AGL Pipelines (NSW) Pty Limited 
ACN 080 842 360

 Revised ACCESS Arrangement Information for Central West Pipeline

8 February 1999

1.	Introduction
1.1	Overview of the Revised Access Arrangement Information

AGL Pipelines (NSW) Pty Limited (“AGLP”) is a wholly owned subsidiary of the AGL Group, and is the owner of the Pipeline referred to in the Access Arrangement.

The Access Arrangement adopts a Net Present Value (NPV) approach (with residual) to the determination of Reference Tariffs.

Terms used in this Revised Access Arrangement Information have the meanings given to them in Schedule 1 of the Access Arrangement.

Attachment 1 to this document shows the information categories listed in Attachment A of the Code and indicates where this information is contained within this document.

IMPORTANT NOTICE

The information contained in this document has been prepared in good faith by AGLP for the limited purpose of facilitating the determination of AGLP’s Access Arrangement application as required under the Code.  The information contained in this document should not be relied on for any other purpose.  The claims contained in this document in support of AGLP’s Access Arrangement application have not as yet been accepted by the Regulator.
1.2	Background to the Central West Project

Having successfully introduced natural gas to other regional centres in New South Wales, the AGL Group began in the 1990s to investigate the potential of transporting and distributing natural gas to the Forbes, Parkes, Narromine and Dubbo environs (known as the “Central West Project”).  However, the project’s relatively small loads and the presence of competing fuels meant that its commercial viability was questionable.

With the establishment of the Federal Government’s Regional Development Program, funding of up to $2 million was made available to the Orana Regional Economic Development Organisation (“ORDO”) towards the installation of gas infrastructure in the Central West region.  The availability of this funding contributed to making the Central West Project a more commercially viable proposal.

A condition of the Federal Government funding was that a tender process to select the preferred developer of the gas infrastructure would be managed by ORDO.  The AGL Group was selected as the preferred developer and by June 1998 had constructed the Central West Pipeline (“CWP”) from the Marsden off-take (on the Moomba to Sydney pipeline) to Dubbo.  The AGL proposal, which was supported by the local communities, included a common (ie zonal) tariff for all Users of the pipeline within the Marsden/Dubbo zone.  A zonal tariff has the benefit that no community within the zone would be at a cost disadvantage relative to any other community in securing a gas supply.

2.	Access & Pricing Principles
2.1	Tariff Pricing Principles

The CWP is a new pipeline which will deliver gas into a yet to be established market, and consequently the Reference Tariff Policy reflects the market realities of introducing natural gas as a competitive energy source in the Central West region.  With reference to market realities, the pricing principles need to take into account the following:

1)	Entry price for gas:  The Code requires that the Reference Tariffs should be designed with a view to replicating the outcomes of a competitive market.  The price of established alternate fuels is a key element in determining a competitive market price for gas in the Central West region.

2)	Price path:  The Code requires that the Reference Tariffs should be designed with a view to providing the Service Provider with the opportunity to earn a stream of revenue that recovers the efficient costs of delivery of the Reference Service over the expected life of the assets used in delivering this Service.  In order to achieve this objective, and recognising the effect of the competitive fuel market on prices, it is necessary to ensure that the price path compensates in later years for the early years of low tariffs.

3)	Market growth:  The Code requires that the Reference Tariffs should be designed with a view to providing an incentive to the Service Provider to reduce costs and to develop the market for Reference and other Services.  In the absence of significant foundation contracts and in the light of competitive fuel prices, AGLP faces significant risks in developing the market for use of the CWP.  The Reference Tariffs must be established at a level which allows AGLP to grow the market as quickly and efficiently as possible, in order to achieve this objective.

4)	Zonal tariffs:  In accordance the AGL Group’s proposal, a single common tariff is to apply for all Users within the Marsden to Dubbo zone.
2.2	Reference Tariff Determination
2.2.1	Price Path

Reference Tariffs will follow a price path determined by applying the NPV methodology over the economic life of the CWP.  During the first Access Arrangement Period, Tariffs will follow a price path that reflects both the need for a low entry price, and the requirement for Tariffs to move to an appropriate level to provide the revenues required to sustain AGLP’s investment in the CWP over its economic life.

Of the Reference Tariffs set out in Section 3 of the Access Arrangement, tariffs of $1.78, $1.98 and $2.17 per GJ for the years ending 30 June 1999, 2000 and 2001 have already been committed to by AGLP and communicated to the market.  This was necessary because at the time the CWP was commissioned the Code was not in place, and Prospective Users required tariff certainty prior to committing to using the CWP.  It is further proposed that prices of $2.37, $2.58 and $2.78 per GJ will apply for years 2002-4 respectively with the price path thereafter to move to a tariff linked to CPI.
2.2.2	Zonal Tariff

For new pipelines (and particularly those with no identifiable cost attributable to any specific user - eg compression costs) linking similar user classes in different geographic areas, a zonal tariff structure ensures that all Users will benefit whilst no user is disadvantaged in terms of price.  One of the concerns of ORDO in pursuing the development of gas infrastructure in the Central West region was that no local community within the zone should be at a price disadvantage to any other.  The benefit of a common zonal tariff for the CWP is that the zonal tariff lies between the stand alone costs of transporting gas to each of the communities along the pipeline and a distance based tariff to service these communities.

A major issue with attempting to underwrite a new pipeline project with a distance based tariff is that while it has intuitive appeal (ie users only paying for the length of pipeline they utilise) it means that unless the entry tariff for users at the end of the pipeline is at or below the equivalent competing fuel price, then the pipeline will not be built to that location.  This has a cascading effect, because in progressively reworking the tariffs for a pipeline to service the remaining users, these users have to bear a higher proportion of fixed costs, resulting in users no longer seeking gas, creating a price spiral.  That is, the users at the end of the pipeline will face a higher tariff than the required entry tariff, so that user drops off the pipeline. This process undermines the economics of the pipeline to the point it is no longer viable.

The Code requires that the legitimate business interests of the Service Provider be taken into account, and the interests of Users and Prospective Users be taken into account.  It was a key element of the AGL Group's tender for the CWP, and its acceptance as preferred developer, that zonal pricing be offered to Users.  Prospective Users of the CWP supported zonal pricing.  The tender and the commitment by the AGL Group to the CWP occurred prior to the finalisation of the Code, and all parties acted in a reasonable expectation that zonal pricing would be accepted in the subsequent Access Arrangement for the CWP.  Accordingly, the acceptance by the Regulator of zonal pricing is in the legitimate business interests of AGLP, and in the interests of Users and Prospective Users.

