economic policy assessment but in practice do so largely by assumption. General equilibrium models are exceedingly abstract, based as they are on a fundamental assumption that economies can usefully be divided into autonomous markets and analysed in terms of price-mediated balances of demand and supply in each market. NIEIR claims that its models are significantly closer to reality. They do not assume away mathematically inconvenient aspects of the economy and, hence, are less likely to deliver counter-productive advice.

 

 

 

 

 

 

 

 

 

 

Energy and the Environment (NER 63)

National Economic Review

National Institute of Economic and Industry Research

No. 63               March 2010

The National Economic Review is published four times each year under the auspices of the Institute’s Academic Board.

The Review contains articles on economic and social issues relevant to Australia. While the Institute endeavours to provide reliable forecasts and believes material published in the Review is accurate it will not be liable for any claim by any party acting on such information.
Editor: Kylie Moreland

© National Institute of Economic and Industry Research

(Australian Farm Institute for the first article)

This journal is subject to copyright. Apart from such purposes as study, research, criticism or review as provided by the Copyright Act no part may be reproduced without the consent in writing of the relevant Institute.

ISSN 0813-9474

Energy and environment

Graham Armstrong, Consultant, NIEIR

Abstract

This paper reviews the global and Australian developments during the months leading to the Copenhagen COP-15 commencing 7 December 2009. As of 20 November it seemed unlikely that a consensus on emissions caps and the role of developing countries (non-Annex B) would be reached. Cuts below 1990 emissions are being sought from developed nations, as well as a slowing of emissions growth by non-Annex B nations. The investment costs to reduce emissions levels below 1990 levels will be huge. In addition, to achieve these reductions more stringent policies are required. The legislation progress and climate action developments of Australia, the USA, China, Japan, Russia, India and Canada are reviewed in the present paper.

Introduction

The 6 months prior to Copenhagen COP-15 saw considerable activity on climate change policies both internationally and in Australia. As this chapter was being finalised, the fate of the Australian carbon pollution reduction scheme (CPRS) was undecided. Set out below are reviews of the global and Australian developments.

Climate change policy options: Senate requests for further modelling

On 22 June 2009, the Senate Select Committee on Climate Policy released a report. The first recommendation was that Treasury be directed to do more modelling of the effects of the CPRS, including considering transition costs, effects on jobs and the environment and effects on regional Australia, allowing for the deterioration in the Australian economy.

The committee recommended Treasury be directed to model five policy alternatives:

  1. a ‘baseline-and-credit’ scheme;
  2. an ‘emissions intensity’ model;
  3. a carbon tax;
  4. a consumption-based carbon tax; and
  5. the McKibbin approach.

Options 1–3 and 5 target Australia’s production of emissions, including those exports that do not affect Australia’s emissions imports. Option 4 targets spending on emissions (embodied and use emissions consumption) and would apply to local spending, including imports and excluding exports. All options involve pricing carbon, whether applied to production or consumption. Another recommendation was that a CPRS-40 (cap of 40 per cent below 2000 emissions in 2020) be modelled.

The Treasury modelling report stated on page 84 that: ‘Emissions allocations based on production are likely to result in higher welfare costs for Australia than allocations based on consumption’. This implies that a consumption-based policy is lower cost than a production-based emissions trading scheme (ETS).

In a draft report open for comment, Climate Strategies provides climate policy modelling results for selected emissions intensive trade exposed industries (cement, steel and aluminium) operating in the European Union (EU). The modelling evaluates ‘carbon leakage’ under six policy options for dealing with trade exposed industries:

  1. full border adjustment (BA full), roughly equivalent to a consumption base;
  2. BA import (BA only for imports);
  3. BA direct (adjustment of exports and imports but only for direct emissions);
  4. BA EU average (adjustment for imports based on the EU emissions average);
  5. BA import direct; and
  6. full auction of permits.

The first five of these options are more or less comprehensive versions of the consumption -based carbon tax identified as option 4 by the Senate select committee. The sixth option is a particular variant of a production-based approach: a pure ETS. For cement, steel and aluminium, the first option, BA full (closest to a consumption-based carbon tax), delivers the lowest carbon leakage. The sixth option (full auction of permits to producers) generates the highest carbon leakage. A consumption-based ETS/tax would reduce the carbon leakage reason for not acting now on climate change.

Carbon pollution reduction scheme: 4 May revisions

2011–2012

Fixing a $10/t CO2e price will:

  • raise revenue (approximately $400 million);
  • not change generator merit order as brown coal generators with <$5/MWh short-run marginal cost (SRMC) and with greenhouse gas intensity at 1.2–1.5t CO2e/MWh would have SRMC increased by $12–15/MWh, to $17–20/MWh. Black coal $8–15/MWh SRMC would have SRMC and 0.8–1.0t CO2e/MWh increased by $8–10/MWh, to $16–25/MWh (lowest in Millmerran and Kogan Creek, Queensland, and Victoria protected due to transmission costs); and
  • have very low impact on electricity use due to low demand elasticity.

2012–2013 on

From 2012–1213, a $46/t CO2e cap will rise at 5 per cent plus inflation until 2020. New forest plantations can generate permits from July 2010.

Carbon pollution reduction scheme: 24 November adjustments

After prolonged negotiations with the opposition, the Federal Government announced several adjustments to the CPRS, outlined in Table 1. As the present paper was finalised, many details were not available.

The net budgetary impact over 10 years was estimated to be $769 million due to, it was stated, accounting procedures and a lower permit (CO2e) price (reason not stated: probably exchange rate assumption changes). Why the permit price would be lower was not explained, but the lower price reduced compensation to households by $916 million. Lower permit prices are probably due to higher exchange rate assumptions and, hence, lower Australian dollar prices of international credit purchases.

The total CPRS assistance package to industry to 2020 now amounts to approximately $120 billion. Whether CPRS-5 will be attained through a mix of domestic actions and purchase of international credits or through external balance effects is yet to be determined.

NIEIR’s current CO2e price scenarios

Following the Garnaut Review paper in June 2008, the Green Paper of the Federal Government in July 2008, the White Paper in November 2008, the 4 May 2009 revisions to the CPRS, and our analysis over the past year of likely Australian climate change policies, a CO2e pricing schedule was developed (see Table 2).

As emphasised above, analysis and projections have to be developed in the absence of emissions caps announcements, and detailed design announcements of an ETS (CPRS). The ‘base’ scenario is considered to be the most likely at this time (November 2009). A lower CO2e cost projection is considered very unlikely (P < 0.2), but a higher CO2e cost projection is a possibility (P = 0.3) post-2020.

In the base CO2e price scenario (essentially under CPRS-5) a higher cap is set and in the ‘high’ CO2e price (essentially CPRS-25) scenario a lower cap is set. The prices actually resulting over the period will depend on caps finally set, actual CPRS design, coal and gas prices, renewables costs, emission reduction technology developments and effectiveness of energy efficiency improvement (EEI) policies.

Table 1 E and E NER 63

 Table 2 E and E NER 63

Emission caps and reductions from business as usual (BAU) to 2020 are presented in Table 3.

Table 3 E and E NER 63

Sources of emission reductions

Domestic actions would largely fall on the stationary energy sector but international permit purchases could limit the domestic actions required, depending on the relative costs of international permits and the costs of domestic greenhouse gas abatement (GHGA).

The base scenario results in lower GHGA permit prices and electricity price impacts, and the high scenario produces higher GHGA, permit prices and electricity prices. We regard these two scenarios as covering the likely range of permit prices to emerge over the next 25–30 years. However, very stringent targets, for example the 40 per cent emissions reduction below 1990 levels by 2035 suggested at Bali COP 13 in December 2007 and Garnaut’s ‘necessary’ cap of a 90 per cent reduction by 2050, could see permit prices rise to much higher levels. In practice, in any scenario there could be significant volatility in CO2e prices as the system adjusts to the CPRS.

Impacts of the two scenarios on energy prices

In the electricity generation area there is relatively good data on generation SRMCs and long-run marginal costs (LRMCs) . Thus, it is reasonably straightforward to estimate the impact on SRMCs and LRMCs of permit price, the main caveat being future gas and black coal prices. There is less reliable data on the costs of reducing emissions from generators (e.g. via carbon capture and storage) and from emissions in other greenhouse (National Greenhouse Gas Inventory) sectors where abatement could contribute to attainment of a given cap. Over time, generator energy efficiencies will improve and reduce the impact of CO2e pricing on new generation entering the market. Accordingly, it is difficult to predict the permit price that would produce the abatement required to attain a given cap (EEI and generator mix responses) and to estimate the impact of permit prices on electricity prices.

In addition, demand responses to increased energy prices and to complementary measures that contribute to GHGA will reduce the permit price required to attain a given cap. In the EU ETS, and proposed by the Australian state/territories work on an ETS as well as the White Paper and Garnaut, complementary measures to cover EEI, renewable energy (RE) targets and support for R&D, demonstration and commercialisation are seen as desirable. Federally, there appears to be some ambivalence on EEI and RE complementary measures. Effective EEI measures such as minimum performance standards, rebates and targeted business sector programs can provide significant GHGA at lower costs per tonne of CO2e than can be delivered by reducing greenhouse gas (GHG) emissions from fossil electricity generation.

Higher mandated renewable electricity targets, although delivering relatively high cost abatement (>$30/t CO2e), reduce the contribution from fossil generators of delivering a national greenhouse gas abatement target from an ETS because this RE GHGA contributes to the cap outside the ETS. The mandated contribution from RE increases electricity prices until CO2e inclusive fossil generation costs rise to RE cost levels.

For NEMMCO and Transgrid in April 2008, NIEIR estimated impacts of an ETS on generators in the inter-connected NEM regions based on ACIL-Tasman (for NEMMCO, 2007) SRMC estimates and NIEIR LRM/AC estimates. For Western Australia the resulting electricity prices are likely to be similar as the generation mix (black coal and gas) is broadly similar to that in the NEM. In the Northern Territory, which has a gas-based system, the impact will be lower. Again, we emphasise that without details of the final ETS design and modelling of these details, it is only possible to develop broad estimates of future electricity prices under an ETS.

Note that the estimates for existing and new gas plants depend on the price at which gas can be sourced (there are low and high views on future gas prices) . In addition, for new gas plants the capital costs are escalating as demand for gas turbines increases globally. New coal plants are also subject to cost (capital and operating) pressures but not to the same extent as new gas plants.

Note also that coverage of fugitive emissions as proposed in the CPRS increases the fuel costs for gas and black coal generators and for gas use in water heating. That is, the sent out costs of gas and black coal generators increase relative to brown coal generators (very low upstream emissions) because of the carbon cost of transport of the fuels to generators and the fugitives (methane, CO2) from production and processing. In New South Wales, these indirect (Scope 3) emissions for large users of gas (generators etc.) are 0.013t CO2e/GJ and for coal depend on the actual coal source, but average approximately 0.009t CO2e/GJ. In New South Wales for gas each $10/t CO2e would add approximately $0.13/GJ to the price of gas, for a CCGT would add approximately $0.80/MWh and for ‘gassy’ black coal approximately $0.85/MWh.

If these emissions are covered in the CPRS design (as proposed) they would raise the costs of gas and black coal generators if, as expected, the fuel price impacts were passed on in fuel prices purchased by the generators.

Peak and off-peak electricity prices

Currently, in most regions, off-peak electricity (10.00 pm to 7.00 am) is met by coal plants. The exceptions are the Northern Territory and, to some extent, South Australia and Western Australia (in Tasmania, with Basslink in place, hydro water is conserved for peak operation and off-peak power is mainly imported from Victoria).

Under the CPRS, as permit prices rise, a level (approximately $30/t CO2e) will be reached where only very efficient coal plants (Millmerran and Kogan Creek) can compete with gas plants in off-peak periods. Gas plants will have to operate at higher capacity factors and coal plants at lower capacity factors at the projected permit prices required for the emissions cap to be attained. To maximise net revenues, coal plants will run in periods where pool prices are higher.

