N.T. GAs Pty. Limited 
ACN 050 221 415

ACCESS Arrangement Information for THE 
AMADEUS BASIN TO DARWIN Pipeline

25 June 1999

1	Introduction
1.1	Overview of the Access Arrangement Information

This document is the Access Arrangement Information in relation to the Access Arrangement for the Amadeus Basin to Darwin Pipeline (“ABDP”).  It has been submitted by N.T. Gas Pty. Limited ACN 050 221 415 (“NT Gas”) pursuant to the Gas Pipelines Access Law and Section 2.2 of the National Third Party Access Code for Natural Gas Pipelines (“Code”).  As the operator of the ABDP, NT Gas is the Service Provider in respect of the Pipeline.

The purpose of this document is to set out such information as is necessary to enable Users and Prospective Users to understand the derivation of the elements of the Access Arrangement and to form an opinion as to the compliance of the Access Arrangement with the provisions of the Code.

In accordance with the Code, the form of regulation adopted in this Access Arrangement is a “Price Path” methodology in respect of the determination of Reference Tariffs.

Terms used in this Access Arrangement Information have the meanings given to them in Schedule 1 of the Access Arrangement or the Code as the case may be.

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.

1.2	Background

In the mid 1960s natural gas was discovered at the Amadeus Basin, near Alice Springs, in both the Palm Valley and Mereenie fields.  These discoveries, while significant, remained undeveloped due to the inaccessibility of markets for such remote reserves. In September 1983 gas for base load electricity generation was first produced and delivered to Power and Water Authority (“PAWA”) at Alice Springs, 150kms from the Palm Valley gas field.

In 1984 the Northern Territory (“NT”) Government began construction of a new coal fired power station on Channel Island some 42kms from the city of Darwin.  During the course of constructing the power station, the NT Government, after conducting a feasibility study of the gas reserves in the Amadeus Basin and assessing the economics of hauling natural gas to Darwin via pipeline, committed both the Channel Island and Katherine power stations to be fuelled by natural gas.

NT Gas was formed from a consortium of companies to finance, construct, commission and operate the ABDP.  The pipeline was commissioned in December 1986 and first gas delivered to PAWA in January 1987.

In 1988 the AGL Group acquired through wholly owned subsidiaries 96% of NT Gas, the other shareholders being Darnor Pty. Limited (an NT Government company) 2.5% and Centrecorp Aboriginal Investment Corporation Pty. Limited (a company owned by the Central Land Council) 1.5%.

Ownership of the ABDP is vested in a consortium of banks and the pipeline is leased to NT Gas as trustee of the Amadeus Gas Trust.  The provisions of the Trust Deed specify the manner in which revenue received from the operation of the ABDP is to be distributed to beneficiaries under the Trust who include the shareholders of NT Gas.

Since the commissioning of the ABDP a number of lateral pipelines have been constructed to interconnect into the ABDP (all of which do not form part of the ABDP for the purposes of this Access Arrangement) including the:

•	McArthur River pipeline was commissioned in February 1995 and gas was supplied to fuel the power station at the McArthur River mine.  This pipeline is currently not operating in its intended mode in that its operating pressure is restricted.
•	Darwin City Gate to Berrimah pipeline was commissioned and gas supplied to industrial users in the Darwin environs in January 1996.
•	Mt Todd pipeline was commissioned in October 1996 and gas supplied to fuel the power station at the Mt Todd mine.  In November 1997 mining operations were suspended at the mine after the mine owner Pegasus Gold Australia Pty Limited became insolvent forcing the recently commissioned pipeline infrastructure out of service.  The Mt Todd lateral remains idle.

Current throughput of the ABDP is around 16 PJ per annum, with some 99.7% of total pipeline throughput being delivered to power generation facilities situated at various locations along the pipeline and which are either owned by PAWA or delivered to other such facilities on behalf of PAWA.  The remaining pipeline throughput is to service small industrial customers in the Darwin environs and industrial use at Mataranka.

There is currently no available firm capacity in the ABDP, with all existing capacity being utilised under existing agreements. There is in the vicinity of 5TJ per day of capacity available on an interruptible basis – the availability of such capacity depends on seasonal factors reflecting that gas transported through the ABDP is primarily used for power generation.

1.3	Important Notice

The information contained in this document has been prepared in good faith by NT Gas for the limited purpose of facilitating the determination of NT Gas’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 NT Gas’s Access Arrangement application have not as yet been accepted by the Regulator.
2	
Access & Pricing Principles
2.1	Factors to be taken into account by regulator

The Code requires the Regulator to take the following into account in deciding whether to approve a proposed Access Arrangement:

a)	Service Provider’s legitimate business interests and investment in the Covered Pipeline: the Total Revenue determined by NT Gas, the design of the Reference Tariffs and the recognition of existing contractual rights and obligations is designed to protect these interests and investment;

b)	firm and binding contractual obligations of the Service Provider or other persons: the Rebate Mechanism, the nature of the Interruptible Service and the queuing policy reflect these obligations;

c)	operational and  technical requirements required for safe and reliable operation of the Covered Pipeline: the terms and conditions of the Services are designed to achieve these objectives;

d)	economically efficient operation of the covered Pipeline: this is incorporated in the operating costs for the ABDP and the forecast capital expenditure;

e)	public interest, including in having competition in markets (whether or not in Australia): the public interest in competition is accommodated through cost-reflective pricing, and recovery of only efficient capital and non-capital costs; the public interest in safe and reliable operation of the ABDP is accommodated through recovery of such costs and the general terms and conditions;

f)	interests of Users and Prospective Users: the Rebatable Service and the Negotiated Service are designed to recognise these interests for Prospective Users while recognising the rights and obligations of existing Users.
2.2	Tariff Principles

The Code states that a Reference Tariff and Reference Tariff Policy should be designed with a view to achieving the following objectives:

a)	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: the Total Revenue determined by NT Gas recognises the capital costs of the ABDP (through determination of DORC) and efficient operating costs;

b)	replicating the outcome of a competitive market: this is reflected through the determination of the DORC and adoption of zonal pricing;
c)	ensuring the safe and reliable operation of the Pipeline: this is incorporated in the operating costs for the ABDP and forecast capital expenditure, and is also reflected in the terms and conditions of the Services;

d)	not distorting investment decisions in Pipeline transportation systems or in upstream and downstream industries: this is accommodated through cost-reflective zonal pricing and recovery of efficient capital and non-capital costs;

e)	efficiency in the level and structure of the Reference Tariff: this is reflected through zonal pricing and throughput tariffs; and

f)	providing an incentive to the Service Provider to reduce costs and to develop the market for Reference and other Services: this is provided through the incentive mechanism described in Section 2.6 of this Access Arrangement Information.

2.3	Reference Tariff Determination

Reference Tariffs for the Access Arrangement Period will follow a price path approach with the Total Revenue calculated according to the cost of service methodology during this time.  

As detailed in Section 3, the derivation of the Reference Tariff involves:

a)	determination of the Total Revenue for the ABDP;
b)	allocation of the Total Revenue to the three ABDP pricing zones;
c)	calculation of a per gigajoule throughput tariff for each zone based on estimated throughput in that zone; and
d)	smoothing of the zonal throughput tariffs over the Access Arrangement Period based on a smoothing factor “X” (whilst maintaining the NPV of the Total Revenue during this period).
2.4	Tariff Structure

The Code requires that an Access Arrangement must include a Reference Tariff for:

•	at least one Service that is likely to be sought by a significant part of the market; and

•	each Service that is likely to be sought by a significant part of the market and for which the Regulator considers a Reference Tariff should be included.

The Reference Service in the Access Arrangement is a standard transportation Service where gas is received into the pipeline at any point, and delivered to any other point on the pipeline downstream of the receipt point. Having regard to its experience in operating the pipeline, NT Gas believes this Service is most likely to be sought by prospective users as it reflects the usage of the pipeline to date and the nature of the market served by the pipeline.

The Access Arrangement also offers a Rebatable Service – in which receipt and transportation will be curtailed where capacity is not available – in recognition that there may be a demand for such a Service.  As it is not possible at this time to quantify that demand, or the capacity which will be available from time to time for that Service, NT Gas has not offered it as a Reference Service.

2.4.1	Reference Tariff

The Reference Tariff structure for the ABDP during the initial Access Arrangement Period consists of a throughput tariff for each of the three pricing zones.  Consistent with usual industry practice, the throughput tariff has the following features:

•	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);
•	provision for overruns once the pipeline achieves Contracted Capacity of 85%; and
•	provision for a minimum annual bill (which requires payment for a minimum annual quantity of gas being delivered).