In light of the above, and in recognition of the fact that there is only one Reference Service being offered, it is not commercially and technically reasonable to allocate revenue (or costs) to Users, other than on a zonal (ie common) basis.

2.3	Reference Tariff Structure

In the light of the matters referred to in Section 2.1, the Reference Tariff structure for the CWP during the initial Access Arrangement Period consists of a single throughput tariff.  To stimulate throughput growth in the CWP, Users will pay a Reference Tariff which has the following features:

1)	no load factor adjustment (which is usual for pipelines as a means to adjust throughput tariffs to reflect the pipeline capacity actually required to deliver the gas);
2)	no overruns until such time as the pipeline achieves Contracted Capacity of 85%; and
3)	no minimum annual bills (which usually require payment for a minimum annual quantity of gas being delivered).

This simple tariff structure is designed to encourage usage of the CWP as Users (and particularly inexperienced gas consumers) will know they will pay solely for the quantity of gas delivered, without having to be concerned about load management issues which could impact on their cost of gas transportation.

2.4	Cost Allocation

As discussed in Section 2.3, there is only one Reference Service being offered (ie throughput), and all costs of providing this Reference Service are fully allocated to Users by way of the zonal throughput tariff.  It is not technically and commercially reasonable to allocate costs to particular Users by any other means and maintain the long term viability of the pipeline.

2.5	Incentive Mechanism

The incentive structures in the Reference Tariffs are:

1)	The level of Reference Tariff is determined to enable AGLP to develop the market for Reference and other Services; and

2)	The Reference Tariff set out in the Access Arrangement will apply during each year of the Access Arrangement period regardless of whether the estimates underpinning the Reference Tariffs are realised.

These incentive mechanisms provide an incentive to AGLP to reduce total operating costs on the one hand, and increase pipeline throughput on the other.

2.6	Other Revenue

The Reference Tariff has been designed to recover the revenue attributable to the Throughput Rate of the Throughput Service.  No allowance has been made for other revenue that may accrue from any other charge incorporated in the Reference Tariff as these are not considered material.

3.	Capital Costs
3.1	Asset Base
3.1.1	Depreciated Optimised Replacement Cost (“DORC”)

AGLP has used the DORC methodology to value the CWP.  DORC involves estimating the efficient cost of constructing the asset using current technology to meet current markets which results in the identification of the Optimised Replacement Cost (ORC) of the asset. Depreciation is then applied to the ORC to determine the DORC.

The reasons for selecting the DORC methodology include:

•	the optimisation inherent in DORC allows the benefits of technology to be passed on to Users while the costs of stranded/unutilised assets are not passed on; 

•	it provides a consistent valuation between new and existing assets;
 
•	it  sends correct price signals as to the cost of providing the Service.
3.1.2	Optimised Replacement Cost (“ORC”)

The CWP may ultimately be extended to Tamworth, and so it has been designed to accommodate, in addition to the estimated Marsden to Dubbo loads, the estimated loads between Dubbo and Tamworth.  In effect the CWP has been “oversized” to enable the cost effective haulage of gas to Tamworth in the future.

Various pipeline configurations were considered which identified that on a NPV of whole of life cost basis, the required pipeline configuration between Marsden and Dubbo to service the combined Marsden to Tamworth loads is a combination of 210mm (8”) and 168mm (6”) pipeline.  Until such time as the CWP is extended to Tamworth, it will operate in free-flow (ie no compression) conditions.

For the purposes of this Revised Access Arrangement Information, the CWP has been redesigned to determine an optimised configuration in which the capacity installed to accommodate the load beyond Dubbo is removed and the pipeline sized accordingly.  The optimised replacement cost of the CWP assets is detailed in the following table.

Optimised Pipeline and Replacement Costs ($m)

Asset Type
As at 30 June 1999	
RC
	
ORC
	
Adjusted
ORC
	
DORC
	
Transmission Pipeline
	29.76	26.98	24.98	28.54	
Compressor Stations:
Rotating Equipment
Station Facilities
	
Nil
Nil	
Nil
Nil	
Nil
Nil	
Nil
Nil	
Regulation and Metering Stations
	0.17	0.17	0.17	0.17	
Odourisation Stations
	0.15	0.15	0.15	0.15	
SCADA and Communications
	0.63	0.63	0.63	0.63	
Total Asset Value	30.71	27.93	25.93	29.49	

3.1.3	Valuation of non-system assets

There are no non-system assets (ie land and buildings, plant and equipment) to be added to the valuations in the above table.
3.1.4	Speculative Investment Fund

An amount of $2.78m (ie $29.76m-$26.98m) is to be placed into a Speculative Investment Fund until such time as it can be added to the Capital Base in accordance with the Code.  It is expected that the full amount of this fund will be added to the Capital Base of the CWP upon the construction of an extension to Tamworth.

3.1.5	Economic Depreciation

As is usually the case with “green-field” developments, the growth in pipeline utilisation will be a gradual process.  For the CWP, this means that during the initial Access Arrangement Period estimated returns will not be sufficient to cover the total accounting expenses (including profit and depreciation) of providing the Reference Services.  Accordingly there is a need for a mechanism to provide for the under-recovery of revenue in the early years of the CWP’s life which can be offset against over-recovery in the later years of operation.

The concept of economic depreciation provides such a mechanism and in respect of the CWP is necessary to achieve the objective of the Code, which requires that the Reference Tariffs should be designed with a view to providing the Service Provider with the opportunity to earn a stream of revenue that recovers the efficient costs of delivering the Reference Service over the expected life of the assets used in delivering that Service.

Application of economic depreciation to the CWP is also consistent with the provisions of Section 8.33(a) of the Code, which provides that the depreciation schedule should be designed:

“so as to result in the Reference Tariff changing over time in a manner that is consistent with the efficient growth of the market for the Services provided by the pipeline (and which may involve a substantial portion of the depreciation taking place in future periods, particularly where the calculation of the Reference Tariffs has assumed significant market growth and the pipeline has been sized accordingly)”.

This section of the Code recognises that such a mechanism is necessary to justify commitment to major infrastructure projects, and that this objective outweighs any argument that the ability to roll forward estimated under-recovery lessens incentives for efficiency. In addition, the Code recognises that inherent in investment in pipelines is a significant market risk of growing an undeveloped gas market, as is the case for the CWP.