Demands in peak and off-peak periods will be met at a price where the marginal bidder, whose bid is necessary to meet demand, has an SRMC (including CO2e costs) lower than the spot price (in addition, some off-peak power is, and will continue to be, met by intermittent generators). Currently, peak electricity (i.e. outside off-peak) may be broken down into several periods (e.g. intermediate/shoulder, daily peak and summer peak). Currently, demands in these periods are met by a combination of coal, gas and renewables. In high peak periods (mainly on hot summer days), the marginal generators (those providing the last MWhs required to meet demands) are generally open cycle gas turbines (OCGTs) with perhaps some scheduled hydro generators.

Under the CPRS, OCGTs will still be (with hydro where/when available) the high peak suppliers because of their quick-start capabilities (coal generators cannot respond to rapid demand increases). When the spot price exceeds the CO 2e price adjusted SRMC of these generators, bids will reflect the prices these OCGTs need to cover their long- run average costs (LRACs) at their anticipated capacity factors.

The conclusion of the above discussion is that electricity prices in each period will rise to at least the level at which the marginal generator required to meet demand will cover that generator’s SRMCs. The marginal generators will, over time, have to meet their LRACs by operating in periods where the price of SRMCs gives them enough net revenues to enable their capital as well as operating costs to be covered. However, their capital costs will depend on their asset values: the lower the asset value, the lower will be the excess net revenues over SRMCs to service the asset value (capital costs). Asset values will drop if these excess (over SRMCs) net revenues are insufficient to service current asset capitalisation. Asset values may drop towards zero, at which point if revenues cannot cover SRMCs the plant will cease operation.

Average wholesale percentage price increases for CPRS-5, CPRS-15 and CPRS-25 estimated in the Treasury modelling are presented in Table 4. Higher wholesale electricity prices flow into the retail prices that are faced by households. In the initial years of emission pricing, average Australian electricity prices faced by households increase by 20 per cent for the CPRS-5 scenario and 38 per cent for the Garnaut-25.

The effect on households is muted by rising real incomes over time.

It is very important to note that underlying ($0/t CO2e) average retail prices have risen by approximately 25 per cent over the past 5 years (2004–2009), through increases in wholesale prices and through higher network charges. Similar, probably higher, underlying price increases are likely over the next 5 years, mainly due to higher network charges as networks are refurbished, augmented and extended. Currently, average residential prices (peak) in Victoria are approximately $180/MWh and in the absence of a CPRS could reach $230/MWh or higher by 2020 (2009 dollars). CPRS-5 would increase this price to approximately $275/MWh; off-peak prices would be approximately $185/MWh ($80/MWh in 2009).

Opposition modelling, emissions trading scheme design suggestions

The Coalition opposition commissioned Frontier Economics to model suggested CPRS amendments. Among these, the main amendments were as follows:

  • fugitive emissions from coal mining be excluded;
  • permanently excluding the agricultural sector from the CPRS but allowing the sector to create and trade accredited offsets;
  • reducing emissions through improved soil management, better grazing practices, increased forestry planting and maintenance and use of technologies such as biochar;
  • making power generators only liable for emissions that exceed an industry benchmark, rather than all their emissions (marginal CO2e tax); and
  • trade exposed industries to receive permits for all their emissions provided they conform to world’s best practice.

The Greens proposed (October 2009) a program of $22 billion to EEI retrofit all Australian residences (an approximate average of $2,750/house) and to limit purchases of international credits to 25 per cent of required emission reductions.

Table 4 E and E NER 63

United States climate legislation progress

A Senate Bill (Boxer–Kerry), the Clean Energy Jobs and American Power Act, is similar to the Waxman– Markey Bill: it calls for a 20 per cent reduction on 2006 emissions by 2020, which translates into a 7.3 per cent reduction below 1990 by 2020 (similar to CPRS-5 targets/caps). Seventeen per cent below 2005 (Obama/Boxer/Kerry) would be approximately 5 per cent below 1990 levels by 2020.

There are three main steps that remain to be taken before climate change legislation in the United States comes into force. First, the Senate will have to agree on the ‘Climate Bill’. Second, once approved, the Senate version of the text must be reconciled with the version that passed the House of Representatives. Third, the bill needs to be signed by the President.

China: Climate change action developments

Chinese emissions continue to increase significantly as economic growth continues, electricity generation based on coal soars, emitting industries continue to expand and personal consumption increases rapidly. However, there is also substantial action on GHG emission reductions through investments in EEI, RE and replacement of other greenhouse gases such as hydrofluorocarbons.

In China’s 2008–2009 stimulus package of A$650 billion, approximately 40 per cent was dedicated to sustainable initiatives. In the United States stimulus of A$850 billion, 12 per cent was allocated to such initiatives; of the Australian A$27 billion, 9 per cent; and the South Korea A$45 billion, 80 per cent.

Chinese initiatives

Chinese initiatives include the following:

  • solar water heaters: 50 per cent of global production, 65 per cent of installations;
  • photovoltaics: 40 per cent of global supply;
  • energy efficiency: energy intensity down 60 per cent since 1980, and a further reduction of 20 per cent by 2010; 240 million tonnes of coal equivalent reduction by 2010;
  • new building standard: 50 per cent savings compared to current standard;
  • subsidies to photovoltaic (PV) production;
  • installation of 25 MW of solar PV in 2008; 100 MW since 2000;
  • 6,000 MW of wind installed by 2008; 3,000 MW in 2007 increasing by over 40 per cent per year (doubled in 2008 to 12,200 MW) and could reach 100,000 MW by 2020; and
  • 15 per cent renewable electricity target by 2020.

China went to the Copenhagen conference with an offer of a significant (40 per cent) intensity (tCO2e/GDP) reduction by 2020.

Japan’s commitment

Japan’s Prime Minister, Yukio Hatoyama, pledged to cut GHG emissions by 25 per cent below 1990 levels by 2020. However, this proposal is contingent on similar ambitious goals by other major emitters. In 2008, emissions were 16 per cent above Kyoto targets for 2008–2012. Major initiatives to attain the Japanese target are an ETS and a feed-in-tariff for production of electricity from renewables. It is not clear what the domestic/international offset balance for emission reductions would be in meeting the target.

Japan’s largest business association, Keidanren, opposes cuts of greater than 6 per cent by 2020.

Russian situation

In 2007, Russia’s actual emissions were almost 34 per cent lower than in 1990. Since Kyoto, many experts have expressed concerns about these surpluses flooding the international carbon market, thereby lowering carbon prices.

It will be interesting to see what Russia’s position will be in a post-2012 climate regime. Russia has the legal right under the Kyoto Protocol to use its surplus assigned amount built up during 2008–2012 for complying with follow-up commitments after 2012 (conservatively assuming that Russia’s emissions will remain constant at 2007 levels, a tradeable surplus of well over 1 billion assigned amount units could emerge).

Russia has officially announced a 10–15 per cent emission reduction target compared to 1990 levels to be achieved by 2020. According to a study by Anna Korppoo and Thomas Spencer (The Dead Souls: How to Deal with the Russian Surplus?, 2009), this target ‘neither reflect[s] the country’s efficiency potential, nor modelled trends’. Korppoo and Spencer argue that Russia could commit to a target of approximately –30 per cent below 1990 levels by 2020.

Indian position

The Indian Government stated on 29 November 2009 that it would not commit to binding emission cuts, but would sign onto a deviation from BAU. India has taken significant steps towards increased penetration of renewables and EEI. Over the past 10 years there has been an average of 8–9 per cent economic growth, with only 3.8–3.9 per cent growth in energy use.

China, Brazil, India and South Africa agreed to a draft statement on climate change for COP-15 as a basis for negotiations. India might follow China in setting an energy intensity reduction target without jeopardising a 7–8 per cent growth continuance.

Global emissions market

In 2008, it is estimated that the global emissions market was worth approximately US$126 billion, of which approximately US$92 billion was trading in EU abatement allowances. Clean Development Mechanism (CDM) certified emission reduction (CER) credits were valued at US$26 billion, five times 2007 levels. European utilities are the most significant players in the market. They also use derivatives as an instrument to hedge against energy prices.

Credit prices dropped in 2008 and 2009 as the economy declined, reducing CO2 emissions, thus reducing the demand for allowances. EU abatement allowance prices in the third quarter of 2009 were €13– 15/t CO2e (A$21–24/t CO2e). CDM CER prices were slightly lower.

 

Canada

Canada’s greenhouse gas emissions keep on rising

Canada’s National Inventory Report for 2007 emissions was filed with the UN on 17 April 2009 in compliance with its reporting obligations under the Kyoto Protocol. The report shows that there has been a 4 per cent increase in GHG emissions in Canada since 2006 and more than a 26 per cent increase since 1990. This increase makes Canada the G8 nation with the most significant rise in GHG emissions. Under the Kyoto Protocol, Canada pledged to reduce emissions to 6 per cent below 1990 levels. This latest report confirms that as of 2007, Canada was 33.8 per cent above its international commitment. The report indicates that transportation and energy production are primarily responsible for the rise in emissions as these sources account for approximately 143 million tonnes of the 155 million tonne increase since 1990.

On 18 November 2009, the Canadian Government declared that it would not announce new climate change policies until 2010.

Alberta (Canada)

Alberta’s Climate Change and Emissions Management Act and its associated Specified Gas Emitters Regulation set province-wide emissions reduction goals and provide the framework and regulatory enactment authority for the regulations that set out the details of Alberta’s emissions reduction and trading regime.

Alberta has set targets based on emissions intensity (emissions reductions per unit of output) . Its legislative regime requires mandatory reporting for all releases of specified gas (the term used to define GHGs and their global warming potentials) from facilities that emit more than 100,000 tonnes of GHGs per year (referred to as Large Final Emitters). There are approximately 106 Large Final Emitters in the province. By sector, these Large Final Emitters are power plants (45 per cent), oil sands (21 per cent), heavy oil (7 per cent), gas plants (7 per cent), chemicals (6 per cent) and other (14 per cent).

Large Final Emitters were required to apply for the establishment of a ‘baseline emissions intensity’ by 31 December 2007. The baseline is calculated based on the ratio of total annual emissions to production. A Large Final Emitter must not exceed 88 per cent of its baseline emissions intensity (i.e. 12 per cent below the facility-specific baseline). Reduction amounts are currently static, but more stringent targets are contemplated in the future. The regime contemplates that all new facilities will be subject to gradual reductions from the fourth year of operation, reducing emissions by 2 per cent per year until a 10 per cent reduction is achieved. Those found to be out of compliance may be subject to a $200/tonne fine. Other penalties for contravention of specified sections of the regulation could result in penalties of up to $ 50,000 in the case of an individual and $ 500,000 in the case of a corporation (e.g. failure to submit the required compliance report: s.11). Emitters can also be subject to administrative penalties.

If they are unable to make the mandated reductions on-site, Alberta’s system allows regulated entities to buy credits from other regulated entities, to purchase offset credits or to make a payment into the technology fund. Payment into the technology fund is currently set at $15/tonne of CO2e. Offset project assurance occurs after offset credits are created. Offset credits do not have to be pre-approved before they are used; however, they must be verified by a third party and the reduction must:

  • occur in Alberta;
  • not otherwise be required by law;
  • have a project start date not earlier than 1 January 2002;
  • be real and demonstrable; and
  • be quantifiable and measurable.

Alberta offset projects use government approved protocols to establish the scientific basis for the ultimate assertion that GHGs have been reduced or removed as a result of the project. In Alberta there are currently 24 approved protocols and approximately 14 more are in the review process.

Verified offsets (‘emissions offsets’) can be registered with the Alberta Emission Offset Registry and sold to Large Final Emitters in Alberta. Offset owners may also choose to register and sell their emissions offsets inter-provincially and internationally. In such cases, trading occurs through bilateral contracts outside the Alberta Emission Offset Registry. The Alberta system does not allow offsets from any source outside of Alberta. Large Final Emitters that emit less than their allocation can trade their emissions performance credits or bank them for future use.