This tariff structure is designed:

•	to encourage efficient use of the ABDP by providing a financial incentive to Users to take active steps to implement an effective load management system; and
•	to the extent commercially and technically reasonable, ensure users of the Reference Service pay for that Service on the basis of the cost of providing the Reference Service (ie according to their reasonable use of the assets).

2.4.2	Zonal Tariffs

The existing contracts on the ABDP are on a “postage-stamp” basis - ie the one tariff applies for receipt and delivery of gas for any point along the pipeline.  Such a pricing structure is common when a pipeline project is underwritten by a single user and a significant portion of that user’s load is at the end of the pipeline.  Such is the case with the ABDP.

NT Gas recognises that maintaining such a pricing structure has the potential to impede growth in the utilisation of the ABDP.  This is particularly in the case of price sensitive projects which are located only part way along the pipeline, but which, under a postage stamp tariff, would be charged for delivery of gas as if that gas was transported though the entire length of the pipeline.
In an attempt to develop the market for pipeline Services and to replicate the outcomes of a competitive market, the Reference Tariff for the ABDP is structured on a three zone basis whereby receipt and delivery of gas to any point within a zone is charged at the throughput tariff applicable to that zone.  Should gas be transported across two or more zones then the throughput charge is the sum of the relevant throughput tariffs for each of those zones.  A detailed description of the zone boundaries is in Section 5.2.

2.4.3	Rebatable Service

The Rebatable Service has similar terms and conditions as the Reference Service, but it has the following differentiating features:

•	provision for interruptibility;
•	no load factor adjustment; and 
•	no provision for a minimum annual bill. 

By providing this Rebatable Service, NT Gas is encouraging use of the ABDP by those Prospective Users who may have gas consumption requirements that are able to utilise pipeline capacity which will not uniformly be available.

2.5	Cost allocation

As there is only one Reference Service offered, the Reference Tariff for the Reference Service is designed to recover the whole of the Total Revenue for the ABDP.  The allocation of Total Revenue into each of the three pricing zones is detailed in Sections 3.4 and 4.4.

The zonal pricing, and throughput tariff, is designed to ensure that to the maximum extent technically and commercially reasonable, the portion of Total Revenue to be recovered from sales of the Reference Tariff to a particular User reflects the costs of providing that Service.  The adoption of zonal tariffs is more cost-reflective of a user’s utilisation of pipeline Services than a single postage stamp tariff, while avoiding the complexities and expense of administering a strictly distance-based tariff.  A throughput tariff, adjusted for load factor, has been adopted as it overcomes the rigidity which can be associated with requirements that capacity must be booked and paid for.  It also maintains some consistency with existing transportation contracts on the ABDP.

2.6	Incentive Mechanism

The incentive structures in the Reference Tariff and the Access Arrangement are:

1)	The level of Reference Tariff is determined to encourage NT Gas to develop the volume of sales of Services and to minimise its costs of providing Services ; 

2)	The Reference Tariff will apply during each year of the Access Arrangement Period regardless of whether the estimates underpinning the Reference Tariffs (eg volume and cost estimates) are realised; and

3)	The Rebatable Service is designed to encourage NT Gas to increase pipeline utilisation and to minimise the costs of providing pipeline Services.  At the same time it recognises - through the treatment of the revenue from sales of the Service – existing contractual arrangements.

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

2.7	Other Revenue

The Reference Tariff has been designed to recover the Total Revenue for the ABDP.  No allowance has been made for other revenue that may accrue from any other charges relating to the provision of Reference Services (ie Variance, Overrun or Imbalance charges) as these are not considered material.

3	
Capital Costs
3.1	Initial Capital Base

The Code requires that an Initial Capital Base (ICB) be established for the initial Access Arrangement for a Covered Pipeline.  The Code also addresses the valuation of Covered Pipelines that were in existence at the commencement of the Code.  The ABDP is one such pipeline, and pursuant to the Code, factors to be considered in establishing the ICB for the ABDP are:

a)	the value that would result from taking the actual capital cost of the Covered Pipeline and subtracting the accumulated depreciation for those assets charged to Users (or thought to have been charged to Users) prior to the commencement of the Code (ie Depreciated Actual Cost – DAC);

b)	the value that would result for applying the DORC methodology;

c)	the value that would result from applying other well recognised asset valuation methodologies;

d)	the advantages of each valuation methodology applied above;

e)	international best practise of pipelines in comparable situations and the impact on the international competitiveness of energy consuming industries;

f)	the basis on which Tariffs have been (or appear to have been) set in the past, the economic depreciation of the Covered Pipeline, and the historical returns to the Service Provider from the Covered Pipeline;

g)	the reasonable expectations of persons under the regulatory regime that applied to the pipeline prior to the commencement of the Code;

h)	the impact on the economically efficient utilisation of gas resources;

i)	the comparability with the cost structure of new pipelines that may compete with the Covered Pipeline;

j)	the price paid for any asset recently purchased by the Service Provider and the circumstances of that purchase; and

k)	any other factors the Regulator considers relevant.

In respect of the determination of the ICB for the ABDP, the Code provides that the ICB should normally not be outside the range of values determined through the application of the asset valuation methodologies set out in items (a) and (b) above.
NT Gas has taken account of the requirements of the Code in respect of valuing the ABDP and has determined that the DORC valuation methodology is appropriate, which results in an ICB, as at 30 June 1999, of $265.54 million.

3.1.1	Depreciated Optimised Replacement Cost (“DORC”)

Consistent with recent regulatory decisions in Australia, NT Gas has used the DORC methodology to value the ABDP.  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;

•	redundant or oversized assets are not included in the asset base and therefore are not paid for by User;

•	it provides a consistent valuation between new and existing assets, regardless of the operating and accounting policies applying up to the time of valuation; and

•	it sends correct price signals as to the cost of providing the Service.

A valuation of the ABDP assets (as at 30 June 1999) by application of the DORC methodology has been undertaken.  This valuation has been audited for  accuracy by consulting engineers Venton & Associates Pty Ltd.

Key assumptions adopted in determining the DORC valuation include:

•	Estimates of likely pipeline throughputs were prepared for the 30 year period out to 2029.  Three different scenarios were considered – a base, base reduced and a high case.  The base reduced case considered the possibility of the pipeline throughputs peaking in 2015 and then reducing by approximately 50% by 2030.  This base reduced case reflects NT Gas’ uncertainty as to future throughput which is discussed in Section 3.1.4;

•	The optimised replacement cost of the pipeline and associated ancillary equipment have assumed “brown-field” conditions. This is appropriate as it best replicates the cost of replacing the assets in their present geographical locations;

•	Materials used in the optimisation process assumes the application of current industry practice (eg steel grades and maximum allowable operating pressures);

•	Pipe sizes had been optimised to reflect the application of current industry design and construction practise.  The main impact of this optimisation has been the adoption of smaller diameter pipe in conjunction with higher pipeline operating pressures;

•	The optimum pipeline configuration is selected on the basis of the lowest NPV of estimated capital and operating costs over the analysis period;

•	Economic lives of the components of the ABDP are as detailed in Section 3.1.6;

•	Depreciation is applied to the ORC on a “straight line” basis over the economic life of the assets comprising the ABDP to determine the DORC; and

•	The philosophy of “minimum remaining life” will also be applied, where appropriate, which assumes the asset always has a minimum value until it is replaced or abandoned (effectively the asset is depreciated down to its assigned “minimum remaining life”, and henceforth the asset retains this value until it is replaced or abandoned at which time its value is written off to zero).  For all long lived pipeline assets (ie all asset categories except SCADA and communications equipment) the minimum remaining life is set at 5 years.  All other assets will be depreciated to zero over their economic lives.

The results of the DORC valuation are summarised in the table following.  The ORC valuation listed in the table is the optimum pipeline configuration required to transport the quantities in the base and high case scenarios.  Regarding the base reduced scenario, two additional optimised configurations were considered which resulted in a total replacement cost of $313.12m and $326.77m respectively.

In determining the appropriate ORC valuation to be used to calculate the DORC, three different throughput scenarios have been considered which yielded three optimised pipeline configurations together with the option of replacing the existing pipeline.  The ORC valuations fall in the range $313.12m to $335.77m, with the replacement cost of the current configuration being $318.96m.

In light of the uncertainty over both ORC valuations (in that it is a theoretical exercise) and throughput estimates over a 30 year period, NT Gas considers the replacement of the existing pipeline configuration as being the appropriate basis on which to determine the DORC valuation for the ABDP.