3.1.6	Working Capital

A return on the initial working capital of $10,000 has been allowed for in the project cash flows.

3.1.7	Economic Life and Remaining Economic Lives

Based on AGLP’s experience as a major owner and operator of pipelines in Australia together with various recent access arrangements proposed by service providers, submissions of industry participants and decisions of Regulators, economic lives for the various assets making up the CWP have been established.  These are set out in the table below together with the average remaining economic life of each of the asset classes making up the CWP.

Table Asset Economic Lives (from installation and remaining years)

Asset	Economic Life (years)	Average Remaining Economic life (1 July 1999)
(years)	
Transmission Pipelines (coated and CP protected):
Constructed pre 1970
Constructed post 1970	

60
80	

N/A
79	
Compressor Stations:
Rotating Equipment
Station Facilities	

25
35	

N/A
N/A	
Regulation and Metering Stations	
50	
49	
Odorising Stations	35	34	
SCADA	10	9	
Plant and equipment	5-20	N/A	
Buildings	50	N/A	

3.1.8	Estimated and Committed Capital Expenditure

Capital expenditure for a pipeline system comprises two components:

1)	capacity expansion and system replacement; and

2)	non-pipeline system expenditure (plant and equipment etc).

As there are no non-system assets included in the capital base for the CWP, there is no non-system capital expenditure estimated.

For the CWP, there is no committed capital expenditure during the initial Access Arrangement Period, with the only capital expenditure estimated being that to replace minor pipeline components (ie “stay in business” capital expenditure).  It is assumed such components would include replacement and upgrading of:

•	instrumentation - metering, telemetry remote terminal units etc;
•	pipeline hardware – valves, regulators and fittings etc;
•	minor site capital improvements – fencing, security etc; and
•	specialised major spares.

The amounts estimated for capital expenditure are set out in the table below.

Estimated Capital Expenditure

Year Ending 30 June	1999	2000	2001	2002	2004	2004	
Capital Expenditure ($’000)	6.75	6.92	7.09	7.27	7.45	7.64	

3.2	Rate of Return
3.2.1	WACC Approach

AGLP adopted a weighted average cost of capital (WACC) approach as a guide to determining the appropriate rate of return for the CWP. This approach is similar to that used in recent regulatory decisions relating to gas industry infrastructure in Victoria and New South Wales. 

In October 1998 the ACCC’s decision concerning the Victorian gas transmission system held that 7.75% is a reasonable real pre-tax WACC for mature large scale gas transmission infrastructure in Victoria.  This decision was reached following significant public debate as to the nature of the WACC approach and the nature and value of the variables used in calculating  WACC.  AGLP has assumed that the Victorian outcome will be a relevant factor in determining the WACC for the CWP.

3.2.2	Application of WACC to CWP

The Code provides that the rate of return to be used in determining a Reference Tariff should provide a return which is commensurate with prevailing conditions in the market for funds and the risk involved in delivering the Reference Service (as reflected in the terms and conditions on which the Reference Service is offered and any other risk associated with delivering the Reference Service).  The ACCC’s decision referred to above can reasonably be considered as a benchmark for prevailing conditions in the market for funds - it is then necessary to consider the extent to which the risks involved in delivery of the Reference Services for the CWP are materially different from those involved in the Victorian infrastructure.

Firstly, the Victorian decision appears to have been substantially completed before the full impact of the Longford gas plant incident was known, hence it is unknown whether the risks to service providers highlighted by this incident were fully incorporated into this regulatory decision.

Secondly, the risks involved in the CWP are considerably greater than the risks involved in the Victorian transmission system due to the following factors:
•	the general uncertainty surrounding the CWP due to the fact that it only recently commenced operation, and unlike many other pipelines had no foundation Users to underpin the pipeline economics;
•	the much lower level of maturity of the CWP’s markets (this pipeline only commenced operation in June 1998 and has not yet established markets);
•	the much smaller size of the CWP;
•	the greater concentration of usage among several (relatively) large consumers connected into the CWP (it is expected that the three largest end-users of gas in the region will account for approximately 25% of pipeline throughput but as yet not all of these customers have entered into a binding gas supply agreement); and 
•	the significantly higher city gate price for gas in the Central West region than in Victoria resulting in higher delivered prices to consumers and consequent greater exposure to competing energy options.

To account for these factors a higher cost of equity can be expected.

Thirdly, to a large degree the risk inherent in a pipeline depends on the risk attributable to the end-users which it serves. The large end-users of the CWP are concentrated in agricultural processing, publishing and other resource processing and are typically small by national standards, but nevertheless exposed to both international market and climatic fluctuations.

Asset betas are an accepted measure of specific industry risk, and the asset betas of possible relevant industry groupings of end-users are shown below:

Industry	Asset Beta	
All industrials	0.65	
Diversified industrials	0.71	
Diversified resources	0.90	

In using the WACC approach, the WACC calculation should be used as a guide to identify a range in which a reasonable rate of return may be expected to lie. The selection of a final WACC then relies on consideration of other factors and the exercise of judgment to best meet the objectives of the Code.  Determination of precise values for the relevant parameters to be used in the various WACC calculations is recognised as problematic.

3.2.3	Range of Variables

The ranges of variables used in the WACC calculation are summarised in the table below, together with a general commentary on the major variables and formulas adopted.  Consideration of these parameters will establish a range within which a reasonable WACC could be expected to lie.

Parameter		Ranges	
		High 	Low 	
General 
Economic Parameters	Inflation	2%	3%	
	Corporate Tax Rate	36%	36%	
	Imputation Take Up Rate	25%	50%	
Gearing	Debt	50	60	
	Equity	50	40	
Cost of Debt	10 Year Bond  Rate	5.2%	4.8%	
	2010 CPI Linked Bond Rate	3.5%	3.2%	
	Debt Margin	1.45%	1.0%	
	Bank Costs	0.5%	0.5%	
Nominal Cost of Debt	Based on 10 Year Bond  Rate	6.65%	5.8%	
	Based on CPI Linked Bonds	7.45%	6.7%	
Cost of Equity	Market Risk Premium	7.0%	6.0%	
	Asset Beta	0.9	0.55	
	Equity Beta	1.66	1.23	
	Margin for Asymmetric Risk	1.0%	0	
	Margin for Self Insured Risk	0.5%	0	
Nominal Cost of Equity	Based on 10 Year Bond  Rate	18.2%	12.2%	
	Based on CPI Linked Bonds	19.0%	13.1%	
WACC Results	Nominal Post Tax WACC	10.7%	6.0%	
	Nominal Pre Tax WACC	16.9%	9.4%	
	Real Pre Tax WACC	13.9%	6.8%	

The formulae used to determine the WACC are:

Pre Tax Nominal = {Re  / (1–T(1–y)) x (E/V)}+(Rf +Dm) x (D/V)

Post Tax Nominal ={Re  x [(1–T)/(1–T(1–y))]x(E/V)}+(Rf +Dm) (1–T) x (D/V)

Where:
Re = Cost of Equity
T = Corporate Tax Rate
y = Imputation Credit Take Up Rate
E = Equity
D = Debt
V = Debt plus equity
Rf + Dm = Cost of Debt

Weightings
The weighting used in the WACC approach is the debt to equity ratio applicable to the CWP. According to the Code this weighting should be based on a financing structure that

“reflects standard industry structures for a going concern and best practice”.

