1. Summary Draft greenfields guideline for natural gas ... ACCC... · Moreover, according to the...

Summary1.

Draft greenfields guidelinefor natural gas transmissionpipelines

A guide to the access regulationframework and options for newnatural gas transmission pipelinedevelopments in Australia

June 2002

© Australian Competition and Consumer Commission 2002

ISBN 1 920702 03 2

This work is copyright. Apart from any use as permitted underthe Copyright Act 1968 no part may be reproduced by anyprocess without permission from the Australian Competition andConsumer Commission. Requests and inquiries concerningreproduction and rights should be addressed to the DirectorPublishing, Australian Competition and Consumer Commission,PO Box 1199, Dickson, ACT 2602.

Published by the ACCC Publishing Unit. 6/02.

iiiDRAFT Greenfields guideline

Contents

1. Summary .............................................................................................................................. 1

2. Introduction .......................................................................................................................... 4

3. The regulatory framework .................................................................................................... 7

3.1 Role of the National Competition Council ................................................................... 7

3.2 Coverage under the code ............................................................................................. 7

3.3 Submission of a Part IIIA undertaking ........................................................................... 8

3.4 Similarities between regimes ....................................................................................... 9

3.4.1 Potential for regulatory overlap ........................................................................ 9

3.5 Unregulated pipelines ................................................................................................ 10

4. Risks faced by greenfields pipelines .................................................................................... 11

4.1 The treatment of risk in the regulatory framework .......................................................11

4.2 Financing phase ......................................................................................................... 13

4.3 Construction phase ..................................................................................................... 14

4.4 Operational phase ...................................................................................................... 16

4.4.1 Self-insurance ................................................................................................ 16

4.5 Demand assessment ................................................................................................... 17

4.6 Use of forecasts .......................................................................................................... 18

4.6.1 Forecasts, tariffs and incentives for spare capacity ......................................... 19

5. Additional risk mitigation considerations ............................................................................ 21

5.1 Tariff structures and service contracts ......................................................................... 21

5.1.1 Determination of reference tariffs .................................................................. 21

5.1.2 Contracts in existence before and after an access arrangement ...................... 22

5.1.3 Foundation contracts ...................................................................................... 22

5.1.4 Prudent discounts ........................................................................................... 22

5.1.5 Market based tariffs ....................................................................................... 23

5.2 Determining the initial capital base for a greenfields pipeline ................................... 24

5.2.1 Adjustment mechanisms ................................................................................ 24

5.3 Downside risk mitigation ........................................................................................... 25

6. Managing uncertainty and blue sky opportunities ............................................................... 26

6.1 Demand forecasting ................................................................................................... 27

6.2 Benefit sharing mechanisms ....................................................................................... 27

iv DRAFT Greenfields guideline

6.3 Preservation of blue sky profits ................................................................................... 28

6.4 Duration of an access arrangement ............................................................................ 30

6.5 Fixed principles ......................................................................................................... 31

6.6 Depreciation .............................................................................................................. 31

6.7 Post-tax revenue handbook ......................................................................................... 32

7. Consultation and provision of information ........................................................................... 33

7.1 Consultation before submitting an undertaking or access arrangement ....................... 33

7.2 Provision of information ............................................................................................. 33

7.3 Public consultation and assessment procedures .......................................................... 34

7.4 Timeliness of regulatory rulings .................................................................................. 35

Appendix 1 ............................................................................................................................... 37

Example for derivation of revenues when expected demand is uncertain ............................ 37

Appendix 2 ............................................................................................................................... 44

Example of an adjustment to the initial capital base to reflect actual costs and theeffect on reference tariffs .................................................................................................... 44

Appendix 3 ............................................................................................................................... 51

Example of benefit sharing when demand exceeds a pre-set threshold ................................ 51

Appendix 4 ............................................................................................................................... 56

Summary of consultancies ................................................................................................... 56

Macquarie Bank Limited ............................................................................................ 56

Davis and Handley .................................................................................................... 57

National Economic Research Associates (NERA) ........................................................ 59

Appendix 5 ............................................................................................................................... 60

Summary of code provisions that facilitate regulatory certainty .......................................... 60

Appendix 6 ............................................................................................................................... 64

Glossary .............................................................................................................................. 64

Appendix 7 ............................................................................................................................... 67

Related publications ........................................................................................................... 67

Contacts .................................................................................................................................... 68

1DRAFT Greenfields guideline

The Australian Competition and ConsumerCommission recognises that prospectiveinvestors in new pipelines need to understandhow the regulatory regime will apply to theirinvestment. It has drafted this guidelineshowing the alternatives available under theregulatory frameworks provided by theNational Third Party Access Code for NaturalGas Pipeline Systems (the code) and Part IIIAof the Trade Practices Act 1974 (TPA).

In light of the circumstances faced byprospective service providers when consideringthe construction of a greenfields pipeline, theACCC has prepared this draft guideline to:

# address perceptions of regulatory risk withregard to the application of the regulatoryframework and the ACCC’s approach to theregulation of greenfields projects

# demonstrate the flexibility of the regulatoryframework and the various approachesavailable for the structure of an accessarrangement or access undertaking

# indicate the ACCC’s preferred methods fordealing with project specific risks

# assist prospective service providers toevaluate the likely regulatory outcomes forpotential or proposed greenfields projects.

For the purposes of this guideline, greenfieldsnatural gas transmission pipeline investmentsare considered to be new natural gastransmission pipeline projects, the demand forthe output of which was previously non-existent. These gas projects are generallyacknowledged to face greater uncertaintiesthan established investments.

In preparing this guideline the ACCC consultedwith all sections of the gas industry and soughtthe expert views of consultants. The majorfindings of the consultancies have confirmed:

# the role of foundation contracts inunderpinning new investment, includingsharing the long-term investment risksbetween the pipeliner and users

# debt providers’ information requirements,to assess all the risks associated with aproject. This enables the debt provider toassess the risk profile of the project anddetermine the amount, and cost, of debtthat can be made available to the pipelinedeveloper. Equity providers similarly assessthe risk profile of the project to determinetheir capital contribution, its structure andtheir required rate of return

# that the capital asset pricing model(CAPM) approach to determining theweighted average cost of capital (WACC)is an appropriate framework and specific(i.e. non-systematic) risks associated with agreenfields pipeline should not lead to anadjustment of beta—which reflectssystematic risks only. Any such adjustmentwould be ad hoc and could lead tosignificant biases

# project finance techniques and financialengineering/risk management techniquesare typically used (or are available) toreduce specific risks or pass such risks ontothose willing and able to bear them at leastcost.

The ACCC acknowledges these findings.Accordingly, this guideline seeks to addressthese findings in the context of identifying thevarious risk categories a greenfields pipelineproject is likely to face, and also to provideguidance on how the provisions of the existingregulatory framework can help a prospectiveinvestor address and mitigate relevant risks.These include:

# initial capital base of new pipelines, underthe code, must be based on actual cost

Summary1.

2 DRAFT Greenfields guideline

# the role of foundation contracts and thepreservation of contracts in existencebefore and subsequent to an access regime

# incentives with respect to demandforecasting and linkages with benefit-sharing thresholds. This facilitates pipelinercertainty in that there will be nointra-period re-assessment of forecastswhile retaining the option to unilaterallyseek a review at any time of an accessarrangement in the event that itscircumstances materially change

# derivation of reference tariffs is based onforecast volumes, hence the pipeliner isinsulated from volume risks (with respect tocost recovery) and incentives for buildingspare capacity

# competitive tender processes as a meansfor determining reference tariffs

# benefit sharing mechanisms—which wouldprovide the service provider with certaintyfrom the outset—regarding the nature andeffect of any benefit sharing and at whatpoint it will commence

# term of the regulatory period is notmandated (though subject to regulatoryconsideration)

# CPI-X incentive mechanisms also alleviatea pipeliner’s inflation risk

# depreciation schedules—being themechanism by which pipeline investorsrecover the costs of an investment—can beadopted to best meet the service provider’sobjectives of optimising the use of itspipeline, subject to the requirement that aregulated asset is fully depreciated once,and only once, over its economic life. Forexample, economic depreciationeffectively allows for the carry forward oflosses in the early years of operation

# fixed principles, which provide a means ofestablishing certain aspects (structuralelements) of regulatory certainty acrossaccess arrangement periods.

Background to industry development andregulation

Despite some criticism of the code it is usefulto note that it was designed—with industryinput—to facilitate a fair degree of flexibilityfor service providers in formulating an accessarrangement for regulatory consideration. Thisflexibility provides a range of options forprospective service providers to deal with theunique risks associated with greenfieldsinvestments. Comprehensive examples areincluded in the appendixes to this guidelinethat illustrate how the aforementionedprovisions might be applied in practice by aprospective service provider. It should be notedthat these examples are not intended to beexhaustive and, subject to meeting therequirements of the regulatory framework,project proponents are encouraged to developvariants or alternatives that best meet theirunique circumstances.

A significant level of investment has beenundertaken in gas infrastructure since the gascode was introduced and further investmentsare currently proposed. Since 1995 more than$1 billion has been invested in upstream,transmission and distribution assets each year.Moreover, according to the Australian PipelineIndustry Association, total transmission pipelineinfrastructure has grown from 9000 kilometresin 1989 to over 17 000 kilometres in 2001.1 TheAGA notes that it expects average annualgrowth in demand for gas to be 4.3 per centuntil 2014–15. Gas is currently 17.7 per cent ofthe total energy supplied in Australia. TheAustralian Gas Association (AGA) expects thisto grow to 22 per cent by 2005 and to 28 percent by 2014–15.2

However, despite the substantial investment innew infrastructure in the energy sectors, concernshave been raised about whether the relevantcodes can adequately address the specificneeds of a greenfields investment. Accordingly,the ACCC is conscious of the need to:

# balance the interests of users and investors

# provide incentives for long-term efficientinvestment

1 Australian Pipeline Industry Association, Business Plan2002–2005.

2 Australian Gas Association, Gas IndustryDevelopment Strategy 2000–2015.


# set prices that track efficient costs asclosely as possible.

In making regulatory decisions the ACCC mustestablish an appropriate rate of return. In doingso, balance must be achieved between theneeds of service providers and users. Theperceived short term gains of reducing pricesfor infrastructure services must be balancedwith the ongoing viability of the business andthe industry as a whole. This includes assessingaccess proposals (and not just a rate of return)for a business that will provide the appropriateincentives, and accommodate new efficientinvestment in infrastructure. Only then willlong-term efficiencies arise and benefit theeconomy.

The ACCC’s perception is that the code offers adegree of flexibility that is yet to be fullyrealised by the pipeline industry. The ACCCalso regards access undertakings under Part IIIAas containing a significant level of flexibility.Regulation under Part IIIA may be regarded byservice providers as an alternative to regulationunder the code. The ACCC’s current guide toPart IIIA outlines the provisions andrequirements of the Trade Practices Act.

While prescribing a range of matters that theregulator is required to consider, the gas codealso provides a number of provisions andoptions for prospective regulated greenfieldspipelines that can address any uncertaintyregarding the application of the regulatoryregime. The onus is on the prospective serviceprovider to submit an access arrangement tothe ACCC for assessment that complies withthe objectives of the gas code.

The gas code recognises that to encourageinvestment, a prospective service providershould be given the opportunity to reap someof the returns that exceed the expected levelwhere those returns are attributable to theefforts of the service provider. Often referred toas the ‘blue sky’ potential of the pipeline suchan approach requires regulatory certainty aboutthe treatment of any greater than normalreturns, if realised, in the initial regulatoryperiod/s. The inclusion of an incentivemechanism in an access arrangement (oraccess undertaking) is an important componentof a service provider’s regulatory framework.The ACCC encourages service providers todevelop mechanisms that will best suit theirparticular needs.

Without constraining the intentions of the gascode in this regard, the challenge for regulatorsis to assess access regime proposals to ensurethat they establish fair and reasonableconditions of access for both service providersand users in a manner that preserves theservice provider’s economic incentives to fullyutilise its assets and develop its business. Theaccess regime must also ensure the abuse ofmonopoly power is prevented.

It is intended that this guideline will thereforehelp achieve greater certainty through greatertransparency and resolve some of thereasonable concerns that have been raisedabout the difficulties of developing newpipelines.

Finally, it is important to note that regulation ofgas transmission infrastructure in Australia isnot presumed as a necessary conditionprecedent for the effective functioning anddevelopment of natural gas markets inAustralia. A number of tests must be satisfiedbefore a pipeline, or prospective pipeline, issubject to the requirements of the regulatoryframework. Accordingly, the ACCC is onlyconcerned with the regulation of natural gastransmission pipelines that either meet thecoverage tests under the gas code or aresubject to an access undertaking or declarationunder Part IIIA of the Trade Practices Act.

In Australia the National Competition Councilis responsible for making coverage anddeclaration recommendations.

Nevertheless, some service providers mayperceive benefits in securing certainty aboutthe application of the regulatory framework totheir particular assets at the outset.


Despite the substantial investment in newinfrastructure in the energy sectors, concernshave been raised about whether the regulatoryframework can adequately address the specificneeds of a greenfields investment. The ACCC isconscious of the need to:

# balance the interests of users and investors

# provide incentives for long-term efficientinvestment

# set prices that track efficient costs as closelyas possible.

The ACCC recognises that prospective investorsin new pipelines need to understand how theregulatory regime will apply to theirinvestment. The ACCC has drafted thisguideline to show what alternatives areavailable under the regulatory frameworks ofthe National Third Party Access Code forNatural Gas Pipeline Systems and Part IIIA ofthe Trade Practices Act 1974.

The intention of this guideline is to helpachieve greater certainty through greatertransparency and to resolve some of theconcerns that have been raised about thedifficulties of developing new pipelines.

While each pipeline throughout Australia islikely to face unique and differing levels of risk,greenfields pipeline3 projects are generallyacknowledged to face greater uncertaintiesthan established pipelines. For example, a newpipeline without significant foundationcontracts proposing to supply gas to a new orimmature market, faces greater uncertaintyregarding future demand than a 20-year-oldpipeline that is fully contracted and supplyingto a well established customer base. Thegrowth in future demand for a new pipeline can

Introduction2.

often be dependent upon a number of factors,including other new projects securing fundingand remaining operational (e.g. a fertiliserproduction plant or a gas fired generator) and/or the rate at which users convert from otherfuels to natural gas.

In light of the circumstances faced byprospective service providers when consideringthe construction of a greenfields pipeline, theACCC has produced this guideline to:

# address perceptions of regulatory risk withregard to the application of the regulatoryframework and the ACCC’s approach to theregulation of greenfields projects

# demonstrate the flexibility of the regulatoryframework4 and the various approachesavailable for the structure of an accessarrangement or access undertaking

# indicate the ACCC’s preferred methods fordealing with project-specific risks

# assist prospective service providers toevaluate the likely regulatory outcomes forpotential or proposed greenfields projects.

This guideline outlines the flexibility availableto a prospective service provider whenconsidering the submission of either an accessundertaking or an access arrangement. Thisguideline is not intended to be exhaustive andthe ACCC is receptive to considering alternativemethods, provided that any proposed approachis consistent with the principles of the NationalThird Party Access Code for Natural GasTransmission Pipelines or, in the case of anaccess undertaking, Part IIIA of the TradePractices Act.

3 For the purposes of this guideline, a greenfieldspipeline is generally considered to be a new naturalgas transmission pipeline project, the demand for theoutput of which was previously non-existent.

4 The regulatory framework for natural gastransmission pipelines in Australia is comprised of theNational Third Party Access Code for Natural GasTransmission Pipelines and Part IIIA of the TradePractices Act 1974.


In preparing this guideline the ACCC consultedwith industry, which included hosting aroundtable discussion in November 2001 withrepresentatives from all sections of the gasindustry and regulatory staff. Following theinput received from the roundtable discussionsthe ACCC sought the expert views of:

# Macquarie Bank, on the issues relevant todebt and equity providers5

# Messrs Kevin Davis and John Handley, onthe appropriate cost of capital

# National Economic Research Associates, onthe role of foundation contracts and relatedterms and conditions relevant to greenfieldsnatural gas pipeline projects.

The key findings of these consultancies aresummarised in appendix 5. Copies of theconsultancies are also available at the ACCC’swebsite.6

Prospective service providers are encouragedto consult with the ACCC when developing anaccess proposal. However, it is ultimately theservice provider’s responsibility to design anaccess proposal that best meets its uniqueneeds and circumstances, while complyingwith the principles of the national accessregime. The ACCC can assist prospectiveservice providers with a preliminary non-binding view on a proposed accessarrangement or undertaking; however, for it toprovide a well considered response, a sufficientamount of relevant and useful information willbe necessary. Prospective service providerconsultation with the ACCC is discussed indetail in section 7.

The guideline is structured as follows:

Section 1 Summary

Section 2 Introduction

Section 3 Overview of the regulatoryframework and the bases fordetermining when a prospectivepipeline is likely to be subject toregulation or can be voluntarilysubmitted for a regulatorydetermination.

Section 4 The major risk categories faced bya greenfields pipeline andconsiderations for mitigating thoserisks.

Section 5 The range of risk mitigationoptions available in relation totariff setting, downside risk, therole of foundation contracts andcontractual commitments anddetermination of the regulatoryasset base.

Section 6 Managing uncertainty in relationto demand forecasting andsecuring the potential to reapblue-sky opportunities.

Section 7. Discusses the provision ofinformation and regulatoryconsultation considerations.

Appendix 1 Example of the derivation ofexpected demand and expectedreturn forecasts when facinguncertainty.

Appendix 2 Example of an adjustment to theinitial capital base to reflect actualcosts and the effect/s on referencetariffs.

Appendix 3 Example of determining benefitsharing when demand exceeds apre-set threshold and effect onrevenues, profits and tariffs.

Appendix 4 Summary of the consultanciesundertaken.

Appendix 5 Summary of code provisions thatfacilitate regulatory certainty.

Appendix 6 Glossary.

Appendix 7 Related publications.

5 The ACCC recommends that readers refer to theconsultancy report, including the executivesummary, for a description of the terms of referencefor the report.