DORC Valuation ($m)

Asset Type
As at 30 June 1999	
RC
	
ORC
	
Adjusted ORC	
Accum. Dep.	
DORC

Transmission Pipeline
	
300.31
	
308.12
	
300.31
	
48.81
	
251.51	
Compressor Stations:
Rotating Equipment
Station Facilities
	
2.00
5.00	
6.00
10.00	
2.00
5.00	
0.23
0.41
	
1.77
4.59	
Regulation and Metering Stations
	9.78	9.78	9.78	2.48	7.30	
Odourisation Stations
	0.25	0.25	0.25	0.09	0.16	
SCADA and Communications
	1.62	1.62	1.62	1.40	0.22	
Total Asset Value	318.96	335.77	318.96	53.42	265.54	

3.1.2	Other Factors to be Considered in Establishing the ICB required by the			Code

DAC Valuation

The Code requires consideration be given to the value that would result from taking the actual capital cost of the pipeline and subtracting the accumulated depreciation for those assets charged to User (or thought to have been charged to Users) prior to the commencement of the Code (ie “DAC” valuation).

However, the Code does not provide clear guidance on how a DAC valuation might be determined for the ABDP, particularly given it is a leased asset and therefore NT Gas has to date not been obliged to calculate accumulated depreciation for statutory account purposes.  NT Gas has therefore derived an estimated DAC valuation of the ABDP by assuming the asset was owned and operated by the same entity to date, and then depreciating it according to reasonable accounting standards.

The methodology used and assumptions taken to estimate the DAC of the ABDP are as follows:

•	The actual capital cost of assets represents $324.9 million at 1 July 1986. This represents the actual capital cost of constructing the pipeline;

•	Actual capital expenditure incurred since commissioning of the pipeline has been added to the actual capital cost of constructing the pipeline to arrive at the total capital cost of the assets; and

•	Accumulated depreciation of the assets (charged on the basis of what NT Gas considers would be reasonable) has been subtracted from the total capital cost of the pipeline.

The Application of this methodology results in an estimate of the DAC of the ABDP, as at 30 June 1999, of $234.7 million and is summarised in the table below.

Depreciated Actual Cost

Asset	$m	
Actual Capital Cost	324.9	
Capital Additions	8.7	
Asset Disposals	(0.4)	
Accumulated Depreciation	(98.5)	
Depreciated Actual Cost	234.7	

Other Well Recognised Asset Valuation Methodologies

The Optimised Deprival Value (ODV) is a well recognised asset valuation methodology which establishes a valuation as the lessor of the NPV of the income stream that can be generated by the ABDP and DORC.  Taking the current income stream generated by the ABDP under its existing contracts over a 30 year period and a residual value calculated under the “perpetual method” together with a pre-tax real discount rate of 11% yields an NPV valuation for the pipeline of $308.9m.  Therefore the ODV valuation for the ABDP will be DORC.

For the purposes of this Access Arrangement Information, NT Gas has determined valuations of the ABDP using four separate methodologies – DORC, DAC, ODV and the valuation resulting from the application of economic depreciation.  NT Gas submits that consideration of these methodologies satisfies the Code in respect of well recognised asset valuation methodologies in establishing the ICB for the ABDP.

The Advantages and Disadvantages of Each Valuation Methodology

The advantages and disadvantages of the four valuation methodologies adopted by NT Gas have been the subject of much Regulator, industry and public scrutiny and debate in recent times as regulatory determinations have been finalised.  NT Gas has nothing of substance to add to the recent debate, apart from its belief that the DORC methodology is appropriate for establishing the ICB of the ABDP and satisfies the requirements of the Code.

International Best Practice

It has been suggested that one objective for determining the initial capital base is that it produces tariffs that are consistent with best practice transportation tariffs – presumably such tariffs are for comparable pipelines.  However when considering such comparisons of international best practise of pipelines, it is difficult to make meaningful comparisons given the vagaries associated with pipeline operation and their costs (eg differences in terrain, type of gas consumer, size of pipeline and the distance of transportation are all significant drivers of pipeline operating costs).  As the Commission has noted, strict benchmark comparisons are difficult to obtain.

There are also considerable differences in regulatory practice between countries – to say nothing of assessing regulatory best practice in those countries.  NT Gas notes that valuation methodologies adopted by regulators in the UK tend to be based on float or DORC valuations, while those in North America tend to apply historic costs and nominal returns.  Recent regulatory decisions in Australia suggest that DORC tends to be the valuation methodology accepted by regulators.

In any case, NT Gas is of the opinion that the optimisation and the efficient costs assigned to the ABDP as part of the DORC valuation procedure has covered this criteria in satisfaction of the Code requirements.

Economic Depreciation and Historical Returns

NT Gas has undertaken an analysis of the historical revenues and returns of the ABDP to determine whether there has been an under or over recovery of revenues.  This analysis requires an estimation of the economic depreciation that has occurred on the ABDP since it was commissioned.  Again the Code doesn’t provide clear guidance on how economic depreciation is to be determined for an asset such as the ABDP.

The formula that NT Gas has applied in estimating the economic depreciation for each year of operation is:

economic depreciation = [revenue] - [operating costs] - [return on assets]

If the resulting economic depreciation is positive it is subtracted from the capital base (ie revenue generated is sufficient to provide some return of capital), if it is negative it is added to the capital base (ie revenue generated is not sufficient to return any capital – effectively an under-recovery of capital) to be recovered in later years.

The methodology adopted by NT Gas to determine an appropriate return on assets to be used in the equation for economic depreciation above is:

•	The actual capital cost of assets represents $324.9 million at 1 July 1986. This represents the actual capital cost of constructing the pipeline;

•	Actual capital expenditure incurred since commissioning of the pipeline has been added to the actual capital cost of constructing the pipeline to arrive at the total capital cost of the assets;

•	A notional return on assets is derived by applying a return equivalent to the long-term bond rate in each year plus an additional risk premium (in total equating to an estimation of historical WACC) to the total capital base in that year.

This analysis of economic depreciation yields a value of the ABDP at 30 June 1999 in excess of the DORC valuation of $265.54m.  The analysis also indicates that there has been an under-recovery of revenue in every year since the ABDP was commissioned in 1986 and so, therefore, the DORC valuation methodology is appropriate on which to establish the ICB.

Reasonable Expectations of Persons under the Prior Regulatory Regime

Prior to the introduction of the Code access to and prices for pipeline transportation was a matter of commercial negotiations. Whilst it is impossible to identify precisely the expectations of various parties associated with the ABDP under that regime, an important element of that regime is that the construction of the ABDP was underwritten exclusively by a long term “foundation” transportation contract with PAWA.

The history of the development of the ABDP is such that, without PAWA’s willingness to enter into such a contract, the pipeline would not have been built. It is common in the pipeline industry that foundation users enjoy price benefits relative to later users reflecting the benefit to all users of the foundation user’s early commitment. Given PAWA’s position as foundation customer, it is reasonable to assume that parties would have had an expectation that tariffs for third party usage would be established on the basis of:

•	recognising the role PAWA has played in developing the ABDP as the backbone of gas infrastructure in the Northern Territory; and

•	ensuring that PAWA enjoyed the usual benefits of being the foundation customer particularly in respect of the haulage tariffs (including terms and conditions) under the foundation transportation agreement.

Equally, NT Gas had a reasonable expectation that it would receive a commercial return on the pipeline, that it would not suffer a reduction in the revenue it is entitled to receive under the foundation transportation agreement, and that it would continue to be able to perform its obligations under existing contracts and including its obligations as trustee of the Amadeus Gas Trust.  

Impact on Economically Efficient Utilisation of Gas Resources

Gas resources will be used efficiently if prices reflect the cost of providing services. The application of the DORC methodology to determine the capital base is a proxy for the outcomes delivered by a competitive market and also the actual costs likely to be incurred in the future in renewing or replacing the ABDP.  As the Commission has noted “to the extent that the DORC valuation achieves overall price levels reflective of long run costs, the potential for efficient allocation of gas resources will be enhanced”.  In light of this, NT Gas considers the DORC valuation methodology appropriate.

Comparability with the Cost Structure of Competing New Pipelines

NT Gas considers the DORC valuation methodology is consistent with the stand alone cost of a competing new pipeline that may by-pass the ABDP.  The application of the DORC methodology also reduces the risk of leaving the ABDP open to uneconomic by-pass.  In these circumstances NT Gas considers the DORC methodology as being most compatible with the cost structure that would be incurred for a new pipeline.

Price Paid for Recently Purchased Assets

NT Gas has not recently purchased any pipeline assets.

