Issues
Paper
12345

Access Arrangement by
NT Gas Pty Ltd for the
Amadeus Basin to Darwin Pipeline

August 1999

File No:  C1999/329

Preface
On 25 June 1999 N.T. Gas Pty Limited submitted to the Australian Competition and Consumer Commission (‘the Commission’), for approval under the National Third Party Access Code for Natural Gas Pipeline Systems (‘the code’), a proposed access arrangement and access arrangement information for the Amadeus Basin to Darwin Pipeline.  
The access arrangement and access arrangement information describe the terms and conditions on which the company will make access to its pipeline available to third parties.  The Commission will assess the access arrangement and access arrangement information against the principles in the Code.
Interested parties are invited to make submissions to the Commission on any issues relevant to this access arrangement by 10 September 1999.  The issues identified in this Issues Paper are only indicative and are not meant to be exhaustive.  Parties making submissions are free to identify other relevant issues for consideration by the Commission.  All submissions must be in written form.  Unless submissions are marked confidential, they will be placed on the public registers maintained by the Commission and the Code Registrar and made available to any person or organisation on request.  If a submission contains confidential material, a non-confidential version should also be supplied.  Under the Code, the Commission must not disclose confidential information except if it is of the opinion that disclosure would not be unduly harmful to the legitimate business interests of the service provider, a user or a prospective user.
It would assist the Commission if four hard copies of each submission could be provided and also one copy supplied in electronic format compatible with Microsoft Word 97 for Windows.  Submissions should be addressed to: 
Mr Mark Pearson
General Manager
Regulatory Affairs - Gas
Australian Competition and Consumer Commission
PO Box 1199
Dickson    ACT    2602
Copies of the access arrangement, access arrangement information and this Issues Paper are available from the Commission’s website at http://www.accc.gov.au (under ‘Gas’).  Copies in printed form or on computer disk may be obtained from the Commission by contacting Katarina Glavinic (phone 02 6243 1274, fax 02 6243 1205, email; katarina.glavinic@accc.gov.au). 
Any other inquiries should be directed to David Hatfield on (02) 6243 1266 or Catherine Maloney (02) 6243 1275. 

Contents
1.	Introduction	5

1.1	Purpose  	 5
1.2	The current assessment process	5
1.3	Key issues	6

2. 	The NT gas industry structure and regulatory framework	6

2.1	Structure of the gas industry in the Northern Territory	6
2.2	Regulatory framework	7
2.3	Amadeus Basin to Darwin pipeline	7
2.4	Ownership and organisational structure	8

3.	Criteria for assessing access arrangements	9

4.	Issues for consideration	10

4.1	Compliance with the Code	10
4.1.1	The content of the access arrangement	10
4.1.2	Information disclosure	10
4.1.3	Services policy	10
4.1.4	Terms and conditions	11
4.1.5	Trading Policy	12
4.1.6	Queuing Policy	12
4.1.7	Extensions/Expansions Policy	13
4.1.8	Term and Review	13
4.2	Pricing principles and related issues	14
4.2.1 Introduction	14
4.2.2 Forecast revenue	14
4.2.3 Initial Capital Base	15
4.2.4 Cost of Capital	17
4.2.4 Depreciation Methodology	18
4.2.1 Operating and maintenance (O&M) costs	18
4.2.6 Cost allocation	19
4.2.7 Forecast Volumes	20
4.2.8 Reference Tariffs	21
4.2.9 Incentive Mechanisms	22
4.2.10 Key Performance Indicators	23

Abbreviations and glossary of terms
ABDP	Amadeus Basin to Darwin Pipeline	
Access arrangement	Arrangement for third party access to a pipeline provided by a pipeline owner/operator and submitted to the relevant regulator for approval	
CAPM	Capital Asset Pricing Model	
the code	National Third Party Access Code for Natural Gas Pipeline Systems	
Commission	Australian Competition and Consumer Commission 	
Covered pipeline	Pipeline to which the provisions of the Code apply	
CPI	Consumer Price Index	
DAC	Depreciated Actual Cost	
DORC	Depreciated Optimised Replacement Cost	
GJ	Gigajoule	
NPV	Net Present Value	
NT Gas	Northern Territory Gas Pty Ltd	
PJ	Petajoule (equal to 1,000,000 GJ)	
PSA	Prices Surveillance Authority	
TJ	Terajoule (equal to 1,000 GJ)	
WACC	Weighted average cost of capital	