6 <http://www.accc.gov.au/gas>


Copies of this draft Greenfields guideline fornatural gas transmission pipelines and relatedconsultancies are available on the ACCC’swebsite at: <http://www.accc.gov.au/gas>.

Following the release of the draft guideline theACCC will hold a public forum at whichinterested parties can raise any issues or makecomments on the guideline. Details of thepublic forum will be well publicised in themajor daily press.

Any comments on the draft guideline should beaddressed to the following email address<[email protected]>.

Alternatively, written comments should beaddressed to:

Ms Kanwaljit KaurGeneral ManagerRegulatory Affairs Division—Gas GroupPO Box 1199DICKSON ACT 2602


Essentially, a prospective service provider hasthree possible alternatives regarding theregulatory environment when considering agreenfields pipeline project:

(i) the pipeline becomes ‘covered’ under theNational Third Party Access Code forNatural Gas Pipeline Systems

(ii) an access undertaking in relation to thepipeline is submitted by the serviceprovider under Part IIIA of the TradePractices Act

(iii) the pipeline is unregulated.

Each of these alternatives is discussed furtherbelow.

A prospective service provider may choose tobe regulated from the outset for a number ofreasons depending on the environment andcircumstances facing the pipeline. Forexample, a service provider may prefercertainty from the outset in relation to theapplication of elements of the regulatoryregime or there may be strong reason to believethat coverage will be sought (and approved) onthe pipeline in question.

3.1Role of the NationalCompetition CouncilPart IIA of the Trade Practices Act sets outs thefunctions of the National Competition Council(NCC).7 The NCC is an independent statutorycouncil that has a function in recommending tothe Federal Treasurer and to the responsibleState and Territory Ministers the declaration ofservices under the essential facilities provisionsof Part IIIA.

3. The regulatoryframework

Part IIIA provides for existing access regimes,such as the code, to be recognised as ‘effective’by the relevant Minister (on recommendationfrom the NCC). As at April 2002 the respectiveaccess regimes established by the code and itssupporting legislation have been certifiedeffective in South Australia, Western Australia,New South Wales, Victoria, the ACT and NT,with a decision pending on an application fromQueensland.

Alternatively, in the absence of an accessregime that has been certified as effective underPart IIIA any person (for example a third partywho may have been unsuccessful in privatelynegotiating access on an unregulated pipeline)may apply to the NCC for a recommendation tothe relevant Minister, that the service be‘declared’.8

Additionally, under the code, the NCC has arole in making recommendations to therelevant Minister whether or not a pipelineshould be ‘covered’.9

3.2Coverage under the codeThe code establishes a national access regimefor natural gas pipelines. It sets out the rightsand obligations of service providers, pipelineusers and access seekers. It includes coveragerules, the operation and content of accessarrangements, ring fencing arrangements,information requirements, dispute resolutionand pricing principles. Under the code theACCC is responsible for the regulation of allcovered transmission pipelines in Australia,with the exception of Western Australia.10

8 ACCC, Access regime—a guide to Part IIIA of theTrade Practices Act, November 1995.

9 Refer code section 1.2.10 The Office of Gas Access Regulation (OffGAR) is the

responsible regulator for transmission and distributionof natural gas pipelines in Western Australia.

7 National Competition Council website can be foundat <http://www.ncc.gov.au>.


Once a pipeline becomes covered it is subjectto the principles set out in the code. There arethree ways in which a greenfields pipeline maybecome covered.

# A service provider or prospective serviceprovider can volunteer that a pipeline besubject to the provisions of the code byproposing an access arrangement to theregulator for approval. Following theregulator’s approval the pipeline is coveredfrom the date that the access arrangementbecomes effective until any specified expirydate (sections 1.20 and 2.3 of the code).

# A pipeline is automatically covered if it issubject to a competitive tendering processapproved by the regulator (section 1.21).

# Any person may make an application to theNCC requesting that a pipeline be covered(section 1.3). The NCC subsequentlyprovides a recommendation to the relevantMinister, who makes a decision on thematter. The criteria for determining whethera pipeline should be covered is set out insection 1.9 of the code.

Before deciding on a regulatory approach, ifany, a prospective service provider has theoption to seek a (non-binding) opinion from theNCC11 on whether a proposed pipeline wouldmeet the criteria for coverage in section 1.9.

Flexibility of the code

The ACCC considers that the code has beendrafted with the clear intention ofaccommodating access arrangements forprospective pipelines. This view is supported bythe findings of National Economic ResearchAssociates (NERA), its analysis is that the codeserves as an effective access regime whichhelps, rather than hinders, the expansion of anintegrated gas pipeline infrastructure inAustralia.12

While prescribing a range of matters that theregulator is required to consider, the codeprovides a number of provisions and options forprospective regulated greenfields pipelines that

can mitigate uncertainty regarding theapplication of the regulatory regime. Theseoptions, and illustrative examples, are set out inmore detail in the following sections.

3.3Submission of a Part IIIAundertakingPart IIIA provides a legal regime to facilitateaccess to the services of certain facilities ofnational significance. Under Part IIIA, serviceproviders can submit access undertakings to theACCC specifying the terms on which accesswill be made available to third parties.

Section 44ZZA of the TPA sets out the mattersthe ACCC must have regard to in decidingwhether to accept an undertaking:

# the legitimate business interests of theprovider

# the public interest

# the interests of potential third party users

# whether there is an existing access regime

# any other matters the ACCC thinksrelevant.

The open ended nature of the criteria gives theprospective service provider considerablescope to design and implement an undertakingaccording to its needs and gives the ACCCflexibility in analysing and assessing theundertaking. At the same time such flexibilitymay create uncertainty about the ACCC’sapproach and could lead to concerns overperceived inconsistencies betweenundertakings. To mitigate these concerns theACCC has a guideline, Access undertakings, forthe submission of an access undertaking.13

The undertakings guideline is structured to helpprospective service providers and otherinterested parties understand what is involvedin having an access undertaking accepted bythe ACCC. It outlines:

11 Refer code section 1.22.12 National Economic Research Associates, Natural

Gas Pipeline Access Regulation—Report for BHP,31 May 2001, p. 2.

13 ACCC, Access undertakings—a guide to Part IIIA ofthe Trade Practices Act, September 1999.


# procedures for assessing and lodging accessundertakings

# the legislative criteria for assessingundertakings and the main factors that theACCC will take into account in applyingthem

# guidelines on what an owner/operator of afacility should include in an undertaking.

While the legislative criteria take precedenceover the ACCC’s published guidelines, theguidelines describe the ACCC’s consideredview on how an access undertaking should beapproached. Accordingly, the ACCC, inensuring careful consideration of the merits ofan undertaking proposal, requires owners/operators to provide sound reasoning andjustification should they wish to depart from theapproach foreshadowed in the guideline.

Prospective service providers considering thesubmission of a Part IIIA undertaking shouldconsult the Access undertakings guideline inconjunction with this guideline whenconsidering the content of an undertaking.

3.4Similarities betweenregimesWhile the code may appear more prescriptivethan Part IIIA, both are essentially based on thesame principles.

Part IIIA was the basis upon which the codewas developed and the intention was that an‘access arrangement would be similar in manyrespects to an undertaking under Part IIIA’14 .Further, the code was specifically designed toaddress access to natural gas pipelines and is amajor component of access regimes that havebeen certified as effective in a number ofjurisdictions.

Given this, it is not unreasonable that theACCC would look to the code for guidancewhen assessing a proposed access undertaking.The ACCC considers that the code reflects

necessary principles that are likely to berelevant to any consideration of an accessundertaking. Therefore, the ACCC recommendsthat prospective service providers provide asound rationale should they seek to depart fromthe principles contained in the code.

The Access undertakings guideline indicatesthat whatever pricing methodology is chosen, itwould require reference tariffs to be ‘based onthe efficient costs of providing referenceservices’ and ‘prices should converge towardsefficient costs over time’. In a similar vein thereference tariff principles given in section 8 ofthe code specify, among other things, that areference tariff policy should be designed to‘improve efficiency and to promote efficientgrowth of the gas market’, ‘replicate theoutcome of a competitive market’ and ‘beefficient in level and structure’.

3.4.1Potential for regulatory overlap

Part IIIA provides for existing access regimes,such as the code, to be recognised as ‘effective’by the relevant Minister (on recommendationfrom the NCC). The services covered byjurisdictional gas access regimes that have beenrecognised as ‘effective’ under s. 44N of theTPA can not subsequently be the subject of adeclaration application to the NCC.

However Part IIIA does not explicitly state thatcertification of an access regime as ‘effective’also excludes the operation of an undertaking.Therefore, technically, there is a possibility ofregulatory overlap arising. That is, a particularpipeline could potentially be the subject of anaccess arrangement and an access undertakingat the same time.

In assessing undertakings the ACCC will establishwhether there is an existing access regime andif so whether an undertaking is necessary.15

Given the similarities between the regimes andadditional costs of implementing two regimessimultaneously, the ACCC would be unwillingto accept an undertaking where an approvedaccess arrangement is already in place unlessthere are strong reasons for doing so.

Conversely, it is possible that an application is

14 National Third Party Access Code for Natural GasPipeline Systems, November 1997, p. 1.

15 ACCC, Access undertakings—a guide to Part IIIA ofthe Trade Practices Act, September 1999, pp. 15, 16.


made to the NCC for coverage of a pipelinethat already has an existing access undertakingin place. In its assessment of the applicationfor coverage of the Eastern Gas Pipeline (EGP),the NCC indicated that the presence of anaccess undertaking should be taken intoconsideration when assessing the potentialbenefits of coverage under the code. At thetime Duke Energy International had lodged adraft undertaking for the EGP with the ACCCfor assessment. As the ACCC had not made adecision regarding the undertaking it wasdifficult for the NCC to place much weight onthe undertaking.16 However, the NCC hasindicated that if an approved accessundertaking is in place, it is unlikely that arecommendation for coverage will be made.

Section 1.9(a) of the code requires the NCC(and decision-maker) to be satisfied thatcompetition would be promoted in a dependentmarket by regulation under the code. This is tobe compared with the likely state ofcompetition without regulation under the code(EGP decision). If the pipeline is regulated byan undertaking, it is unlikely that regulationunder the code would promote competition, socriterion (a) will not be met.

This interpretation of section 1.9(a) of the codeis further supported by a recent decision of thedesignated Minister to accept therecommendation of the NCC and not declarethe rail network services provided by FreightAustralia which were the subject of anapplication for declaration. The basis for thisdecision was that declaration would not havepromoted competition given that access wasalready provided under the Victorian accessregime.17 Accordingly s. 44H(4)(a) of the TPAwas not met. Section 1.9(a) of the code isessentially the same as s. 44H(4)(a).

A prospective service provider may request anopinion from the NCC on whether a proposedpipeline would meet the criteria for coveragein section 1.9.18 Prospective service providersconsidering an access undertaking are alsoencouraged to consult with the ACCC in

advance of lodgment.19

3.5Unregulated pipelinesA prospective service provider also has theoption to elect, on the basis of its owncommercial judgment, with or withoutconsultation with regulatory authorities, tobuild an unregulated greenfields pipeline. Forexample, a prospective service provider may beof the view that the pipeline would be too smallto meet the tests under Part IIIA or the code, orthat the costs of imposing regulation wouldoutweigh the benefits.

It is important to note that a service provider’selection not to provide a voluntary accessregime does not preclude access being soughtby some other party in the future. As notedearlier, under the code any person may at anytime make an application to the NCCrequesting that a pipeline be covered. If, basedon the NCC recommendation, the relevantMinister decides that the pipeline should becovered, the service provider would then berequired to submit an access arrangement forthe pipeline. Therefore, while a prospectiveservice provider may consider regulation of apipeline inappropriate or unnecessary, it ispossible that coverage of the pipeline may besought some time in the future by a third party.

In the absence of an access regime that hasbeen certified as effective under Part IIIA anyperson (for example a third party who may havebeen unsuccessful in privately negotiatingaccess on an unregulated pipeline) may applyto the NCC for a recommendation to therelevant minister, that the service be declared.20

If successful the terms and conditions of accessto a declared service are to be negotiated bythe parties in the first instance, with the ACCCbeing empowered to arbitrate access disputesnotified to it, having regard to the arbitrationcriteria specified in the TPA.21

16 NCC, Final recommendation—Application forcoverage of Eastern Gas Pipeline, p. 17.

17 I Campbell (Parliamentary Secretary to theTreasurer), Statement of decision and reasonsconcerning the application for declaration of railnetwork services provided by Freight Australia,1 February 2002.

18 Refer code section 1.22

19 ACCC, Access undertakings—a guide to Part IIIA ofthe Trade Practices Act, September 1999, p. 64.

20 ACCC, Access regime—a guide to Part IIIA of theTrade Practices Act, November 1995.

21 ibid.


The ACCC acknowledges that prospectivegreenfields pipeline investors may face adifferent risk profile to an incumbent pipelineoperator. Although some risks may notnecessarily be unique to the prospectiveservice provider, the overall level of projectrisk may be greater for a greenfields pipelineproject than it is for an established pipelineserving established customers.

Clearly there is a myriad of individual riskelements that require identification andmanagement in any greenfields pipelineproposal. However, it is recognised that, ingeneral terms, greenfields pipelines face thefollowing broad risk categories during theplanning, construction and operational phasesof a pipeline’s life.

(a) Financing phase e.g.:

# procuring materials that might besourced in foreign currency, notingsuch financial risks may occur ineither, or both, the construction andoperational phases of greenfieldspipeline projects.

(b) Construction and completion phases in thedevelopment of a greenfields pipeline e.g.:

# completion delay because of weatheror other factors, significant cost over/under-runs, timing requirements thatmay necessitate a greenfields pipelinecommitting substantial capital wellahead of final approvals.

(c) Operational phase e.g.:

# unexpected failure and maintenanceresulting from a hostile environmentand loss of transportation tariff revenue.

Risks faced bygreenfieldspipelines

4.

(d) Demand forecasting e.g.:

# the uncertainties associated withforecasting demand volumes, likelymarket growth factors and realisablerevenues etc.

With respect to a proposed pipeline, it isrecognised that the aggregate potential effectsof such project risks need to be considered inany greenfields pipeline evaluation, both forthe purposes of the greenfields pipelineassessment of whether or not to proceed withan investment, and for the purposes ofdetermining reference tariffs. In addressing riskit is important to note the different contexts inwhich the term is used. Namely systematic riskwhich is compensated for in the capital assetpricing model (CAPM) in the regulatoryframework, as compared to the more genericconcept of referring to the possibility of anadverse event.

4.1The treatment of risk inthe regulatory frameworkWhether assessing an access proposal under thecode or Part IIIA, the ACCC is required to makea determination that balances the legitimateinterests of the service provider, existing users,potential third party access seekers and thebroader public interest. The legitimate interestsof the service provider include providing a rateof return that is commensurate with prevailingconditions in the market for funds and with thecommercial risk associated with providing thereference service.

Notwithstanding the development risks agreenfields proponent faces (which areaddressed below), it is well established in thefinance literature that the appropriate measure


of risk for determining the rate of return on aproject (whether greenfields or mature) is thesystematic risk of a project and not its total risk.22

As noted by NERA23 , this approach isconsistent with that adopted by the FederalEnergy Regulatory Commission (FERC) in theUS whereby no additional allowance is madein setting the allowed rate of return for the‘risk’ a pipeline service provider faces inneeding to fill capacity or sign long-termcontracts.

To the extent that it may occur in regulatedtransmission pipelines, ‘asymmetric risk’,which is where either the downside risk or theupside risk dominates; over time resulting in anet cost or a net benefit respectively, can beaddressed in the regulatory framework. Clearlyasymmetric risk does not solely affect eitherservice providers or users but depends on thenature of the risk categories being considered.

Risk can be divided into two categories:systematic (non-diversifiable), and non-systematic (diversifiable) risk. Systematic risksare the market-related risks faced by aninvestor irrespective of the industry. Examplesare the risk of political upheavals andeconomic up-turn or down-turn.

Compensation for systematic risk is madethough the market-risk premium and betafactors found in the Capital Asset PricingModel (CAPM). The CAPM requirescompensation for systematic risk only, as firm-specific risk can be eliminated throughdiversification. The equity beta is a statisticalmeasure that indicates the riskiness of oneasset or project relative to the whole market(usually taken to be the Australian stockmarket). With the market average being equalto one, an equity beta of less than 1 indicatesthat the stock has a low systematic risk relativeto the market as a whole. Conversely, anequity beta of more than one indicates that thestock has a relatively high risk.

Where an equity beta is calculated for aparticular company, it only applies to theparticular capital structure of the firm. A

change in the gearing will change the level offinancial risk borne by the equity holders.Hence the equity beta will change. It ispossible to derive the beta that would apply ifthe firm were financed with 100 per centequity, known as the ‘asset’ or ‘unleveredbeta’. This means companies with differentcapital structures can be compared. Theanalyst can then calculate the equivalentequity beta for any level of gearing desired,known as ‘re-levering’ the asset beta.

Non-systematic risks are specific or unique toan asset or project and may include assetstranding, bad weather and operations risk.Such risks by their nature are specific and needto be assessed separately for each accessarrangement. Importantly, specific risks areindependent of the market. For an investor,exposure to the specific risk related to an assetcan be reduced or countered by holding adiversified portfolio of investments.Consequently, specific risk is not reflected inthe equity beta parameter of the CAPM.

While other asset pricing models involvingadditional risk factors have been developed inthe literature, the CAPM is currently stillconsidered to be the dominant approach adoptedin practice for estimating required rates ofreturn.24 The ACCC considers that the CAPMis an appropriate framework for assessing theWACC (weighted average cost of capital)facing a greenfields natural gas transmissionpipeline. Accordingly the integrity of the CAPMmodel should be maintained, in that it onlyrecognises risks of a systematic or marketrelated nature. The ACCC will only considervariations to the CAPM that are purely of asystematic type. Specific, i.e. non-systematic,risks associated with a greenfields pipelineshould not lead to an adjustment of beta—which reflects systematic risks only. Any suchadjustment would be ad hoc and could lead tosignificant bias.25

A matter of significant debate in the ACCC’sassessment of the Victorian access arrangementwas the treatment of specific (diversifiable)risk. As discussed above, the equity beta ismeant to reflect only market-related or non-diversifiable risks. Consistency with the CAPM

22 K Davis & J Handley, Report on cost of capital forgreenfields investment in pipelines, March 2002.

23 National Economic Research Associates, Regulationof tariffs for gas transportation in a case of ‘competing’pipelines: evaluation of five scenarios, October 2000.