3.1.3	Valuation of Non-System Assets

Non-system assets (ie land and buildings, vehicles, mobile plant and equipment etc) are not included in the above DORC valuation.  Non-system assets have been valued at book value and are set out in the table below.

Total Capital Base ($m)

Asset & Valuation Methodology
(as at 30 June 1999)	ABDP	
System Assets (DORC)	265.54	
Non-System Assets (book value)	1.81	
Working Capital	(0.28)	
Total Capital Base	267.08	

3.1.4	Depreciation

For the transmission pipeline assets, NT Gas has applied a depreciation methodology referred to as “kinked straight-line” depreciation (discussed below).  For the remaining assets (ie compressor stations, regulation, metering and odourisation stations, SCADA and communications and non-system assets) straight-line depreciation has been applied.  In both cases depreciation has been applied over the economic lives of the relevant assets.

The straight-line depreciation approach is consistent with recent other access arrangements submitted to, and accepted by, Regulators. The benefits of the straight-line depreciation approach include that it is accepted by industry, its application is easily understood, and it is transparent.

The application of straight-line depreciation is also in accordance with the Code in that:

•	the assets comprising the ABDP are depreciated over the economic life of each of those assets; and

•	depreciation will occur consistent with the likely utilisation of the assets over their economic life.

In accordance with the Code, at the commencement of each Access Arrangement Period, NT Gas will review and where necessary adjust the depreciation schedules to reflect changes in the expected asset economic lives.

NT Gas has applied the kinked straight-line depreciation methodology to reflect its concern about the sustainability of current levels of throughput over the economic life of the pipeline (ie out to 2066).  NT Gas is not aware of any public, detailed information on which it can rely to develop meaningful forecasts for pipeline usage over the remaining economic life of the ABDP. The foundation gas transportation agreement expires in 2011 and, combined with the lack of information regarding future production expectations of the existing Amadeus Basin fields, NT Gas can have no certainty as to the usage of the ABDP after 2011.

In addition to this is the uncertainty created by the possibility of the Timor Sea becoming the predominant source of gas in the Northern Territory at some future time.  Until recently, such a scenario has been considered, at best, a remote possibility.  However given the combination of the growth prospects of the Australian domestic gas market together with the depressed demand for LNG in Asia, it is becoming more likely that any near term development of the Timor Sea gas fields will be focussed on delivering gas to the Australian domestic market.

The obvious implication for the ABDP is that there may well be an alternative source of gas made available for consumers at Darwin thereby by-passing the pipeline.  Regarding the delivery on any Timor Sea gas to other parts of Australia (Queensland has been mooted), if there are large volumes to be transported the ADBP faces the risk of by-pass given its relatively small capacity.

To recognise these concerns and the impact on NT Gas of a significant reduction in pipeline utilisation after 2011, NT Gas will depreciate the transmission pipeline assets from the current DORC valuation of $251.51m (as at 1 July 1999) on a straight-line basis to $61.84m in 1 July 2011.  From 1 July 2011 onwards these assets will be depreciated on a straight-line basis over the remainder of the economic life to an ultimate value of zero.

The timing of the “kink” in the depreciation schedule has been set in 2011 to reflect the uncertainty about the timing and magnitude of significant reductions in pipeline throughput.  Rather than setting a somewhat arbitrary date based on guesses of when reserves may expire, NT Gas believes that it is appropriate that the depreciation schedule should mirror the existing contractual and financial arrangements for the pipeline.

This section has been intentionally left blank – confidential information.

This section has been intentionally left blank – confidential information.

In respect of the calculation of depreciation for Total Revenue purposes, NT Gas has adopted the Current Cost Accounting (CCA) approach.  Under the CCA approach assets are revalued each year in line with inflation and depreciation is calculated on the revalued capital base.  The formula approved by the Commission to determine the CCA depreciation and return on assets and adopted in this Access Arrangement Information is:

a)	depreciation = accounting charge * (1+CPI)n;
b)	return on assets = written down value (WDV) of assets * real WACC; and
c)	WDV of assets (current) = WDV of assets brought forward * (1+CPI)n + 50% of current year capex * (1+CPI).

3.1.5	Working Capital

The anticipated working capital required to fund the day to day operation of the ABDP is $0.28m (negative) as at 30 June 1999, which has been allowed for in the calculation of the ICB detailed in the table in Section 3.1.3.  Working capital requirements has been quantified as accounts payable less accounts receivable plus taxation payable.
3.1.6	Economic Life and Remaining Economic Lives

Based on NT Gas’s experience in operating a high pressure transmission pipeline, various recent access arrangements proposed by service providers and submissions of industry participants and decisions of Regulators, economic lives for the various system assets making up the ABDP have been established.  These are set out in the table below together with the average remaining economic life of each of the asset classes noted.  Minimum remaining lives of all of the assets classes in the table have been set at 5 years, apart from SCADA which has no minimum remaining life.

ABDP System Assets
Economic Lives (from installation and remaining years)

Asset	Economic Life (years)	Average Remaining Economic life (1 July 1999)
(years)	
Transmission Pipeline (coated and CP protected):
Constructed 1986	

80	

67	
Compressor Stations:
Rotating Equipment
Station Facilities	

25
35	

22
32	
Regulation and Metering Stations	
50	
37	

Odorising Stations	
35	
22	

SCADA	
15	
2	

3.1.7	Estimated and Committed Capital Expenditure

The Code provides that Reference Tariffs may be determined on the basis of New Facilities Investment that is forecast to occur within the Access Arrangement period provided that such investment is reasonably expected to pass the prudency tests set out in the Code which are that New Facilities Investment must:

•	not exceed the amount that would be invested by a prudent Service Provider acting efficiently, in accordance with accepted industry practice, and achieve the lowest sustainable cost of delivering Services; and

•	meet one of the following conditions:

•	the Anticipated Incremental Revenue generated by the New Facility exceeds the New Facilities Investment; or
•	the New Facility has system-wide benefits that justify a higher Reference tariff; or
•	the New Facility is necessary to maintain the safety, integrity or Contracted Capacity of Services.

The amount of New Facilities Investment that is expected to occur within the Access Arrangement Period is based on the amount of capital expenditure required by NT Gas to provide Services to Users during this period.  New Facilities Investment for the ABDP system comprises three components:
•	capacity expansion – capital required to expand the capacity of the ABDP to meet demands both within the Access Arrangement Period and beyond;
•	system replacement – capital required to maintain the integrity of the ABDP which would include items such as replacement of instrumentation (eg metering, telemetry remote terminal units etc), pipeline hardware (eg pipes, meters valves, regulators and fittings etc), site capital improvements (eg fencing, security etc), and specialised major spares; and
•	non-pipeline system expenditure – capital required for replacement of items such as vehicles and computer equipment.

The amounts estimated for New Facilities Investment are set out in the table below.

Estimated Capital Expenditure ($’m)

Year Ending 30 June	2000	2001	2002	2003	2004	
Expansion Capital	0	0	0	0	2.26	
Replacement Capital	0.67	0.22	0.32	0.25	0	
Non-System Capital	0.74	0.67	0.70	0.55	0.56	
Total Capital Expenditure	1.41	0.89	1.02	0.80	2.82	

The expansion capital required in 2004 is to provide for the upgrade in capacity of the Mereenie supply line.  The higher system replacement capital in 2000 is largely due to replacement of SCADA components.

It is not NT Gas’s usual practice to commit to capital expenditure for significant periods in advance of that expenditure.  Rather a capital budget is prepared annually which is subject to both management and board approval.

All of the New Facilities Investment represent best estimates arrived at on a reasonable basis and is required to maintain either the safety and integrity of the ABDP or its Services in satisfaction of the Code requirements.

3.2	Rate of Return
3.2.1	WACC Approach

NT Gas has adopted a weighted average cost of capital (WACC) approach as a guide to determining the appropriate rate of return for the ABDP. 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 Commission’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.  NT Gas has assumed that the Victorian approach will be a relevant factor in determining the WACC for the ABDP.

3.2.2	Application of WACC to ABDP

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).  

Various assumptions contained in the Commission’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 risk free rate has changed since this decision; and

•	the extent to which various physical, commercial and other risks involved in delivery of the Reference Services for the ABDP differ from those involved in the Victorian infrastructure.

The first point above is largely an issue of direct observation and is reflected in the “Range of Variables” table in this section.

The second point above is not as easy to address and is discussed below.

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 illustrated by this incident were fully incorporated into regulator’s decisions on risk.

Secondly, the risks involved in the ABDP are considerably greater than the risks involved in the Victorian transmission system due to the following factors:

•	The higher possibility of field failure. Amadeus Basin fields are much smaller than the Bass Strait fields, and as there is little associated oil the Amadeus Basin fields are unlikely to have the on site and off site support and analysis available to the Bass Strait fields.