Payment into the technology fund was a popular method of compliance in the first round of the program, ensuring that the price of carbon would not move much higher than $15/tonne. In the first compliance period, 1.5 million emissions offsets were created and over 2.6 million tonnes worth of payments into the technology fund were made. In 2007, 1 million emission performance credits were created, but only 250,000 were used for compliance purposes. In 2008, 1.9 million tonnes of emission performance credits were generated and 1.3 million of those were banked for future use. 2008 also saw 5.47 million tonnes worth of payments deposited into the technology fund and 3.4 million offset credits generated, 2.7 million of which were used for compliance purposes.

There have been over 5 million offset credits created under the Alberta system. Alberta emitters have spent more than $155 million on technology fund credits and offsets. The program saw 32 per cent of compliance attained by real intensity reductions in 2007 and 38 per cent in 2008.

The Chicago and Montreal Carbon Exchanges

With respect to emission reductions, the Chicago Carbon Exchange (CCX) is a self-contained voluntary regulatory scheme and trading system. Credits can be created on the CCX, in much the same way as in a government regulated system. On the one hand, a company may become a member of the exchange and agree to reduce its carbon emissions, thereby becoming a sort of voluntary regulated entity. On the other hand, a company may create a reduction project, the reductions from which, once they have been verified by a verifier that is approved by the CCX, may be registered on the exchange and traded. In short, the CCX acts as its own regulatory framework and determines the reduction requirements for its members as well as the validation criterion for reduction projects that are entitled to register credits on the exchange. The market for which the CCX is a platform is a voluntary market, in that the participants are not bound by law to reduce their emissions.

The Montreal Carbon Exchange (MCX) for its part is not a platform for a voluntary market but rather a market for forward contracts for delivery of ‘Canadian compliance units’ that will be created in a future regulated market to be put in place by the Canadian Federal Government. As such, the MCX is reliant on the coming into force of an eventual federal GHG emissions trading scheme in Canada. The MCX does not determine reduction requirements for any of its members, develop criteria for the validation of emission reductions or do anything other than function as a trading platform and clearing house for the contracts described above. The trading unit is a contract for future delivery of 100 ‘Canada Carbon Dioxide Equivalent Units’. Each such unit will be an entitlement to emit 1 ton of CO2 equivalent in the system to be defined by the government of Canada. The contracts will expire quarterly and the first expiration date is June 2011. Currently, the rules of the MCX provide for the physical settlement of the contracts with an alternative delivery procedure being available to the parties on an ad hoc basis.

Montreal Carbon Exchange activity

Although the exchange opened on 2 May 2008, the level of activity has been negligible. Exchange representatives attribute this to the federal government’s failure to deliver key elements to its offset system promised in mid-2008. This failure, along with the federal government’s non-committal attitude toward the execution of its proposed GHG regulatory scheme has depressed activity on the CCX market due to the uncertainty that the underlying element of the forward contracts will be available for delivery on the contract expiration dates.

The trading volume for the first quarter of 2009 for the four contracts that are currently traded is very low. Until such time as the federal government begins to create more certainty with respect to the timing of the coming into force of GHG regulation in Canada, there is little reason to expect any significant pick-up in the transaction volumes handled by the MCX.

The MCX must now contemplate what it will do in the event that nobody comes to the party in June 2011. In February 2009, the MCX sent out a survey to market participants asking them to give their view on different courses of action that could be adopted by the MCX in the event that the federal framework for GHG emissions trading is not in place by June 2011.

 

United States Cash for Clunkers Program: Greenhouse gas emission and other impacts

This program, part of the United States’ stimulus package, cost approximately $3 billion and concluded in September 2009. Approximately 700,000 rebates were used to purchase new cars in July and August, adding 0.3–0.4 per cent to GDP in the third quarter of 2009.

Greenhouse gas emission costs and benefits of the program

New York Times study concluded the following:

On average, USA cars are driven 12,000 miles per year, according to government statistics. Considering that the traded-in clunkers had an average fuel economy of 15.8 m.p.g. while the new ones deliver 24.9 m.p.g., a swap saved some 278 gallons of gas per year – which would have released almost 2.8 tonnes of carbon dioxide when burned.

Assuming the clunkers would have been driven four more years, the $4,200 average rebate removed 11.2 tonnes of carbon from the atmosphere, at a cost of some $375 per tonne. If they would have been driven five years the carbon savings cost $300 per tonne. And if drivers drive their sleek new wheels more than they drove their old clunkers, the cost of removing carbon from the atmosphere will be even higher.

To put this in perspective, an allowance to emit a tonne of CO2 costs about US$20 on the European Climate Exchange. The Congressional Budget Office estimated that a tonne of carbon would be valued at US$28 under the cap-and-trade program in the clean energy bill passed by the House in June.

The program might have been more efficient with modifications, like a smaller rebate. But even if the new cars bought under the program had zero emissions, the price of removing the clunkers’ carbon dioxide from the atmosphere would have been nearly $140 per tonne.

However, the New York Times analysis ignores two other major benefits of the program: air quality improvement and safety health benefits. Analysis of the similar British Columbia ‘Scrap it’ program concluded that air quality improvement benefits from removing older vehicles from the roads in Vancouver (the major city in British Columbia) could justify the program there. In addition, the health cost reductions by replacing older vehicles with much safer (e.g. ESP, ABS and air bags) new vehicles, would together with the CO2e and air quality index reduction benefits, make the program very attractive from a social cost–benefit viewpoint. Analysis of a similar program that could be adopted in Australia is required.

Energy and Environment (NER 60)

National Economic Review

National Institute of Economic and Industry Research

No. 60               December 2006

The National Economic Review is published four times each year under the auspices of the Institute’s Academic Board.

The Review contains articles on economic and social issues relevant to Australia. While the Institute endeavours to provide reliable forecasts and believes material published in the Review is accurate it will not be liable for any claim by any party acting on such information.

Editor: Dr A. Scott Lowson

© National Institute of Economic and Industry Research

This journal is subject to copyright. Apart from such purposes as study, research, criticism or review as provided by the Copyright Act no part may be reproduced without the consent in writing of the Institute.

ISSN 0813-9474

Energy and environment

Graham Armstrong, NIEIR

Abstract

Graham Armstrong provides an update on the Kyoto Protocol before considering several related issues. These include the differing responses to greenhouse policy by the Australian States and Territories on the one hand and the Federal Government on the other, developments in this field in the European Union, an update of the New Zealand Kyoto Target, and carbon trading in Australia.

Kyoto Protocol update

  1. The Kyoto Protocol (KP) was developed in 1997 by two major groups of countries: Annex B and non-Annex B (see below for definitions). Since 1997 the countries party to the Agreement have met regularly as the Conference of the Parties (COP) to clarify and refine the Articles of the KP.
  2. Annex B countries comprise developed economies and economies in transition (mostly eastern European countries) who have made commitments to reduce greenhouse gas (GHG) emissions to the levels set out in Annex B of the Kyoto Protocol document. The specified levels are for the first commitment period, 2008-12, where emissions levels are compared with a 1990 base. Non-Annex B countries, loosely called developing economies, comprise all other countries signatory to the KP.
  3. Annex B countries were called on to ratify the KP, that is to be legally bound by their commitments in Annex B. When countries comprising 55 per cent of emissions covered by total Annex B emissions had ratified the treaty the KP came into force. This occurred on 16 February 2005 following ratification by the Russian Federation.

 

As of 1 July 2005, the percentage of Annex B emissions covered by ratifying countries had reached 61.6 per cent with 0.2 per cent of emissions from countries likely to ratify. The countries opposing ratification, the United States and Australia, comprise 38.2 per cent of emissions (USA 36.1 per cent, Australia 2.1 per cent).

 

  1. Australia and the United States continue to oppose ratification for two main reasons: potential damage to their economies and the non-inclusion in Annex B of major and rapidly growing emitters, particularly India and China.

It is important to note that:

  • projections by the Australian Greenhouse Office (AGO) continue to indicate Australia will meet its Kyoto target, but mainly through reduction of emissions from land clearing;
  • all Australian States and a significant number of USA States support KP ratification; and
  • close neighbours and trading partners of the United States and Australia, Canada and New Zealand, have ratified the KP and are implementing strategies to meet their Kyoto commitments.

 

  1. COP meetings and discussions in countries around the globe are increasingly looking towards policies and programs to address greenhouse (global warming climate change) in the post Kyoto period, that is beyond 2012. The two major issues are:

 

  • how to include Annex B ratifiers in Annex B and non-Annex B countries in a post 2012 agreement; and
  • what form post 2012 agreements should take.

Post-2012 global policy discussions dominated the COP-10 meeting in Montreal, Canada, in December 2005.

 

  1. The United States and Australia (depending on future government make-ups), and some major non-Annex B countries, are likely to oppose targets and timetables for the post 2012 era, whereas most Annex B ratifiers appear to favour continuation of the Kyoto Protocol targets and timetables approach. However, there is broad global agreement that major GHG emissions reductions (“deep-cuts”) will eventually be required.

The Asia-Pacific Partnership on Clean Development

The recently announced Asia-Pacific Partnership on Clean Development, although not viewed by partners as an alternative to Kyoto, will be a factor in future global policy discussions. An inaugural meeting of the group was held in Adelaide in March 2006. Current members of the Partnership are the United States, Australia, China, Japan, South Korea and India. Together they account for about half the world’s population, gross domestic product and greenhouse gas emissions. Of the countries only Japan is an Annex B Kyoto Protocol ratifier.

The primary aim of the Partnership, as set out in the group’s Vision Statement, is to achieve regional cooperation in developing and adopting cleaner (lower emission) energy technologies, including those based on coal, natural gas, nuclear (fission and fusion) and renewables, and technologies to capture and store GHG emissions.

Essentially the Partnership is a multi-lateral extension of existing clean technology agreements, for example that between Australia and India on clean coal. The main implication for States of the Partnership is that, in conjunction with the federal Low Emission Technology Fund, State development of low emission technologies could receive a further boost, depending on how the Commonwealth intends to act on progressing the aims of the Partnership.

Technology development, though essential for reducing global greenhouse gas emissions, does not alone lead to implementation of these technologies to actually reduce greenhouse gas emissions. Market signals complemented by market responsive regulations are a necessary adjunct to technology development. In this respect the plans and proposal outlined in Victoria’s Greenhouse Challenge for Energy (2004), and now being implemented, represent an exemplary integrated approach to future greenhouse policy development.

Thus, the Energy Technology Innovation Strategy (ETIS) and the earlier establishment of the Centre for Energy and Greenhouse Technology (CEGT), support for provision of market signals through development (with other jurisdictions) of an Emissions Trading System (ETS) and the development of Victorian Energy Efficiency and Renewable Energy Strategies (VEES and VRES), represent a balanced and responsible approach to the great challenges posed by global warming to global energy systems.

The Federal versus State/Territorial greenhouse policy positions

Introduction

The Federal and the States/Territories have very different views on greenhouse policy. Thus, despite some cooperation in the areas of energy efficiency (the National Framework for Energy Efficiency (NFEE), Minimum Energy Performance Standards) and in technology development there is fundamentally a wide difference in approaches to greenhouse policy.

Kyoto

The Federal Government continues to oppose Kyoto Protocol ratification whereas the States/Territories, while recognising that Kyoto is just a first tentative step towards an integrated global policy, support ratification.

Emissions trading system (ETS)

The Federal Government continues to oppose the introduction of an ETS whereas the States/Territories are putting a major effort into designing an ETS appropriate to Australian circumstances. Consultations on the ETS design principles developed earlier in 2005 were held around the country over the September/November period. Efforts are now focussed on detailed proposals on the 10 design propositions set out in the Background Paper for Stakeholder Consultation dated 12 September 2005 (www.cabinet.nsw.gov.au/greenhouse/emissions trading). A Secretariat has been formed headed by Anthea Harris (formerly of Frontier Economy).

Design issues to be considered as a priority

Point of liability – and liability average (large and small final emitters, comprehensive coverage).