24 K Davis & J Handley, Report on cost of capital forgreenfields investment in pipelines, March 2002.

25 ibid.


framework therefore requires that specific risksbe factored into projected cash flows ratherthan the cost of capital. The ACCC indicated inits Draft Statement of Regulatory Principles thatthis is the approach the ACCC will normallyadopt with respect to identified and quantifiedspecific risks26 and has done so in allsubsequent decisions. This is consistent with theformer Office of the Regulator General’s (nowthe Victorian Essential Services Commission)assessment, as stated in its first consultationpaper for the 2003 review of gas accessarrangements:

… while events that are unique to particularbusinesses do not affect the cost of capital, theyare not irrelevant. Rather, the price controlsshould be designed to ensure that the regulatedentity expects to earn its costs of capital onaverage, taking account of all possible events.27

The ACCC understands that prospective serviceproviders will need to undertake detailedmarket surveys, technical and financialanalysis of a range of matters in the projectevaluation phase of a greenfields pipeline andthat a number of parties involved in such aproject will need to assess such data. Forexample, as noted in Standard and Poor’scriteria for the project financing of pipelines28

an in-depth analysis of the type and nature ofthe contracts in place between a serviceprovider and users is required to be undertakento assess the credit profile of a pipeline.Financiers similarly need to conduct acomprehensive due diligence of the marketsurvey assessments and projections undertakenfor a pipeline financing proposal to assess theoverall risk and viability of the fundingproposition sought.29

Regulatory decision making processes similarlyneed to consider such data. However, in theregulation of gas transmission pipelines theACCC does not conduct traditional rate ofreturn regulation. Rather, it adopts an incentive

regime that encourages the regulated businessto outperform the benchmarked return (asdetermined by the reference tariff for the‘reference service’, forecast costs and forecastdemand) for the regulatory period. This regimeprovides incentive mechanisms by encouragingservice providers to reduce their costs in anygiven regulatory period and maximise theefficient use of the infrastructure. If theprovider realises cost savings in that period,while maintaining a given level of servicestandards, it may be able to retain thosesavings. A service provider can also earnabove benchmark returns by increasing itscustomer usage above forecast demand.

The ACCC’s post tax revenue model30 providesprospective service providers with aninteractive working example that demonstratesthe application of these principles to facilitatecompensation for systematic risks and therelevant operations and maintenance,depreciation and net tax payable costs incurredover the regulatory periods.

4.2Financing phaseConsistent with the benchmarking approachoutlined above and with the objectives of thecode and Part IIIA, the ACCC considers thatwhen legitimate costs are incurred as a resultof, or in an attempt to mitigate, financial riskthen such costs can be appropriatelyrecognised and compensated for in theregulatory regime. Clearly compensation forsuch costs can only apply where they are of anon-systematic nature and are not otherwisecompensated for, eg where such costs are notprovided for as an element of the costs towhich the incentive based benchmarkingapproach applies.

For example, a project might procure materialsfrom overseas and manage its financial riskthrough the use of appropriate hedging orswaps arrangements. If the related costs areattributable to construction related costs thensuch costs could be capitalised and reflected inthe initial capital base (ICB) of the asset.

26 ACCC, Draft Statement of Principles for theRegulation of Transmission Revenues, 27 May 1999,p. 79.

27 Office of the Regulator General, 2003 Review of GasAccess Arrangements, Consultation Paper No. 1,p. 60, May 2001.

28 Standard and Poor’s, Infrastructure finance—Criteriafor project financing of pipelines, 2001.

29 Macquarie Bank Limited, Issues for debt and equityproviders in assessing greenfields gas pipelines,May 2002.

30 ACCC, Post-tax revenue handbook, October 2001.This can be found on the ACCC’s website at<http://www.accc.gov.au/gas/>.


Similarly, for variations in capital costs thatmight occur as a result of changes in theexchange rate, the code provides for the use ofactual cost to value the capital base for newpipelines.

4.3Construction phaseThe ACCC recognises that in the planning andconstruction phases of a greenfields pipelinethere is a range of risk elements common toany construction contract, irrespective ofwhether the construction is related to anunregulated or regulated service.

For greenfields pipelines that are to be subjectto a regulatory regime, the code providesscope for insulating a prospective greenfieldspipeline from construction cost risk, in that costoverruns will be included in the ICB as acomponent of ‘actual capital cost’31 and,subject to the provisions of section 8.9 of thecode, there is no reassessment of actual cost insubsequent regulatory reviews.32

Similarly, Part IIIA requires the ACCC to haveregard to the legitimate business interests ofthe service provider, which includes theongoing viability of services covered by theundertaking and commercial returns oninvestment in the facility.

One of the aims of both Part IIIA and the codeis to promote efficiency. Application of PartIIIA or the code does not provide forcompensation to prospective service providersfor any damages arising from failure, on thepart of the service provider, to meetcontractual obligations to its customers.Therefore, in the event that a delay isattributable to a prospective service providerthis should not create the perverse situationwhereby any resulting costs are ultimatelypassed on to users as a component of thereference tariff(s).

Accordingly, the ACCC does not consider thatit is the intention of Part IIIA or the code to

compensate a prospective service provider forrisks that can be addressed through normalcommercial practice, such as the managementof construction risks via contractual or otherarrangements for gain/pain sharing betweenowners, prime and sub-contractors. For example:

# regarding possible timing overruns, theACCC notes that in fixed price or cost pluscontracts, accepted practices provide forback to back provisions in such contractualarrangements

# alternatively, alliance-contractingprinciples provide a range of options andincentives for all contracting parties to bestmanage project risks.

For example, a prospective service providermight enter into a contractual commitmentwith a prospective user that incorporatedpenalties for failure to deliver gas by a pre-agreed date. Then, in the event of a failure todeliver by that date, it would clearly be anundesirable outcome if the regulatoryframework effectively allowed the serviceprovider to recoup those penalty payments byreflecting them in the capital base. The effectof this would be to ultimately pass those coststhrough to those same users.

Such contractual management arrangements inconstruction contracts are not an explicitcomponent of the regulatory regime and areentirely within the remit of the prospectiveservice provider. Further, a prospective serviceprovider can insulate itself from claims byfoundation customers by providing flexibility infoundation contracts. Where delays are notattributable to the prospective service provider,the ACCC would anticipate that a prudentservice provider would seek to recover anydamages arising under its contractualarrangements.

This approach is consistent with the findings ofDavis and Handley who noted:33

Project finance techniques and financialengineering/risk management techniques aretypically used (or are available) to reducespecific risks or pass such risks onto thosewilling and able to bear them at least cost.Provided that the capital base concept adoptedfor use in regulatory price determination reflectsthe cost of such risk transfer, or that the cash

31 Refer code section 8.12.32 Refer code section 8.14. Note this is subject to the

provisions of section 8.9 with respect to new facilitiesinvestment, recoverable portion, depreciation andredundant capital. 33 Davis & Handley, loc.cit.


flows required to insure/hedge such risks arereflected in operating costs, no furtheradjustment for risk would appear to bewarranted.

The ACCC recognises that time lags areinvolved in construction before cash inflowsare realised. Davis and Handley34 haveadvocated that project viability requires thatthose outlays should be compounded at therequired rate of return in determining the costbase of the project.35 This approach isanalogous to the application of the existingprovisions of the code regarding the treatmentof a speculative investment fund36 (as opposedto a greenfields type project). The ACCCacknowledges this approach and, consistentwith the ACCC’s Draft Statement of Principlesfor the Regulation of Transmission Revenues37,considers that it can be accommodated withinthe scope of section 8.12 of the code.

The approaches outlined above also ensure thefollowing objectives are met:

# maintaining the economic and financialincentives for the prospective serviceprovider to manage construction in themost efficient manner while ensuring theproper recognition of, and compensationfor, those costs prudently incurred

# avoiding the imposition of costs on usersfor risks that can be adequately addressedduring the construction phase and bear nodirect relationship to the cost of service forgas haulage

# ensuring risks that are ordinarily and bestmanaged via contractual arrangementscontinue to be managed in that manner

# ensuring that a prospective greenfieldspipeline does not receive compensation

that would be additional to what it couldreceive in a competitive environment.

The provisions for managing construction costsunder the code are significantly more flexibleand accommodating than in some overseasjurisdictions. For example, in the US the FERC,in its statement of policy, places the financialresponsibility for new greenfields gas pipelinedevelopment on the prospective serviceprovider. Similarly, the risk of construction costoverruns rest with the prospective serviceprovider, unless it is apportioned between itand shippers in their contracts. Additionally,the prospective service provider is leftresponsible for the costs of under-utilisedcapacity and cost overruns.

As part of the FERC’s regulatory applicationprocess, a prospective service provider has tosubmit estimated construction cost data for thepipeline project. The FERC will approvetransportation tariffs for the prospective serviceprovider taking these construction data intoaccount, along with other relevant cost dataand information. Thus, to the extent that theprospective service provider incurs greaterconstruction costs than budgeted for in itssubmission to the FERC, the prospectiveservice provider will not be permitted torecover these additional costs from shippersthrough higher tariffs.

However, the FERC has approved a mechanismthat provides incentive for prospective serviceproviders to remain within the estimated targetcosts of a specific pipeline constructionproject. Under this incentive mechanism thecosts of the expansion are subject to a projectcost containment mechanism (PCCM). ThePCCM establishes a target cost of each newpipeline project. If a prospective serviceprovider manages to carry out the pipelineproject for less than the target cost it will shareits savings with shippers. If the actualconstruction costs are higher than the targetcosts, the prospective service provider has tobear most of these cost overruns.3834 ibid.

35 For example, if a project involves an outlay of $1 atdate 0, has a required rate of return of r, andgenerates no cash flows until date 2, the requiredcash inflow at date 2 is $1(1+r)2 if the project is tohave a zero NPV. If target cash flows at date 2 are tobe determined at date 1, the appropriate capital basefor use at that date is $1(1+r).

36 Refer code section 8.19(b).37 ACCC, Draft Statement of Principles for the

Regulation of Transmission Revenues, 27 May 1999,p. xii.

38 National Economic Research Associates, Foundationcontracts and ‘greenfields’ gas pipelinedevelopments: experience from the United Statesand other jurisdictions—final report, March 2002,p. 14.


4.4Operational phaseGenerally, regardless of whether a pipeline is agreenfields investment or a well-establishedincumbent, it is likely that it faces some formof operational risk. The ACCC understands thatonce established, the operational risk profile ofa greenfields pipeline is unlikely to differmaterially from an established pipeline.Accordingly such risks should be treated in thesame manner as for established pipelines.

Consistent with the benchmarking approachoutlined in the introduction to this section andwith the objectives of the code and Part IIIA,costs prudently incurred that are attributable tospecific risk mitigation can be included in theoperations and maintenance costs of the pipeline.However, this can only apply when such costsare not otherwise compensated for as anelement of the costs to which the incentivebased benchmarking approach applies. Forexample, insurance against the event of someforms of failure (other than force majeureevents) or loss of transportation tariff revenue.

Service providers also have the option ofincorporating a number of other operationalrisk-related mitigation options. For example,economic depreciation effectively allows forthe carry forward of losses in the early years ofoperation and the derivation of reference tariffsis based on forecast volumes, hence thepipeliner is substantially insulated from volumerisks (with respect to cost recovery). Volumerisks associated with demand forecasting arediscussed in more detail in section 4.5. Apipeliner also has the right to unilaterally seeka review at any time of an access arrangementin the event that its circumstances materiallychange.39 CPI–X incentive mechanisms alsoalleviate a pipeliner’s inflation risk.

4.4.1Self-insurance

In common with mature pipelines, greenfieldsprojects face a number of specific risks thatmay impinge on cash flow returns available tothe venture. Because such risks are non-systematic it is inappropriate to try to reflect

such risks in the asset beta established for theregulatory framework. The ACCC maintainsthat such risks should be compensated for inthe cash flow analysis.

As noted above, prudently incurred insurancecosts can be included in the operations andmaintenance costs (O&M) of the pipeline.

The ACCC understands that a service providercontemplating assuming self-insurance riskwould ordinarily conduct a detailed riskanalysis to satisfy debt provider and/orcorporate governance requirements. Suchanalysis is likely to include an assessment ofthe particular risk/s involved, the impact on thebusiness and its cashflow should the eventoccur and the probability of occurrence.

Accordingly, for a regulator to adequatelyassess a proposal for self-insurance, in relationto prudency and validation of an appropriatepremium, it would need to consider suchmatters as: a report from an appropriatelyqualified insurance consultant that verifies thecalculation of risks and correspondinginsurance premiums; confirmation of the boardresolution to self-insure; and the relevant self-insurance details that unequivocally set out thecategories of risk the company has resolved toassume self-insurance for.

A regulated entity’s resolution to self-insurewould also be expected to explicitlyacknowledge the assumed risks of self-insuring.In the event of future expenditure required as aresult of an insurance event40 such costs wouldnot be recoverable under the regulatoryframework as the relevant premiums wouldhave already been compensated for within theoperations and maintenance element of theallowed tariffs and funded by users.41

Therefore, where the risk is self-insurable andassumed by a service provider, one approachfor compensating the service provider would beto adopt a fair actuarially determinedinsurance premium for each specific risk andinclude these as part of O&M forecastexpenditures.

39 Refer code section 2.28.

40 An insurance event refers to an event, which triggersan insurance claim, including a notional claim in thecase of self-insurance.

41 This is also the case for expenditure arising fromconventional insurance claims when users havealready funded the insurance premiums.


The following are key parameters required tomodel self-insured events as part of the cash-flow analysis.

# The realistic estimates of the likelyoccurrence of each type of event. Someprobabilities will depend on the age,operating pressure of the pipeline etc. andthese can be reflected as time or volumedependent probabilities.

# The expected financial impact of theevent, which may be technical or relatedto legal liabilities. Again such costs mustbe realistic, for example the cost cannotcredibly exceed the asset value of thecompany at the time of occurrence.

This is precisely the same information requiredto actuarially determine insurance premiumsfrom a third party perspective but without thetruncation of liabilities or risk abatementstrategies available to the pipeline company.

4.5Demand assessmentThe ACCC recognises that there is inherentuncertainty in determining demand growthforecasts for a greenfields pipeline, especiallywhere immature or undeveloped demandexists. However, the code provides a highdegree of flexibility to facilitate the design of areference tariff policy that meets the specificneeds of each pipeline system.

From a regulatory perspective there are twomain implications arising from uncertaindemand.

# The difficulty associated with determininga best estimate of forecast demand.

# The increase in potential volume risks,relative to that for a pipeline with greatercertainty of demand.

Demand risk faces any new investmentproposal regardless of whether the assets are tobe regulated or not. However, the possibility ofregulation adds another dimension to such risk.Davis and Handley42 note that should access

prices be derived on the basis of applying arequired rate of return to an asset base (at somedate 2), conditional on an assumed level offuture output which is different to thatexpected at the time the investment was made(date 1), then this approach is not necessarilycompatible with providing appropriate signalsfor investment.43 For example in the event thatthe regulatory assessment of expected demandoccurred at a point in time after projectcommitment and after which some aspects ofdemand uncertainty had been resolved, thereference tariffs determined could vary fromthose anticipated on commitment.

The ACCC acknowledges this issue and thepossible difficulties in managing the inherentuncertainty. As indicated in the consultationsections of this guideline, one potential solutionto this problem is to bring forward the regulatorydecision date so that it occurs earlier in theproject appraisal and development orconstruction stage rather than after projectsuccess has been observed, for example,coincident with financial close of a project.

In such circumstances the regulator will thenbe assessing expected demand with the sameinformation set and uncertainty considerationsthat are committed to by the project proponentsand its financiers at financial close.Considerations for assessing forecast gas demandare discussed further below, while downsiderisk mitigation is addressed in section 5.Section 6 deals specifically with the issue thatthe regulatory framework could potentiallycompromise the expectations of returns(especially blue sky) thought possible at thetime of project commitment.

The regulatory provisions that assist inmitigating demand risk are discussed in moredetail in the following sections. Appendix 1also provides an illustrative example of howuncertain demand scenarios can be modelledto derive an expected return. Together theseincentive properties can provide greaterflexibility to a prospective service providerthan, for example, the approval process in theUS. In the US an application for a certificate ofpublic convenience and necessity requires thata prospective service provider applying forsuch a certificate must have conducted an‘open season’ before submitting the application.

43 In this context it is the expected level of demand atthe time the project is committed that determines theexpected return and hence the incentive to invest.

42 Davis & Handley, loc.cit.


The open season essentially consists of‘requests for capacity’ from potential newshippers as well as ‘requests for relinquishmentof capacity’ in expiring transportation contractsfrom existing shippers (if the new capacity isan expansion). In this way an open seasonenables a prospective service provider to assessthe demand for its proposed new or expandedpipeline network. However, the open seasondoes not deal with the issue of transportationtariffs for new pipeline development; itsprinciple purpose is to get an indication ofshippers demand for new capacity.

4.6Use of forecastsThe code recognises the requirement forregulators to rely on forecast data informulating reference tariffs.44 Such forecastsmay need to be determined for:

# capital expenditure

# operations and maintenance expenditure

# demand for volumes over the life of apipeline.

The ACCC is cognisant of forecastingdifficulties and is open to consultation withgreenfields pipeline proponents to discusspossible options that remain consistent with thecode or Part IIIA.

It should be noted that the level of demand riskis dependent upon the extent to whichfoundation contracts underpin a greenfieldsproject’s viability. For example, a new pipelinesupplying gas to a new or immature marketfaces greater uncertainty regarding futuredemand than a pipeline that is fully contractedand supplying a well established market. Thegrowth in future demand for a new pipelinecan often be dependent upon a number offactors, including new projects securingfunding and others remaining operational (e.g.industrial plant or gas fired generation) and/orthe rate at which users convert from some otherfuel source to natural gas.