The ability of the Amadeus Basin fields to meet all future market requirements is also uncertain.
•	The location and commercial environment.  This environment is more risky than that faced by persons operating in Victoria and therefore supports a higher return than that applicable for similar gas pipeline businesses in Victoria. 

The ABDP is largely located in remote and relatively inaccessible regions. This remoteness adds to the possibility of pipeline failure as remote, minor problems are not always easily detected before they escalate in size and even when detected there is a time and travel factor involved in addressing the problem before it escalates.

End use markets are largely dependent on the strength of the Northern Territory economy, which in turn is largely dependent on the resources sector, the armed forces and the general condition of the South East Asian economy. This makes gas consuming businesses more risky than those in Victoria.

NT Gas does not hold easements for the pipeline, but relies on a right of way granted by the NT Government. This is unlike normal pipelines constructed in easements held in perpetuity by the pipeline owner.

•	The inability of insurance to adequately cover all natural and force majeure style risks. The ABDP is insured for a variety of natural risks. Given the length of the pipeline and the region in which it is located the pipeline is subject to more natural risks than many other pipelines. For example the pipeline is subject to risks of flooding and wash-outs every wet season and is subject to greater earthquake risk than most other, if not all other, Australian pipelines. These are illustrated by the fact that since its commissioning the pipeline has been subject to:

•	an earthquake near Tennant Creek in 1988 which resulted in substantial damage to the pipeline;

•	lightning strikes; and

•	various instances of flooding, including the Katherine Floods of January 1998.

As well as directly effecting the ABDP these disasters also affect the gas usage levels of the ABDP’s customers.

Obtaining full insurance for these risks is problematic and it is usually not possible to recover all of these “natural risk” style expenses through insurance. Given the high level of natural risks to which the ABDP is exposed either additional self insurance or higher risk variables should be factored in to WACC calculations. 

•	Explicit regulation has never applied to the ABDP. Unlike many other gas pipelines and networks in Australia the ABDP has never previously been subject to explicit economic regulation. While acknowledging that the ACCC regulatory process will be transparent, the exact process and form of regulation and the reaction of industry participants and customers to this regulation is unknown, creating uncertainty, at least in the short term.

•	The much lower level of maturity of the ABDP’s markets. The Northern Territory gas market is slowly developing – there is no significant history of natural gas usage in the Northern Territory. Given the Northern Territory’s climate the range of applications suitable for gas is limited – it is largely restricted to electricity generation, industrial and commercial use and, potentially, gas-fired cooling systems.

It should be noted that various laterals attached to the pipeline, which serve industrial customers (eg Northern Cement, the industrial area at Berrimah) are operating at below the usage levels forecast when they were constructed.

•	The much higher levels of concentration of usage among ABDP’s consumers. The largest single User of the ABDP is PAWA who has in excess of 99% of pipeline throughput delivered to power stations along the pipeline.  The largest of these power stations is PAWA’s Channel Island power station which accounts for approximately 65% of pipeline throughput while  the three largest power stations accounts for approximately 90% of pipeline throughput.

This concentration of demand makes the pipeline particularly vulnerable to any shift in fuel usage or shift in gas source. For example if a new power station selling power at a cheaper price than Channel Island used another energy source (eg coal, fuel oil) or gas from another source (eg the Timor Sea) then the ABDP would be uneconomic as its load would be reduced by at least 65% (assuming Channel Island no longer operated). At these usage levels the ABDP is uneconomic.

Recent media reports suggest that a gas supply to the Northern Territory (ie gas made available at Darwin) from the Timor Sea is becoming increasingly likely.

Alternatively the Channel Island Power Station itself could use another energy source or gas from another source. The possibility of this occurring in the short term is limited by current transportation agreements. However, the sale of the Channel Island power station, industry restructuring etc may lessen the effectiveness and application of these agreements.

Given recent world oil price movements fuel oil and diesel may become competitive alternatives to natural gas for power stations served by the ABDP.

•	The risky nature of many of the ABDP’s smaller consumers.  Some of the ABDP’s smaller consumers are mining sites, which are usually served by dedicated lateral pipelines which are uneconomic if the mine site itself becomes uneconomic and ceases to operate. Given that mine sites are exposed to world commodity markets the possibility of such an occurrence is significant. This risk can be partly reduced by take or pay style contracts but these contracts are ineffective if the contracting party becomes insolvent.  Accordingly, these laterals are at least as risky as the mining industry they serve.

An example of the above situation can be seen at the Mt Todd gold mine. This mine was expected to have an annual consumption of gas of around 3.2PJ for 10 years and on this basis a lateral costing $3.2 million was constructed to the mine site. The expected Mt Todd gas usage was also a significant consideration in a decision to install a compressor costing $6.6 million on the ABDP.  Two years after the construction of the lateral, following a fall in the world gold prices, the Mt Todd mine ceased operations. This example illustrates the risk involved in serving the mining industry and why higher rates of return are needed to compensate for this greater risk.

•	The high city gate price for gas in the Northern Territory.  Relatively high delivered gas prices to consumers restrict market growth and the competitiveness of natural gas with other fuels. This in turn contributes to the relative immaturity of the Northern Territory gas market and greater exposure to competing energy options.

To account for these above factors a higher cost of equity is considered necessary.

3.2.3	Range of Variables

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.

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.

Range of Variables

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	5.9%	5.5%	
	2010 CPI Linked Bond Rate	3.7%	3.4%	
	Debt Margin	1.4%	1.0%	
	Bank Costs	0.5%	0.5%	
Nominal Cost of Debt	Based on 10 Year Bond  Rate	7.3%	6.5%	
	Based on CPI Linked Bonds	7.6%	6.9%	
Cost of Equity	Market Risk Premium	7	6	
	Asset Beta	0.9	0.55	
	Equity Beta	1.65	1.25	
	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	19.0%	12.9%	
	Based on CPI Linked Bonds	19.3%	13.3%	
WACC Results	Nominal Post Tax WACC	10.9%	6.5%	
	Nominal Pre Tax WACC	17.0%	10.2%	
	Real Pre Tax WACC	14.1%	7.5%	

The formulae used to determine the WACC are:

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

Post Tax Nominal ={Re  * [(1–T)/(1–T(1–y))]*(E/V)}+(Rf +Dm) (1–T) * (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 ABDP. 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 NT Gas 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. NT Gas 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 nominal risk free rates were used:

•	the nominal ten year bond rate; and

•	a CPI indexed bond 2010 series with an inflation component added.

With regard to this latter indicator CPI indexed bonds plus an inflation component may be a proxy for risk free rates. Recent regulatory decisions have used expected inflation rates of 2.5%, these rates have not matched the inflation rates implicit in the difference between CPI indexed bond rates and nominal bond rates.

The debt margin used by NT Gas in calculating the WACC is in the range 1.4% to 1%.  In a recent regulatory decision the ACCC adopted a 1.2% debt margin.  

The approach above produces a cost of debt in the range of 7.6% to 6.5%,

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 NT Gas 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. NT Gas 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 * 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 NT Gas CAPM approach is:

Cost of Equity = Risk Free Rate + Beta Risk Measure * 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.  NT Gas has contrasted the results derived by the following formulae:

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

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

CSFB: Be =  Ba + [Ba - Bd] (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 17.8% to 12.9%, which then needs to be adjusted for asymmetric risk and self insured costs.

Asymmetric risk has been independently estimated at 1.3%, with NT Gas considering a range of 0 to 1.0% appropriate.  Assessment of self insured costs is difficult to quantify, however NT Gas 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 ABDP based on a CAPM approach modified for asymmetric risk and self insured risk lies within the range of 19.3% to 12.9%.

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. NT gas believe that to adjust for tax first and then inflation is correct as in reality tax is applied to nominal figures, not real figures.

Final WACC
NT Gas 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	17.3 %	14.3 %	
Cost of Debt	7.4 %	6.7 %	
Real Pre Tax WACC	11.7 %	8.5 %	

A real pre-tax WACC from the upper end of the range was chosen. A WACC from the low end of the range could be a disincentive for investment, particularly given the immature state of infrastructure development in the Northern Territory. The WACC considered appropriate by NT Gas is 11% pre-tax real.

3.3	Total Revenue

The Code provides that one of three calculation methodologies can be used to determine the Total Revenue.  NT Gas has adopted the “cost of service” approach whereby Total Revenue is equal to the cost of providing all Services (some of which may be the forecast of such costs), and with this cost to be calculated on the basis of:

•	a Rate of Return on the value of the Capital Base; plus

•	depreciation of the Capital Base; plus

•	the operating, maintenance and other non-capital costs incurred in providing all Services provided by the pipeline.