  • Cap – what range of caps should be analysed: level, timing, flexibility.
  • Allocation – the methods of allocation, permit duration and impacts on electricity prices of different designs, the basis for administrative allocation (“grandfathering”) and the role(s) of auctioning.
  • Offsets – definitions, sources, baseline issues, impacts on permit prices.
  • Treatment of energy intensive trade exposed sectors: definitions, treatment options and impacts of these options.
  • The roles of research, development, demonstration and commercialisation (R, D, D and C) in longer term greenhouse gas abatement and how an ETS can promote these roles.

Process issues to be considered as a priority

There are a number of other issues which should be addressed as a matter of priority which are essentially process related. These include:

  • the legal basis for a scheme – particularly in relation to the constitutionality of a State based scheme. There is no point in States designing a preferred model, without considering what form of scheme is constitutionally sound; and
  • reporting requirements.

Short, medium and longer term greenhouse policies

The Federal Government has virtually no short or medium term policies, seemingly content to assume current policies (or lack thereof) will attain Australia’s Kyoto target, that medium term (2012-20) policies such as an interim carbon signal are not required until global action post-2012 is decided on, and that in the longer term current technology development policies are adequate.

The States/Territories believe that integrated market based and regulatory policies are required for short, medium and longer terms to put us on a path for an orderly transition to a more stringent carbon constrained economy. That is, there is a belief that early action to place activities on a progressively carbon constrained economy is required.

Thus, for example, the States/Territories and the Federal Government’s seeming abandonment of MRET is poor policy and short sighed despite the federal government’s R, D, D and C support for renewables. And the States/Territories are moving on a more rigorous approach to energy efficiency improvement (EEI) and promotion of lower greenhouse gas intensive (GHGI) electricity production.

Developments in the European  Union (EU) ETS

The EU ETS which began on 1 January 2005, has been beset by start-up problems. Firstly, about half the EU countries have not finalised their National Allocation Plans and this has restricted EU ETS trading in emission allowances.

Secondly, allowance prices have been much higher than expected: up to E30/tonne (now down to about E20/tonne compared with an expected range of E10-15/tonne. Besides the partial market (should the commencement have been delayed until 2006 to allow for completion of all NAPS), the rise in oil prices has led to a significant rise in oil linked gas prices, leading to substitution of coal for gas in electricity generation. This resulted in a higher than expected demand for allowances (in a restricted market) with generators not better off paying for coal plus allowances rather than generating with high priced gas.

New Zealand Kyoto target update

Original estimates (2002) of New Zealand’s carbon trading status were that New Zealand would have a 30 Mt surplus of CO2 credits over 2008-12, worth about NZ$450 million. However, 2005 projections indicate a deficit of 36.2 Mt costing NZ$543 million due to rapid growth in energy (mainly transport), industrial process emissions, miscalculation of Kyoto forest sequestration credits and over-estimation of program (EEI, etc.) impacts.

The New Zealand carbon tax of NZ$15/t CO2e was estimated to cost the average household about NZ$4/week and raise about NZ$360 million a year. A review of the New Zealand Climate Change program in the fourth quarter 2005 resulted in termination of the proposed carbon tax and development of a new climate change policy is now underway.

The New Zealand experiences should indicate for Australia:

  • doubts on whether the Australian emission target will, in fact, be attained as the Federal Government continues to claim; and
  • the difficulties associated with climate change policy designs and impacts.

Carbon trading in Australia Current markets

Currently a range of initiatives, mandatory (M) and voluntary (V), most with a trading element, are reducing, or aim to reduce, greenhouse gas (GHG) emissions through greenhouse gas abatement. Certificates associated with these measures have a market value in 2005 totalling about $ 325 million. These measures are briefly outlined below.

1.             MRET (M)

 

MRET is currently a high cost route to GHGA, effectively sunsetted at about 6 Mt CO2e GHGA in 2010. Renewable energy certificates (RECs) from accredited renewable sources are now trading at about $30/MWh (about $ 25-35/t CO2e) from a range of renewable electricity sources.
The value of REC market in 2005 is about $100 million and about $285 million in 2010.

 

2.             New South Wales’ Greenhouse Abatement Scheme (GGAS) (M)

Recently extended to 2020, the Scheme requires electricity retailers to purchase their share (based on electricity sales of the estimated target market determined by regulations each year). NSW Greenhouse Abatement Certificates (NGACs), from a range of accredited renewable, fossil and energy efficiency improvement sources, are currently trading at about $14/t CO2e.

The value of the NGAC market in 2005 is estimated to be about $155 million and to be about $315 million in 2010.

3.             Queensland 13% Gas Scheme (M)

This measure is aimed at increasing the share of gas in the Queensland electricity generation mix and requires electricity retailers in Queensland to source 13 per cent of their electricity from gas (large loads over 750 GWh/year) are exempt (see Section 4.5 of this report for details). The Scheme which commenced on 1 January 2005 is implemented through tradable accredited Greenhouse Electricity certificates (GECs) which are currently trading at about $15/MWh.

The value of the GEC market in 2005 is estimated at about $70 million and in 2010 about $60 million (GEC price expected to drop despite increased volumes).

 

4.             Green Power (V)

Green Power involves the voluntary payment of a premium for electricity to cover the retailer costs of acquiring Green Power RECs which cannot be used for acquitting MRET liabilities.

The value of the Green Power market in 2005 is estimated to be about $15 million and perhaps some increase to $20 million in 2010.

5.             Greenhouse Friendly Certificates (V)

GFCs which accredit GHGA from eligible sources (including flaring of methane at landfill gas sites) are voluntarily purchased by companies to offset their greenhouse gas emissions from their activities. Currently there is a very limited market for GFCs which are trading at about $4/t CO2e.

The estimated GFC market value in 2005 is <$5 million and in 2010 to be about $10 million.

6.             Greenhouse Abatement Certificates (GACs) (V)

This market, which is just commencing, is the voluntary purchase of GHGA accredited certificates by entities to offset GHG emissions from their activities. The GACs differ from GFCs because of the wider range of eligible sources and their generally more stringent eligibility (additionality) criteria.

The rationales for purchasing GACs vary from “green image” to “contingent liabilities” and “learning by doing” in advance of a mandatory emissions trading system (ETS) introduction. Use of renewables for production of thermal energy (process heat, water heating), which are not eligible under MRET, GGAS or GP can be eligible to produce GACs.

The estimated value of the GAC market in 2005 is <$1 million and in 2010 possibly $ 10 million plus, as interest in GACs increases.

Total estimated value of the above “carbon” markets in 2005 is about $280 million.

Some companies, such as Energy Developments Ltd (EDL), are significant players in this market (EDL Annual Report indicates about $20 million of accredited certificates in 2004).

Future carbon markets

  • Current markets, in absence of new measures, could build to about $700 million in 2010.
  • The 31 October 2005 announcement by Victorian Premier Bracks of a Victorian Renewable Energy Obligation (VREO) to sustain the renewable electricity in Victoria is faced with collapse as a result of a static MRET. The VREO target is 10 per cent of electricity end-use consumption by 2010. Compared with an MRET only policy this would require about another 2,500 GWh of Victorian RE by 2010. At $35/MWh VREO (higher cost than MRET RECs) this “carbon” market would be worth about $90 million in 2010. VREO details are currently being considered.
  • Main potential future measure is an Emissions Trading System (ETS) now commencing operation in the EU, Norway and proposed for Canada to meet their ratified Kyoto Protocol commitments.
  • ETS elements: tradable carbon emission permits to attain a specified greenhouse target (information available on www.iea.org.).
  • Federal Government remains opposed to ETS but supported by States/Territories who are now designing a national “made in Australia” ETS.
  • Ten design propositions/issues including:
  • method of allocating permits (auction, AA, hybrid);
  • target: now looking at beyond Kyoto (2012) period and approach to GHGA (greenhouse versus economic uncertainty);
  • point of permit liability (who must hold and acquit permits) – some stationary energy sector possibilities set out in Figure 2.1; and
  • means of addressing adverse economic impacts on certain economic sectors.

ETS permit prices, economic impacts and size of the permit market will depend on the specific design of the ETS: potentially $3 billion total value of permits (at $10/t CO2e) in 2010.

Table 1 E and E NER 60

The concept of Australian Greenhouse Gas Abatement Program (GAP)

Currently in the absence of an emissions trading system (ETS) there is no national carbon signal initiative. As indicated above, there is a range of State programs encouraging greenhouse gas abatement (GHGA) that mainly focus on renewable electricity (gas electricity in Queensland and New South Wales).

MRET and Green Power are high cost GHGA routes and no program covers the range of GHGA opportunities, thus not encouraging least cost GHGA. For example, except for domestic solar hot water (SHW) under MRET production of thermal energy from renewables (for example, production of biogas from renewable wastes avoiding landfill and displacing fossil fuels), although often relatively low cost, is not eligible under any programs.

What is suggested here, in advance of an ETS, is a national GAP implemented through tradable certificates and based on new projects with a greenhouse gas intensity of <0.3t/CO2e and not viable under market conditions (that is, the projects would be additional, beyond BAU, as under the Kyoto Protocol Clean Development Mechanism rules). Energy efficiency improvement (EEI) projects would also be eligible, albeit raising difficult baseline/additionality issues.

More work is required on the GAP concept, but it is one worthy of consideration, perhaps initially on a voluntary basis (there are niche market opportunities) and later to replace existing programs.

Potential GAP features

  • Energy sources, including production of thermal energy from thermal sources, with a GHGI lower than 0.2-0.3t CO2e/MWh would be eligible for tradable abatement certificates.
  • Would be a greenhouse gas abatement measure (NOT a renewable electricity scheme) implemented through tradable GACs not RECs.
  • Between 0 and 0.2t CO2e/MWh GHGIs which fossil fuel technologies would qualify?
  • fuel cells: 0.4+?;
  • cogeneration: probably not but depending on how GHGI estimated (electricity, heat) could qualify at 0.25;
  • other? Geosequestration with CCGTs and possibly coal, hybrid RE/fossil technologies for example biogas/gas electricity generation;
  • energy efficiency: difficult baseline issues.
  • Would eligible sources be restricted to emerging technologies? If so, how would emerging technologies be defined? Additionality test?

Definitions of Large Final Emitters (LFEs) and Small Final Emitters (SFEs):

  • data sources on energy use (sources) and emissions (levels) (ABARE, AGO) and decision, following analysis, of SFEs, LFEs. LFEs in Canada emit >8,000t CO2e (about 0.16 PJ of gas emits 8,000t CO2e);
  • treatment of fugitive emissions.

Decisions required for these emissions on acquittal points (upstream, downstream) and/or alternative policies: analysis and recommendations being prepared by Vic. ETS Technical Group (DPI, DSE, DOI).

Suggest an 0.3 upper limit

  • All renewable energy applications would qualify, not just renewable electricity as in MRET, GGAS, GP: thermal applications of renewable energy would qualify.
  • However, given MRET and VREO would renewable electricity qualify?
  • Should a portfolio approach be adopted?
  • Could be badged as a greenhouse abatement program (GAP) OR low emission technology application (LETA) program.
  • Implemented through gas and electricity retailers and certificates. Target?
  • Project cost of certificates? Up to $20/t CO2e if renewable electricity excluded. If used portfolio approach, different prices for each portfolio would emerge.

 

Demand Side Management in California

National Economic Review

National Institute of Economic and Industry Research

No. 60               December 2006

The National Economic Review is published four times each year under the auspices of the Institute’s Academic Board.

The Review contains articles on economic and social issues relevant to Australia. While the Institute endeavours to provide reliable forecasts and believes material published in the Review is accurate it will not be liable for any claim by any party acting on such information.

Editor: Dr A. Scott Lowson

© National Institute of Economic and Industry Research

This journal is subject to copyright. Apart from such purposes as study, research, criticism or review as provided by the Copyright Act no part may be reproduced without the consent in writing of the Institute.