However, the ACCC notes that for a greenfieldspipeline that is likely to pass the regulatorythreshold tests, the established industrypractice for the purposes of securing debtfinancing requires a minimum commitment ofan appropriate duration from foundation typeusers to determine the underpinning viability ofthe project (for a given level of equitycontribution).

The ACCC considers that the impact of demandrisks on regulatory revenue can be mitigatedthrough careful information analysis and thedesign of the regulatory arrangements. Forexample, a number of probability weighteddemand scenarios could be used to determinean expected demand (ED) forecast. Anappropriate mechanism could then allow anyunder recoveries in the early years of an accessregime to be subsequently recouped whendemand grows.

Forecasts tend to be subject to an inherentelement of subjectivity. Accordingly, the codeprovides for appropriate review mechanisms45

to be triggered if forecasts diverge significantlyfrom realised outcomes. For example, if aservice provider found that discounted tariffswere required to meet its volume forecasts itcould seek a review of its access arrangement.Such mechanisms can be designed to ensurethey will operate in a way that is understood inadvance.

As a preferred alternative, demand scenarioscould be linked to a benefit sharingmechanism (discussed below) so that anaberrant demand scenario is catered for inadvance. The prospective owner would haveadequate scope to capture some of the ‘bluesky’ potential of a project but some of thebenefits would also flow to users. At the sametime, such an approach could limit anyincentive to skew demand scenario forecasts tothe lower end of the spectrum. For example,the best case demand scenario might form thevolume or revenue threshold point from whichbenefit sharing commenced. The benefitsharing mechanism could also be invokedwhen demand is much worse than expected. Inthis case users of the pipeline also bear someof the burden and the financial consequencesfor the pipeline developer are less severe.These options are described in greater detail insection 6.

44 Refer code section 8.2. 45 Refer code sections 3.18, 8.44 and 8.45.


The measures outlined above can give aservice provider ex-ante certainty about howan access regime will apply and the likelyreturns under a range of demand outcomes.Collectively these measures can substantiallymitigate the demand risks associated withregulation of a greenfields pipeline. Inaddition, a service provider has a number ofoptions available to facilitate tariff smoothing/price path approaches which can be used tooptimise demand growth.

The code’s approach to demand risk differsfrom the ‘defined capacity’ approach adoptedby the FERC in regulating gas transmissionpipelines in the US. Under a defined capacityapproach reference tariffs are based on thepipeline’s capacity rather than forecastvolumes. Ceteris paribus, ‘defined capacity’reference tariffs are likely to be lower than ifforecast demand is used, particularly in theinitial stages of the life of a greenfieldspipeline that has been built with excesscapacity in the expectation of future demandgrowth. Compared with the US approach, thecode provisions facilitate the transfer of someof this demand risk away from a prospectiveservice provider to customers.

4.6.1Forecasts, tariffs and incentives forspare capacity

In the US despite prospective service providershaving the option of offering different tariffmethodologies for transportation services asoutlined above, prospective service providerscontinue to offer mostly cost-of-service basedtariffs. Traditional cost-of-service based tariffsin firm transportation contracts generally followthe ‘straight fixed variable’ method (SFV) oftariff design. Under this method tariffs arestructured to enable the prospective serviceprovider to recover its prudently incurred costsand an adequate return on its investments.

Under the SFV method, the tariff for a firmtransportation service is made up of twocomponents, a fixed rate and a variable rate —where the fixed capacity component coversinvestment costs and a variable componentcovers the marginal costs of transporting gas on

a pipeline system.46 The rationale behind theSFV approach is that most of the costs to obtainfirm capacity are fixed, i.e. they are not afunction of the amount of gas transported onthe pipeline. These fixed costs are apportionedamong firm shippers based on the amount ofeach shipper’s reserved capacity on thepipeline.47

However, the SFV approach does not guaranteea prospective service provider will recover thefixed costs from ‘overbuilt’ capacity. It onlyallows a prospective service provider torecover all fixed costs (independent of gasthroughput) for that part of the network that isfully contracted to shippers.

Consequently, if a prospective service providerhas only contracted half of its capacity on anew pipeline development, the prospectiveservice provider bears the full risk (andassociated fixed costs) for the uncontractedpart of the network. The SFV approach appliedby the FERC does not allow the prospectiveservice provider to recover fixed costs fromuncontracted capacity from existing or newshippers. As a consequence, there are limitedincentives on prospective service providers to‘overbuild’ new greenfields gas pipelines in theUS.48

In contrast to the US approach the codeprovides prospective service providers with anumber of options that do not discouragebuilding excess capacity in pipelines. Anillustrative example of how the ACCC couldassess a prospective service provider’s demandforecasts to determine an appropriate referencetariff is provided at appendix 1. As noted abovein relation to construction costs, the actual costof the initial capital base is used as an input toderive a reference tariff based on forecast

46 National Economic Research Associates, Foundationcontracts and ‘greenfields’ gas pipelinedevelopments: experience from the United Statesand other jurisdictions—final report, March 2002,pp. 21, 36.

47 The fixed portion of a firm shipper’s pipeline rate isthus similar to the rent one pays for office orapartment space. The shipper pay a fixed fee to rent‘space’ on a pipeline on a contractual basis,regardless of the degree to which the shipperactually uses the ‘space’ it has contracted for. Thecost of reserving that space is proportional to theamount reserved, and the shipper chooses inadvance how much is needed.

48 National Economic Research Associates, op.cit., p. 22.



volumes. Importantly for service providersthere is also no scope for reassessment of theregulatory asset base at subsequent regulatoryreviews, subject to the provisions of section 8.9of the code.49 For completeness, theappendix 1 example should be reviewed inconjunction with the risk mitigation, blue skyand consultation sections of this guideline(refer sections 5 to 7 below).


This section provides guidance on the scopeand flexibility a prospective service providerhas under Part IIIA and the code that enable itto mitigate various categories of risk. It alsooutlines possible mechanisms prospectiveservice providers might consider incorporatingwhen formulating an access proposal. Whererelevant the ACCC has enunciated its viewabout the scope for interpretation andapplication of the relevant provisions.

As discussed in section 3, the code andPart IIIA of the Trade Practices Act set out anumber of principles and requirements thatguide regulators and establish the bounds totheir discretion. Accordingly the ACCC, as anindependent statutory authority, assesses accessproposals within these established regulatoryframeworks. These bounds therefore providepredictability and certainty about theapplication of the regulatory framework.

However, within the regulatory framework aprospective service provider has a substantialamount of flexibility when formulating anaccess proposal. The onus remains with theprospective service provider to submit anaccess arrangement to the ACCC forassessment that complies with the objectives ofthe code50 or an access undertaking, dependingon the regulatory option sought.

5.1Tariff structures andservice contracts

5.1.1Determination of reference tariffs

In an access arrangement, reference tariffs arederived with the objective that serviceproviders may expect to earn a reasonable rate

Additional riskmitigationconsiderations

5.

of return on their investment. The referencetariff serves as a benchmark price at which aprospective user is entitled to gain access toservices and applies only to the referenceservice as defined in the access arrangement.

Reference tariffs are limited in their applicationto third parties seeking access and the codeexplicitly preserves the right of serviceproviders and users to enter into negotiatedcontractual arrangements. Similarly, tariffs canbe negotiated if the service required by theuser is different to the reference service.

The reference tariff regime can be incentivebased. For example, it may allow serviceproviders to earn potentially higher returns thanthe regulatory rate of return by retaining thebenefits resulting from market growth andefficiency improvements in areas such asoperating and maintenance costs.

In addition the ACCC notes that referencetariffs are derived to ensure service providerscan earn a reasonable rate of return on theirinvestment. There is no restriction on a serviceprovider and user negotiating a price above orbelow the reference tariff, if the servicerequired by the user is different to that providedfor by the reference service.

In the US, despite prospective service providershaving the option of offering different tariffmethodologies for transportation services,prospective service providers continue to offermostly cost-of-service based tariffs.Accordingly, as noted in section 4.5, the FERCcontinues to apply a cost based approach withan SFV as the principal methodology forregulating interstate transportation tariffs.

However, under the capacity based approachfor determining tariffs the prospective serviceprovider in the US framework is potentiallyexposed to greater volume risk than under theforecast volumes based approach in theAustralian regulatory framework for derivingreference tariffs.50 Refer code section 8.1.


5.1.2Contracts in existence before and afteran access arrangement

The regulatory approval process for a greenfieldspipeline access proposal does not affect theability of a prospective service provider tocontract on negotiated terms with users.

The code does not permit the regulator todeprive a person of pre-existing contractualrights. Nor is there any regulatory interventioninto provisions that may be included in anyfoundation contract. The only exception is forcontractual terms relating to exclusivityrights.51 For example, under section 2.25 of thecode, contracts in place before the approval ofan access arrangement are preserved.

Further, under Part IIIA the ACCC is preventedfrom making a determination in an accessdispute that would deprive any person of aprotected contractual right.52

In the case of foundation contracts, the ACCCnotes that market participants that may havesignificant countervailing power and familiaritywith the industry may enter into thesearrangements. Prudent commercial arrangementsfor foundation customers might ordinarilyinclude escalation and/or discount provisions,that may be driven by factors such as realisedgrowth in volumes, and share the risks, costsand benefits in a developing market.

5.1.3Foundation contracts

The role of foundation type customers inAustralia is similar to that observed in the US.Long-term transportation contracts in the USthat involve financial commitments to reservedcapacity by shippers have played afundamental role in the development of the USgas network and continue to drive new gaspipeline development by sharing long terminvestment risks between service providers andshippers.53 At the same time, the regulatoryregime has evolved in tandem with marketconditions, to provide continued support for

efficient gas pipeline development.

The arrangements for new gas pipelinedevelopment in the US have the followingmain characteristics:

# long-term transportation contracts betweenprospective service providers and shippersthat underpin the size, timing and financialrisks of new pipeline investments

# an ‘open season’ process that bringstogether proponents of new pipelines withprospective shippers, before application forcertification by the FERC

# a transparent application and certificationprocess under which the FERC assessesnew pipeline proposals by reference towhether overall benefits outweigh costs

# the integration of the above processes withan evolving framework for FERC-decisionson whether and how pipeline tariffs shouldbe regulated.54

5.1.4Prudent discounts

It is widely accepted that price discriminationamong shippers may increase economicefficiency through increased networkutilisation. This will particularly be the case forpipelines that are significantly under-utilised.Consistent with this the Australian codeexplicitly provides for prudent discounts to beoffered by shippers.55

The US FERC regulatory model also recognisesthat selective discounting can promote theefficient use of a pipeline. In the US contextdiscounting generally refers to the cost-of-servicebased tariffs. The reason is that a discount ontransportation tariffs encourages higher networkutilisation that generally causes a pipeline’sfixed costs per unit of output to decrease.

In the US prospective service providers areprohibited from granting any undue preferenceor advantage with respect to any transportationservice, requiring that tariffs to similarly

51 Refer code section 2.25.52 TPA, section 44W.53 National Economic Research Associates, op.cit.,

section 2.11.2.

54 National Economic Research Associates, op.cit.,section 4.1.1.



situated shippers must not be undulydiscriminatory. To ensure that tariffs are notunduly discriminatory the FERC requiresprospective service providers to make thediscounts available to all ‘similarly situatedshippers’, which are generally defined asshippers that take service over the same part ofthe pipeline and face the same end-marketcircumstances. Prospective service providersmust file specific information to enableshippers to determine if they are similarlysituated to discounted shippers56 and publishdiscounts so non-discounted shippers candetermine if they are entitled to similardiscounts.57 Prospective service providers thatemploy discounted rates must file those rateswith the FERC.

In contrast to the economic efficiencyobjectives underpinning the use of prudentdiscounting, ‘most favoured nation’ (MFN) typeclauses in foundation contracts are optionalprovisions and potentially prevent prospectiveservice providers from offering differenttransportation tariffs among shippers.

NERA has observed that to the extent thatprospective service providers opt to limit theirflexibility to offer discounted tariffs byincorporating MFN clauses in foundationcontracts, then capacity utilisation is likely tobe reduced, the market will develop moreslowly, and the overall efficiency of newpipeline investment is likely to be sub-optimal.58

In the US foundation contracts do not generallycontain MFN clauses. It is not clear whether ornot MFN type clauses have been widelyadopted in Australia. However, it is widelyunderstood that price discrimination on apipeline network generally increases economicefficiency by encouraging increased networkutilisation. The ACCC notes the intent of theprudent discount provisions of the code in thisregard.59

5.1.5Market based tariffs

Industry representatives have proposed the useof market-based tariffs for greenfields pipelinesbut are concerned that they may not be allowedunder the Gas Code. The ACCC understands theterm refers to a proposal to base the referencetariffs that would be available to third partieson the negotiated tariffs at which foundationcustomers contract with a service provider.

The fundamental issue to consider under thisproposal is whether a pipeline should beregulated. Both the code and Part IIIA providetests to determine whether services will beregulated. Clearly, negotiated tariffs apply inthe case of an unregulated pipeline.

The FERC’s January 1996 policy statement onAlternatives to traditional cost-of-serviceratemaking for natural gas pipelines60 onlypermits unregulated tariffs subject tosatisfaction of tests that are required todemonstrate a lack of market power for anatural gas pipeline. In summary, the pipelinewould have to either:

# demonstrate that it lacks significant marketpower because users have sufficient goodalternatives

# meet specific conditions to prevent theexercise of any market power it may have.

Regulation of gas transmission pipelines inAustralia is only applied when naturalmonopoly characteristics exist and the serviceprovider is capable of exerting some degree ofmarket power.61 To the extent that the serviceprovider can exert market power, negotiatedtariffs would be unlikely to reflect those thatwould apply in a competitive market. This isconsistent with the Brattle Group’s observationthat there is no evidence that negotiatedaccess regimes have produced any of thepositive benefits, such as superior innovation offlexibility, that are sometimes cited in favourof negotiated access.62

56 Tennessee Gas Pipeline Co., 77 FERC ¶61,877(1996).

57 Order No. 566, FERC Stats. and Regs., RegulationsPreambles 1991–1996 ¶30,997 (1994).

58 ibid.59 Refer code section 8.43.

60 FERC, Alternatives to traditional cost-of-serviceratemaking for natural gas pipelines (Docket No.RM95-6-000), 31 January 1996.

61 In Australia the National Competition Council (NCC)assesses market power.

62 The Brattle Group, Third-party access to natural gasnetworks in the EU, March 2001, p. 2.Copies of this report are publicly available on thewebsite of the European Federation of Energy Tradersat <http://www.efet.org>.


When regulating pipeline services, the ACCCis required to comply with the code provisionsor Part IIIA requirements which include havingregard to the cost reflectiveness of access pricingproposals and providing the service providerwith the opportunity to earn a reasonable returnon its investment. In the case of the code, areference tariff operates as a benchmark tarifffor a specified reference service while meetingthe code objectives.63 Accordingly, in principlea negotiated tariff would only be expected to begreater than a reference tariff to the extent thatthe service provider can exert market power.

The ACCC is only concerned with the regulationof natural gas transmission pipelines that eithermeet the coverage tests under the Gas Code64

or are subject to an access undertaking ordeclaration65 under Part IIIA of the TPA.

# Under either regime, access prices aredesigned to provide a reasonable return tothe service provider. In this regard theregulatory framework affords considerablecertainty to prospective service providers.

# Where a negotiated tariff exceeds areference tariff it would appear that thenegotiated tariff would be providing thepipeline owner with a greater than normalreturn.

5.2Determining the initialcapital base for agreenfields pipelineSection 8.12 of the code provides for the initialcapital base (ICB) of a new pipeline to beincluded at the actual capital cost of the assetsat the time they first enter service.66 And thereis no scope for reassessment of actual cost insubsequent regulatory reviews.67 This contrastswith the treatment of existing pipelines where

the regulator must consider valuations based onmethodologies such as depreciated actual costand depreciated optimised replacement cost.Part IIIA does not provide this degree ofprescription and certainty to greenfieldsinvestors. However, the ACCC is likely tovalue the ICB at actual cost unless there isstrong reason to do otherwise.

The ACCC is aware that the costs of agreenfields pipeline may not be known withprecision until some time after operationscommence and that initial reference tariffswould need to be determined based on forecastcapital and non-capital costs.

The ACCC considers that a forecast ICB couldbe used when determining the initial referencetariff in conjunction with an appropriatemechanism to adjust the tariff when the actualcapital cost is known with certainty.

5.2.1Adjustment mechanisms

The ACCC considers that section 8.12 of thecode provides sufficient flexibility to allow theinclusion of a symmetric adjustment mechanismto accommodate any material variancebetween the forecast and final cost of the ICB.

Incorporating an appropriate adjustmentmechanism would:

# alleviate any downside risk to the serviceprovider in the event that the final cost ofthe ICB was greater than forecast

# pass through benefits to users in the eventthat final cost was lower than forecast.

An appropriate adjustment mechanism wouldbe expected to: mitigate under or overrecovery; avoid potential discontinuities in thereference tariff price path to avoid volatility intariffs; and provide certainty for users.

While the design of the adjustment mechanismwould largely depend on the service provider,the ACCC expects that both the timing anddollar cost effects could be parameterised andclearly expressed from the date ofcommencement of the access arrangement.Prospective users could then contract forcapacity at the reference tariff (with ex-ante

63 Refer code section 8.1.64 As determined by the NCC.65 As determined by the NCC.66 Refer code section 8.12.67 Refer code section 8.14. Note this is subject to the

provisions of section 8.9 with respect to new facilitiesinvestment, recoverable portion, depreciation andredundant capital.


certainty as to the methodology for calculatingany variance in tariffs once the actual ICB isknown). As noted above, parties also retain theright to negotiate for access.

A range of appropriate adjustment mechanismsis possible. The optimal approach from theservice provider’s perspective is likely todepend on the weight it attaches to stability inreference tariffs as compared to the speed ofcost recovery, noting that either approachwould be equivalent in net present value (NPV)terms.

An illustrative approach to adjustmentmechanisms is outlined at appendix 2.