The Total Revenue to be recovered from the sales of all Reference and Negotiated Services during the Access Arrangement Period is based on the following assumptions:
•	a real pre-tax return of 11% (refer to Section 3.2);

•	an initial Capital Base (applying the DORC methodology) of $265.54m (refer to Section 3.1), which is adjusted each year to:

•	include estimated New Facilities Investment (refer to Section 3.1.8);

•	reflect depreciation calculated on either a straight-line or kinked straight-line basis depending on the particular pipeline asset (refer to Section 3.1.4);

•	take account of inflation (ie indexing the Capital Base using the CCA approach outlined in Section 3.1.4); and

•	forecast Non-Capital Costs (Sections 4.1 and 4.2).

As discussed in Section 1.2, the capacity of the ABDP is fully committed to Users under pre-existing transportation contracts, therefore NT Gas does not anticipate that any revenue will be generated by the sale of the Reference Service or Negotiated Service within this Access Arrangement Period.  In addition, the revenue being earned by NT Gas under the existing transportation contracts is less than the Total Revenue NT Gas is likely to be entitled to recover under the Code.

NT Gas is of the opinion that there is substantial uncertainty regarding the expected future revenue from sales of the Rebatable Service due to the nature of, and market for, that Service.  Consequently NT Gas has made no provision for a portion of the Total Revenue to be recovered from the sale of the Rebatable Service.

The table below sets out the estimated Total Revenue for each year of the Access Arrangement Period.

Total Revenue ($m)

Year Ending 30 June	2000	2001	2002	2003	2004	
Regulatory Asset Base	273.0	261.8	252.2	243.7	235.7	
EBIT
Depreciation
Total Operating Costs	30.0
17.2
6.7	28.8
17.8
6.9	27.7
18.3
7.2	26.8
18.8
7.3	25.9
19.4
7.5	
Total Revenue	54.0	53.4	53.3	52.9	52.8	
Throughput (PJ)	15.7	16.0	16.4	16.4	16.8	

3.4	Allocation Of Total Revenue

The Total Revenue determined in Section 3.3 is allocated into each of the pricing zones as detailed in the following table.

Total Revenue ($m) – Zonal Basis

Year Ending 30 June	2000	2001	2002	2003	2004	
Zone 1:
EBIT
Depreciation
Total Operating Costs	
13.2
7.6
3.0	
12.6
7.8
3.1	
12.2
8.0
3.2	
11.7
8.2
3.3	
11.4
8.5
3.3	
Total Revenue - Zone 1	23.7	23.5	23.4	23.2	23.2	
Throughput (PJ) – Zone 1	15.7	16.0	16.4	16.4	16.8	
Zone 2:
EBIT
Depreciation
Total Operating Costs	
9.3
5.4
2.0	
9.0
5.5
2.0	
8.6
5.7
2.1	
8.3
5.8
2.2	
8.1
6.0
2.2	
Total Revenue – Zone 2	16.7	16.5	16.5	16.3	16.3	
Throughput (PJ) – Zone 2	15.3	15.6	16.0	16.0	16.4	
Zone 3:
EBIT
Depreciation
Total Operating Costs	
7.5
4.3
1.7	
7.2
4.4
1.8	
6.9
4.6
1.9	
6.7
4.7
1.9	
6.5
4.8
1.9	
Total Revenue – Zone 3	13.6	13.4	13.4	13.3	13.3	
Throughput (PJ) – Zone 3	13.3	13.6	14.0	14.0	14.4	

For each year of the Access Arrangement Period the allocation of:

•	total operating costs to each pricing zone is generally on the basis of length of pipeline operated in each zone (discussed in Section 4.4); and

•	return on capital (ie EBIT) and return of capital (ie depreciation) to each pricing zone is on the basis of the proportion that the ORC of the pipeline assets in each pricing zone bears to the total ABDP ORC as at 30 June 1999.

3.5	Reference Tariff for Pricing Zones

Having allocated the Total Revenue to each pricing zone, the Reference Tariff for each zone for each year can be determined on a per gigajoule basis by dividing the estimated throughput into the required revenue for that year.  However such an approach, whilst yielding the precise Reference Tariff applicable for that year, will result in Reference Tariffs that are somewhat variable over the Access Arrangement Period given the fluctuating throughput quantities.

In order to smooth the Reference Tariff over the Access Arrangement Period, a smoothing parameter “X” has been applied to the Reference Tariffs calculated in 2000 which will provide a smooth price path for Users over the Access Arrangement Period, in addition to avoiding price shocks at the commencement of the next Access Arrangement Period.

Whilst the Reference Tariffs calculated using the smoothing factor are slightly different than those calculated without the smoothing factor, the NPV of the Total Revenue has been preserved over the Access Arrangement Period.

The table following sets out the Reference Tariffs applicable to each pricing zone calculated in accordance with a smoothing factor of X = - 2.44% being applied.

Reference Tariff ($/GJ)

Year Ending 30 June	2000	2001	2002	2003	2004	
Zone 1	1.49	1.46	1.42	1.39	1.35	
Zone 2	1.11	1.08	1.06	1.03	1.01	
Zone 3	1.03	1.00	0.98	0.95	0.93	

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

Estimates of non-capital costs have been developed by NT Gas for the Access Arrangement Period.  Pursuant to the Code the forecasts of non-capital costs detailed in this section represent best estimates arrived at on a reasonable basis.  In particular, the forecast non-capital costs would be those incurred by a prudent Service Provider, acting efficiently, in accordance with accepted and good industry practise. The estimates of non-capital costs have been established taking into account costs expected to be incurred during the Access Arrangement Period together with the historical cost of operating the ABDP.

The efficiency of the estimated non-capital costs incurred in operating the ABDP is demonstrated in Section 6.  In respect of both capital and non-capital expenditure on the ABDP, it is to be noted that NT Gas has always had this proposed expenditure scrutinised within the prudential constraints imposed by its Board of Directors.  In light of this continued commercial discipline, NT Gas believes that there are no readily achievable efficiency gains to be made which would significantly reduce the expenditures forecast.  This is in contrast to the productivity savings that could be expected from a Government enterprise that is about to be, or has been recently, privatised.

4.1	Operations and Maintenance Costs

Operation and maintenance costs are the direct costs of operating and maintaining the ABDP and are detailed in table below in the categories specified in the Code.  An additional category has been included which identifies the infrequent but recurring costs of intelligent pigging activities on the pipeline.  

Operational activities undertaken include the continuous monitoring, operation and control of the:
•	pipeline,
•	pipeline right of way,
•	pipeline facilities; and
•	compressor station.

Maintenance activities undertaken include the maintenance of the :
•	pipeline,
•	pipeline facilities,
•	right-of-way maintenance,
•	Pipeline SCADA and communications system; and
•	regulation, metering and gas measurement equipment.

Other activities related to the operation and maintenance activities include pipeline integrity management, pipeline facility upgrading and training for emergency response.

There has been no allowance made for system use gas in the operations and maintenance costs, since system use gas will be provided by the user.  There has been no allowance made in the operating and maintenance costs for contingency.

Operating and Maintenance Costs ABDP

Year Ending June 30 ($’000)	1999	2000	2001	2002	2003	2004	
Wages and salaries	2358	2452	2550	2652	2758	2868	
Cost of outside services	1151	1221	1209	1240	1270	1302	
Intelligent pigging	320	0	0	108	0	0	
Materials and supply	1123	1151	1179	1207	1237	1267	
Property taxes and levies	517	530	543	557	571	585	
Total O & M Cost	5469	5354	5481	5764	5836	6022	

4.2	Overheads and Marketing Costs

Overhead costs (ie Administration and General) include expenditure relating to:
•	insurances,
•	directors fees,
•	regulatory activities,
•	compliance,
•	personnel and training,
•	legal,
•	accounting,
•	taxation; and
•	Government levies.

Sales and Marketing costs include expenditure relating to:
•	advertising and promotion of gas transportation services,
•	investigation and feasibility studies for potential gas consuming projects,
•	commercial negotiations relating to gas transportation services, and
•	general contract management and administration activities.