Recent regulatory decisions relevant to the gas industry have adopted a 60:40 debt to equity ratio.

Risk Free Rate and Cost of Debt
The cost of debt for AGLP can be simply expressed as:
	
	Cost of Debt = Risk Free Rate + Margin

Ideally the risk free rate should reflect the rate “on the day”, however daily rates are volatile. AGLP has adopted a process of averaging the risk free rate over a short time span to remove daily volatility. Similar processes have been used in recent regulatory decisions relevant to the gas industry.

Two indicators of risk free rates were used:
•	the nominal ten year bond rate; and
•	a CPI indexed bond 2010 series with an inflation component added.

This latter indicator was chosen as recent regulatory decisions have used expected inflation rates of 2.5%, however these inflation rates do not seem to accord with differentials between nominal and CPI indexed bonds.  If this expectation of inflation is correct then CPI indexed bonds plus an inflation component may be a proxy for risk free rates.

The debt margin used by AGLP in calculating the WACC is in the range 1.45% to 1%.  In a recent regulatory decision the ACCC adopted a 1.2% debt margin.

Cost of Equity
A modified Capital Asset Pricing Model (CAPM) approach is being used to determine the cost of equity. 

The CAPM approach assumes all risk is symmetrical, however AGLP faces asymmetric risk as well as symmetric risk. The cost of equity is adjusted for this asymmetric risk.

The CAPM approach assumes all insurable risk will be insured against. AGLP chooses to self insure for various risk. The self insurance funds retained for these risks should be viewed as a component of the cost of equity.

The usual CAPM approach is:

Cost of Equity = Risk Free Rate + Beta Risk Measure X Market Risk Premium

or, more formally:

Re = Rf + Be (Rm – Rf)

Where:
Rf = Risk Free Rate
Be = equity Beta
Rm – Rf = Market Risk Premium

The modified AGLP CAPM approach is:

Cost of Equity = Risk Free Rate + Beta Risk Measure X Market Risk Premium
			+ Asymmetric Risk Measure + Allowance for Self Insurance

Cost of Equity Components
To derive an equity Beta an asset beta should be derived and then adjusted for financial structuring. There is some debate as to the correct form of these adjustment formulae.  AGLP has contrasted the results derived by the following formulae:

Monkhouse: Be =  Ba + (Ba - Bd) (1-(Rf + Dm))/(1 +(Rf + Dm)T) x (D/E)

Davis: Be =  Ba [1+(1-(1-y)T)D/E]

CSFB: Be =  Ba + [Ba - Bd]  x (D/E)

Where:
Bd = (Rd - Rf - Bank costs)/(Rm – Rf)	(ie the debt Beta)
Ba = asset Beta 

The equity Betas derived from these formulae were similar when identical inputs were used.

The equations and variables above produce a simple CAPM approach cost of equity in the range of 17.5 % to 12.2 %, which then needs to be adjusted for asymmetric risk and self insured costs.

Asymmetric risk has been independently estimated at 1.3%, with AGLP considering a range of 0 to 1.0 % appropriate.  Assessment of self insured costs is difficult to quantify, however AGLP considers the range of 0 to 0.5% appropriate.

In summary, after considering asymmetric risk and self insured costs, a cost of equity for the CWP based on a CAPM approach modified for asymmetric risk and self insured risk lies within the range of 19.0% to 12.2%.

Nominal Post-tax to Real Pre-tax Conversion
In this analysis, converting from a nominal post-tax WACC to a real pre-tax WACC is on the basis of first adjusting for tax, then adjusting for inflation.

Final WACC
AGLP recognises that the upper and lower ends of all the ranges of the parameters detailed in the previous table are unlikely to occur simultaneously and hence in its analysis identified the following as being reasonable ranges:

Parameter	High 	Low	
Cost of Equity	17.0 %	13.7 %	
Cost of Debt	7.3 %	6.0 %	
Real Pre Tax WACC	11.5 %	7.7 %	

A real pre-tax WACC from the upper half of the range was chosen as a low WACC could be a disincentive for investment. It is noted that the lower end of the range of WACCs derived above is approximately equivalent to the WACC determined in the Final Decision on the Victorian TPA Access Agreement.  However, to adopt a similar WACC for the CWP (ie 7.75%) would imply that the risks of the Victorian assets and the CWP are the same – which AGLP does not believe is the case.  On this basis the WACC considered appropriate by AGLP is 10.0% pre-tax real.
3.3	
Throughput and Cash Flow Projections

Information contained in this section 3.3 is not made publicly available. 

Information contained in this section 3.3 is not made publicly available. 

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4.	Non-Capital Costs:  Operations and Maintenance and Overheads and Marketing

Estimates of non-capital costs have been developed by AGLP for the five years to 30 June 2004.  As discussed in this section, such estimates have been established in the light of operations and maintenance activities being provided on a contract basis, with general, administration and marketing costs provided to AGLP as a corporate service from the AGL Group.

4.1	Operations and Maintenance Costs

Operation and maintenance activities for the CWP are to be performed under contract by EAP Operations Pty Limited (EAPO) which also performs such activities on the Moomba to Sydney pipeline.  The efficiency of the operating and maintenance costs incurred under this arrangement are discussed in Section 6.

As the CWP has only been recently constructed and is only part way through its first full year of operation, there are no historical financial data available to compare estimated operations and maintenance costs.  Operating and maintenance costs are based on actual costs expected to be incurred over the Access Arrangement Period.  There has been no allowance for contingency, and in respect of the operations and maintenance costs over the life of the CWP, infrequent but recurring costs (eg intelligent pigging) have been accounted for in the cash flow analysis in the year in which they are expected to occur.