ISSN 0813-9474

Demand side management in California: current and proposed measures

Graham Armstrong, NIEIR

Abstract

Although definitions vary, demand side management (DSM), demand management (DM) and demand response (DR) measures generally encompass energy efficient improvement, load shifting and peak load control. Over the past five years, increasing peak load demands and regional supply shortfalls (due to one or a combination of inadequate inter-connections, generator capacity, unexpected summer load peaks) have focused DSM/DR/DM efforts on peak load control of air conditioning equipment.

In Australia air conditioning loads are increasing at a rate of about 50 per cent above overall load growth. Although there has been increasing interest over the past five years in DSM to address this peak load growth, there have been few actions beyond analysis and discussion of the issue. Peak load growth has been met by supply augmentation.

On the other hand in California, where electricity prices soared and supply shortfalls were experienced in 2000, a range of measures has been introduced.1 Today, California is almost certainly the jurisdiction with the most comprehensive array of DSM/DM/DR measures. These measures are mainly designed (often with overall government direction by the State’s Government) and delivered by energy utilities operating in the State.

Graham Armstrong believes that the United States experiences with measures for addressing peak loads are useful when considering the situation in Victoria and Australia in general – with the important qualification that policy design must be based on our particular circumstances and provides a preliminary program design for consideration and analysis.

Introduction

California can in some ways be viewed as a stand-alone nation state which has the fifth largest economy in the world. The Californian electricity demand requires a capacity of nearly 55,000 MW (about 25 per cent imported): this compares with total Australian generation capacity of about 50,000 MW (Victoria 8,000 MW). 2 Accordingly, California is a very significant global entity in the energy field.

California – A Nation State

  • Population of 34 million in 2002, 41 million by 2010.
  • 5th largest economy in the world.
  • 5th largest consumer of energy in the world.
  • 2nd largest consumer of gasoline and diesel – only the total United States uses more.
  • Lowest US per capita electricity consumption.
  • 1.5 per cent of world’s greenhouse gas emissions but low per capita emissions.

Source:   California Climate Change Programs: An Overview, Conference of the Producers, The Hague, 12 May 2003 presented by James D. Boyd, Californian Energy Commission.

In 2004 the State electricity usage was about 265,000 gigawatt hours of electricity per year. Consumption is growing at 2 per cent annually. Over the 1994-2004 period, between 29 per cent and 42 per cent of California’s in-state generation used natural gas. Another 10 -20 per cent was provided by hydroelectric power that is subject to significant annual variations. Almost one third of California’s entire in-state generation base is over 40 years old. California’s transmission system is also ageing. While in-state generation resources provide the majority (average annual of about 75 per cent) of California’s power, California is part of a larger system that includes all of western North America. Fifteen to thirty per cent of state-wide electricity demand is imported from sources outside State borders.

Peak electricity demands occur on hot summer days. California’s highest peak demand was 52,863 megawatts which occurred on 10 July 2002. On average peak demand is growing at about 2.4 per cent per year, requiring the equivalent of about three new 400 MW peaking power plants per year. Residential and commercial air conditioning represent at least 30 per cent of summer peak electricity loads.

California’s demand for natural gas also is increasing. Currently the State uses 2 trillion cubic feet (2,100 PJ, Victoria approximately 250 PJ) of natural gas per year. Historically the primary use of this fuel was for space heating in homes and businesses. Electricity generation’s dependence on relatively clean burning natural gas now means that California’s annual natural gas use by power plants is expected to increase. Overall, natural gas use is growing by 1.6 per cent per year. Eighty five per cent of natural gas consumed in California is supplied by pipelines from sources outside the State.

Californian initiatives in DSM/DR/DM have evolved in three fairly distinct phases over the past 30 years.

In the first phase, extending from the mid 1970s to around 1990, the emphasis, led by utilities such as Pacific General Electric (PGE), was on energy efficiency in an integrated resource planning (IRP) framework, in which the costs of reducing energy demand were compared with the costs of expanding supply. In this phase measures focused on energy efficiency with some attention to load control.

In the second phase, extending into the 1990s, less attention was paid to DM/DSM/DR as supply pressures (costs, levels) eased: a situation common around the world. Environmental concerns increased, particularly urban air quality and greenhouse, but more attention was paid to transport rather than stationary energy. DSM funding, focused on energy efficiency improvement (EEI) varied considerably in the period as regulatory wrangles remained unresolved.

The third phase, commencing in 2000, was precipitated by the electricity supply disruption and soaring wholesale prices. Since then DSM/DR/DM measures (both voluntary and the use of incentives) have been vigorously pursued with substantial public spending. The 2001 summer peak, weather and growth adjusted, was 10 per cent below the 2000 peak. The immediate response to the 2000 events was to install emergency peaking plants and to engage in a publicity campaign and incentive measures (lower tariffs for reducing demand below the previous year) to curtail demands. Rebates for the purchase of higher efficiency products were also tried to curb power consumption in 2000-01, but this approach was judged to be relatively ineffective as take-up was low and wholesale electricity prices fluctuated from one hour to the next, but retail prices did not.

Program funding has mainly been based on a combination of State funds provided on measured energy savings and utility funding, but in 2000 -01 the Californian Energy Commission (CEC) was appropriated an additional $ 380 million from special taxpayer funds for a range of DSM programs.

Recent developments

Although rebates continue, the policy focus has shifted to the potential use of time-of-use (interval) meters, which could be used with time -of-use (t-o-u) pricing (dynamic pricing in Californian terms, which includes consideration of real time pricing, RTP, covering price changes as wholesale prices change).

Backed by data from the t-o-u meters, rates can be adjusted according to several market variables, including demand, supply, wholesale prices and individual use. The State, with the major utilities, conducted a test to gauge customer response to variable pricing. About 2,500 small scale users across the State were given t-o-u meters and put on different pricing plans. In one plan, consumers were charged 13 cents a kilowatt hour for most hours except for 2:00 p.m. to 7:00 p.m. on weekdays, when the price went to 25 cents. On a few occasions the price was increased to 66 cents a kilowatt hour to mimic a period of special system needs. Evaluation indicated the program reduced peak demand by about 13 per cent.3

Results of the evaluation of 2003 programs is presented on www.energy.ca.gov.

Test results and results from general use of t-o-u might be quite different. Some customers might adjust their use to realise cost savings, while others might ignore the pricing changes. However, utilities, the Californian Energy Commission (CEC) and the Californian Public Utilities Commission (CPUC) are confident that, on the basis of the t-o-u pilots, this approach is effective.As a result, three major Californian utilities – PGE, Southern California Edison (SCE) and San Diego Gas and Electric (SDGE) are planning to replace conventional gas and electricity meters with up to 15 million t-o-u meters at a cost of around US$6 billion, beginning in 2006. The t-o-u meter expense will be offset to an unknown extent (depends on implementation policies and responses to them), by reduced peak usage: rate increases as a result of the meter rollout is expected by PGE to be small. In the period before t-o-u metering can make an impact, the California Energy Commission (CFC) estimates, that a 1 in 10 summer could result in a Southern Californian region shortfall of capacity of 2,000 MW (3.3 per cent) below demand by September 2005. Normal weather would not result in a shortfall and reserves would be adequate.As a response to the potential shortfall situation, the Californian Public Utilities Commission (CPUC) approved SCE’s request to implement additional energy efficiency programs aimed at reducing peak demand by 36 MW: insignificant compared to the potential shortfall. The decision orders SCE to expand four energy efficiency programs to immediately and significantly reduce peak demand – from residential customers and small, medium and large businesses.7

The programs:

  •  expand residential customers’ options for “instant rebates” – which are done at the point of sale – and are currently only available for compact fluorescent light purchases. The expanded program will include pool pumps and motors, refrigerators, air conditioners and whole house fans;
  • give  small  businesses  “no-cost”  lighting retrofits.  SCE    estimates    reaching approximately 10,000 customers through this effort; and
  •  allow larger business customers to apply for incentives of up to 100 per cent of the cost of the project on lighting retrofits.

Review of the Californian situation indicates that:

  • despite a range of in-place DSM/DR/DM programs the Californian system is still susceptible to disruptions;
  • t-o-u pricing may still some time off; and
  • the supply system is not being expanded at a sufficient rate to meet increasing demands.

 

The Californian Energy Commission (CEC) Integrated Energy Report8

This report, which is prepared every two years, with an update each alternative year, reports on the status of the State’s energy system and makes recommendations for action where it is deemed necessary.

Key issues identified in the 2004 Update are as follows:

  • implementation of the Energy Action Plan’s loading order strategy;
  • improved transmission planning is required to address inadequate transmission as it presents a significant barrier to accessing renewable energy sources critical to diversifying fuel sources;
  • reliability issues with ageing power plants;
  • the need for accelerated renewable energy developments; and
  • the need for acceleration of demand response programs that signal the actual price of electricity to customers in peak periods.

In the demand response area, the primary focus of this report, the 2004 Update calls for electrical utilities to aggressively implement the 2007 State-wide goal of reducing peak demand by 5 per cent. The 2004 Update appears to rely essentially on “dynamic pricing” (implemented through tariffs using t-o-u, interval meters) to meet this target.

Given the interval metering rollout schedule, likely rollout delays and uncertainty regarding peak tariffs and their impacts, it would seem that attention to other peak demand reduction and supply security are required if the target is to be attained. Thus, despite the 2000-01 disruptions actions to avoid a repeat the Californian system continues to be vulnerable to high (1 in 10) summer peaks.

The lesson for Victoria (and Australia generally) is that even after actual and significant supply disruptions, the implementation of preventive actions lags the requirements. Victoria/Australia has different circumstances: the private sector is responding on the supply side (but the Basslink delay reminds us of supply side reliance fallibility). BUT after five years of discussion, etc. little DSM to address peak loads has been implemented.9 (Would a serious disruption help?)

The 2004 Update, reviews progress on 2003 recommendations. In the DR/DSM/DM area:

(i)                        significant progress is reported on increasing energy efficiency funding and evaluation and monitoring of energy efficiency programs;

(ii)                       improved efforts are needed is reported on maximising energy efficiency of existing buildings; and

(iii)                     improvement is needed on rapid deployment of advanced (t-o-u, interval) meters and implementation of dynamic pricing tariffs.

In the case of (i) the Energy Commission recommended that the State10:

  • “Ramp up public funding for cost effective energy efficiency programs above current levels to achieve at least an additional 1,700 MW of peak electricity demand reduction and 6,000 gigawatts (GWh) of electricity savings by 2008.
  • Standardise and increase the evaluation and monitoring of energy efficiency programs to ensure that savings and benefits are being delivered. (Importance to be noted in VEES development.)

The State has made significant progress in this area, with the CPUC’s recent decision to adopt more aggressive goals for the investor owned utilities (IOUs) than the 2003 Energy Report recommended. These new goals, based on collaborative staff work between the Energy Commission and CPUC, require peak electricity demand reductions of 2,205 MW by 2008, exceeding the 2003 Energy Report goal by 505 MW, and energy consumption reductions of 10,489 GWh by 2008, exceeding the 2003 Energy Report goal by 4,489 GWh. These new goals will require approximately $522 million in annual funding by 2008 compared to the annual spending level of $348 million for 2004 and 2005.” And in the Executive Summary of the Update11 it is stated that “As recently as the 2000-01 electricity crisis, Californians embraced energy efficiency and demand response programs, reducing State demand by approximately 6,000 MW, more than 10 per cent of peak demand.”

In both cases (the 2003 Energy Report goals and the reductions to 2000-01) no evaluations are provided. This detracts from the credibility of the program results (see an outline of recent evaluation policies below). The Californian energy agencies (CPUC, etc.) proposed in a 2003 Energy Action Plan, in the energy conservation and resource efficiency area, that:

“California should decrease its per capita electricity use through increased energy conservation and efficiency measures. This would minimise the need for new generation, reduce emissions of toxic and criteria pollutants and greenhouse gases, avoid environmental concerns, improve energy reliability and contribute to price stability. Optimising conservation and resource efficiency will include the following specific actions:

  1. Implement a voluntary dynamic pricing system to reduce peak demand by as much as 1,500 to 2,000 megawatts by 2007.12
  2. Improve new and remodelled building efficiency by 5 per cent.13
  3. Improve air conditioner efficiency by 10 per cent above federally mandated standards.14
  4. Make every new state building a model of energy efficiency.
  5. Create customer incentives for aggressive energy demand reduction.
  6. Provide utilities with demand response and energy efficiency investment rewards comparable to the return on investment in new power and transmission projects.
  7. Increase local government conservation and energy efficiency programs.
  8. Incorporate, as appropriate per Public Resources Code section 25402, distributed generation or renewable technologies into energy efficiency standards for new building construction.
  9. Encourage companies that invest in energy conservation and resource efficiency to register with the State’s Climate Change Registry.”