1.	Introduction
1.1	Purpose
Chapter 2 of the National Third Party Access Code for Natural Gas Pipeline Systems (‘the Code’) specifies that the service provider of a gas pipeline covered by the Code is required to establish an access arrangement and submit it to the regulator for approval.  The service provider is defined as ‘a person who owns (whether legally or equitably) or operates the whole or any part of a Pipeline’. NT Gas Pty Ltd is the Service Provider for the Amadeus Basin to Darwin Pipeline.   
The purpose of this Issues Paper is to: 
•	list a number of issues that the Australian Competition and Consumer Commission (‘the Commission’) has identified as relevant to its role in assessing the access arrangement and access arrangement information for the ABDP (which comprises the mainline and some lateral pipelines) submitted by NT Gas; and
•	invite interested parties to make submissions on these and other relevant issues that they consider the Commission should examine in its assessment of the access arrangement; and
•	all data presented in this Issues Paper is sourced from the proposed Access Arrangement and Access Arrangement Information.
1.2	The current assessment process
The proposed access arrangement and access arrangement information describe the terms and conditions on which NT Gas will make access to the ABDP available to third parties during the initial access arrangement period, which NT Gas proposes will last four and half years.  Under the Code, NT Gas has the discretion to submit revisions earlier than the scheduled review.   
Under the Code, the Commission is required to:
•	inform interested parties that it has received the access arrangement from NT Gas; 
•	publish a notice in a national daily paper which at least describes the covered pipeline to which the access arrangement relates; states how copies of the documents may be obtained; and request submissions by a date specified in the notice;
•	after considering submissions received, issue a draft decision which either proposes to approve the access arrangement or not to approve the access arrangement and states the amendments (or nature of the amendments) which have to be made to the access arrangement in order for the Commission to approve it.  Submissions will be sought again following release of the Commission’s draft decision;
•	after considering any additional submissions, issue a final decision that it either approves or does not approve the access arrangement (or revised access arrangement) and states the amendments (or nature of the amendments) which have to be made to the access arrangement (or revised access arrangement) in order for the Commission to approve it; and
•	if the amendments are satisfactorily incorporated in a revised access arrangement, issue a final approval.  If not, the Commission must draft and approve its own access arrangement.
1.3	Key issues
The Commission has identified a range of issues (refer to Chapter 4, in particular) which are likely to be relevant to its assessment of the proposed access arrangement and for which it invites comments. Key issues that the Commission will focus on during its assessment include:
•	the proposed asset valuation methodology based on Depreciated Optimised Replacement Cost (‘DORC’);
•	the proposed rate of return, a real pre-tax weighted average cost of capital (‘WACC’) of 11 per cent, and the parameters forming the WACC;
•	other components of NT Gas’s revenue requirements (operating and maintenance costs);
•	depreciation methodology;
•	level and structure of tariffs, including zonal-based pricing; 
•	the reasonableness of volume forecasts; and 
•	incentive mechanisms.

2. 	The NT gas industry structure and regulatory framework
2.1	Structure of the gas industry in the Northern Territory
Briefly, the gas industry in NT has the following key characteristics:
There are two gas producers in the Northern Territory that access gas from the Amadeus Basin. Magellan operates the field at Palm Valley, and Santos operates the Mereenie field. The total amount of gas produced by these basins was 18.3 PJ last financial year.
The gas transmission pipeline from the production points to the users is leased to and operated by NT Gas as trustees of the Amadeus Gas Trust. AGL owns a 96% percent share of NT Gas. The subsidiary pipelines that service larger users are operated by NT Gas in association with other companies. Envestra and NT Gas operate the transmission pipeline from Palm Valley to Alice Springs, and Power and Water Authority (PAWA) with NT Gas operate the Macarthur River pipeline that services the large Macarthur River mine.
The gas produced in the Northern Territory is largely used for electricity generation. Of the 18.3 PJ produced, 13.6 PJ is used in electricity generation at Channel Island, Katherine and other power stations along the pipeline. 0.15 PJ goes to reticulation in urban areas such as Alice Springs, Katherine and other smaller towns along the pipeline. The remaining 4.5 PJ is used by major users such as the mines at Macarthur River and smaller industrial users in the Mataranka industrial region outside Darwin. Boral and NT Gas are the retailers in the Northern Territory.
2.2	Regulatory framework
The main legislation and relevant documents regulating access to the NT gas transmission industry are:
•	the Code, under which transmission service providers are required to submit access arrangements to the Commission for approval;
•	the Gas Pipelines Access (South Australia) Act 1997; and
•	the Gas Pipelines Access (NT) Act 1998.
Code Bodies and Appeals Bodies in NT with respect to transmission pipelines are:
•	the Commission – Regulator and Arbitrator; 
•	the National Competition Council – Code Advisory Body;
•	the Commonwealth Minister – Coverage Decision Maker;
•	the Federal Court – judicial review; and
•	the Australian Competition Tribunal – administrative appeal.