Estimated operations and maintenance costs for the Access Arrangement Period have been included in the table below.  These costs include all direct operation and maintenance activities relating to the CWP, and as previously noted will be carried out under contract by EAPO.  AGLP has been advised by EAPO that of the estimated costs, labour, outside services, and materials and supply account for some 29%, 27% and 6% of the total operations and maintenance cost respectively.  Property taxes of $2,750 are also included in EAPO’s operations and maintenance cost.

No allowance has been made for system use gas in the operations and maintenance costs, since system use gas will be provided by the user.
4.2	Overheads and Marketing Costs

The cost of corporate services provided to AGLP in respect of general and administrative activities relating to the CWP and to market its services are as set out in the following table.

Total Operating Cost

Year Ending June 30 ($’000)	1999	2000	2001	2002	2003	2004	
Operations and Maintenance
	450.0	461.3	472.8	484.6	496.7	509.1	
Administration and General (including insurance, regulatory affairs, compliance, personnel and training, legal, accounting, taxation and government levies)
	223.5	229.1	234.8	240.7	246.7	252.9	
Sales and Marketing
	50.0	51.3	52.5	53.8	55.2	56.6	
Total	723.5	741.7	760.1	779.1	798.6	818.6	

4.3	Fixed versus Variable costs

Operating and maintenance costs of the CWP will not vary with throughput during the Access Arrangement Period.
4.4	Cost Allocation

All of the operating and maintenance costs are direct costs to AGLP and will be applied to all Users in the single zone applying under the CWP Access Arrangement.  Overheads and marketing costs will be applied on the same basis.  There is no regulated/unregulated differentiation of Users.

5.	System Capacity and Volume Assumptions
5.1	General

This section provides details relating to the technical specifications and throughput assumptions of the CWP.  As the CWP has only been recently commissioned, its design specification provides an appropriate description.
 
The CWP is designed for a maximum operating pressure of 10.2MPa.  The pipeline is 219.1mm (8”) for the southern 130km to Alectown (near Parkes) and 168.3mm (6”) outside diameter for the remaining 125km.

The pipeline steel specification is API 5L Grade X65 and X52 (in accordance with API Specification for Line Pipe, API Spec 5L).  Pipeline wall thickness design has been determined in accordance with the Pipeline Code AS2885.  A brief summary of technical details associated with the CWP is a follows:

Applicable Code			AS2885-1997

Maximum allowable		10,200 kPa (class 600)
operating pressure (MAOP)

Steel grades			API 5L X52 and X65

Diameter and Wall		168.3mm	4.8mm – 50% SMYS
thickness						6.4mm – 40% SMYS
							and
					219.1mm	5.0mm – 50% SMYS
							6.4mm – 40% SMYS

Length				255km

External coating			high density polyethylene – 1.2mm thickness

Internal coating			epoxy

Depth of cover			1200mm in roads and most locations

					5000mm for directional drills
					2000mm under rails and 1200 under rail reserve
					900mm in private property

Marker tape			in designated areas (built up areas, road crossings etc)

Concrete coating		at watercourses and flood plains

Concrete slabs			under table drains on road crossings

Valve coating			Intertuff UHB over 2.5 blast clean

Joint coating			Polyken 943-30 (inner) and 955-20 (outer) tape

•	Five off-take points (off-take and valve) supply reticulation systems in Forbes, Parkes, Narromine, Dubbo and Dubbo West.
•	An extension to the existing off-take station near Marsden, incorporating metering, line valve and scraper station and a new odourant facility.
•	Scraper stations near Alectown West and at the Dubbo end site.
•	Additional above-ground valve sites at average 27km intervals.
•	Pipeline markers and cathodic protection test points at intervals throughout.

5.2	Map of CWP and Pipe Specification

A map of the CWP Route is attached as Attachment 3.

Pipe sizes, lengths and delivery capability is set out in the tables below:

Pipeline Section	Diameter
(mm outside)	Length (km)	
•	Marsden off-take to Alectown Scraper Station	219.1	130	
•	Alectown Scraper Station to Dubbo	168.3	125	

Maximum Delivery Capability
(Marsden inlet pressure = 4000kPa, free flow conditions)	10.1 TJ/d	

5.3	Average Daily and Peak Demands

As the CWP has very little operating history, the estimated throughput and load profiles detailed in the table below are based on experience in comparable projects and assumptions as to the timing and level of penetration of natural gas.

City Gate/Parameter	1999	2000	2001	2002	2003	2004	
Forbes:
Total Annual Volume (TJ)
Average Daily Flow Rate (GJ)
Peak Day Flow Rate (GJ)
Minimum Delivery Pressure (kPa)

Parkes:
Total Annual Volume (TJ)
Average Daily Flow Rate (GJ)
Peak Day Flow Rate (GJ)
Minimum Delivery Pressure (kPa)

Narromine:
Total Annual Volume (TJ)
Average Daily Flow Rate (GJ)
Peak Day Flow Rate (GJ)
Minimum Delivery Pressure (kPa)

Dubbo:
Total Annual Volume (TJ)
Average Daily Flow Rate (GJ)
Peak Day Flow Rate (GJ)
Minimum Delivery Pressure (kPa)	
11
30
52
1750

97
266
454
1750

5
14
23
1750

163
447
764
1750	
105
288
492
1750

118
323
553
1750

18
49
84
1750

257
704
1204
1750	
120
329
562
1750

147
403
689
1750

24
66
112
1750

429
1175
2010
1750	
167
458
782
1750

183
501
857
1750

30
82
141
1750

562
1540
2633
1750	
213
584
998
1750

233
638
1092
1750

42
115
197
1750

676
1852
3167
1750	
224
614
1049
1750

246
674
1152
1750

48
132
225
1750

737
2019
3453
1750	

5.4	Estimated Load Across Each Pricing Zone

Estimated average daily, peak and total pipeline load for years ending 30 June 1999 – 2004 are set out below.  There is only one pricing zone for the CWP.

Load and Volume	1999	2000	2001	2002	2003	2004	
Average Daily Load (GJ/D)	757	1364	1973	2581	3189	3438	
Peak Load (GJ/D)	1295	2335	3376	4417	5458	5884	
Annual Volume (TJ)	276	498	720	942	1164	1255	

5.5	System Load Profile by Month

Given the CWP has very little operational history, the monthly load profile is based on estimated loads.  In addition, as the estimated loads vary significantly, the load profile is presented in terms of percentages.