5.3Downside risk mitigationSection 2.28 of the code provides that theservice provider may seek revisions to itsaccess arrangement at any time. In contrast theACCC cannot initiate an early review.68 Similarprovisions apply to an access undertakingunder Part IIIA. That is, a service provider maywithdraw or vary an access undertaking at anytime, but only with the consent of the ACCC.69

These provisions afford protection to aprospective service provider in the event thatunforeseen factors affect it and constrain itsability to earn a reasonable return.

Thus, service provider initiated, unscheduledrevisions to an access arrangement can assist aservice provider who finds unforeseen factorssignificantly impinging on its ability to earn areasonable return. Further, where demand isexpected to grow gradually over time, adepreciation profile may be chosen that allowsthe opportunity for expected early underrecoveries to be recouped in later years. This isdiscussed in further detail in section 6.5 of thisguide.

68 Specific major events may require a service providerto submit revisions under the code. Refer codesection 3.17(ii).

69 TPA, s. 44ZZA(7).


A criticism levelled at regulators byprospective investors is that perceptions ofregulatory risk in a regulated industry act as adisincentive to investment. These perceptionsare on the assumption that a regulated entity’sdownside risk is not capped whereas its ‘bluesky’ opportunities are, including the potentialfor regulators to claw back or otherwise limitthe blue sky potential of a new investment atthe next regulatory review.

These views fail to recognise the provisions ofthe code that mitigate both of these risks whileensuring compliance with the code’s objectivesof earning a reasonable return to serviceproviders and benefit sharing with users. Theseare outlined further below. Prospective serviceproviders are encouraged to discuss suchoptions with the ACCC when formulatingaccess arrangements for regulatory approval.

It is also instructive to note that in its paper onnatural gas pipeline access regulation70 , NERAfound the code to be a sound piece ofregulatory legislation and demonstrated thatappropriate access regulation will not deterinvestment in gas pipeline infrastructure. Onthe contrary, NERA found that sound regulatoryregimes contain numerous provisions thatpromote rather than discourage gas pipelineinvestment, and appropriate regulatory regimesprovide risk-averse investors with the certaintythey require for their investments. In a surveyof declared post tax regulatory rates of returnacross various jurisdictions in the UnitedKingdom and North America it was found thatAustralian regulators were providing highervanilla post-tax weighted average costs ofcapital than in the other jurisdictionsexamined.71 Similarly the Brattle Group notedin its comparative analysis of tariffs in the

Managing uncertaintyand blue skyopportunities

6.

European Union that where prices weretransparently linked to underlying costs theywere generally substantially lower than thosethat were not.72

The code recognises that to encourageinvestment, a prospective service providershould be given the opportunity to reap someof the blue sky potential of the pipeline, whereprospective blue sky profits are needed tooffset prospective losses from a dismal (blacksky) outcome. Further, the investor needsregulatory certainty on the treatment ofabnormal (extreme scenarios both optimisticand pessimistic) returns during the initialforecast time horizon and certainly during theinitial regulatory period/s. The inclusion of anincentive mechanism in an accessarrangement73 (or access undertaking) is animportant component of a service provider’sregulatory framework. The ACCC encouragesservice providers to develop mechanisms thatwill best suit their particular needs.

Without constraining the intentions of the codein this regard, the challenge for regulators is toassess access regime proposals that establish aframework which ensures the service provider’seconomic incentives to maximise utilisation ofits assets and development of its business whilenot imposing unreasonable cost transfers to users.

A number of options are available toprospective service providers when formulatingan access proposal that can provide certaintyin the context of both blue sky and black skyscenarios. These include the term of the accessarrangement/undertaking period; benefitsharing mechanisms; fixed principles,downside risk mitigation review triggers;

70 Natural gas pipeline access regulation—Report forBHP, 31 May 2001

71 National Economic Research Associates,International comparison of utilities’ regulated posttax rates of return, March 2001.

72 The Brattle Group, Third-party access to natural gasnetworks in the EU, March 2001, p. 24.Copies of this report are publicly available on thewebsite of the European Federation of Energy Tradersat <http://www.efet.org>.



depreciation schedules and any combinationsthereof. Each of these is discussed below.

Additionally the ACCC is receptive to otherproposals from prospective service providers tomitigate the risk profile of a greenfieldspipeline, provided it is consistent with theobjectives of the code or Part IIIA, dependingon the access regime sought.

6.1Demand forecastingThe ACCC acknowledges the inherentuncertainty a prospective service provider islikely to face in forecasting demand volumesand growth profiles, beyond its contractedfoundation customer base, in immature orundeveloped markets.

The ACCC understands, irrespective of whethera greenfields pipeline is to be regulated or not,that during the investment analysis phase for aprospective greenfields pipeline the proponentsconduct substantial market analysis. Thisdetailed analysis to determine the projectslikely demand and growth potential, and tosecure the levels of commitment necessaryfrom foundation customers to ensure theeconomic viability of the project, is understoodto be an essential precursor to securing thenecessary board and financing approvals.74

As noted above, demand forecasts will be afunction of the underpinning foundation typecontracts including contracted or plannedexpansion in foundation customer demand, andmarket analysis of likely demand from thirdparty users and rate of growth in that demand.Accordingly the ACCC considers that anexpected demand forecast can be modelled toaccount for the inherent uncertainty for thepurposes of deriving a reference tariff. Demandrisks could then be mitigated through theanalysis of a number of probability weighteddemand scenarios to provide a known revenueprofile to the prospective investor for eachdemand scenario proposed.

While there is an inherent element of judgmentassociated with forecasts, the code provides for

appropriate review mechanisms75 in the eventthat forecasts diverge significantly fromrealised outcomes. For example, mechanismsare available to ensure that under recoveries inthe early years of an access regime can becompensated for in the regulatory framework.

The ACCC notes that the use of such aframework may increase the incentive forprospective service providers to ‘game’ itsexpected demand forecasts. For example, aprospective service provider could have theincentive to skew, or weight, forecast demandprobabilities in favour of less optimisticoutcomes (while still maintaining an NPV notless than zero), thus leading to a lowerexpected demand and a higher reference tariff.

However, if this approach was adopted, itcould potentially result in an adverse outcomefor the service provider such as negativeimplications for longer term marketdevelopment (regarding price signalling) andthe lowering of a benefit sharing thresholdpoint (see 6.2 below). The formal approvalprocess of an access proposal also requirespublic consultation that would provide anopportunity for interested parties to commenton the proposed demand forecasts.

Accordingly, an effective framework needs toestablish an agreed basis that providescertainty at the outset and incentives for aprospective service provider to maximise theuse of its reference service and earn a greaterthan normal return up to a pre-determined pointand for a known period. The ACCC considersthat the inclusion in an access proposal of athreshold point from which benefit sharingshould occur, is an appropriate mechanism.76

6.2Benefit sharingmechanismsThere is a range of benefit sharing mechanismsthat a prospective service provider couldconsider when formulating an access proposal.A benefit sharing mechanism would involve

74 Macquarie Bank Limited, Issues for debt and equityproviders in assessing greenfields gas pipelines, May2002.

75 Refer code section 3.18.76 In the case of an access arrangement the threshold

would need to be formulated in accordance withreview mechanisms set out in section 3.18 of the code.


the inclusion of a methodology for the sharingof greater than expected revenues between theservice provider and users, and may alsoidentify an event that will invoke the benefitsharing provisions. The inclusion of such aclause in the access arrangement orundertaking would provide the service providerwith certainty from the outset, regarding thenature and effect of any benefit sharing and atwhat point it will commence. Possiblemechanisms could be based on:

# demand focused capacity/volume thresholds

# revenue based

# profit based

# a combination of the above.

Expected demand, revenue and profit scenarioscan be linked to any benefit sharing mechanismsthat may be required. This would ensure theappropriate incentive to capture some of theblue sky potential of a project and alleviate thepotential incentive to skew demand scenarioforecasts to the lower end of the spectrum.

It should be noted that the inclusion of abenefit sharing mechanism does not involve orrepresent a review of the access proposalbefore the expiration of the agreed regulatoryperiod, in any way. Rather, benefit sharingwould only commence once a threshold pointhas been reached and would follow themethodology previously agreed upon and setout in the approved access proposal.

The ACCC also notes that the benefit sharingmechanism would only come into operationafter the prospective service provider has beenadequately rewarded for undertaking theinvestment, and the service provider would stillcontinue to receive a financial benefit fromany further growth in demand.

An illustrative example of one possible form ofa potential benefit sharing mechanism to applyonce the threshold has been reached isprovided at appendix 3. This example is basedon a demand focused volume threshold. Notethat in this example any further increase indemand beyond the threshold continues to berevenue and profit cumulative to the serviceprovider, albeit at a reduced rate. The benefitsharing mechanism would only be initiatedonce a pre-determined volume threshold had

been reached. As outlined above the ACCCenvisages that such a threshold would be setsuch that the prospective service providerwould realise and retain the blue sky benefits itidentified as potentially realisable in derivingits expected demand, before the benefitsharing provisions took effect.

It should also be noted that the sharingmechanism proposed at appendix 3 issymmetric in that the costs to the pipelinedeveloper of abnormally low demand isdiminished with potential users of the pipelinesharing those costs in higher future tariffs.

6.3Preservation of blue skyprofitsA major concern of the pipeline industry seemsto be that the regulatory framework will operatein a non symmetric fashion so that at the firstreview of an access arrangement the regulatorwill observe the current demand levels thenrevise reference tariffs on the basis of thesemore certain demand forecasts. When thesenew forecasts are higher than the average ofthe forecasts proposed initially this implies areduction in tariffs relative to what would havebeen reasonably expected at the time ofcommitment to the pipeline proposal. Theasymmetry emerges from the fact that if demandturns out to be worse than expected thenraising tariffs to restore the required return maynot be possible with weak levels of demand.

This is illustrated in figure 6.1 below. Therevenues shown in this figure are based on therevenue sharing example in appendix 3. Thethree upward sloping revenue lines are therevenues expected under the three scenariosfrom tariffs set at the commitment stage of thepipeline project. Of course each of theserevenue streams gives rise to a differentachieved return to capital as was expected exante. These ex ante returns are recorded in thefirst column of table 6.1.

However, if the first regulatory review for theperiod commencing period 6 was based ondemand observed at that time, then the tariffsnecessary to maintain the required rate ofreturn into the future would be different to


those based on the average of the threepotential scenarios considered possible at thetime of project commitment.

It is clear that both scenarios two and threecould sustain the required WACC from period 6with a lower tariff than determined initially. Ifthis was the basis for setting tariffs for period 6onwards the revenue stream expected inscenarios two and three would be that given bythe dark horizontal line shown in figure 6.1,capping revenues at $75 million.

Of course, if this was the expected regulatorytreatment, using the ex post observation of actualdemand, then the expected returns would beless than those at the outset without a regulatoryreset and there would be an inadequate returnto justify the investment. The lower returns areshown as column two in table 6.1. The averageover the three scenarios is 7.6 per cent, belowthe required WACC of 8 per cent.

The purpose of this section is to confirm thatthis is not the proposed regulatory frameworkthat the ACCC would apply to greenfieldsinvestments. Instead, subject to the length ofthe initial regulatory period and the relevantforecast interval, a regulatory reset need not bebased on observed demand at a periodicreview. In such reviews the forecastprobabilistic scenarios would be maintained forthe timeframe over which they were made.Beyond that point it would be expected thatmarket demand would have stabilised at alevel which would make the application of thestandard approach to regulation for maturepipelines more appropriate.

An obvious concern is whether this approach isinvalidated when demand forecast scenariosare proven to be incorrect. This may be a resultof dramatically higher or lower outcomes. Theanswer to this question must be no. That is whythe introduction of the benefit sharingmechanism is important. It does not correct foran invalid set of forecast scenarios but it doesmoderate the impact towards the regulatoryoutcome that would have emerged had a betterset of forecasts been made.

The impact of revenue sharing is shown in thethird column in table 6.1. The returnsachievable in the upper (scenario 3) and lower(scenario 1) demand scenarios are modifiedslightly, but the expected return on capital isnot compromised and remains at 8.0 per cent.

Appendix 3 gives further examples of whathappens with revenue sharing when outcomesare much higher/lower than forecast.

The key reason why the forecasts cannot berevisited even when proven incorrect is that itis impossible to come up with a completelyaccurate set of ex ante forecasts at projectcommitment. Although the robustness of the exante forecasts is likely to be related to theproportion of foundation customers, theirveracity can only be assessed once actualdemand levels have been observed.

Under the gas code the regulator cannotinitiate a review of an access arrangementwhen circumstances are observed to changeexcept at a review.77 The important point hereis that the regulator will not take account ofupdated demand forecasts even at the time ofa scheduled review occurring in the forecasttime horizon.

In contrast to the options available to theregulator, the service provider may seek areview on the basis of changed circumstances.However, an important corollary of theapproach outlined here is that a shortfall indemand expectations cannot be used as thebasis for raising reference tariffs. Instead, therevenue sharing mechanism also provides thedownside protection likely to be sought by theservice provider. As noted in appendix 3, theprotection is unlikely to come in the form ofhigher immediate tariffs (which would have theeffect of reducing demand further) rathercapitalisation of financial losses is thepreferred mechanism. This enables a moresatisfactory return to be achieved even in ablack sky scenario but over a longertimeframe. Of course, not all financial loss canbe compensated for in a sharing mechanism.The amount will depend on the level of sharingestablished as part of the sharing mechanism.A higher level of sharing provides greaterprotection but also shares more of the blue skyprofits with customers.

77 Specific major events may require a service providerto submit revisions under the code. Refer codesection 3.17(ii).


Figure 6.1 Revenue expected from three different 10 year demand scenarios proposed with andwithout reassessment of demand expectations at first review for the periodcommencing in period 6.

Table 6.1 Estimates of achievable return (WACC) on capital in different scenarios (%) over10 years

Scenario Ex ante1 Ex post2 Sharing3

Low (scen. 1) 7.0 7.0 7.2

Middle (scen. 2) 8.0 7.7 8.0

High (scen. 3) 9.0 8.0 8.8

Average 8.0 7.6 8.0

6.4Duration of an accessarrangementThe code allows the regulator to consider anaccess arrangement period of any length.However, when the access arrangement periodis greater than five years the code requires theregulator to consider whether mechanismsshould be included in case the risk of forecastson which the terms of an access arrangementswere based and approved were incorrect.78

The ACCC’s final decision for the Central WestPipeline (CWP)79 provided for an access

arrangement period of approximately 10 years.The extended period was to provide the serviceprovider with an additional incentive todevelop the natural gas market in the centralwest and (potentially) central ranges.

By allowing for a longer access arrangementperiod, and in conjunction with any benefitsharing mechanism as outlined above, theservice provider is able to retain for a longerperiod any higher returns it earns fromoutperforming its forecasts. In effect, thebusiness has the potential to earn, and retainfor an extended period, a rate of return higherthan the benchmark set by the ACCC. TheACCC considers that a longer period provides agreater incentive to the service provider toimprove its performance and build its marketsand the opportunity to reap more of theproject’s blue sky potential. Under the code, inthe event that expected returns are not realised

78 Refer code section 3.18.79 ACCC, Access arrangement by AGL Pipelines (NSW)

Pty Ltd for the Central West Pipeline final decision,30 June 2000.

Notes: 1. Ex ante no recontracting.

2. Ex post if recontracting occurred for years 6 to 10.

3. Sharing with no recontracting.


service providers are also able to seek a reviewat any time.80

With regard to Part IIIA, while an accessundertaking must specify an expiry date, nomaximum or minimum term is specified.81

Therefore, as with the code, the term of anaccess undertaking is flexible.

6.5Fixed principlesThe service provider can also seek to ensurecertainty for the application of structuralelements of the access arrangement byincorporating fixed principles in its referencetariff policy.82 Fixed principles may includeany structural element. A fixed principle maynot be changed without the agreement of theservice provider for a specified period, thefixed period. However, in determining thefixed period regard must be given to theinterests of the service provider, users andprospective users.

Sections 8.47 and 8.48 of the code deal withfixed principles. They provide a means ofestablishing certain aspects (structuralelements) of regulatory certainty across accessarrangement periods. In this way a pipelinecompany seeking certain provisions to besustained over a long term can do so withoutnecessarily having to propose a very longaccess arrangement duration. Structuralelements specifically include:

# the depreciation schedule

# the financing structure

# that part of the rate of return that exceedsthe return that could be earned on an assetthat does not bear any market risk.

These provisions can give investors long-termregulatory certainty over how their investmentwill be treated. The provisions clarifyparameters over which the regulator mightotherwise seek to exercise discretion andwhich could leave investors unclear aboutfuture regulatory changes.

6.6DepreciationUnder the code a depreciation schedule shouldreflect the following principles:83

# the change in reference tariffs over time isconsistent with the efficient growth of themarket for the services provided

# depreciation occurs over the economic lifeof the asset(s) with progressive adjustmentswhere appropriate to reflect changes inexpected economic lives

# an asset is depreciated only once and thattotal accumulated depreciation will notexceed the valuation of the asset wheninitially incorporated in the capital base.

Standard straight-line depreciation over theeconomic life of the asset has typically beenthe methodology used when depreciating apipeline’s capital base. However, provided thatthe principles of the code are adhered to, aservice provider is able to use an alternativeapproach.

For example, the ACCC’s CWP final decisionprovided for the use of economic depreciationas part of the service provider’s NPV/price pathmethodology to determine total revenue.Economic depreciation was calculated in thefollowing manner:

Economic depreciation = total revenue –operating costs – return on capital

The ACCC approved, with qualifications84 , theservice provider’s proposed economicdepreciation approach in recognition of thebeneficial effect it would have in allowing theservice provider to recoup under-recoveriesaccrued in the early period of the life of theCWP. This approach also provided lower tariffsduring the initial phase of the life of the CWP,enabling greater opportunities for marketdevelopment. This approach to depreciationwas considered consistent with the codeobjective that the service provider should havethe opportunity to earn a stream of revenue

80 Code section 2.28.81 TPA, s. 44ZZA.82 Refer code section 8.47.

83 Refer code section 8.33.84 ACCC, Access arrangement by AGL Pipelines (NSW)

Pty Ltd for the Central West Pipeline final decision,30 June 2000, pp. 68–72.


that recovers the efficient costs of deliveringthe reference services over the expected life ofthe assets.85 This approach is particularlyhelpful for new pipeline developments wherefull cost recovery would imply high initialtariffs and consequently poor take-up ofavailable capacity. The approach means thatthe company can charge lower tariffs initiallyand encourage gas usage without incurring anon-recoverable financial loss.