2.3	Amadeus Basin to Darwin pipeline
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 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.

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.

2.4	Ownership and organisational structure
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.

3.	Criteria for assessing access arrangements
The Commission may approve an access arrangement only if it is satisfied that the access arrangement contains the elements and satisfies the principles set out in sections 3.1 to 3.20 of the Code, which are summarised below.  An access arrangement cannot be opposed on the basis that it does not address a matter that section 3 of the Code does not require it to address.  Notwithstanding, the Commission has a broad discretion in accepting or opposing an access arrangement.  
An access arrangement must include the following elements:
•	services policy which must include a description of one or more services that the service provider will offer to users and prospective users;
•	reference tariffs and reference tariff policy, including one or more reference tariffs.  Tariffs must be determined according to the reference tariff principles in section 8 of the Code;
•	terms and conditions on which the service provider will supply each reference service;
•	a statement that the covered pipeline is either a contract carriage or market carriage pipeline (capacity management policy);
•	a trading policy that enables a user to trade its right to obtain a service (on a contract carriage pipeline) to another person; 
•	a queuing policy to determine users' priorities in obtaining access to spare and developable capacity on a pipeline; 
•	an extensions/expansions policy to determine the treatment of an extension or expansion of a pipeline under the Code; 
•	a date by which revisions to the access arrangement must be submitted; and 
•	a date by which the revisions are intended to commence.  
In considering whether an access arrangement complies with the Code, the Commission must take into account, pursuant to section 2 of the Code:  
•	the legitimate business interests of the service provider;
•	firm and binding contractual obligations of the service provider or other persons (or both) already using the covered pipeline;
•	the operational and technical requirements necessary for the safe and reliable operation of the covered pipeline;
•	the economically efficient operation of the covered pipeline;
•	the public interest, including the public interest in having competition in markets (whether or not in Australia);
•	the interests of users and prospective users; and
•	any other matters that the Commission considers are relevant.  