The Decision builds upon Decision (D.) 04-09-060 and D.05-01-055 and an 21 April 2005 Decision 05-04-05, establishing the goals, policies and administrative framework to guide future energy efficiency programs funded by the ratepayers of the four largest investor-owned utilities (IOUs): Pacific Gas and Electric Company (PGE), San Diego Gas & Electric Company (SDGE), Southern California Edison Company (SCE) and Southern California Gas Company (SoCalGas).

D.04- 09- 060 established aggressive energy savings goals to reflect the critical importance of reducing energy use per capita in California. For the three electric IOUs, these goals reflected an expectation that energy efficiency efforts in their combined service territories should capture on the order of 70 per cent of the economic potential and 90 per cent of the maximum achievable potential for electric energy savings, based on the most recent studies of that potential. If successful, these efforts are projected to meet 55 to 59 per cent of the IOUs incremental electric energy needs between 2004 and 2013. On the natural gas side, adopted savings goals represent a 116 per cent increase in expected savings over the next decade, relative to the status quo. A three year cycle for updating savings goals, in concert with a three year program planning and funding cycle for energy efficiency (“program cycle”) was established and load reductions were included in savings goals.

In addition, an administrative structure for evaluation, verification and measurement (EM&V) was established to create a clear separation between “those who do” (the Program Administrators and program implementers) and “those who evaluate” the program or portfolio performance. (Victorian EES to note!) In particular, for program year (PY) 2006 and beyond, the Californian Energy Division will assume the management and contracting responsibilities for all EM&V studies that will be used to:

(i)                 measure and verify energy and peak load savings for individual programs, groups of programs and at the portfolio level;

(ii)                generate the data for savings estimates and cost effectiveness inputs;

(iii)              measure and evaluate the achievements of energy efficiency program, groups of programs and/or the portfolio in terms of the “performance basis” established under Commission-adopted EM&V protocols; and

(iv)               evaluate whether programs or portfolio goals are met.

The budget for EM&V was set, as a guideline, at 8 per cent of total energy efficiency program funds. (Note the significant resources that could be available for program evaluation at this level of funding.)15

Case study: Sempra Energy Inc/San Diego Gas and Electric (SDGE)16

Sempra/SDGE, serving a region in capacity constrained Southern California, operates a range of DSM programs, covering:

  • reduction of load during peak periods;
  • dynamic pricing; and
  • energy efficiency.

The utility claims over the past ten years to have cumulatively saved 1.9 million MWh, reduced peak load by 409 MW and provided cost savings to customers of over US$200 million.

2004-05 energy efficiency programs

Residential sector

Description of market segment:

Includes single family homes, condominiums, multi-family units, mobile homes and multi-family common areas.

The utility territory mainly has moderate coastal climate with high density housing and sparsely populated rural high desert and desert climates.

Provides electric service provision to approximately 1.2 million households.

Residential sub-segments:

  • single family customers;
  • multi-family customers; and
  • hard to reach.

Further segmented by end-use – air conditioners, all-electric homes.

Statewide residential rebates

Target market

All residential customers residing in SDGE’s service territory living in dwellings of 4 units or less, including condominiums and mobile homes.

 

Measures – rebates for:

  • Appliances;
  • Building shell – insulation;
  • Building shell – windows;
  • HVAC – air conditioning systems;
  • HVAC – controls;
  • HVAC – Ventilation systems;
  • Lighting – comprehensive products; and
  • Water heating – systems.

Industrial and commercial sectors

Commercial/industrial market segment includes over 138,000 electric meters and close to 30,000 gas meters.

Approximately 20 per cent of market consists of “large” customers – monthly kW demand above 500 kW.

Remaining 80 per cent of market consists of small and medium sized business with monthly demand of 500 kW or less.

  • Majority of the customer segment are considered “Hard-To-Reach”: rent or lease space; where English is the second language; businesses have less than ten employees; are outside urban San Diego, and annual electric demand is less than 20 kW or annual gas consumption is less than 10,000 therms, or both.
  • Almost 90 per cent of small and medium sized business customers have a monthly demand under 20 kW.

Industries are varied, including food service, property management, manufacturing, lodging, grocers and food growers.

Programs in these sectors include:

  • rebates for high efficiency HVAC systems and electric motor: delivered through system/product distributors;
  • provision of energy audits;
  • education and training programs for contractors, retailers, manufacturers;
  • building operator training and certification;
  • standard performance contract development and dissemination; and
  • incentives to participate in savings by design targeted at building owners and design teams to achieve “better than code” performance.

More information on the Sempra/SDGE program is set out in overheads from the utility’s Energy Efficiency Programs, Public Workshop, 3 March 2005. Although these programs are not targeted at peak load control, which will be addressed through t-o-u metering and tariffs, the SDGE’s comprehensive DSM measures that are summarised above:

  • can have a significant impact on peak loads; and
  • are well ahead of anything being implemented by Australian utilities.

It might be argued that the southern Californian situation has brought about such action and that program evaluation detail is lacking, but the SDGE programs (current and planned) indicate an innovative attach on energy efficiency improvement and peak load control that appears to be accepted by the government and its agencies.

Other USA state measures

A 2004 paper, Demand Response in the United States, prepared by the Wedgemere Group for the New Zealand Energy Efficiency and Conservation Authority (EECA) outlines DR/DSM/DM programs in a range of USA states17 and Ontario, Canada.

The outlines are a useful summary of these initiatives (websites are provided). TOU meters, coupled with dynamic pricing, is strongly supported in the EECA paper based mainly on the results of pilot programs in the USA: an average 0.3 demand elasticity is reported (for example, a 30 per cent demand reduction for a 100 per cent increase in price).

Program packages to address peak loads are not critiqued. Attachment B of the EECA report outlines reasons why new direct load control programs were not proposed in California.

The reasons provided are:

(i)                 the load impacts from these programs are already well understood;

(ii)               they limit customer choice: the utility determines the end-use (usually AC) and response level and does not allow customer overrides;

(iii)             they limit peak reduction potential to the chosen end-use load;

(iv)              they are inequitable because they offer a reward to owners of AC units, but not to non-owners; and

(v)                they are expensive because customers are paid even when the program is not used.

However, the possibilities for designing innovative load control programs in combination with t-o-u dynamic pricing and EEI programs are not considered in the EECA paper. This detracts from the usefulness of the paper from a policy perspective in the Victorian/Australian context.

Briefly, the reasons for rejecting direct load control are critiqued as follows.

(i)                 Load impacts from the earlier direct control may be well understood but are not for new designs of direct load control programs.

(ii)               More innovative designs can allow customer overrides: but if overridden full peak pricing would apply.

(iii)             They could be extended to other than A/C peak loads but A/C load is the load which is overwhelmingly weather dependent.

(iv)              They can be designed to reward non-A/C owners with lower rates than all A/C owners: that is, A/C owners taking direct load control would still pay more than non-A/C owners, but less than A/C owners not taking direct load control.

(v)                In combination with t-o-u meters, there is no reason why customers taking direct load control need not be paid when the program is not used.

Concluding comments

The United States experiences with measures for addressing peak loads are useful for analysis and consideration in the Australian/Victorian situation.

However, policy design here must be based on our particular circumstances.

Preliminary program designs for consideration and analysis (modelling, etc.) are set out in Attachment A.

Attachment A:

Scenarios for long run projections of Victorian peak demands

Introduction

This paper outlines potential measures for addressing summer peak load demands and suggests three scenarios for analysis of these measures.

For given weather patterns, population, income, economic trends, and consumer preferences, peak electricity demands will be driven by:

  • overall electricity prices (peak prices are considered separately), which rise to some extent as new plants are commissioned, but significant price increases will be mainly due to greenhouse (carbon price/permit) policies;
  • efficiencies of air conditioning units;
  • peak pricing policies; and
  • building trends.

Over the past five years, when it has been very evident that summer peak demands were increasing rapidly, the “non-policy” has been to build low capacity peaking plants or inter-connections. There has been virtually no policy directed at peak load control. This brief paper suggests how peak load control might be addressed. The study focuses on scenarios of policies to reduce (from BAU) peak demands in the residential sector: commercial and industrial sector analysis of peak demands requires separate analysis.

Three scenarios, two of which progressively reduce peak demands below BAU, are presented below for the 2005-50 period.

Under the BAU scenario electrical energy summer peak demand will continue to grow as population and incomes increase in each scenario. Income growth and consumer choice may translate into increases in average dwelling size, cooling of a greater proportion of space volume (whole house rather than one or two rooms), longer hours of operation and perhaps lower summer space temperatures. In the projections presented, these economic and social factors are held constant: further scenario development work would be required to assess their impacts.

Potential peak reducing policies

Emissions trading (carbon pricing)

Although the Federal Government continues to oppose the introduction of an emissions trading system for the pricing of carbon and trading of emission permits, States and Territories are continuing to work on the design of an ETS appropriate for Australia.

Action by the States/Territories and the possibility of a change in federal policy, suggests a carbon/permit price of $5/t CO2e by 2010 in a mild policy scenario and a price of $20/t CO2e by 2010 in a stringent policy scenario.

In the study these prices are assumed to remain over the 2010 to 2020 period, but increase to $10/t CO2e and $30/t CO2e respectively over 2020-2050 as the global greenhouse policy regime becomes more stringent, offset to some extent by technology advances which constrain the emissions permit price.

No explicit carbon pricing is included in the BAU scenario.

Peak load pricing and direct load control

In Victoria the installation of interval meters in all buildings will not be completed until about 2020. By 2013 only about one third of households will be fitted with interval meters (GWA, p.2918). Accordingly, unless there is a roll-out schedule change, universal time of use (TOU)/peak pricing in Victoria will not be possible until 2020.

There are several alternatives for direct control (for example through radio waves) of air conditioner loads and several trials are underway (New South Wales, South Australia, Western Australia) and a Ministerial Council on Energy (MCE) Committee is addressing the options. Work in this area commenced in 2000, but to date progress on developing policies and measures has been very slow.

Minimum energy performance standards (MEPS)

Levels for three phase air conditioning units were raised in 2004 and MEPS for single phase units introduced in 2004 are due to be raised in 2006 and 2007, with the final stage to match 2004 world’s best regulatory (not economic) practice in 2007. An indication of the impact of these MEPS changes is provided by GWA 2004, Table 4, p.23 and in the accompanying text.

There will be a rated performance improvement for the least efficiency split system units permitted to be marketed in Australia from April 2006. This improvement will be about 2 per cent for <4 kW and 5 per cent for >4 kW units compared with the average units sold in mid- 2004. Of current models available, about 10 per cent of <4 kW and 17 per cent of >4 kW would meet the proposed 2006 standard (GWA, 2004).

It is estimated (GWA, 2004) that the sales weighted efficiency for single phase units will then be 13-14 per cent higher, compared with 2004, than it would have been without the new 2006 MEPS.

World best practice for air conditioners is led by Taiwan and South Korea. The Australian MEPS lag the use of regulatory world best practice. As indicated above, MEPS applies, as the name implies, to the minimum acceptable rating (1- star) when the most efficient units (5-6 stars) are up to 40 per cent more efficient. The impact of higher air conditioning unit efficiencies on peak demands is debatable. Wilkenfeld, in a recent paper (GWA, 2004) claims, “where operation is intermittent and/or limited to one space, it is more likely that an increase in efficiency will lead to somewhat cooler internal conditions but have little effect on peak load”. (p.4, GWA 2004)

Why cooler internal conditions would result is not explained. In any case, this type of limited, intermittent situation is likely to become less important over time. MEPS levels could be raised by 2008 (or at least by 2010 -12) and/or greater efforts made to promote higher efficiency (5-star and higher) units.