Part IIIA does not specify any particulardepreciation methodologies. Consequently aprospective service provider has equalflexibility in tailoring an appropriatedepreciation methodology to meet itsrequirements.

6.7Post-tax revenuehandbookThe ACCC released the Post-tax revenuehandbook and related model (PTRM)86 inOctober 2001. The handbook presents asimplified model that provides interestedparties with an overview of the post-taxrevenue model as applied by the ACCC in itsregulation of various Australian utilities.

Prospective service providers can apply theconcepts outlined in this document andexamples to determine the necessary inputs forthe PTRM and thus derive indicativeunadjusted and smoothed reference tariffs.Subject to the robustness of input data, theoutputs derived in this manner will beindicative of the ACCC’s approach to assessinga prospective service provider’s accessproposal.

The PTRM also includes a normalisationmodule and an example of the normalisationapproach that can be adopted to avoid revenueor price volatility in the face of rapid changesin a service provider’s tax liabilities byadjusting depreciation to offset tax costs in anNPV neutral manner.

85 Refer code section 8.1(a).86 Electronic copies of the handbook and model can be

found on the ACCC’s website under<http://www.accc.gov.au/gas>


The ACCC notes that there are significantsimilarities between the processes that it mustfollow when assessing access arrangementsand access undertakings. Both require it toundertake a public consultation process and, asnoted earlier, the ACCC will consider similarframeworks in assessing any application.

7.1Consultation beforesubmitting an undertakingor access arrangementAs discussed throughout this guideline, aprospective service provider has a number ofoptions available when formulating an accessarrangement or undertaking that best addressesthe requirements and risks of its particularpipeline project. The ACCC welcomes openand constructive discussions with prospectiveservice providers to facilitate the developmentof an appropriate regulatory approach thatrecognises the particular circumstances of aproposed greenfields pipeline project. TheACCC has developed this guideline to provideusers with certainty of regulatory outcomes.

To provide a preliminary non-binding view onreference tariffs to a prospective serviceprovider, the ACCC will require sufficientinformation to complete its assessment. Whilethe prospective service provider would not bebound to provide the information discussed inthe next section, the ACCC would consider thisa good indication of the information necessaryto provide a considered and informedassessment of likely reference tariffs.Notwithstanding issues raised during publicconsultation, the accuracy of the ACCC’spreliminary views are very much dependentupon the amount and relevance of theinformation provided.

Consultationand provisionof information

7.

The ACCC would consider the process ofproviding a preliminary view as confidential innature and any information provided by theprospective service provider, including theoutcome of the assessment, would be treatedas commercial in confidence.

In the event that a formal application is madethe ACCC is then bound by the consultationprovisions of the code or Part IIIA, dependingon the nature of the regulatory regime sought,and service providers are required to provideall relevant information.

Where possible the ACCC aims to preserve theconfidentiality of commercially sensitiveinformation during the formal consideration ofan access regime proposal. Prospective serviceproviders are referred to sections 7.11 to 7.14of the code and page 70 of the Accessundertakings guideline for the position onpreserving confidential information for accessarrangements and undertakings respectively.

7.2Provision of informationUnder the code, a service provider is normallyrequired to submit access arrangementinformation in conjunction with its proposedaccess arrangement. Section 2.7 of the codestates that the access arrangement informationmay include any relevant information but mustinclude at least the categories of informationdescribed in attachment A to the code (asummary of which is shown in Box 7.1).

The access arrangement information mustcontain sufficient information to enable usersand prospective users to understand thederivation of the elements in the proposedaccess arrangement and to form an opinion asto the compliance of the access arrangementwith the provisions of the code.87



Box 7.1. Summary of attachment A information

The information required is divided into six categories:

Category 1: access and pricing principles

Tariff determination methodology; cost allocation approach; and incentive structures.

Category 2: capital costs

Asset values and valuation methodology; depreciation and asset life; committed capital worksand planned capital investment (including justification for); rates of return on equity and debt;and debt/equity ratio assumed.

Category 3: operations and maintenance costs

Fixed versus variable costs; cost of services by others; cost allocations, for example, betweenpricing zones, and cost categories.

Category 4: overheads and marketing costs

Costs at corporate level; allocation of costs between regulated and unregulated segments; costallocations between pricing zones, services or categories of asset.

Category 5: system capacity and volume assumptions

Description of system capabilities; map of piping system; average and peak demand; existingand expected future volumes; system load profiles and customer numbers.

Category 6: key performance indicators

Indicators used to justify ‘reasonably incurred’ costs.

In the case of an access undertaking, Part IIIAdoes not prescribe the information that shouldbe provided in an access undertaking.However, the ACCC’s Access undertakingsguideline does provide a broad list ofinformation that could be included in anyproposal for any access undertaking.88 Asdiscussed earlier, the two regimes are verysimilar and it is likely that the same type ofinformation would be necessary to assess theapplication under either access regime.Therefore, prospective service providerssubmitting an access undertaking should alsobe guided by the information set out inattachment A of the code.

As noted in section 5.2, actual capital costswill be used to value the initial capital base fora greenfields pipeline once it is completed.However, in the case of a pipeline yet to beconstructed or still under construction, the

actual capital costs of the pipeline are not yetknown. In the case of future capitalexpenditure and operating and maintenancecosts, both new and established pipelines arerequired to provide forecast values. Whilethese costs may not be as easily ascertained fora new or proposed pipeline, it is highly likelythat they will fall within a fairly limited range.89

7.3Public consultation andassessment proceduresThe public consultation and assessmentprocedures are essentially the same for both anaccess undertaking and an accessarrangement. A service provider submitting anundertaking can vary or withdraw it at any

88 See ACCC, Access undertakings—a guide to Part IIIAof the Trade Practices Act, September 1999, p. 65. 89 Refer appendix 2.


time subject to the ACCC’s consent. However,under the code, only a service provider who hassubmitted a voluntary access arrangement90

(that is, a pipeline that has not been deemedcovered) can withdraw its access arrangementbefore approval. Although service providerssubject to an access arrangement under thecode may submit to the regulator proposedrevisions at any time.91

Further, while the ACCC is required to issue adraft decision under the code, the ACCC canexercise its discretion to issue a draft report foran undertaking depending upon whether anydifficult or controversial issues have beenraised. Box 7.2 outlines and compares thepublic consultation and assessment proceduresfor both an access undertaking and an accessarrangement.

7.4Timeliness of regulatoryrulingsThe assessment of access regime proposals,provision of all relevant information by aservice provider and required publicconsultation processes outlined abovenecessitates an assessment period of severalmonths. The code92 provides that the regulatormust issue a final decision within six months ofreceiving a proposed access arrangement.

Six months is considered to be a reasonablelength of time, given the long lead timesinherent in gas pipeline investments and timeneeded for consultation and due process. TheACCC notes that any delays in issuing anaccess arrangement final decision is likely tobe a concern for providers of capital. Tomitigate timing uncertainties for regulatorydecisions regarding greenfields pipelineprojects it is incumbent on project proponentsto pro-actively manage regulatorydetermination processes to ensure the regulatoris able to promulgate determinations within theminimum prescribed timeframe.

90 Refer code section 2.3.91 Refer code section 2.28.92 Refer code section 2.21 (subject to 2.22).


Box 7.2. Comparison of public consultation and assessment procedures


Example for derivation ofrevenues when expecteddemand is uncertainThe following example sets out one possibleapproach to setting parameters of customerdemand survey results and determiningexpected returns where there is uncertainty.The ACCC notes that there may be many waysof developing such a framework. However thefollowing example is provided.

In a greenfields project part of the demand isunderwritten by foundation contracts but a partof expected demand is uncertain and may notemerge as envisaged despite market research.This example quantifies aspects of uncertaintyinherent in forecasting demand and growthfactors beyond the certainty provided byfoundation contract type commitments.Assessment of the information set outlined inthis example is consistent with the duediligence type requirements of debt and equityproviders in their respective analyses of apipeline proposal.

Interesting points to note in the followingexample are:

# the manner in which a large number ofsimulations for a number of customerclasses with varying take up rates can bemodelled

# how capacity constraints impact on theblue sky earnings capability of a givenpipeline specification, thus enablingproject proponents to assess the optimalsizing and amount of spare capacity tobuild into a pipeline from the outset.

The basic question of future demand is just ascritical for investment decisions concerningwhether to build the pipeline and its optimaldiameter/sizing as it is for any regulatorydecisions concerning tariffs. The nature of

Appendix 1

information required is the same for both tasks.Both require an appreciation of who thepotential customers may be and what theirenergy demands are likely to be. For existingusers of energy in the region served thisrequires an assessment of the delivered gasprice that would lead them to switch to naturalgas as a primary source of energy, the capitalcosts involved in doing so and how long thismay delay any such switchover. In additionthere will be other potential customers whomay emerge because of the availability of gassupply. The delivered gas price will beimportant in determining what new businessesmay be attracted.

To be better informed on these issues it shouldbe possible to survey customers about theirlikely needs. It is not expected that such asurvey will eliminate uncertainty. It is likelythat considerable uncertainty would remainabout the intentions of many potentialcustomers. However, such a survey wouldallow a probabilistic appreciation of thepotential market.

For each customer it is expected that thepipeline proposers could develop an opinionconcerning the following:

# the existing energy needs of a customerand whether these are likely to expand

# the delivered price of gas at which thecustomer is likely to find gas a moreeconomical energy source in the long term

# short term factors such as new capital coststhat may prevent or delay early adaptation

# the impact that the delivered gas price islikely to have on a customer’s choice ofenergy and timing of any changeoverdecision

# other factors influencing a customer’sdecision to become a gas user.


There will be concerns regarding someresponses and overall considerable scope forsubjective interpretation of any informationprovided by potential customers. Nevertheless,any serious attempt to compile such informationwill help define the nature and extent ofuncertainty concerning possible demand. Themere act of identifying potential customers is amajor advance even before questionsconcerning their costs and needs are explored.

There are many ways of developing such aframework. Below, just one possible approachto setting parameters of customer demandsurvey results is considered.

Customer specific demand forecasts

A customer’s existing demand for energy isestimated to be E(0) and this demand isexpected to increase by x per cent of GDPgrowth g (or a similar index of economicactivity). On the basis of the existing energysource (which may be LPG, electricity, dieseletc.) it could be estimated that the price ofdelivered gas that would make a switch to gasas the energy source economically attractivein the short term is A(0), in the absence ofother switching costs.

This switching price may be expected to varyas time progresses according to A(t). This maylink to the rate of change in alternative fuelsources (say a(t) per annum). However, animmediate switch may be ruled out because ofchangeover costs and existing operationalplant which is too costly to replaceimmediately. The effect of such changeovercosts is to reduce the threshold price at whichgas becomes economically attractive. Thisimpact could be assessed as K(0) which is theamount the gas price P(0) would need to bebelow A(0) to achieve an immediateconversion. This discount can be expected toreduce over time as existing plant is written offand needs replacement, say in L years time. Asimple linear expression for variation of theconversion discount over time could be used toapproximate this aspect of the decision:

K(t) = K(0) . t / L (1)

To determine what transport tariff is needed toattract the customer the well head gas priceG(t) needs to be subtracted.

Setting these parameters identifies the period (t)in which the customer changes over to gasaccording to whether the following relation istrue

P(t) < A(t) – K(t) = A(t) –K(0) .t / L (2)

The price of alternative fuels A(t) is determinedby the process

A(t) = A(t-1) . (1 + a(t)) (3)

where a(t) is the growth in alternative fuelprices from the previous year.

The quantity of gas is likely to be fairlyinsensitive to the transport tariff and would beequal to

E(t) = E (t-1) . (1+ x . g(t)) (4)

The service provider has some discretion whenconversion may take place by setting the tariff

T(t) < P(t) – G(t)< A(0) – K(0) . t/L (5)

In any event if this inequality holds it assumesthat the potential customer switches to gas inperiod t and contracts for E(t) units and continuesto use gas as its main fuel source thereafter.

This form of analysis can be considered for arange of customer types and the survey resultsexpanded to develop a picture of the overallmarket.

Setting such parameters suggests what may bethe appropriate sizing of the pipeline, theoptimal discount to offer foundation customersand an efficient time profile for change in tariffs.

This is a rather simple characterisation ofcustomer behaviour but there is no reason whyit can not be made as sophisticated as desiredby the pipeline sponsor.

Setting the parameters does not require a highdegree of precision and certainty. First of all itis unlikely that the survey will be exhaustiveand will therefore require some extrapolationto the market as a whole. Secondly, customersbeing surveyed may be indefinite about theirrequirements and the surveyor may need toqualify the results with subjective estimatesbased on experience and secondary informationsources. Thirdly a service provider may


constrain itself by charging the same tariff toall customers.

The degree of uncertainty associated with eachparameter then becomes an integral part ofeach assessment. For simplicity we assumebelow that such uncertainty is expressed as anormal distribution with the standard deviationchosen to reflect the degree of uncertainty.93 Toscale the survey up to derive overall marketbehaviour it is necessary to survey eachcustomer class and estimate the number ofcustomers and likely volumes associated witheach class. The estimated numbers in eachclass is also subject to uncertainty but forlarger customers it is expected that the surveywould involve total coverage and that theelement of uncertainty is limited to whether apotential major user may choose to establish anew plant or not.

In addition to specific customer requirementforecasts a number of market wide forecastsare required.

Market-wide forecasts

Although generally available market growthforecasts could be used, by themselves they donot capture uncertainty associated with them.The following is an example of one approachthat could be adopted.

Benchmark economic growth g could be basedon official forecasts of real GDP growth but

93 actually any probability distribution may becontemplated.

Table A1.1. Summary of parameter definitions for a company being surveyed

Parameter Definition

E(t) Energy demand in period t

x Ratio of demand to GDP growth

A(t) Price of alternative energy

a(t) Increase in A(t) over previous year

K(t) Measure of gas changeover cost

L No years for K(t) to fall to zero

uncertainty could realistically be representedas a near random walk (autoregressive) processabout the level chosen. For this example

g(t) = 0.03 + u(t)whereu(t) = 0.6u(t-1) + e(t) (6)

and e(t) is distributed as N(0, 0.01). i.e.normally distributed with mean zero andstandard deviation 0.01.

The price rise for alternative fuels a(t) isassumed to follow a similar process. In thiscase it is assumed all alternative fuels followthe same price growth but a number ofdifferent fuels could have easily beenconsidered. In this example assume

a(t) = 0.02 + v(t)wherev(t) = 0.4v(t-1) + e(t) (7)

and e(t) is distributed as N(0, 0.01).

Another global variable is the well head gasprice G(t). In this example it is assumed itfollows the same price path as the alternativefuels

That is G(t) = G(t-1) . a(t) (8)

For the purpose of this example gas distributioncosts are not explicitly modelled and thereforecould be thought of as being included with thewell-head price of gas G(t).


Generating the demand scenarios

An example of survey outcomes for 10customer classes is illustrated below.

Table A1.2. Customer characterisation survey example.

Customer Expected E(0) X A(0) Initial gas Remainingclass number of Energy Ratio of Price of change- life of

customers demand demand alternative over cost existing(random)1 at time 0 to GDP energy at K(0) plant L

(PJ pa) growth time 0 (random)2 (random)2

1 2 10 1.00 10 N(1,0.3) N(5,2)

2 3 4 0.80 10 N(2,1) N(5,2)

3 6 2 1.20 10 N(2,1) N(5,2)

4 11 1 1.00 10 N(2,1) N(5,2)

5 23 0.5 0.50 10 N(2,1) N(5,2)

6 45 0.2 1.50 10 N(2,1) N(5,2)

7 75 0.1 1.00 10 N(2,1) N(5,2)

8 165 0.05 1.00 10 N(2,1) N(5,2)

9 550 0.02 1.00 10 N(2,1) N(5,2)

10 2250 0.005 1.00 10 N(2,1) N(5,2)

Notes: 1. Expected number of customers is generated from a number distribution with amean as specified and a standard deviation set equal to 20 per cent of the mean.The sample values are rounded to the nearest whole number.

2. Random value from normal distribution identified in the table cell. For exampleN(5,2) denotes selection of a random number from a distribution with a mean of5 and a standard deviation of 2.

To generate demand forecasts based on theseparameters the tariff path needs to bespecified. In the sample simulations shownbelow it is assumed that the tariff in year 0 is$1.100 per GJ and escalates on a yearly basisaccording to a CPI-X rule (CPI=2.5% and X=1%).

The first five scenarios generated by theparameter assumptions are shown in graph A1.1.

Note that in all five scenarios demand inperiod one is non zero, that is some customerswill require gas in the first period of eachsimulation. However, this is not necessarily thecase for individual customers whose

changeover costs make an immediatetransition to gas uneconomic. The non zeroresults in the early years indicates that thereare always some customer classes for which animmediate transition to gas is worthwhile. Therelatively steep take-up in the early yearsreflects the fairly rapid reduction in thetransition related disadvantages of gas. That isthe more rapid demand growth in early years iscaused by customers switching to gas fromother fuel sources as changeover costsdiminish. In later years, when most potentialcustomers have made the switch growth reliespurely on the growth in energy demand ofexisting customers.


To obtain a fuller appreciation of the spectrumof scenario possibilities significantly moresimulations are required. Below the analysis isbased on 500 scenario simulations. The rangeof outcomes is illustrated in graph A1.2 whichshows demand levels in each year based on adecile based breakdown of volumes in eachyear. The values for the 1st, 3rd, 5th, 7th and9th deciles are chosen as an indicator of themedian within each quintile range.