4.	Issues for consideration
4.1	Compliance with the Code
4.1.1	The content of the access arrangement
The required contents of an access arrangement were listed in broad terms earlier in Chapter 3.  The Commission must be satisfied that NT Gas’ access arrangement meets the content requirements of the Code before it can approve the access arrangement.  It must also be satisfied of the reasonableness of the terms and conditions on which services will be offered.
4.1.2	Information disclosure
The Code requires that a proposed access arrangement must be supported by access arrangement information.  Section 2.6 specifies that access arrangement information must contain such information as in the opinion of the regulator would enable users and prospective users to understand the derivation of the elements in the proposed access arrangement and to form an opinion as to the compliance of the access arrangement with the provisions of the Code.  Section 2.7 states that the access arrangement information may include any relevant information but must include at least the categories of information described in Attachment A to the Code (refer to Attachment A to this Issues Paper). 
Whilst ensuring that sufficient information is available to users and prospective users, the Commission must also ensure that any information disclosed is not, in its opinion, unduly harmful to the legitimate business interests of the service provider, users or prospective users.   
Issues for consideration
(a)	Is the information disclosed in the access arrangement and the access arrangement information sufficient to enable users and prospective users to understand the derivation of the elements in the proposed access arrangement and to form an opinion as to the compliance of the access arrangement with the provisions of the Code?
(b)	Are the items listed in Attachment A adequately addressed?  If not, what additional information (including any relevant information in addition to Attachment A) should be provided, and in what form?
4.1.3	Services policy
Sections 3.1 and 3.2 of the Code require an access arrangement to include a services policy which must include a description of one or more services that the service provider will make available to users and prospective users.  The policy must contain one or more services which are likely to be sought by a significant part of the market, and any service or services that in the regulator’s opinion should be included in the services policy. 
To the extent that is practicable and reasonable, a service provider should make available only those elements of a service required by users and prospective users and apply a separate tariff for each element if this is requested. 
NT Gas proposes three classes of services to apply under this access arrangement: transportation, interruptible and negotiated services.
Transportation Service — Reference Service for transport from the Receipt Points to any Delivery Points on the Pipeline with tariffs charged on the basis of throughput ($ per GJ of throughput).  
Interruptible Service – Rebatable Service (non-Reference Service) for transport from the Receipt Points to any Delivery Points on the Pipeline with tariffs charged on the basis of throughput ($ per GJ of throughput), where NT Gas is entitled to cease receiving gas from, or delivering gas to, the User when pipeline capacity is constrained/curtailed or to meet the capacity requirements of other Users.
Negotiated Services — agreements negotiated to meet the needs of a user which differ from those in the Transportation Service or the Interruptible Service.
However, the applicant has stated there is currently no firm capacity available in the pipeline with all capacity utilised under pre-existing Service Agreements for forward haul services in the nature of the Transportation Service. The Commission has requested copies of the pre-existing Service Agreements and will review any implications they have for this access arrangement.
Issues for consideration
a)	Are the proposed services likely to be sought by a significant segment of market participants?
b)	Are there any other services that should be included in the services policy? If so, please specify.
4.1.4	Terms and conditions 
Section 3.6 of the Code requires an access arrangement to include the terms and conditions on which a service provider will supply each reference service.  To be approved, these terms and conditions must be considered reasonable by the regulator.
The terms and conditions of transportation service and interruptible services are to be set out in the standard service agreement. NT Gas proposes the terms and conditions of the service agreement will be consistent with its access arrangement and will also incorporate Schedule 2. Schedule 2 contains general provisions on the relationship between NT Gas and users, gas balancing and gas quality specification.
A request for service has been included in the access arrangement but not the actual service agreement.
Issues for consideration
a)	Does the access arrangement clearly identify the relevant terms and conditions, which enable a prospective user to be sufficiently well informed before making a specific access request?
b)	Should the service agreement be included as part of the access arrangement?
c)	Are the proposed terms and conditions reasonable?
4.1.5	Trading Policy
Sections 3.9 to 3.11 of the Code set out the requirements for a trading policy.  If a pipeline is a contract carriage pipeline (as is proposed by NT Gas for the ABDP), the access arrangement must include a trading policy which explains the rights of a user to trade its right to obtain a service to another person.  The trading policy must also allow a user to transfer capacity.
NT Gas permit a bare transfer without their consent provided the transferee notifies NT Gas of the portion of Contracted Capacity subject to the Bare Transfer (as defined in the Code) and of the nature of the Contracted Capacity subject to the Bare Transfer. For any other form of transfer the User is required to seek NT Gas consent. NT Gas may withhold consent on reasonable commercial or technical grounds.
Issues for consideration
a)	Does the proposed trading policy sufficiently explain the rights of the user to trade a service to another person?
b)	Should a transfer other than a bare transfer be subject to NT’s consent on reasonable commercial grounds?
4.1.6	Queuing Policy
Sections 3.12 to 3.15 of the Code set out the requirements for a queuing policy.  An access arrangement must include a queuing policy that determines the priority given to users and prospective users for obtaining access to a covered pipeline and for seeking dispute resolution under section 6 of the Code.  
The policy must set out sufficient detail to enable users and prospective users to understand in advance how it will operate; to the extent reasonably possible, accommodate the legitimate business interests of the service provider, users and prospective users; and to the extent reasonably possible, generate economically efficient outcomes.
NT Gas proposes to give first priority to existing users with contractual rights to increase capacity reservation where an offer has been made to enter into a Service Agreement but where the user has not yet entered into the Service Agreement.
Issues for consideration
(a)	Are there sufficient details in the proposed queuing policy that would enable users and potential users to understand how the queuing policy will operate?
(b)	Does the proposed queuing policy accommodate the legitimate business interests of the service provider, users and prospective users? 
(c)	Is it reasonable for NT Gas to give priority to existing contractual users on capacity reservation?