Building trends: stock, sizes, retrofits and standards

The energy efficiency of buildings is increasing due to increased awareness of the net economic and environmental benefits achievable by improving the thermal efficiency of building envelopes and systems. Stock increases form a standard part of NIEIR’s projection methodology, but judgments on thermal efficiency trends must be made on the basis of policy and underlying trends.
In the case of new buildings, the Building Code of Australia (BCA) is moving to higher levels of thermal efficiency. From the early 1990s to 2004 there was only a slow and moderate increase in the thermal efficiency of new buildings. For example, in Victoria the 1992 thermal efficiency standard for new residences of about a 2 star rating had only increased to an average of about 2.7 by 2003. However, in 2004 a 4 star rating was mandated and on 1 July 2005 a 5 star rating will become mandatory. And work is being undertaken on a 6 star rating which is being achieved in a small proportion of homes.

Similarly, in the commercial sector movement to a 5 star rating for new buildings is likely (but not certain) in 2006. In the existing buildings area, retrofits are achieving higher thermal efficiency but the trend has not been quantified. Offsetting these trends, which reduce peak demands for a given stock, is an increase in building size (new or through refurbishment). Again, this trend has not been quantified.

No peak load pricing or direct load control is assumed in the BAU scenario. Faced with this uncertainty the following scenarios are suggested by NIEIR.

Scenarios for analysis of summer peak demands

Business-as-usual (BAU)

Over the past eight years, peak electricity demands have been increasing at about 4.0 per cent per year and are projected to increase at 2.6 per cent per year based on a 10 per cent POE through to 2015.

Although interval metering continues to be rolled out throughout the NEM, differential peak electricity pricing and specific load control measures are not introduced in this scenario. MEPS are held at 2004 levels in this scenario.

A 5 star requirement for new residences over the entire projection period (30 per cent net reduction in space cooling requirement compared with pre- 2005 new residences). No net increase in building size. No explicit carbon price is assumed in the BAU scenario.

Mild policy intervention

In this scenario the following new policy measures are introduced.

  1. An emissions trading system (ETS) is introduced in 2010 which results in a permit price of $5/t CO2e over 2010-2020 and an average electricity price increase of $6.5/MWh in Victoria over 2010-2020 (GHC4E), compared with 2005 levels. Over 2020-50 as the permit prices increase to $10/t CO2, average electricity prices increase by $10/MWh ($10/t CO2) as Victoria’s electricity greenhouse gas intensity reduces to an average of 1.0t CO2/MWh compared with 1.3t CO2/MWh over 2005-20).
  2. Air conditioner MEPS are accelerated resulting in an average 15 per cent increase in efficiency of new air conditioner units sold from 2008. (This means in effect, for example, that a previously rated 2 MW unit becomes a 1.7 MW unit from 2008 to 2020 compared with 2004.) This can be modelled by reducing the 2008 on growth in temperature dependent demands by 15 per cent.

By 2050 efficiencies are assumed to improve by 35 per cent (compared to 2004 levels).

(i)                 Peak pricing policies increase summer (October-April) peak prices by 30 per cent over 2005-20.

Customers are offered a lower price increase of 10 per cent if they agree to direct load control achieved through fitting devices to AC units which enable central control of AC units (for example through radio waves). Thirty per cent of customers accept this offer by 2020. Over 2020-50 peak prices increase by 50 per cent and customers are offered a lower price increase of 20 per cent if they agree to direct load control: 50 per cent of customers accept this offer by 2050.

(ii)               A 5 star requirement (30 per cent net reduction) for new residences from 2005-20 and 6-stars (40 per cent net reduction) from 2020 to 2050. No net increase in building size.

Stringent policy intervention

In this scenario the following policy measures are introduced.

  1. An ETS in 2010 results in a permit price of $20/t CO2e and an average electricity price increase in Victoria of $26/MWh over 2010-2020. Over 2020-2050 the average price increase is $40/MWh from a permit price of $40/t CO2e.
  2. Air conditioner MEPS are accelerated resulting in a 30 per cent increase of new air conditioner units sold from 2008 to 2020. (This means in effect that a previously rated 2 MW unit becomes a 1.4 MW unit.)

Over 2020-2050 average efficiencies of new air conditioner units increase by 50 per cent compared with 2004 levels.

  • Peak pricing policies increase summer peak prices by 50 per cent over 2005-2020.

Customers are offered a lower price increase of 20 per cent if they agree to direct load control as in 2. above. Fifty per cent of customers accept this offer.

Over 2020-2050 peak prices increase by 80 per cent and customers are offered a lower price increase of 30 per cent if they agree to direct load control: 75 per cent accept this offer.

5 stars for new residences over 2005-10, 6 stars over 2010-2020 and 7 stars (50 per cent net reduction from 2004 new residences) over 2020-30. No net increase in building size.

Note that in the latter two scenarios customer behavioural attitudes (for example in temperature control) to air conditioning is assumed to be similar to those in the BAU scenario. Behavioural changes scenarios could be introduced into the analysis but would require considerably more resources than proposed above.

Demand side management in California: current and proposed measures

Footnotes:

1        See Armstrong, G., California South: Coming to a Network Near You?, National Economic Review, No. 50, February 2002, for a review of the electricity situation which spawned many of these measures. 

2        Bob Thorkelson, Executive Director, Californian Energy Commission (CEC), Statement to Californian Senate Energy Utilities and Communications Committee, April 2005. 

3        Wall Street Journal, Rebecca Smith, 11 May 2005. 

4        The CPUC regulates the older so-called investor-owned-utilities (IOUs). Newer utilities are referred to as private utilities. In addition, there are municipally-owned utilities. 

5        Joint press release, 11 May 2005. 

6        CPUC press release, 5 May 2005 (www.cpuc.ca.gov). 

7        Thorkelson, op. cit. 

8        Californian Energy Commission, Integrated Energy Report, November 2004 update. 

9        Energy Australia time-of-use meter implementation 

Energy Australia announced in June 2005 that it will offer Sydney, Central Coast and Hunter Valley residents lower cost electricity in shoulder and off-peak prices via new “smart” power meters. The meters will allow Energy Australia to introduce different rates at different times. Lower prices will be offered in the morning and overnight, with customers able to reduce power bills by choosing the pricing period in which they use appliances such as dishwashers and air conditioners. 

The three tiered pricing structure will mean peak prices are charged between 2:00 and 8:00 p.m., “shoulder” prices from 7:00 a.m. to 2:00 p.m. and 8:00 p.m. to 10:00 p.m., and off-peak prices from 10:00 p.m. to 7:00 a.m. 

The new system will be phased in gradually, with new residential homes, those upgrading their electricity installation and big users with annual bills in excess of $4,000 the first to be offered the new meters. Existing customers can convert to the new meters if they pay for installation. According to Energy Australia, prices will be 70 per cent higher in the peak period than current prices, 20 per cent cheaper in the shoulder period and 60 per cent cheaper during off-peak times. 

The company claims a family with a $900 bill could save $100 by changing 5 per cent of their peak electricity usage to off-peak and another 5 per cent to the shoulder times. An audit of Energy Australia customers has found changing operating times for pool pumps, washing machines, dryers and dishwashers could have a marked impact on bills.

10      2004 Update, p.54.

11      Ibid, p. xiii. 

12      California continues to actively evaluate and implement such pricing systems under a CPUC rule-making (R.02-06-001) edict. 

13      The Energy Commission’s new building standards, to be adopted in 2006, when combined with training and enforcement, are expected to reduce energy needs in new buildings by approximately 5 per cent. 

14      New federal appliance standards will increase air conditioner efficiency by approximately 20 per cent by 2007. However, if California were granted a waiver from federal standards, by 2007 the CEC estimates that California air conditioner efficiency could increase by another 10 per cent. 

15      Interim Opinion: Updated Policy Rules for Post-2005 Energy Efficiency and Threshold Issues Related to Evaluation, Measurement and Verification of Energy Efficiency Programs, Decision 05-04-051, 21 April 2005. 

16      Summary of Sempra Energy/SDGE presentation, Energy Efficiency Programs, Public Workshop, 3 March 2005. 

17      The paper regards Demand Response (DR) as only applying to peak load reduction measures, including distributed generation (DG), but including EEI in only a long term sense. This definition is not universally accepted. 

18      A National Demand Management Strategy for Small Air Conditioners, for the National Appliance and Equipment Energy Efficiency Committee (NAEEC) and the Australian Greenhouse Office (AGO), November 2004 (GWA 2004).

Economic Overview (NER 58)

National Economic Review No. 58 September 2005

The National Economic Review is published four times each year under the auspices of the Institute’s

Academic Board.

The Review contains articles on economic and social issues relevant to Australia. While the Institute endeavours to provide reliable forecasts and believes material published in the Review is accurate it will not be liable for any claim by any party acting on such information.

Editor: Dr A. Scott Lowson

National Institute of Economic and Industry Research

This journal is subject to copyright. Apart from such purposes as study, research, criticism or review as provided by the Copyright Act no part may be reproduced without the consent in writing of the Institute.

ISSN 0813-9474

Economic overview

Peter Brain, Executive Director, NIEIR

Abstract

Peter Brain assesses the Australian economy and describes alternative scenarios

Although the GDP growth for 2003-04 was 3.6 per cent, this represented a relatively poor performance.

The GDP growth rate of 3.6 per cent for 2003-04 was the same as earlier projections. However, it represented a relatively poor performance. The reason for this assessment is due to the fact that over 2003-04 the Australian farm sector recovered from the drought. Farm product in 2003-04 grew by 27 per cent, adding 0.7 per cent to GDP growth. However, non-farm GDP grew by 3 per cent for 2003-04 despite a 5.6 per cent private consumption growth which represents the highest rate of growth for a number of years. Moreover, the growth rate of all the private investment components was 6 per cent or greater.

The reason for the relatively poor GDP growth outcome is, firstly, the poor performance of exports and, secondly, the growth in imports. There is a lag between farm production recovery and exports so the growth in exports resulting from the farm recovery will occur in 2004-05.

In 2003-04 imports grew by 13.1 per cent, only slightly below the growth in 2002-03. This represents a growth in import penetration across a wide range of sectors, including clothing, textiles, motor vehicles, chemicals and machinery. Imports represent one quarter of GDP. Hence, a 13.1 per cent import growth rate means that the growth in imports over 2003-04 reduce GDP by 2.5 per cent from what would otherwise have been the case if imports had growth in line with GDP.

Over the last two years in particular, the growth in imports has been a major negative factor in determining

Australia’s growth performance.

Australia’s exports performance has also been poor but will recover over the next three years.

In the few years since 1999-00, the value of Australia’s non-resource based exports has been flat. That is, no change has occurred. This is despite the value of trade in the Asia-Pacific region for non-resource based products growing between 30 and 40 per cent over the past four years.

In 2004-05 exports of goods and services are expected to grow by 5.1 per cent, in part due to the recovery of the farm sector. Exports will also recover over the next two to three years because of the coming on-line of major resource projects that were commenced in 2002 or 2003. The most important of these will be the fourth liquefied natural gas (LNG) train on the North West Shelf. In 2006 the Darwin LNG train will come on-line.

Both the United States and Australian dollars will devalue over the next five years relative to our trading partners.

Exports may well recover, but without a substantial devaluation of the Australian dollar, import growth will continue to outstrip the growth of exports. With the upswing in the world interest rate cycle now occurring, the continuation of the current growth in imports would lead to an Australian current account deficit of around 7 per cent of GDP. To hold the current account deficit at the 5 per cent level, which is the projection to 2008-09, it is necessary for the Australian dollar to devalue,

in weighted average terms of around 15 per cent over the 2006 to 2009 period. This is built into the projection.