Month	% of total Annual Load	
January	4.9	
February	6.4	
March	6.7	
April	8.5	
May	10.1	
June	10.8	
July	11.6	
August	11.2	
September 	9.6	
October	7.5	
November	7.1	
December	5.6	
Total	100	

5.6	Numbers of Users on the CWP as at December 1998

Number of Users	1	

6.	
Efficient Costs and Performance Measures for Pipelines
6.1	Introduction

(a)	Objective of Demonstrating Efficient Costs

The Code provides that a Service Provider’s Reference Tariff and Reference Tariff Policy should be designed to provide the Service Provider with the opportunity to earn a stream of revenue that recovers the efficient cost of delivering the Reference Service and that costs be those incurred by a prudent Service Provider acting efficiently, in accordance with accepted and good industry practice to achieve the lowest sustainable cost of delivering the Reference Service.

(b)	Issues Relating to Performance Measures and Benchmarking of Transmission Pipelines

The ACCC in its Final Decision on the access arrangements submitted by Transmission Pipelines Australia (TPA):

“…recognises the challenges in identifying KPIs and benchmarks especially in a newly deregulated environment such as the Victorian natural gas industry.”

These same challenges will continue to exist throughout the Australian gas transmission industry until such time as there is sufficient meaningful information relating to performance in the public domain.  In addition to the difficulty of identifying KPIs and benchmarks, there are further challenges to be overcome in working up meaningful comparisons of the performance of individual pipelines in the industry including:

•	Prior to now there has been only limited publicly available information (mostly from Government owned entities many of which have now been privatised),
•	Privatisation within the industry has meant private companies have declined to release performance indicators on the basis of commercial sensitivity and restrictions on disclosure, and
•	Difficulty of “normalising” pipelines to yield meaningful comparisons due to extremely diverse characteristics of pipelines (eg size, length, geography and topography of location, operational characteristics etc).

Nevertheless, it is recognised that it is necessary for the Regulator to benchmark performance, despite these very real difficulties.  In this context, whilst the performance data presented is necessarily at a high level and of limited scope, it will contribute to the development of meaningful industry performance measures over time.

(c)	Tariff Setting and Performance Measures

Before performance indicators can be used to benchmark operating efficiency, an appropriate range of such measures must be developed for comparable pipelines in relation to the service offered.  While it is anticipated that such measures will be developed over time to suit the Australian industry, they are not currently established.

Therefore, performance comparisons presented have not been used to set or establish tariffs, but rather to demonstrate that AGLP is operating the CWP in an efficient and prudent manner.
6.2	Cost Structure of Pipelines

Operating pipelines is a capital intensive industry.  As a general rule, some 80–90% of annual accounting costs of operating a pipeline are attributable to capital related expenses in the form of depreciation and EBIT.

Annual accounting costs attributable to operating and maintenance costs make up the balance – some 10-20%.
6.3	Performance Measures for Pipelines
6.3.1	Capital Costs

As capital related expenses represent 80-90% of annual accounting costs, the cost of constructing the pipeline is clearly the dominant cost and therefore the most important to measure.  However, to enable a comparison of construction costs, it is necessary to adjust the costs to take into account the factors driving capital costs, such as: 

•	surface conditions – bare, forest,
•	soil type and condition – rock, sand,
•	remoteness – urban, rural,
•	type of steel – for example high tensile yields lower capital expenditure,
•	price of steel – steel prices have dropped some 20% over the last year (steel makes up some 30% of installed cost of pipelines),
•	delays – approvals, land title, weather etc.

It is difficult to “normalise” these factors between various pipeline construction costs to allow meaningful comparison.

Given these difficulties, an industry accepted measure of pipeline installation cost efficiency is $/Millimetre/km.  Throughput related measures (eg $/GJ or $/GJ/km) are poor measures of efficiency because of potential distortion due to differences in economies of scale between different sized pipelines and they ignore the effects of load factors and the level of utilisation of the pipeline.
6.3.2	Operating Costs

Even though operating and maintenance costs drive a minor portion of annual pipeline costs, the range of activities required to operate and maintain a pipeline are, like capital costs, affected by a series of pipeline specific factors including:

•	terrain; river, road and rail crossings etc,
•	remoteness,
•	age of pipe,
•	condition of coating,
•	type of steel,
•	rotating equipment (eg compressor stations).

Given these factors, industry accepted measures of pipeline operating and maintenance efficiency include:

•	$/km,
•	direct pipeline O&M expense/replacement cost of pipeline, and
•	direct pipeline rotating equipment O&M expense/replacement cost of rotating equipment.

As with capital costs, throughput related measures ($/GJ or $/GJ/km) are poor indicators of efficiency for the same reasons applicable to capital costs.

6.4	Key Performance Indicators
6.4.1	Australian Comparisons
6.4.1.1	Capital Costs

The table below is data extracted from a paper “Australian Transmission Pipeline Costs” presented at the 1998 Australian Pipeline Industry Association (APIA) Convention.  The table lists those pipelines not dissimilar to the CWP in length and diameter and expresses the capital cost on a $/mm/km basis.

Pipeline	When Constructed	Length (km)	Diameter (mm)	Unit Cost $/mm/km	
Mereenie to Alice Springs
	1985	270	200	730	
Young to Lithgow
	1987	212	150	1115	
Canarvon Lateral
	1988	171	150	719	
Whyalla Lateral
	1989	71	200	1212	
Gladstone to Rockhampton
	1991	96	200	957	
Junee to Griffith
	1993	170	150	805	
Marsden to Dubbo	1998	130
125	200
150	620	

The unit cost figures presented in the table above suggest that capital applied to the construction of the CWP has been utilised efficiently.
6.4.1.2	Total Operating Costs - Actual

As noted in Section 4, AGLP will operate the CWP on the basis of direct operations and maintenance being performed under contract by EAPO with general administration and marketing requirements provided to AGLP as a corporate service.  On this basis, the total operating costs estimated for year ending June 1999 is $723,500.

6.4.1.3	Total Operating Costs – Stand Alone

On the basis of AGLP’s experience as a major owner and operator of transmission pipelines in Australia, our assessment of a stand alone organisation to operate the CWP is that an equivalent of around 10 people would be required.  In addition, such a stand alone organisation would incur significant costs associated with providing:

•	offices and a field depot,
•	vehicle and tools necessary for operating and maintaining the pipeline and associated systems,
•	stand alone SCADA, telemetry and control facilities, and
•	sub-contracting of specialist services such as payroll, legal, training, superannuation, auditing, project engineering, etc.