4.1.7	Extensions/Expansions Policy
Section 3.16 of the Code requires an access arrangement to include an extensions/expansions policy which sets out the method to determine which extensions and expansions will be treated as part of the covered pipeline and, if covered, how they will affect reference tariffs.
NT Gas propose in the event that they do elect to increase capacity on the pipeline, that reference tariffs for existing delivery points will not be affected by any extension that is considered to be part of the pipeline. At the time of expansion NT Gas will elect to either include the additional capacity as part of the pipeline for the purposes of this access arrangement and utilise the revisions section, or will submit a separate access arrangement for the additional capacity.
Issues for consideration
(a)	Does the proposed extensions/expansions policy constitute a ‘method’ in accordance with the Code?
(b)	Does the proposed access arrangement sufficiently specify how the extensions and expansions will affect reference tariffs?  

4.1.8	Term and Review
Section 3.17 of the Code states that an access arrangement must include a revisions submission date and a revisions commencement date. NT Gas propose the commencement date of the access arrangement to be the date on which the approval by the ACCC takes effect under the Code. 
It is also proposed the revisions to the access arrangement should begin on the date 4 years and 6 months after the commencement of the access arrangement. The revisions to this access arrangement will commence on the later of:
•	the date being 6 months after the Revisions Submission Date; or
•	the date on which the approval by the ACCC of the revisions to the access arrangement takes effect under the Code.
Issues for consideration
The Commission recognises the need to balance the rapidly changing nature of the natural gas industry and the uncertainty which naturally arises in such an environment (which suggests a short access arrangement period) against the need for business certainty (which typically coincides with longer periods).  
(a)	The Commission is interested in views as to the appropriate timing of the first review of the access arrangement.
Section 3.17(b)(ii) of the Code makes provision for specific major events to be defined that trigger an obligation on the part of the service provider to submit revisions to the access arrangement prior to the revisions submission date.  
(b)	Should a review mechanism be included in the access arrangement? If so, please specify.
4.2	Pricing principles and related issues
4.2.1 Introduction
The pricing of transportation services is the core element of an access arrangement.  Accordingly, section 8 of the Code establishes pricing principles for setting the prices of transportation services.  While these principles provide for considerable flexibility, they are designed to achieve the key objectives listed in section 8.1 of the Code. 
In broad terms, these objectives require the tariffs to generate sufficient revenue to enable the service provider to make a commercial return on its investment in pipeline assets over the life of those assets, and to provide it with an appropriate incentive to expand the system in a timely manner.  At the same time the return needs to be set so that revenues do not reflect the exercise of market power often available to an unregulated natural monopoly operation.  In addition, tariffs need to be cost reflective to promote economic efficiency in the use of the system.  Finally, the Code recognises the dulling effect revenue constraints can place on efficient pipeline operations and suggests the inclusion of mechanisms to provide incentives for the service provider to strive for efficiency improvements. 
It remains for the Commission to determine whether the proposed pricing methodology is consistent with the outcomes sought by the Code.  The methodology proposed for the setting of reference tariffs is contained in the access arrangement and access arrangement information.  NT Gas has applied the following approach to the development of its proposed reference tariffs: 
(a)	a current cost accounting methodology is used to determine the revenue requirement;
(b)	the initial capital base is valued by the application of the depreciated optimised replacement cost methodology (DORC);
(c)	a real pre-tax rate of return of 11 per cent will be applied to the initial capital base;
(d)	the rate of return is set to provide NT Gas with a return commensurate with prevailing conditions in capital markets and with the risks involved in providing the reference services;
(e)	an accelerated form of depreciation as distinct from the straight line method is proposed for the main transmission pipeline assets;
(f)	reference tariffs are structured to reflect the costs of providing the reference services;
(g)	reference tariffs are to reflect the distance the gas is transported through the pipeline. 

4.2.2	Forecast revenue
Forecast revenue is set at a level over the life of the asset that allows the service provider to earn a reasonable rate of return on assets employed in providing tariffed transmission services.  The key parameters in establishing forecast revenue are: 
•	regulatory asset values;
•	cost of capital; and
•	non-capital costs. 
Table 1 shows NT Gas’ forecast revenue and its components over the initial access arrangement period. Each component is considered in more detail later in this section.