It can be seen from Table 1 that the United States/Australian exchange rate stays relatively unchanged over the projection period. The projection also allows for the outcome that the United States dollar devalues 20 per cent against the Euro, yen and yuan over the projection period. Because Australia maintains parity with the United States dollar, it follows that there is an equivalent devaluation of the Australian dollar against these currencies. The appreciation of the yuan against the United States dollar is also assumed to trigger the appreciation of other Asian currencies against the United States dollar.

It is the devaluation of the Australian dollar that leads to a more subdued growth rate for imports over 2008 and 2009.

The recent evidence is that the downside phase of the dwelling cycle has commenced.

It has long been NIEIR’s contention that the down-phase of the current dwelling cycle would only commence when significant growth in established house prices ceased. By the June quarter 2004, established house prices had stabilised with a fall in established house prices in Sydney offset by more moderate price growth elsewhere. Moreover, the trend in approvals and the financing of dwellings for new construction all point to falls in dwelling construction over the next two years. Over the next two years the cumulative decline in housing construction is projected to be 18 per cent.

The borrow and spend behaviour of households is now reaching its peak. Household balance sheet constraints will be a negative factor for growth for the foreseeable future.

The ending of the established house price boom will also lead to a curtailment of a key driver of recent Australian economic growth, namely household borrowing to support consumption expenditure.

The growth in established house prices since 1996 resulted in the ratio of household net worth (the value of the housing stock plus financial assets less financial liabilities) increasing from 6 to 7.8 by June 2005 (Figure 2). From Figure 4, this allowed households to borrow to fund a borrowing gap which has reached 15 per cent of disposable income by June quarter 2004. The borrowing gap represents the difference between consumption expenditure and discretionary income. Discretionary income is significantly smaller than household income in the national accounts because it includes superannuation contributions and superannuation interest, which represents income that is not available for current consumption.

From Figure 3, by the June quarter 2004 the build up in debt to fund the borrowing gap (as well as the high level of housing investment) drove the household debt to net disposable income ratio to 163 per cent. In the June quarter 2002 the rate stood at 137 per cent.

From Figure 1, the household debt service ratio now stands at 25 per cent of disposable income, the highest on the historical record.

The combined impact of stable (or falling) house prices, high debt service and debt-income ratios will, at the most optimistic, force households to hold the borrowing gap at around 15 per cent of income. This will force consumption expenditure to grow in line with household disposable income, which in turn will reduce the rate of growth of private consumption expenditure to between 2 and 3 per cent over the medium term.

Even with modest consumption growth, the debt-income/debt-service ratio will continue to rise. A recession is likely at some point before 2010.

If the borrowing gap is held at 15 per cent, the debt-income ratio will still increase by around 7 percentage points per year. By 2009, given the projection in Table 1, the debt to income ratio will reach 200 per cent. If households decide to stabilise their debt-income ratio then the household savings ratio will have to rise to 6 to 8 per cent. Household consumption would most likely fall and the economy would experience a recession, probably a severe recession.

However, given the forecast methodology outlined above, this aspect has been translated into a lower trend rate of growth rather than a recession and this aspect makes the low case projection of more interest than the high case projection.

Fiscal stimulus will support the household sector in the short term.

The position in the short term is not as bleak as the borrowing gap would suggest because of the strong fiscal stimulus being given to the economy. The May 2004 Federal Budget and the election promises of October 2004 will give a stimulus of around 1 per cent per annum to household income over the next two to three years. This will probably be enough to partially offset the constraints of the household debt-service ratio. Beyond 2007, if a severe recession is to be avoided, further significant fiscal stimulus will be required. That is, as the growth in household debt slows, public sector new borrowings will have to increase significantly.

The alternative scenarios

The problem for Australia is that Australia is not the only economy with households with large amounts of illusionary wealth created by housing price bubbles. The same is true in North America, the United Kingdom and some Western European economies. An economy that is an indicator, in terms of a low scenario over the medium term, is the Netherlands. The Netherlands was a fast growing economy over the second half of the 1990s, in part driven by rapid increases in borrowings funding a house prices-wealth creation consumption boom. In 2001, house prices stabilised due to tightening monetary policy. In 2003 the economy was in recession with private consumption falling by 1.5 per cent, the largest fall since World War II.

For the Netherlands the catalyst was tightening European monetary policy over 2000. For Australia the likely trigger for a low scenario is also most likely to be an external shock such as illustrated in Table 2. There are a number of potential shocks with good probabilities of occurring over the next two to five years. They are listed in the Table.

The reason why a transition path from the base to low scenario is likely to be associated with an external catalyst is that there are two factors that would allow policy authorities to keep the economy on the base scenario trajectory despite increasing constraints in growth. These are:

  • strong public sector balance sheets which would allow fiscal policy to be expansionary for a decade or more; and
  • the potential for Australian nominal interest rates to be lowered by between 1 and 2 percentage points.

This cushion would allow the base scenario to be achieved if the world economy remained supportive.

Unfortunately, because of vulnerable households in a number of major economies, any negative shock to the world economy is likely to trigger the ushering in of a long period of low growth for Australia, in particular, and many parts of the developed world in general. In short, the low scenario, at least to 2012 or thereabouts, does not have a low probability of outcome.

The high scenario assumes the most optimistic outcomes for the world political economy.

Australian energy trade, 2004-10

ABARE and NIEIR analysis and estimates of Australian energy trade trends are presented below. Over the period there continues to be an energy trade surplus with projected increases in net oil imports being more than offset by coal, natural gas and uranium export increases.

In 2004-05 the trade surplus, at a projected $7.4 billion (NIEIR/ABARE), will be about $2 billion higher than in 2003-04 due to higher thermal coal exports (tonnes, prices) and higher LNG exports.

Table 1        Major economic aggregates: financial year averages (annual per cent rate of change)

1998-99

1999-00

2000-01

2001-02

2002-03

2003-04

2004-05

2005-06

2006-07

2007-08

2008-09

International
G7 real GDP

2.3

3.4

2.4

0.2

1.9

3.1

3.3

2.6

2.0

2.5

2.2

Trade partners real GDP

1.4

5.6

3.7

1.6

3.6

4.9

5.0

4.2

3.7

4.4

4.3

G7 CPI

1.0

1.5

2.0

1.1

1.5

1.5

1.8

1.8

1.7

1.9

2.0

Trade partners CPI

6.0

2.1

2.7

3.1

2.9

2.8

2.9

3.0

3.0

3.3

3.3

GDP and components
Private consumption expenditure

4.8

4.1

2.9

3.3

3.8

5.6

4.1

2.8

2.8

2.6

3.5

Non-dwelling construction

13.2

-8.6

-18.4

12.3

32.0

12.0

5.8

5.4

2.1

-0.2

6.3

Equipment

1.0

11.1

6.1

6.1

16.7

6.0

9.6

5.4

5.3

5.5

5.3

Housing

7.6

14.4

-20.8

19.2

15.4

7.7

-6.3

-10.5

4.3

8.5

6.9

Public consumption expenditure

4.0

2.9

2.0

2.1

4.4

3.3

4.2

3.5

4.2

4.5

3.6

Public investment expenditure

3.9

7.6

-11.9

0.9

6.4

5.3

6.1

3.3

3.7

4.1

-0.9

Stocks and other (% points)

-1.3

0.6

-0.2

-0.4

0.1

-0.7

1.0

-0.1

-0.3

-0.2

0.4

Exports

2.0

9.6

7.3

-1.1

-0.5

0.9

5.1

6.6

4.8

4.3

2.3

Imports

4.8

12.9

-1.3

2.2

13.5

13.1

5.1

3.7

4.1

4.3

4.4

GDP

5.3

3.8

2.0

3.9

3.1

3.6

3.0

2.9

3.1

3.1

3.5

Farm GDP

13.7

9.9

-0.8

4.6

-25.2

26.8

-1.9

-2.3

4.9

5.4

0.0

Non-farm GDP

5.0

3.6

2.1

3.9

4.1

3.0

3.2

3.0

3.1

3.0

3.5

Dwelling sector
Commencements

-34.1

45.3

3.4

-0.8

-13.3

-7.9

16.3

-5.1

0.4

Labour market
Employment

2.0

2.1

2.1

1.2

2.5

1.8

1.9

1.8

1.8

1.7

2.4

Unemployment rate

7.4

6.6

6.4

6.8

6.2

5.8

5.6

5.6

5.6

5.7

5.7

Population

1.1

1.2

1.4

1.2

1.2

1.3

1.2

1.2

1.2

1.2

1.1

Wages and prices
Average weekly earnings

3.5

2.9

4.8

5.3

5.3

5.6

4.2

3.9

4.2

4.7

4.8

CPI

1.3

2.4

6.0

2.9

3.1

2.4

2.6

2.5

3.2

3.3

3.1

Real household disposable income

4.4

3.9

4.6

1.9

1.3

5.1

3.6

2.4

1.8

2.3

3.5

Finance
90 day bill rate (%)

4.9

5.6

5.8

4.6

4.8

5.3

5.4

5.1

5.0

5.1

5.5

10-year bond yields

5.4

6.5

5.8

5.9

5.3

5.7

5.8

5.6

5.8

5.9

6.1

$US/$A

0.63

0.63

0.54

0.52

0.58

0.71

0.73

0.74

0.72

0.70

0.71

External sector
Current account balance ($billion)

-33.6

-32.6

-18.0

-20.6

-40.3

-47.4

-45.7

-46.2

-48.2

-50.2

-55.5

Current account balance (% of
GDP)

-5.5

-5.1

-2.6

-2.8

-5.2

-5.7

-5.2

-5.0

-4.9

-4.8

-4.9

Table 2 The alternative scenarios: potential drivers

Low scenario

  • 1. Terrorist strike against oil supply infrastructure in the Middle East. Oil price spikes to US$70 and above. World growth falls to zero 2005-2007.
  • 2. Sharp devaluation of US dollar. Capital flight. US dollar devalues 40 per cent. Inflationary pressures in United States forces interest rates up to 8 per cent. Severe United States recession followed by a decade of slow growth.
  • 3. Slow growth in developed world results in protectionist measures against China/India. Environmental and economic problems, drying up of capital inflow from low Chinese growth after Beijing Olympics. China becomes isolated and military tensions in North Asia return to 1960 levels.
  • 4. The rise in world interest rates and slower world growth results in Australia’s current account deficit rising to 8 per cent of GDP. Australian interest rates are raised to reduce domestic demand. Consumption expenditure falls 5 per cent over two years. Capital flight from Australia devalues currency by 40 percent in trade weighted terms. Inflation of prices critical in demand expansion measures for some time. Governments are slow to adopt expansionary fiscal policies.

High scenario

  • 1. Iraq stabilises and political solutions reached in Middle East between Jews and Israelis.
  • 2. Terrorism reduced to minimum levels. Oil price returns to US$15 to US$25 range.
  • 3. Euro Asia adopts expansionary monetary policies. Current high savings ratios allows the borrow and spend dynamic to drive above average European growth rates for 10 to 15 years. European growth takes pressure off United States balance of payments. Reformist United States government from 2008 raises taxes and stabilises the fiscal situation. China continues to open up and changes from a commercial economy to a market economy.
  • 4. Political transition to a basic democratic framework. World trade expands at 6 to 9 percent a year resulting in a rapid convergence of living standards between India/China and the developed economies.

Table 3        Australian energy trade trends

(A$ billion nominal)

Commodity

2004-05

2010

Coal (thermal)1

6.3

7.5

Natural gas (LNG)2

3.5

5.1

Uranium3

0.5

0.6

Oil (crude and products)4

-2.9

-5.0

Total

7.4

8.2

Notes:

  1. 1.2004 average price = $50/t.
  2. 2004 exports = 8 Mt; 2010 exports = 20 Mt.
  3. Contract prices (A$/lb U3O8) rising by 20 per cent, 2003-10.
  4. 2004; 80 per cent net self sufficiency at A$60/b.
    2010; 65 per cent net self sufficiency at A$50/b.

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