Graph A1.1. Demand projection scenarios based on randomised parameter

Graph A1.2. Selected deciles of demand in each year from 500 projection scenarios based onrandomised parameter values

It should be noted that graph A1.2 also plotsthe average demand scenario over the 500simulations and that this almost coincides withthe plot for the 5th decile of demandssimulated (i.e. the median outcome). Thissuggests that the demands are more or lesssymmetrically spread either side of the averageor expected demand scenario.


Table A1.3. Possible pipeline configurations—capacity and costings

Aspect Configuration 1 Configuration 2

Pipeline cost $500m $600m

Economic life (years) 80 80

Initial capacity (PJ pa) 100 150

Capacity (1 compressor) 130 195

Capacity (2 compressors) 150 225

Cost of compressor $30m $33m

Economic life (years) 30 30

Real operating costs pa $10m $12m

is available from the project. To illustrate thisaspect of the analysis it is assumed that twopipeline configurations are possible each withexpansion capacity provided by up to twocompressors (see table A1.2).

The returns available from demand generatedin any scenario can be linked with a return onequity available with either pipelineconfiguration. A summary of returns observedfrom the 500 scenarios is shown in table A1.4.The simulations assume that compressors areinstalled just in time to meet any projecteddemand in the year ahead. However, ifmaximum capacity is exceeded no additionalrevenue is forthcoming as the additionaldemand cannot be met. This acts as a cap onthe blue sky available from higher demandscenarios, particularly in the case of thesmaller pipeline proposal.

The five scenarios graphed represent asummary of demand outcomes and could beused as a basis for further simulations withoutthe need to simulate demand from individualcustomers. In this summary portfolio ofoutcomes each scenario presented has equalprobability (0.2). Such a simplified approachwould be attractive when the complexities ofcalculating costs and rates of return inconjunction with each demand simulationrepresents a significant computational burden.

Revenue and rate of return implications

Any developer of a pipeline needs to go onestep further before deciding on the feasibility ofthe project. The cost of building and operatingthe pipeline needs to be factored into theanalysis to observe whether a satisfactory return

Table A1.4. Summary of rate of return outcomes from each pipeline configuration (return onequity over 10 years per cent pa)

Demand scenario Configuration 1 Configuration 2

Average of 500 scenarios 13.81 14.74

Average demand scenario 14.02 14.91

Decile 1 scenario 10.93 11.33





Average of 5 scenarios 13.91 14.77


The average demand scenario is notsignificantly affected by the capacityconstraint and therefore does not capture thenegative impact on return from the constraint.In other words the returns from the variousscenarios under pipeline configuration 1 revealthat it is not sufficient to merely consider theaverage demand scenario. Taking the averageof the returns estimated for each of the 500demand simulations offers a better guide to theexpected return. In configuration 1 the returnfrom the average scenario is quite a bit higherthan the expected return overall even thoughthe demand scenarios are symmetrical aboutthe mean. This is a result of the averagedemand scenarios not being constrained bypipeline capacity. However, it is clear that in anumber of scenarios (see graph 1.2) thecapacity will be a constraint on blue skyrevenues within the 10 year period beingconsidered in about 20 per cent of theoutcomes with pipeline configuration 1.

This conclusion is evident in the returnscalculated for configuration 2 when capacityconstraints are not a limit on additionalbusiness (indeed the second compressor isrequired in only about 0.25 per cent of thesimulations). The average of returns obtained inindividual simulations is close to the returnexpected from the average scenario. Further,the higher returns from the demandcorresponding to the 7th and 9th deciles aremuch higher for configuration 2 and this lendssupport to the conclusion that the capacityconstraint reduces the return expectations withpipeline configuration 1.

It was noted above that the return analysiscould be performed using the summary fivedecile scenarios graphed above. Because theseinclude scenarios where the capacityconstraint bites, the asymmetry effect isreflected in the average of returns from the fivescenarios. Each of the five scenarios representsthe median of a range of outcomes with equalprobability. Therefore the unweighted averageof returns provides an unbiased estimate of theexpected value of returns over all outcomes.This average is close to the result obtained with500 simulations and illustrates thecomputational saving of working with thesummary scenarios.

Summary

Significantly, the expected return fromconfiguration 1 is much lower than forconfiguration 2, suggesting that it will be morecost effective to build the larger pipelinedespite the higher costs and the fact that inconfiguration 2 the pipeline is not expected tobe used to its full capacity in many instances.

The example of capacity constraint illustratesthe value of scenario simulation when thereare issues of asymmetry to deal with. Wherethere is an asymmetry in potential revenuesabout a normal or median outcome the returnscalculated on the assumption of the mediandemand outcome offers a poor guide as to theprospective return that may be expected. Thisis true whether the pipeline is regulated or not.However, if there is a concern that theregulatory framework itself gives rise to theasymmetry the approach offers a mechanismfor dealing with it. This particular issue iscovered further in appendix 3.

Finally, table A1.4 shows that the actualoutcome may be significantly higher or lowerthan the regulatory rate of return with anachievable return on equity of over 18.05 percent being consistent with an averageexpected return of 14.77 per cent.94

As a final step in the use of such simulationsfor regulatory purposes it is necessary to findthe reference tariff that provides an expectedrate of return equal to the CAPM basedregulatory rate of return. This is found by asystematic adjustment of the initial tariffsetting or the X factor so that the desired returnon equity is the result of the average return onequity over a large number of simulations withthe selected pipeline configuration.

94 Some of the higher demand scenarios gave rise to anachieved return on equity over 19.0 per cent.


Example of an adjustmentto the initial capital baseto reflect actual costs andthe effect on referencetariffsThe ACCC considers the inclusion of asymmetric adjustment mechanism canaccommodate any material variance betweenthe forecast and final cost of the initial capitalbase (ICB); facilitate certainty regarding howunder or over recovery of costs can beremedied; avoid potential discontinuities in thereference tariff price path to avoid volatility intariffs; and provide certainty for users.

Clearly a range of appropriate adjustmentmechanisms are possible and the optimalapproach from a service provider’s perspectiveis likely to depend on its own uniquecircumstances. The following illustrativeexamples set out a number of mechanisms thatcould be used.

Suppose that the pipeline is forecast tocomprise two classes of asset A and B. A hasan expected life of 50 years and B has anexpected life of 20 years. Forecast costs foreach class of asset is $100m each. Assume atthe end of year two actual costs becomeknown and expenditure on A is $120m and onB is $90m.

Reference tariffs would have been initiallyformed on the basis of the $100m forecastcosts. The building block approach is used toestablish the target revenues to derive thereference tariffs. See table A2.1.

# The WACC is assumed set at 8.00 per cent.

If the regulator had perfect foresight it wouldhave used actual numbers for capex andobtained revenues as shown in table A2.2.

Appendix 2

Perfect foresight is not available but at thebeginning of year two or at the nextconvenient reset opportunity, tariffs and theregulatory asset base roll forward calculatedcan be adjusted in a mechanistic way to fullyaccommodate the error in capital expenditureestimates.


Regulatory asset base roll forward

Period 1 2 3 4 5 c/f RAB tonext reset

Asset value at start of period

Asset A ($m) 100.00 98.00 96.00 94.00 92.00 90.00Asset B ($m) 100.00 95.00 90.00 85.00 80.00 75.00

Total RAB 200.00 193.00 186.00 179.00 172.00 165.00

Depreciation during periodDepreciation on asset A 2.00 2.00 2.00 2.00 2.00

Depreciation on asset B 5.00 5.00 5.00 5.00 5.00

Total depreciation 7.00 7.00 7.00 7.00 7.00

Building block componentsReturn on capital (WACC 8%) 16.00 15.44 14.88 14.32 13.76

Depreciation 7.00 7.00 7.00 7.00 7.00

O&M 5.00 5.00 5.00 5.00 5.00

Total (target revenue) 28.00 27.44 26.88 26.32 25.76

Forecast volume (PJ pa) 30.00 31.00 32.00 33.00 34.00

Average tariff ($/GJ) 0.933 0.885 0.840 0.798 0.758

Initial expected net cash flows 23.000 22.440 21.880 21.320 20.760 178.21

NPV of cash flows1 $200.00

Table A2.1. Tariffs based on forecast capex costs

Note: 1. The NPV of net cash flows is valued at the start of period 1 and includes the value of the carriedforward value of the RAB ($165m) at the end of period 5 (this value is shown in column 6adjusted up to accommodate discounting between periods 5 and 6). A regulatory frameworkgiving a prospective rate of return must have the NPV of net cash flows equal to the initial costof the assets.


Table A2.2. Tariffs based on actual capex costs


Period 1 2 3 4 5 c/f RAB tonext reset

Asset value at start of periodAsset A ($m) 120.00 117.60 115.20 112.80 110.40 108.00

Asset B ($m) 90.00 85.50 81.00 76.50 72.00 67.50Total RAB 210.00 203.10 196.20 189.30 182.40 175.50





Depreciation 6.90 6.90 6.90 6.90 6.90

O&M 5.00 5.00 5.00 5.00 5.00Total (target revenue) 28.70 28.15 27.60 27.04 26.49



Net over-recovery usingforecast figures in table A 2.1 -0.700 -0.708 -0.716 -0.724 -0.732

Expected cash flows under option 23.700 23.148 22.596 22.044 21.492 189.54

NPV of cash flows $210.00

It is not necessary to track the errors in thedepreciation building blocks and for the return oncapital components to achieve this. All that isrequired is to observe the difference in revenuescalculated under the two different sets of capex.The updated revenue estimates may be aboveor below those calculated initially. Where it isabove, the initial revenue estimate is inadequateto provide both the necessary return on capitaland provide for the planned path of depreciation.It is convenient to assume that all the shortfallis accounted for by a temporary stalling in thereturn of capital. Similarly, where updatedrevenues are below the initial estimates it isassumed there has been an excess over theplanned rate of return of capital.

Under this interpretation all that needs to bedone to re-validate the regulatory accounts isto explicitly recognise the accumulatedexcess/shortfall in the regulatory accounts andmake adjustments to ensure that the integrityof the regulatory asset base roll forward ispreserved.

This may be done in a number of ways thatpreserve the expected rate of return oninvestment calculated as appropriate in theinitial regulatory decision.


95 Generally, assets within a regulatory framework areclassified by function of the assets and the rate ofdepreciation (or economic life) assigned to thoseassets. In this context it is sufficient to classify assetsaccording to their planned depreciation profile (or byexpected economic life).

Option 1. Allow an immediate change in tariffsto follow the price path calculated based on theactual capex data when it is available. Thisapproach requires an adjustment of the regulatoryasset base at the next regulatory reset to reflectthe excess/shortfall in the return of capital carriedforward and the potential return on that portionof capital. There is some discretion in decidingwhich class of assets should be subjected to theaccommodating adjustment; however, anapportionment in proportion to the written downasset value would seem fairly reasonable.95 Theadjustments relevant to the examples above areshown in table A2.3. It should be noted that theNPV of the cash-flows following theseadjustments equates to the initial capital costsconfirming consistency with the regulatory rateof return as an expected outcome.

Table A2.3. Option 1—Adjustments to remedy errors in forecast capex costs (assuming actualcapex costs become known at end of period 2)

Period 1 2 3 4 5 RABadjustment

Extra depreciation -0.70 -0.71 0.00 0.00 0.00 0.00

Accumulated extra depreciation -0.70 -1.41 -1.41 -1.41 -1.41 -1.41

Accum depr + return on it -0.70 -1.46 -1.58 -1.71 -1.84 -1.84

Actual cost carried forward RAB 175.50Modified carried forward RAB 177.34



Option 2. Allow the initial forecast price pathto continue until the next regulatory reset. Thisis likely to lead to an increase in the excess/shortfall capital return. The principles used arethe same as option 1 and require an adjustmentto the carried forward value of the RAB. If theprice changes are minor this may be thesimpler approach. The main shortcoming ofdeferring any adjustment is that there may be amore significant tariff adjustment required intransition to the next regulatory period.

Table A2.4. Option 2—Adjustments to remedy errors in forecast capex costs (although actual capexcosts become known at end of period 2 forecast price path is used until next reset)

Period 1 2 3 4 5 RABadjustment

Extra depreciation -0.70 -0.71 -0.72 -0.72 -0.73 0.00

Accumulated extra depreciation -0.70 -1.41 -2.12 -2.85 -3.58 -3.58Accum depr + return on it -0.70 -1.46 -2.30 -3.20 -4.19 -4.19

Forecast carried forward RAB 175.50

Modified carried forward RAB 179.69




Option 3. In principle it is possible to make anovercompensating adjustment in a move to thenew price path so that by the end of theregulatory period any excess/shortfall capitalreturn is reduced to zero. This avoids the needto make a further adjustment to the RAB carryforward value. These calculations are shown intable A2.5. The calculations recognise that the

Table A2.5 . Adjustments required under option 3 —recalculating price path to accommodateforecast error to date and creating the carried forward RAB value consistent withknowing actual costs from the start (assuming actual capex costs become known atend of period 2)


Period 1 2 3 4 5 CF RAB tonext reset

Net over recovery of revenue -0.7 -0.7

Cumulative over-recoveryat start of period 0.0 -0.7 -1.5 -1.6 -1.7 -1.8

Asset value at start of periodAsset A ($m) 120.00 117.60 115.20 112.80 110.40 108.00

Asset B ($m) 90.00 85.50 81.00 76.50 72.00 67.50

RAB adjustment 0.00 0.00 1.46 0.98 0.49 0.00

Total RAB 210.00 203.10 197.66 190.28 182.89 175.50


Depreciation on asset B 4.50 4.50 4.50 4.50 4.50Notional extra depreciation -0.70 -0.71 0.49 0.49 0.49



Depreciation 6.20 6.19 7.39 7.39 7.39

O&M 5.00 5.00 5.00 5.00 5.00Total (target revenue) 28.00 27.44 28.20 27.61 27.02





Note: Approximate values can be obtained by dividing the accumulated extra depreciation to date bythe number of periods left. However, this ignores the return on that component of capital. Inpractice it is a simple matter to use the ‘goal seek’ values for depreciation which restore the ARBbased on actual costs going into the next reset period.

net over-recovery of depreciation needs to beundone over the remaining periods of theaccess arrangement. Such an approach is notgenerally favoured for those scenarios wherethe tariff path has relied on smoothing or wherevolumes are changing rapidly as the revenueimplications are complex and the necessarytariff adjustments much more difficult to assess.


Option 4. Finally, it is possible toacknowledge the error in revenues posed bythe capex forecasts and recalculate the tariffsgoing forward accordingly. This is similar tooption 3 in that there is a jump to a new pricepath. But because of any net over recovery ofdepreciation to date is not explicitly reversedthe carried forward asset value is alsomodified. Despite the modifications on thesetwo fronts the approach has appeal in that itbest reflects an immediate recognition of theprevious error and recalculates all future tariffsand asset values taking that error into account.

The relevant calculations are shown in tableA2.6.

Table A2.6. Adjustments required under option 4—recalculating price path to accommodateforecast error to date (assuming actual capex costs become known at end of period 2)


Period 1 2 3 4 5 CF RAB tonext reset

Net over recovery of revenue -0.7 -0.7

Cumulative over-recoveryat start of period 0.0 -0.7 -1.5 -1.6 -1.7 -1.8

Asset value at start of periodAsset A ($m) 120.00 117.60 115.20 112.80 110.40 108.00Asset B ($m) 90.00 85.50 81.00 76.50 72.00 67.50

Cumulative RAB adjustment 0.00 0.00 1.46 1.46 1.46 1.46

Total RAB 210.00 203.10 197.66 190.76 183.86 176.96



Notional extra depreciation -0.70 -0.71Total depreciation 6.20 6.19 6.90 6.90 6.90


Depreciation 6.20 6.19 6.90 6.90 6.90

O&M 5.00 5.00 5.00 5.00 5.00

Total (target revenue) 28.00 27.44 27.71 27.16 26.61





It should be noted that the validity of eachoption is confirmed by calculating the NPV ofthe resultant cash flows and the residual assetvalue carried forward to the next reset usingthe WACC as the discount rate. Under eachoption, for adjustment to take account of theerror in capex forecast, the NPV should equalthe actual cost of the assets at commencementof operations (start of period 1). Each of thefour options outlined above are consistent withthe building block approach and are confirmedby its NPV equivalence. Accordingly, from afinancial perspective, a service provider shouldbe indifferent between the four options.


Q&A

Question 1. Should the existence offoundation contracts alter the approachtaken to these adjustments.

Answer 1. No. The tariffs in foundationcontracts have been negotiated and arenormally legally binding. They may includerise and fall clauses to accommodateunexpected changes in costs but these do notimpinge on the regulatory calculations.96

Question 2. Suppose volumes andconsequently revenues are quitedifferent from those forecast as part ofthe regulatory decision. Does this alterthe calculations that are required toadjust for updates in capital costs?

Answer 2. No. No adjustment would be madein such cases if there were no error in forecastcapital costs. A shortfall or excess of revenuesin such cases is part of incentive mechanismwithin the regulatory framework for the serviceprovider to expand the market for its services.Those incentives must be preserved within theadjustment mechanism so it is only the targetrevenues emerging from the regulatorycalculations that need to be factored into theadjustment.

96 Refer code section 2.25 and 6.15(e)


Example of benefitsharing when demandexceeds a pre-setthresholdThis appendix builds on the frameworkdemonstrated in appendix one in relation todetermining expected demand and revenues inthe face of uncertainty. In the event that anupside or downside outcome was realisedduring a regulatory period that was extreme oroutside the range of outcomes reflected in thesimulations, the regulator is required toconsider sharing mechanisms.

This appendix provides an illustrative exampleof how such a benefit sharing mechanism maybe designed in order to provide ex-antecertainty regarding its operation and effect onrevenues subsequently realised beyond acertain point.

The framework in appendix one depended onassigning probabilities to the range of feasibleoutcomes. In general, there is no way ofknowing whether the scenarios developed arefree from bias and an observed actual demandoutcome is a genuine random event consistentwith the scenarios postulated. An exception tothis is when an actual outcome is outside therange of the probabilistic scenarios considered.Such an outcome may or may not be a result ofmisrepresentation of likely scenarios. It doesnot matter whether the divergence is above orbelow the range of forecasts made. In eithercase, it is clear that the basis for establishingthe reference tariffs was flawed and areassessment warranted. However, such areassessment poses a problem of principlelinked to the need to use expectations at thetime of financial close.