Total Operating Cost ABDP

Year Ending June 30 ($’000)	1999	2000	2001	2002	2003	2004	
Operations and Maintenance	5469	5354	5481	5764	5836	6022	
Administration and General	1126	1226	1258	1289	1321	1354	
Sales and Marketing	128	131	134	138	141	145	
Total Operating Cost	6723	6711	6873	7191	7298	7521	

4.3	Fixed versus Variable costs

For the throughputs estimated for the ABDP during the Access Arrangement Period, operating and maintenance costs will not vary significantly with throughput during this period.
4.4	Cost Allocation

All of the operating and maintenance costs are direct costs to NT Gas and will be fully allocated to the Reference Service specified in the ABDP Access Arrangement on the basis of length of pipeline operated in each of the three ABDP pricing zones.  Length of pipeline is the fundamental driver of operating and maintaining a pipeline.

Administration and general costs are allocated to each of the ABDP pricing zones on the same basis as operating and maintenance costs, since these costs are driven primarily by operating and maintenance costs.

Sales and marketing costs are allocated on the basis of the quantity of gas delivered out of the pipeline from delivery points within each of the ABDP pricing zones.  Such an allocation process assumes that sales and marketing costs within each of the ADBP’s pricing zones are strongly influenced by quantity of gas delivered within those zones.

The allocation of non-capital costs into each pricing zone is detailed in the following table.

Total Operating Cost ABDP (Zonal Basis)

Year Ending June 30 ($’000)	1999	2000	2001	2002	2003	2004	
Zone 1	3002	2992	3064	3207	3254	3354	
Zone 2	1991	1989	2037	2131	2162	2228	
Zone 3	1729	1730	1772	1853	1881	1939	
Total Operating Cost	6723	6711	6873	7191	7298	7521	

There is no regulated/unregulated differentiation of Users on the ABDP.
5	
System Capacity and Volume Assumptions
5.1	General

This section provides details relating to the technical specifications and throughput assumptions of the ABDP.  For background information on the history of the ABDP refer to Section 1.2.

The reason the ABDP was built was to connect gas production facilities at the Palm Valley and Mereenie gas fields to the Channel Island Power Station.  The pipeline system includes a branch supply line from the Mereenie production facilities together with small lateral pipelines at Tennant Creek and Katherine.

The ABDP has a maximum allowable operating pressure of 9.6Mpa.  The main pipeline is:

•	355.6mm (14”) outside diameter (OD) for the southern 1110km connecting Palm Valley to Mataranka;
•	323.9mm (12”) OD for the 391km section between Mataranka and the Darwin City Gate; and 
•	219.1mm (8”) OD for the 12km section between the Darwin City Gate and Channel Island.

The Mereenie branch supply line is 273.1mm (10”) outside diameter and 116km in length.  This pipeline has a maximum allowable operating pressure of 10.2Mpa.

The pipeline steel specification is API 5L Grade X60 (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 ABDP is as follows:

Applicable Code			AS2885

Maximum allowable		9,650kPa(g) (class 600)  mainline; and
operating pressure (MAOP)	10,150kPa(g) (class 600) - Mereenie spur

Steel grade			API 5L X60

Diameter and wall		355.6mm	5.8mm (Palm Valley - Mataranka);
thickness				323.9mm	5.25mm (Mataranka -Darwin City Gate);
					219.1mm	7.92mm (DCG – Channel Is); and
					273.1		4.78mm (Mereenie Spur)

Length				1513km

External coating	Extruded high density polyethylene (Shaw - Yellow Jacket)

Internal coating			None

Depth of cover			1200mm in roads and most locations;
					5000mm for directional drills;
					2000mm under rails and 1200mm under railway						reserves; and
					900mm in private property

•	2 remotely monitored inlet stations at Palm Valley and Mereenie gas fields.
•	7 remotely monitored delivery stations at Tennant Creek, Elliott, Katherine, Daly Waters for the McArthur River pipeline, Cosmo Howley, Channel Island and the Darwin City Gate.
•	10 intermediate scraper stations consisting of remotely actuated mainline valves and pig launch and receive facilities.
•	17 remotely actuated valves co-located at the delivery stations and scraper stations and 13 manually actuated mainline valves.
•	1 gas odourisation plant located at Tylers Pass (interconnection of the Mereenie spur line and the main pipeline).
•	1 compressor station located at Warrego north of Tennant Creek.  The compressor is a Solar 2 stage centrifugal unit driven by a Solar Saturn 1.2 MW gas turbine.  The compressor station was commissioned in October 1996.
•	1 pipeline control centre in Palmerston which uses a SCADA system to remotely control and continuously monitor the pipeline.
•	Cathodic protection system.
•	4 regional bases – Katherine, Tennant Creek, Alice Springs, and Daly Waters.
•	Head office and operations base at Palmerston.
5.2	Map of ABDP and Pipe Specification

A map of the ABDP Route is attached as Attachment 3, together with a schematic of the three pricing zones for the pipeline.  It is to be noted that only those pipelines noted as being included in Pipeline Licence 4 in attachment 3 are included in the ABDP system for the purposes of this Access Arrangement Information.  For information purposes, all gas transmission infrastructure connected into the ABDP has been included in the map in Attachment 3.

A detailed description of the boundaries of the three pricing zones is in the following table.

Zone	Boundaries	
1	Outlet of Palm Valley and Mereenie production facilities to the inlet of the Warrego compressor station.	
2	Inlet of the Warrego compressor station to the inlet of the Mataranka scraper station (end of 350mm pipeline and commencement of the 300mm pipeline).	
3	Inlet of the Mataranka scraper station to the outlet of the Channel Island meter station.	

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

Pipeline Section	Diameter
(mm outside)	Length (km)	
Palm Valley to Mataranka	355.6	1110	
Mataranka to Darwin City Gate	323.9	391	
Darwin City Gate to Channel Island	219.1	12	
Mereenie to Tylers Pass Supply Lateral	273.1	116	
Tennant Creek Lateral	114.3	24	
Katherine Lateral	114.3	5	

Zone	Length of Pipeline (Klms)	
1	730	
2	521	
3	407	

Maximum Delivery Capability	
Free-flow conditions	44 TJ/d (approx)	
With compressor operating	54 TJ/d (approx)	

5.3	Average Daily and Peak Demands

The table below sets out the gate station load profiles for the calendar year 1998.

Off-take/Parameter	1998	
Channel Island:
Total Annual Volume (TJ)
Average Daily Flow Rate (GJ)
Peak Day Flow Rate (GJ)
Minimum Delivery Pressure (kPa)(a)

Cosmo Howley Off-take:
Total Annual Volume (TJ)
Average Daily Flow Rate (GJ)
Peak Day Flow Rate (GJ)
Minimum Delivery Pressure (kPa)(a)

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

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

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

Elliott Off-take:
Total Annual Volume (TJ)
Average Daily Flow Rate (GJ)
Peak Day Flow Rate (GJ)
Minimum Delivery Pressure (kPa)(a)

Daly Waters Off-take:
Total Annual Volume (TJ)
Average Daily Flow Rate (GJ)
Peak Day Flow Rate (GJ)
Minimum Delivery Pressure (kPa)(a)

Mataranka Off-take:
Total Annual Volume (TJ)
Average Daily Flow Rate (GJ)
Peak Day Flow Rate (GJ)
Minimum Delivery Pressure (kPa)(a)

Darwin City Gate Off-take:
Total Annual Volume (TJ)
Average Daily Flow Rate (GJ)
Peak Day Flow Rate (GJ)
Minimum Delivery Pressure (kPa)(a)	
10721
29368
42082
2800

26
72
1930
2800

1884
5159
5912
2800

445
1218
6445
2800

1030
2822
3387
2800

25
69
75
2800

1771
4851
6031
2800

36
100
120
2800

14
37
45
2800	

5.4	Estimated Load Across Each Pricing Zone

Estimated average daily, peak and total pipeline load in each of the three pricing zones of the ABDP for years ending 30 June 1999 – 2004 are set out below.  These estimates are an amalgamation of forecasts provided by Users.

Load and Volume	2000	2001	2002	2003	2004	
ZONE 1
Average Daily Load (TJ/d)
Peak Load (TJ/D)
Annual Volume (PJ)	
1.2
1.5
0.5	
1.2
1.5
0.4	
1.2
1.5
0.4	
1.2
1.5
0.4	
1.2
1.5
0.4	
ZONE 2
Average Daily Load (TJ/d)
Peak Load (TJ/D)
Annual Volume (PJ)	
5.3
6.0
2.0	
5.4
6.0
2.0	
5.5
6.0
2.0	
5.5
6.0
2.0	
5.5
6.0
2.0	
ZONE 3
Average Daily Load (TJ/d)
Peak Load (TJ/D)
Annual Volume (PJ)	
36.3
50.2
13.3	
37.2
51.2
13.6	
36.3
56.4
14.0	
38.2
57.6
13.9	
39.3
59.3
14.3	
TOTAL ABDP
Average Daily Load (TJ/d)
Peak Load (TJ/D)
Annual Volume (PJ)	
42.9
48.9
15.7	
43.9
49.3
16.0	
44.0
53.7
16.4	
44.8
54.8
16.4	
45.9
56.6
16.8	

The table below contrasts financial year 1999 total pipeline throughput as derived from User forecasts and a combination of actual throughputs to date with the addition of NT Gas’s expectations for the months of May and June.  As is demonstrated by the table, historically actual pipeline peak day loads have generally been higher than User forecasts.