Based on our experience a budget for such a stand-alone pipeline operation would be in excess of $1.2m per annum.
6.4.1.4	Total Operating Costs - Indicative Based On Experience

From AGLP’s experience in constructing and operating pipelines, indicative “rules of thumb” have been developed which are used to estimate total operating costs in investigating new pipeline opportunities.  Whilst acknowledging that applying generalised averages to establish a total operating cost is somewhat subjective it nevertheless provides an indication of what operating costs can be expected under “average” conditions to be incurred in operating pipelines.  These are set out in the table below.

Indicative Total Pipeline Operating Expenses as a Percentage of
Asset Replacement Cost

Asset	Average	Large Pipeline	Small Pipeline	
Pipeline	2%	1.5%	2.5%	
				
Asset	Average	Multiple Units	Single Unit	
Compressors (gas turbines)	6%	5%	7%	

6.4.1.5	Total Operating Cost – Comparison with TPA

The most recent publicly available total operating cost information is that of TPA whose transmission system includes compression.  Applying the indicative measures above to TPA’s total operating expense is set out in the table below.

TPA Total Operating Cost ($m) – 1998

	Replacement Cost	AGLP Indicative Measure Applied	Indicative Operating Cost	Actual TPA Estimated Operating Cost	
Pipeline Direct
	596.3	2%	11.9	N/a	
Compression
	62.3	6%	3.7	N/a	
Total	658.6		15.6	19.5	

Assuming the indicative operating cost attributable to compression is correct, then operating cost attributable to the pipeline component of TPA is around $15.8m (ie $19.5m – $3.7m) which is 2.6% of replacement cost.

A comparison of total operating cost using AGLP’s indicative measure with TPA’s estimate as applied to both the TPA and the CWP is set out in the table below.  Note that the compression related operational costs have been removed as per the above analysis.

Comparison of Operating Costs by Applying AGLP Indicative Measure
and TPA Estimates

	Replacement Cost

($m)	AGLP indicative measure 2%
($m)	TPA estimate 2.6%

($m)	
TPA	596.3	11.9	15.5	
CWP	30.71	0.61-0.77	0.80	

The above analysis, whilst not being based entirely on precise information does suggest that a reasonable cost of operating the CWP is within the range of $770,000 (from the above table) to $1,200,000 (on a stand alone basis) per annum.  AGLP has estimated total operating expense to be $723,500 per annum which is at the low end of the range.
6.4.1.6	Total Operating Cost – Comparison with Australian Pipelines

The table below sets out comparisons of estimated total operating costs for the CWP, TPA and a selection of (albeit somewhat dated) other Australian pipeline operators on a $m/1000 km basis.  The data has been sourced from the TPA Access Arrangement.

Company	AGLP	TPA	TPA	AlintaGas	Pipeline Authority	PASA	
State

Year

$m/1000km	NSW

98/9

2.8	VIC

98

11.0 – 16.0	VIC

95/6

9.9	WA

95/6

13.6	NSW

94/5

10.4	SA

94/5

10.1	

Even making allowance for the fact that these pipeline systems all have compression, and are very much larger than the CWP, the above comparisons point to the total operating costs for the CWP being efficient.

6.4.2	US Comparison
6.4.2.1	Capital Costs

NERA has developed construction cost estimates for long distance transmission pipelines on a per diameter/km basis for various pipe diameters for use in planning purposes in North America.  Given recent exchange rate volatility, a range of exchange rates between 62-78 US cents per $AUS has been applied to the NERA costs which then have been used to calculate an estimated construction cost of the CWP.  The comparison is set out in the table below, in US dollars.

	Actual $/mm/km	NERA estimate $/mm/km	
CWP	385-484	620	

6.4.2.2	Operating Costs

In contrast to Australia the US has a significant amount of data publicly available on gas pipeline operating costs which is in a standard form as required by the Federal Energy Regulatory Commission (FERC).  However the same problems of comparability that exist in Australia arise because of the environmental differences which affect costs between each pipeline.

Nevertheless, the static comparison below of total operation and maintenance expense/km of transmission pipeline provides useful insight into the efficiency of AGLP in operating the CWP when compared to a range of US pipelines.  It is noted that the US pipelines in the comparison tend to be very large by Australian standards and probably all having compression.  Data on the US pipelines has been sourced from the 1997 FERC filings of 36 pipeline companies.

ATTACHMENT 1

CATEGORIES OF INFORMATION TO BE DISCLOSED AS PART OF THE ACCESS ARRANGEMENT INFORMATION
Category in Access Code	Reference in the Revised Access Arrangement Information	
Category 1: Information regarding Access & Pricing Principles

Tariff determination methodology.
Cost Allocation approach.
Incentive structure.

Category 2: Information regarding Capital Costs
Asset values for each pricing zone, service or category of asset.
Information as to asset valuation methodologies – historical cost or asset valuation.
Assumptions on life of asset for depreciation.
Depreciation.
Accumulated depreciation.
Committed capital works and capital investment.
Description of nature and justification for planned capital investment.
Rates of return – on equity and on debt.
Capital Structure – debt/equity split assumed.
Equity returns assumed – variables used in derivation.
Debt costs assumed – variables used in Derivation.

Category 3: Information regarding Operations and Maintenance Costs
Fixed versus variable costs.
Cost allocation between zones, services or categories of asset & between regulated and unregulated.
Wages & Salaries – by pricing zone, service or asset category.
Cost of services by other including rental equipment.
Gas used in operations – unaccounted for gas to be separated from compressor fuel.
Materials and supply.
Property Taxes.

Category 4: Information on Overheads & Marketing Costs
Total service provider costs at corporate level
Allocation of costs between regulated and unregulated segments.
Allocation of costs between particular zones, services or categories of asset.

2.2
2.4
2.5

3.1.2

3.1.1, 3.1.2
3.1.7
3.1.5
3.1.5
3.1.8

3.1.8
3.2.3
3.2.3
3.2.3
3.2.3

4.3

4.4
4.1
4.1

4.1
4.1
4.1

4.2

4.4

4.4	

Category in Access Code	Reference in Revised Access Arrangement Information	
Category 5: Information regarding System Capacity & Volume assumptions

Description of system capabilities
Map of piping system – pipe sizes, distances and maximum delivery capability.
Average daily and peak demand at “city gates” defined by volume and pressure.
Annual volume across each pricing zone, service or category of asset.
System load profile by month in each pricing zone, service or category of asset.
Total Number of customers in each pricing zone, service or category of asset.