Table 1: 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	

NT Gas is proposing a current cost accounting methodology to determine its revenue requirements. This involves the expression of the revenue components in real or constant dollars and indexing the capital base and depreciation for inflation.
Issues for consideration
a)	Is the use of a current cost accounting methodology appropriate for determining the revenue stream? If not, what methodology should be used?
4.2.3 Initial Capital Base
In establishing the value of the initial capital base, the Code requires the regulator to consider the depreciated actual cost (DAC), the Depreciated Optimised Replacement Cost (DORC) and other factors outlined in section 8.10 of the Code.  In practice, DAC may be considered to set the lower boundary of valuations and DORC the higher. NT Gas proposes to adopt the DORC methodology.  Table 2 shows the DORC values proposed by NT Gas and economic life assumptions.
Table 2: 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	

Issues for consideration
(a)	Is NT Gas’ approach for valuing the initial capital base consistent with the requirements of the Code?
(b)	Do the DORC values represent the most rational, optimal configuration? 
(c)	Is DORC the most appropriate asset valuation methodology for the ABDP?  If not, what would be a fair and reasonable value for the ABDP?  What is the basis of your estimate?
(d)	Is the valuation likely to result in inefficient consumption or investment decisions?
(e)	The Code also allows the regulator to take into account the purchase price paid by the service provider. Is AGL’s acquisition of 96% of NT Gas a relevant purchase price?
(f)	Who should carry the risk of stranded assets?  How and when should this be determined?

4.2.4 Cost of Capital
NT Gas’ rate of return is based on the Capital Asset Pricing Model (‘CAPM’) and Weighted Average Cost of Capital (‘WACC’) approaches. NT Gas is proposing a real pre-tax WACC of 11 per cent. NT Gas has assumed the Commission’s approach in considering the Victorian access arrangements will be a relevant factor in determining the WACC for ABDP. NT Gas concludes that the risk associated with the ABDP is higher than the Victorian system and justifies a higher rate of return.
The parameters listed in Table 3 form the basis for NT Gas’ proposed WACC.
Table 3: 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%	

Issues for consideration
(a)	Are the formulae (and conversion process from post-tax nominal WACC to pre-tax real WACC) employed to calculate the WACC consistent with current thinking for application to a regulated asset base?  Is the resulting rate of return appropriate?  If not, what alternative would more likely represent the risk profile of the NT Gas assets? 
(b)	Do the various components of WACC accurately reflect prevailing market rates?  Is the use of 10 year bonds as an estimate of the risk free rate appropriate for this application?  How should the risk free rate be estimated?
(c)	Are the asset and equity betas appropriate? 

4.2.4 Depreciation Methodology
NT Gas is proposing to depreciate the transmission pipeline assets from the current DORC valuation of $251.51m using a kinked straight line methodology to $61.84m. The kink is proposed to occur at 2011 and then depreciation will continue until the end of the economic life of the pipeline (2066).
Issues for consideration
a)	Is the proposed depreciation methodology appropriate? Does it reflect changes in the expected economic life of the assets? Is the depreciation methodology consistent with proposed DORC valuation approach?
b)	Are the proposed economic lives of the various assets appropriate? Do they properly reflect the remaining gas reserves in the Amadeus Basin and possible alternative uses of the pipeline?
4.2.1	Operating and maintenance (O&M) costs
The Code allows for the recovery of non capital costs. Table 4 shows NT Gas’ forecast operating and maintenance costs.
Table 4: 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	

NT Gas’ proposed total operating costs are shown in Table 5.
Table 5: 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	

Issues for consideration
(a)	Are the forecast operating and maintenance costs reasonable?
(b)	Do they represent the efficient costs of delivering the reference services, in accordance with industry best practice in Australia and overseas, taking account of pipeline age, size and industry structure? 
4.2.6	Cost allocation
As a general principle under the Code, the costs of operating and maintaining the transmission assets should be allocated to users according to their use of those assets, where attributable.  Costs that cannot be directly attributed should be allocated to various users in an efficient and equitable manner. Moreover, tariffs for a reference service should reflect the costs of providing that service.
Characteristics of NT Gas’ cost allocation are as follows:
•	All operating and maintenance costs are direct costs to NT Gas and will be recovered from the user on the basis of length of the pipeline the user utilises;
•	Administration costs and general costs will be allocated to each of the pricing zones in the same manner as operating and maintenance costs; and
•	Sales and marketing costs will be allocated on the basis of the quantity of gas delivered out of the pipeline from delivery points within each of the ABDP pricing zones.
The proposed operating costs are shown in Table 6.
Table 6: 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	