It is NT Gas’s expectation that the actual peak day deliveries over the Access Arrangement Period will be higher than that forecast by Users, and further, that the ABDP will at times be running at capacity to fulfil existing User contracts.

Load and Volume	1999
Forecast	1999
Actual	
Average Daily Load (TJ/D)	45.4	43.9	
Peak Load (TJ/D)	50	57	
Annual Volume (PJ)	16.6	16.1	

5.5	System Load Profile by Month

The table below sets out the ABDP load profile by month in terms of percentage of total annual pipeline throughput delivered in each month for calender year 1998.  This load profile in expected to be indicative of the load profile of each of the three ABDP pricing zones.

Month	% of total Annual Load	
January	7.9	
February	7.5	
March	8.5	
April	8.2	
May	9.0	
June	7.4	
July	8.3	
August	7.9	
September 	8.5	
October	9.7	
November	8.9	
December	8.2	
Total	100	

5.6	Numbers of Users on the ABDP as at June 1999

There is currently a total of three Users on the ABDP.  The number of Users in each of the pricing zones is detailed in the following table.

Zone	Number of Users	
1	1	
2	1	
3	3	

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 Commission 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 NT Gas is operating the ABDP 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	 Total Operating Costs – Indicative Comparison

The comparison of indicative total operating costs as determined by the application of industry accepted “rules of thumb” and estimated actual ABDP total operating costs for financial year 1999 is set out in the table below.

	ABDP Replacement Cost ($m)	Indicative Measure Applied	Indicative Operating Cost ($m)	Actual Operating Cost
($m)	
Pipeline Direct	312.0	2%	6.2	6.2	
Compression	7.0	7%	0.5	0.2	
Total	319.0		6.7	6.4	

6.4.1.2	Total Operating Costs – Comparison with Australian Pipelines
The table below sets out comparisons of estimated total operating costs for the ABDP and a selection of (albeit somewhat dated) other Australian pipeline operators on a $m/1000 km basis.  Unless otherwise noted, the data has been sourced from the Central West Pipeline Access Arrangement and is in 1999 dollars.

Company	State/Pipeline	Year	$m/1000km	

NT Gas

AGLP

Epic Energy

EAPL

CMS ENERGY

TPA

TPA

Alinta Gas

Pipeline Authority

PASA	
NT (Amadeus Basin to Darwin)

NSW (Central West Pipeline)

SA (Moomba to Adelaide)

Moomba to Sydney

WA (Parmelia)

VIC (Victorian Transmission System)

VIC (as above)

WA (Dampier to Bunbury)

NSW (Moomba to Sydney)

SA (Moomba to Adelaide)	
1998/99

1998/99

1999

2001

2000

1998

1995/96

1995/96

1994/95

1994/95	
3.9

2.8

7.3

6.1

9.3

11.0 - 16.0

9.9

13.6

10.4

10.1	

Even making allowance for the fact that there are significant differences in these pipeline systems (including varying amounts of compression) the above comparisons point to the total operating costs for the ABDP being efficient.
6.4.2	US Comparison - 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 NT Gas in operating the ABDP 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.  Given recent exchange rate volatility, a range of exchange rates between 62-78 US cents per $AUS has been applied to the US operating cost information.  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 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

3.1.1

3.1.1, 3.1.2
3.1.6
3.1.4
3.1.4
3.1.7

3.1.7
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 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	19	Overthrust Pipeline Co	
2	Black Marlin Pipeline Co	20	Panhandle Eastern Pipeline Co	
3	Chandeleur Pipeline Co	21	PG&E Gas Transmission Northwest Corp	
4	Columbia Gulf Transmission Co	22	Questar Pipeline Co	
5	East Tenessee Natural Gas Co	23	Sabine Pipeline Co	
6	El Paso Natural Gas Co	24	Sea Robin Pipeline Co	
7	Florida Gas Transmission Co	25	Stingray Pipeline Co	
8	Great Lakes Gas Transmission LP	26	Tenessee Gas Pipeline Co	
9	High Island Offshore System	27	Texas Eastern Transmission Corp (Tetco)	
10	Iroquois Gas Transmission LP	28	Texas Gas Transmission Corp	
11	K N Interstate Gas Transmission Co	29	Trailblazer Pipeline Co	
12	Kern River Gas Transmission Co	30	Transcolorado Gas Transmission Co	
13	Midwestern Gas Transmission Co	31	Transwestern Pipeline Co	
14	Mojave Pipeline Co	32	Trunkline Gas Co	
15	Mississippi River Transmission Co	33	U-T Offshore System	
16	Mobile Bay Pipeline Co	34	Viking Gas Transmission Co	
17	Northern Border Pipeline Co	35	Williams Gas Pipelines Central	
18	Northern Natural Gas Co	36	Wyoming Interstate Co Ltd	

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 ABDP is being operated efficiently.

ATTACHMENT 3

MAP OF AMADEUS BASIN TO DARWIN PIPELINE ROUTE AND SCHEMATIC DETAILING ZONE BOUNDARIES

AMADEUS BASIN TO DARWIN PIPELINE
ZONE BOUNDARIES

1	Introduction	1
1.1	Overview of the Access Arrangement Information	1
1.2	Background	1
1.3	Important Notice	3
2	Access & Pricing Principles	4
2.1	Factors to be taken into account by regulator	4
2.2	Tariff Principles	4
2.3	Reference Tariff Determination	5
2.4	Tariff Structure	5
2.4.1	Reference Tariff	6
2.4.2	Zonal Tariffs	6
2.4.3	Rebatable Service	7
2.5	Cost allocation	7
2.6	Incentive Mechanism	8
2.7	Other Revenue	8
3	Capital Costs	9
3.1	Initial Capital Base	9
3.1.1	Depreciated Optimised Replacement Cost (“DORC”)	10
3.1.2	Other Factors to be Considered in Establishing the ICB required by the   Code	12
3.1.3	Valuation of Non-System Assets	17
3.1.4	Depreciation	17
3.1.5	Working Capital	19
3.1.6	Economic Life and Remaining Economic Lives	19
3.1.7	Estimated and Committed Capital Expenditure	20
3.2	Rate of Return	22
3.2.1	WACC Approach	22
3.2.2	Application of WACC to ABDP	22
3.2.3	Range of Variables	25
3.3	Total Revenue	29
3.4	Allocation Of Total Revenue	30
3.5	Reference Tariff for Pricing Zones	31
4	Non-Capital Costs:  Operations and Maintenance and Overheads and Marketing	33
4.1	Operations and Maintenance Costs	33
4.2	Overheads and Marketing Costs	34
4.3	Fixed versus Variable costs	35
4.4	Cost Allocation	35
5	System Capacity and Volume Assumptions	37
5.1	General	37
5.2	Map of ABDP and Pipe Specification	38
5.3	Average Daily and Peak Demands	39
5.4	Estimated Load Across Each Pricing Zone	41
5.5	System Load Profile by Month	42
5.6	Numbers of Users on the ABDP as at June 1999	42
6	Efficient Costs and Performance Measures for Pipelines	43
6.1	Introduction	43
6.2	Cost Structure of Pipelines	44
6.3	Performance Measures for Pipelines	44
6.3.1	Capital Costs	44
6.3.2	Operating Costs	45
6.4	Key Performance Indicators	45
6.4.1	Australian Comparisons	45
6.4.1.1	Total Operating Costs – Indicative Comparison	45
6.4.1.2	Total Operating Costs – Comparison with Australian Pipelines	46
6.4.2	US Comparison - Operating Costs	47

ATTACHMENT 1	CATEGORIES OF INFORMATION TO BE DISCLOSED AS PART OF THE ACCESS ARRANGEMENT INFORMATION ………..…………………………..48
ATTACHMENT 2	COMPILATION OF US DATA FOR COST COMPARISON ………………….…50
ATTACHMENT 3	MAP OF AMADEUS BASIN TO DARWIN PIPELINE AND SCHEMATIC DETAILING ZONE BOUNDARIES …………………..…………………………..52