Category 6: Information regarding Key Performance Indicators
Industry KPIs used by The Service Provider to justify “reasonable incurred” costs.
Service provider’s KPIs for each pricing zone, service or category of asset.

5.1, 5.2, Attachment 3

5.3

5.4

5.5

5.6

6.3

6.4

ATTACHMENT 2

COMPILIATION OF US DATA FOR COST COMPARISION

2.1	Companies Included in Cost Comparison

The table below identifies the pipeline companies which have been included in the cost comparison study.

1	ANR Pipeline Co	21	PG&E Gas Transmission Northwest Corp	
2	Black Marlin Pipeline Co	22	Questar Pipeline Co	
3	Chandeleur Pipeline Co	23	Sabine Pipeline Co	
4	Columbia Gulf Transmission Co	24	Sea Robin Pipeline Co	
5	East Tenessee Natural Gas Co	25	Stingray Pipeline Co	
6	El Paso Natural Gas Co	26	Tenessee Gas Pipeline Co	
7	Florida Gas Transmission Co	27	Texas Eastern Transmission Corp (Tetco)	
8	Great Lakes Gas Transmission LP	28	Texas Gas Transmission Corp	
9	High Island Offshore System	29	Trailblazer Pipeline Co	
10	Iroquois Gas Transmission LP	30	Transcolorado Gas Transmission Co	
11	K N Interstate Gas Transmission Co	31	Transwestern Pipeline Co	
12	Kern River Gas Transmission Co	32	Trunkline Gas Co	
13	Midwestern Gas Transmission Co	33	U-T Offshore System	
14	Mojave Pipeline Co	34	Viking Gas Transmission Co	
15	Mississippi River Transmission Co	35	Williams Gas Pipelines Central	
16	Mobile Bay Pipeline Co	36	Wyoming Interstate Co Ltd	
17	Northern Border Pipeline Co			
18	Northern Natural Gas Co			
19	Overthrust Pipeline Co			
20	Panhandle Eastern Pipeline Co			

2.2	Company Selection Criteria

Initially some 75 companies were identified from FERC filings as being “pipeline” companies.  However, as some of these companies are integrated businesses which could include production, storage, transmission and distribution activities a filtering process was applied to identify those companies whose dominant business activity was transmission.

This filtering process identified 36 companies whose core business is transmission, and whose other activities (ie production, storage and distribution) make up a minor portion of total operating costs.

2.3	Operation and Maintenance Expense

In the cost comparison, only the operation and maintenance expense for transmission activities were included (ie any operation and maintenance expense allocated to production, storage or distribution have been deleted).

2.4	Marketing and Overhead Expenses

The FERC requires operating and maintenance cost data to be allocated to each of a company’s operating activities, however this doesn’t apply for marketing and overhead expenses.  Because marketing and overhead expenses are not allocated to separate operating activities, the share of these expenses to each of the operating activities can not be accurately determined.  This means that the marketing and overhead expenses used in the cost comparison are for the total business, however because transmission activities of the companies selected are dominant, any overstating of marketing and overheads expense would be minimal, and have no impact on the conclusion drawn from the US/AUS comparison that the CWP is being operated efficiently.

ATTACHMENT 3

MAP OF CENTRAL WEST PIPELINE ROUTE

1.	Introduction	1
1.1	Overview of the Revised Access Arrangement Information	1
1.2	Background to the Central West Project	1
2.	Access & Pricing Principles	3
2.1	Tariff Pricing Principles	3
2.2	Reference Tariff Determination	3
2.2.1	Price Path	3
2.2.2	Zonal Tariff	4
2.3	Reference Tariff Structure	5
2.4	Cost Allocation	5
2.5	Incentive Mechanism	5
2.6	Other Revenue	6
3.	Capital Costs	7
3.1	Asset Base	7
3.1.1	Depreciated Optimised Replacement Cost (“DORC”)	7
3.1.2	Optimised Replacement Cost (“ORC”)	7
3.1.3	Valuation of non-system assets	8
3.1.4	Speculative Investment Fund	8
3.1.5	Economic Depreciation	9
3.1.6	Working Capital	9
3.1.7	Economic Life and Remaining Economic Lives	10
3.1.8	Estimated and Committed Capital Expenditure	10
3.2	Rate of Return	11
3.2.1	WACC Approach	11
3.2.2	Application of WACC to CWP	11
3.2.3	Range of Variables	13
3.3	Throughput and Cash Flow Projections	17
4.	Non-Capital Costs:  Operations and Maintenance and Overheads and Marketing	19
4.1	Operations and Maintenance Costs	19
4.2	Overheads and Marketing Costs	19
4.3	Fixed versus Variable costs	20
4.4	Cost Allocation	20
5.	System Capacity and Volume Assumptions	21
5.1	General	21
5.2	Map of CWP and Pipe Specification	22
5.3	Average Daily and Peak Demands	22
5.4	Estimated Load Across Each Pricing Zone	23
5.5	System Load Profile by Month	24
5.6	Numbers of Users on the CWP as at December 1998	24
6.	Efficient Costs and Performance Measures for Pipelines	25
6.1	Introduction	25
6.2	Cost Structure of Pipelines	26
6.3	Performance Measures for Pipelines	26
6.3.1	Capital Costs	26
6.3.2	Operating Costs	27
6.4	Key Performance Indicators	27
6.4.1	Australian Comparisons	27
6.4.1.1	Capital Costs	27
6.4.1.2	Total Operating Costs - Actual	28
6.4.1.3	Total Operating Costs – Stand Alone	28
6.4.1.4	Total Operating Costs - Indicative Based On Experience	29
6.4.1.5	Total Operating Cost – Comparison with TPA	29
6.4.1.6	Total Operating Cost – Comparison with Australian Pipelines	30
6.4.2	US Comparison	31
6.4.2.1	Capital Costs	31
6.4.2.2	Operating Costs	31

ATTACHMENT 1	CATEGORIES OF INFORMATION TO BE DISCLOSED AS PART OF THE ACCESS ARRANGEMENT INFORMATION ………..…………………………..33
ATTACHMENT 2	COMPILATION OF US DATA FOR COST COMPARISON ……………………35
ATTACHMENT 3	MAP OF CENTRAL WEST PIPELINE ……………………….…………………..37