4.2.7 Forecast Volumes
NT Gas has provided a forecast of volumes ascertained from users from 2000 to 2004. There is a marginal increase in volumes forecasted over this five year period.
NT Gas’ forecast volumes for the regulatory period are shown in Table 7.
Table 7: Forecast Volumes for the Regulatory Period
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 
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	

Issues for consideration
a)	Are the volumes forecasted by NT Gas reasonable? If not, what would be reasonable a volume forecasts?
4.2.8 Reference Tariffs
For reference tariff purposes, NT Gas has differentiated the ABDP into three different pricing zones; Zone 1, Zone 2 and Zone 3. The reference tariff for each year is proposed to be calculated on a per gigajoule basis by dividing the estimated throughput into the required revenue for that year. NT Gas propose to smooth the reference tariff over the access arrangement period by using a smoothing parameter “X”. Table 8 sets out the reference tariffs applicable to each pricing zone.
Table 8: 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	

Issues for consideration
a)   Is a zonal pricing approach appropriate? Are the suggested zone boundaries reasonable?
a)	To what extent are the reference tariffs likely to replicate the outcomes of a competitive market?
b)	Will the proposed tariff structure and principles encourage investment decisions congruent with a competitive market outcome?
c)	Does the proposed level and structure of tariffs promote efficiency in pricing?  Are the pricing principles economically sound in terms of providing price signals for maximising the efficient utilisation of the system?  
d)	Are the reference tariffs sufficient to allow the safe and reliable operation of the facility?
e)	Is the revenue generated from the proposed tariffs consistent with NT Gas’ efficient costs?
4.2.9 Incentive Mechanisms
The Code promotes the use of incentive mechanisms within the Reference Tariff Policy that encourages the Service Provider to seek additional returns that exceed the level of returns expected at the beginning of the access arrangement period. Section 8.46 of the Code lists the relevant objectives that should feature in the design of the incentive mechanism.
NT Gas propose an incentive structure designed to reduce total operating costs and to increase pipeline throughput. The key features of their incentive mechanism is a rebatable service which is designed to recognise existing contractual arrangements and fixed tariffs over the access arrangement period.
Issues for consideration
(a)	Do the incentive mechanisms encourage NT Gas to increase sale volumes of all services without providing an artificial incentive to favour the sale of one service over another? 
(b)	Do the mechanisms provide NT Gas with sufficient incentive to reduce costs?  Are there adequate safeguards on service quality to ensure cost reductions are not achieved at the expense of quality?
(c)	Are the benefits of the incentive mechanisms shared equitably between NT Gas and users?
4.2.10 Key Performance Indicators
Attachment A requires key performance indicators from the service provider to justify “reasonably incurred” costs. NT Gas has provided a comparison of total operating costs within Australia and the US.
Issues for consideration
(a)	Are the supplied performance indicators relevant?  Have they been interpreted correctly?  Are more appropriate measures available? 

Attachment A
INFORMATION DISCLOSURE BY A SERVICE PROVIDER TO INTERESTED PARTIES
Pursuant to section 2.7 the following categories of information must be included in the Access Arrangement Information.
The specific items of information listed under each category are examples of the minimum disclosure requirements applicable to that category but, pursuant to sections 2.8 and 2.9, the Relevant Regulator may:
	allow some of the information disclosed to be categorised or aggregated; and
	not require some of the specific items of information to be disclosed,
if in the Relevant Regulator's opinion it is necessary in order to ensure the disclosure of the information is not unduly harmful to the legitimate business interests of the service provider or a user or Prospective user.
Category 1: Information Regarding Access & Pricing Principles
				Tariff determination methodology
				Cost allocation approach
				Incentive structures
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 economic 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 & Maintenance
				Fixed versus variable costs
				Cost allocation between zones, services or categories of asset & between regulated/unregulated
				Wages & Salaries ‑ by pricing zone, service or category of asset
				Cost of services by others including rental equipment
				Gas used in operations ‑ unaccounted for gas to be separated from compressor fuel
				Materials & supply
				Property taxes
Category 4: Information Regarding Overheads & Marketing Costs
				Total service provider costs at corporate level
				Allocation of costs between regulated/unregulated segments
				Allocation of costs between particular zones, services or categories of asset
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
				Total annual volume delivered ‑ existing term and expected future volumes
				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 "reasonably incurred" costs
				Service provider's KPIs for each pricing zone, service or category of asset