If demand turns out to be worse than envisagedin any of the scenarios there is already amechanism available to reconsider regulated

Appendix 3

revenues since the code allows the serviceprovider to seek a review at any time.However, this scenario too poses the sameconflict of principle in that the risk basedframework would be put aside.

If the outcome involves demand higher thanany scenarios considered in establishingreference tariffs there is no mechanism bywhich the regulator can seek a review. A resetof tariffs based on actual blue sky demand ‘expost’ is considered detrimental to incentivesand is the main reason for establishing theframework such as that described inappendix 1.

Therefore, the regulatory framework needs tobe able to cater for unexpected demandaberrations at the time of the initialassessment. This is because it is inconceivablethat any probabilistic scenarios postulated inresponse to the deviant outcome could beviewed as an ex-ante expectation. Hence theconcept of maintaining revenues on the basisof expectations held at the time of financialclose would be lost. To cope with the situationa benefit sharing mechanism is proposed thatenables customers to receive some of thebenefits of greater than expected demand. Tohandle the symmetrical issue of demand shortfall a parallel mechanism could also beproposed to allow the service provider toregain lost ground. In the case of high demandrealisations, this could be achieved byreducing the proposed reference tariffs whendemand exceeds certain pre-set thresholds.97

This will reduce some of the blue sky that mayhave been obtainable by the service provider,but if sharing is an anticipated possibility it the‘ex ante’ net value of that blue sky

A benefit of such a mechanism is to reduce theincentive for a service provider to distort its

97 While this can be thought of as tariff moderation thebenefit sharing may be achieved in practice byrebates or treating the excess return as a return ofcapital that will lead to a reduction in the value ofthe carried forward asset base at the next review.


view of anticipated demand outcomes. This isachieved because the benefit sharingmechanism is less likely to be triggered whenforecasts are accurate. In this way the serviceprovider gains greater certainty of expectedreturns in such circumstances by truthfulrevelation of demand scenarios. Such sharing isto occur in any period in which demandexceeds the preset threshold. A similarmechanism for sharing can be specified whenthere are shortfalls in demand.

A suggested mechanism

The threshold for sharing is derived from thescenarios used to establish the reference tariffs.The upper threshold demand trigger in period t,TU(t) beyond which sharing is to occur, is setequal to the average demand Dav(t) plus thestandard deviation SD(t) of demand outcomesforecast for period t.

TU(t) = Dav(t) + SD(t) (1)

Beyond this level of demand the extrarevenues achieved are to be shared with usersthrough a rebate mechanism or a reduction intariffs.

A low threshold demand trigger TL(t) can besimilarly defined.

TL(t) = Dav(t) - SD(t) (2)

Below this level of demand the shortfall inrevenues achieved are to be partiallyrecovered in future tariffs.

The sharing could be on a 50/50 basis but asliding scale could also be used. Such a rebateformula is given by:

Rebate(t) =(0.5 x (D(t)—TU(t))/ D(t)) x Revenue (3)where D(t) is actual demand in period t.

Note that in this instance Rebate(t) represents apercentage of the revenue from demandserviced in year t and which needs to berebated to customers.

A simple example

Suppose three scenarios are proposed initiallyeach with equal probability. Each scenariostarts with demand at 100 PJ pa in period 1. Butin

scenario 1 demand grows at 2 PJ paie D1(t) = 100 + 2t PJ;

scenario 2 demand grows at 4 PJ paie D2(t) = 100 + 4t PJ; and

scenario 3 demand grows at 6 PJ paie D3(t) = 100 + 6t PJ.

Suppose for simplicity the reference tariff willbe set at a constant price per GJ. The averagescenario is scenario 2 and the standarddeviation in period t is 1.6t PJ.

thus the upper trigger threshold demand path isgiven by:

TU(t) = 100 + 4t + 1.6t (4)

And the lower trigger threshold by:

TL(t) = 100 + 4t —1.6t (5)

As shown in graph A3.1 the lower and upperthresholds are exceeded in scenarios 1 and 3respectively. That is there will be an element ofrevenue sharing in these scenarios even thoughthey are represented in the portfolio of possiblescenarios postulated. This is not considered aproblem since the revenue sharing mechanismis also integrated into the reference tariffframework described in appendix 1. Themodification of the revenues is taken intoaccount when establishing the reference tariff,which may be somewhat higher or lower thanit otherwise would have been. In this case thesymmetry in the demand scenarios means thatthe middle or average scenarios would giverise to the same reference tariff as using theprobabilistic scenarios. However, in theexample below part of this symmetry is lostbecause demand exceeds pipeline capacity inscenario 3 in periods 9 and 10.

Assumptions:

Target WACC is set at 8.00 per cent;

The initial capital cost is $800m;


The residual asset value after 10 years is$700m;

Maximum pipeline capacity 150 PJ peryear; and

O&M costs are a constant $25m per year.

Cash flow modelling shows that the referencetariff consistent with these assumptions and the

Graph A3.1. Demand volumes forecast under the three scenarios and high and low triggervolumes for revenue sharing

Graph A3.2. Demand volumes under the three corresponding scenarios but with demand broughtforward by two periods, original high and low trigger volumes for revenue sharingare also shown

assumed level (50 per cent) of benefit sharing$0.8047 per gigajoule. With different sharinglevels the reference tariff may vary butbecause of the symmetry in demand scenariosthe variations in this example as shown ingraph A3.1 below are minor. With zero sharingthe reference tariff would be $0.8040 pergigajoule and with 100 per cent sharing$0.8054 per gigajoule.


Under scenarios 1 (low demand) and 3 (highdemand) a mild amount of revenue sharing isalready occurring. As shown in graph A3.1 andtable A3.1, this is reflected in the achievedrate of return with sharing featured. Graph A3.2illustrates what could happen in the future ifdemand increases more than expected (in thiscase illustrated by bringing demand forward bytwo periods. The extent by which actual demandexceeds the trigger volume line indicates theamount of sharing. For example under a 50 percent sharing mechanism the revenues achievedin a year would be as if demand was midwaybetween the actual demand and the triggervalue. A similar picture of demand shortfall isproduced by assuming demand growth isdelayed by two periods.

Table A3.1 shows the actual return that wouldbe achieved under each outcome and sharingassumption.

Table A3.1. Impact of revenue sharing on achievable returns under alternative scenarios

Ex ante expectations of achievable rate of return on assets

Percent sharing % 0 25 50 75 100

Ex ante expectations of return on assets

Scenario 1 7.03% 7.08% 7.13% 7.17% 7.22%

Scenario 2 8.04% 8.04% 8.03% 8.03% 8.02%

Scenario 3 8.92% 8.88% 8.84% 8.80% 8.76%

Average return (%) 8.00% 8.00% 8.00% 8.00% 8.00%

Reference tariff ($/GJ) 0.8054 0.8051 0.8047 0.8044 0.8040

Rate of return achievable on assets with increased demand with above reference tariffs(brought forward two periods earlier than expected)

Percent sharing % 0 25 50 75 100

Achievable rates of return on assets

Scenario 1 7.43% 7.43% 7.43% 7.43% 7.43%

Scenario 2 8.83% 8.78% 8.73% 8.67% 8.62%

Scenario 3 9.84% 9.56% 9.30% 9.03% 8.76%

Average return (%) 8.70% 8.59% 8.48% 8.38% 8.27%

Rate of return achievable on assets with reduced demand with above reference tariffs(market growth delayed by two periods)

Percent sharing 0 25 50 75 100

Achievable rates of return on assets

Scenario 1 6.63% 6.78% 6.92% 7.07% 7.22%

Scenario 2 7.26% 7.26% 7.26% 7.26% 7.26%

Scenario 3 7.88% 7.88% 7.88% 7.88% 7.88%

Average return 7.26% 7.31% 7.35% 7.40% 7.45%


Other points to note from the simulations are asfollows.

As expected, the effect of the sharing is tobring the returns under the extreme demandscenarios closer to the average expectation.

Regardless of the proportion of sharingproposed it is always possible to find the tariffthat provides an ex ante expectation of therequired 8 per cent return on assets.

This tariff decreases slightly with the level ofsharing assumed because the sharingmoderates the downside scenario more thanthe upside that is capped by the capacityconstraint.

Without sharing (i.e. sharing of 0 per cent) theimpact of an unexpected surge in demand is toincrease achieved revenues and achievedreturn on assets. Similarly, a shortfall indemand reduces returns.

The increase in achieved returns is moderatedby the impact of the sharing mechanism withthe extent of moderation depending on thelevel of sharing specified. Returns are similarlystabilised when demand falls.

Where the sharing mechanism is not triggeredunder a scenario there is no change in returnfrom what would be observed in the absence ofbenefit sharing.

At the extreme in scenario 3 when the triggerwas already operating without the demandsurge, the impact of 100 per cent sharing is toprevent any additional returns being achievedby the service provider. A similar effect isobserved in scenario 1 in conjunction with theshortfall in demand expectations (the 100 percent sharing example is included as illustrationonly and is not a proposed sharing setting).

# In all cases (apart from the last) the serviceprovider retains an incentive to pursuemarket expansion as a means of increasingprofits.

This example does not specify how the benefitsharing takes place. Different approaches maybe applicable in different circumstances. Thefollowing are examples.

# Where additional demand (or demandshortfalls) can be anticipated in advance ofannual price adjustments for CPI the actualtariff for the year ahead could be reduced/increased by the amount that reduces/increases revenues by the amount of thesharing.

# Where demand cannot readily beanticipated the benefits could be shared byproviding appropriate rebates to customersat the end of the accounting year.

# Where it is difficult to anticipate demand,and where it is difficult to arrange end ofyear balancing arrangements or rebates(e.g. it would be difficult to extractadditional charges from customers at theend of the year), an adjustment could bemade to the residual value of the assetbase to reflect the over or under recoveryof revenues. When the residual isaugmented, the revenues are subsequentlyrecovered in future regulatory periods afterthe next regulatory review.98 When theresidual value is reduced (customers paidtoo much) customers receive reducedtariffs in the future as compensation.

The choice of mechanism is more a matter ofpracticality rather than being a matter ofregulatory principle.

98 This is similar to the economic depreciation approachproposed for the Central West Pipeline where loss orunder recovery of revenues because of low demandin early years is compensated by capital appreciationof the regulatory asset base to allow eventualrecovery when the market matures.


Summary of consultancies

Macquarie Bank Limited

‘Issues for debt and equity providers inassessing greenfields gas pipelines’

Introduction

Macquarie Bank Limited (MBL) was engagedto advise the ACCC on what information wouldgenerally be required by debt and equityproviders in assessing a greenfields natural gastransmission pipeline project. The reportdescribes MBL’s opinion, based on itsexperience of the Australian energy market.

Key findings

Debt holders require information on all therisks associated with the project. This enablesthe debt holder to assess the risk profile of theproject and determine the amount, and cost, ofdebt that can be made available to the project.Equity holders also assess the risk profile of theproject to determine their capital contribution,its structure and their required rate of return.

A single purpose company or trust is oftenestablished as the ‘project vehicle’ toundertake a pipeline project. This has thebenefit of quarantining the project risks fromthe parent business. The project vehicle willthen seek to minimise its cost of capital bymaximising the relatively less expensive debtcomponent. It should be noted that the sourceof funds from the domestic banking market isgenerally limited to $1 billion. Funds will alsobe limited by each bank’s exposure to theproject and the industry as a whole. Fundingfrom the capital markets can be more costeffectively used once projects have movedfrom the construction phase to the operationphase. In addition, if a business is able to

Appendix 4

obtain an investment grade credit rating from arecognised agency and meets the creditcriteria of the monoline insurers then it may beable to utilise ‘credit wrapping’.

MBL advises that equity participants of aproject generally determine their contributionto the business’ capital with regard to theirrequired rate of return for an investment withthe specific risk profile and the time horizonfor the investment. An equity holder generallyseeks to maximise the nominal after-tax returnfrom the project’s cashflows. While equityholders use a similar approach to riskassessment as debt providers, they may bewilling to assume a higher risk and make moreaggressive assumptions.

MBL identified 14 specific risk categories thatwould be considered in a debt financingassessment. These included the following.

# Construction risk. Large pipelines are verysensitive to construction risk as they have aconsiderable period when revenue is notearned but borrowings are accruinginterest. Debt providers seek to ensure thatcontractual arrangements allocateresponsibilities and risks appropriately overthis time.

# Market and revenue risk. While debtproviders consider the extent that apipeline has foundation contractsestablished in forming a view on the debtavailable for a project, equity providers aremore likely to take the risk that thepipeline’s market will not develop aspredicted. This risk increases with thegreater proportion of capacity that isuncontracted.

# Interest rate and inflation. Debt providersrequire pipeline companies to use interestrate hedges to reduce the extent of risk andimprove cashflow certainty. If debtproviders consider that a regulator willredetermine the business’ return at the end


of the regulatory period then they willrequire interest rates to be hedged to thisdate.

# Regulatory risk. In considering thecashflows of the new pipeline, debtproviders will form their own view onwhether the pipeline will be regulated andthe nature of the regulatory framework. Thisview is formed with reference to (amongstother things) previous regulatory decisionsin Australia for a variety of businesses. Ifthe regulatory regime is clear and a highlevel of confidence can be establishedregarding the cashflows, including theregulator’s assessment of the forecasts, thenthe risk profile of the business willdecrease.

In assessing the various categories of risk,financiers may rely upon expert advice from arange of independent consultants, for exampleto provide assistance in developing forecasts inregard to the regulatory price paths and thesupply and demand for gas. Debt providersmay rely upon an expert engaged by a serviceprovider or may appoint their own. They mayalso require independent certification ofconstruction costs and operating andmaintenance and capital expenditure forecasts.In some instances debt providers have in-houseexpertise. Reports will also be required fromindependent parties concerning theaccounting, tax and legal aspects of theproject.

Any issues identified by the consultants will bediscussed by the debt providers with equityproviders and the results will be incorporatedinto the debt providers financial model and/orthe terms and conditions of the debt facility.All the required experts’ reports must bespecifically addressed to each debt provider.The debt providers will be relying on thereports for their lending decisions and must beable to have legal recourse to the expert forincorrect information.

Davis and Handley

‘Cost of capital for greenfields investmentsin pipelines’

Introduction

Kevin Davis and John Handley99 prepared areport for the ACCC that considered theappropriate determination of the cost of capitalfor greenfields investments in gas transmissionpipelines. Specific questions to be addressed atthe request of the ACCC included:

1. Whether the CAPM is an appropriateframework for assessing the WACC facinga greenfields pipeline.

2. How should risks that are specific to theproject be recognised and compensated?For example, the level of return that mayaccrue to a greenfields pipeline is moreuncertain than the returns to a maturepipeline owing to variation in financialparameters during development andconstruction (such as exchange rates),construction cost variability, operating costvariability (including teething problems)and demand uncertainty (beyondfoundation contracts).

3. Whether the CAPM should be augmentedto account for the specific risks facing agreenfields pipeline. Specifically, is itappropriate to inflate the beta and, if so,over what period should the inflated betaoperate.

4. Whether it is appropriate to utilise a singlebeta for the pipeline industry as a whole, orwhether separate betas should bedeveloped for mature and greenfieldspipelines. Is there a case for separatingcash flow streams (for example, foundationcontracts and speculative demand) andapplying different WACCs to each.

99 Kevin Davis is Commonwealth Bank Group Chair ofFinance, Department of Finance, The University ofMelbourne. John Handley is senior lecturer,Department of Finance, The University ofMelbourne.


5. Subject to the views regarding 1 to 4above, does a CAPM approach todetermining WACC and compensatingspecific risks in cash flows provideadequate compensation for potentialdownside risks.

Key findings

Davis and Handley conclude that the CAPMmodel is an appropriate framework forassessing the appropriate WACC facing agreenfields pipeline project. Noting that whilethere are a number of alternative approaches tothe CAPM framework‘none of the alternativeapproaches have surpassed the CAPM inpopularity or use in practice’ at this time.

Project finance techniques and financialengineering/risk management techniques aretypically used (or are available) to reducespecific risks or pass such risks onto thosewilling and able to bear them at least cost.Provided that the capital base concept adoptedfor use in regulatory price determinationreflects the cost of such risk transfer, or that thecash flows required to insure or hedge suchrisks are reflected in operating costs, no furtheradjustment for risk would appear to bewarranted.

Specific, that is non-systematic, risksassociated with a greenfields pipeline shouldnot lead to an adjustment of beta—which isintended to reflect systematic risks only. Anysuch adjustment would be ad hoc and couldlead to significant biases.

Davis and Handley note the issues involved indetermining an appropriate beta for thepurposes of regulating an asset. The suggestionthat the beta for greenfields pipelines should behigher than the beta used for establishedpipelines is considered. In the absence ofregulation the authors note there are somegrounds for believing that the systematic risk ofa greenfields pipeline may be somewhat higherthan that of a mature pipeline. The authorssuggest that the most significant factor is thelong time frame over which cash flows areexpected (that is, the cash flows are distant).However the authors also note that theregulatory approach to access pricing (egredetermining access prices periodically; losscarry forward provisions; and the requirementof the code to use the actual construction costs

of a new pipeline as the initial capital base)and the arrangements contained in foundationcontracts may reduce this effect.

While it is, in principle, possible to decomposecash flow streams into foundation contracts andnon-contract components with different riskcharacteristics, the practical problems ofapplying such an approach appear to make itinfeasible.

Time lags are involved in construction beforecash inflows are realised, and project viabilityrequires that those outlays should becompounded at the required rate of return indetermining the cost base of the project.100

Finally, the authors stressed that access pricesderived on the basis of applying a required rateof return to an accounting asset base (at somedate 2), conditional on an assumed level offuture output which is different to thatexpected at the time the investment was made(date 1), are not necessarily compatible withproviding appropriate signals for investment. Ifit is possible that the investment will ex-post(that is, at date 2) have a negative NPVresulting from low demand, and that accesswill only be sought in cases where demand ishigh, it is necessary that in that latter (highdemand) case the ex-post (date 2) NPV willneed to be positive if the ex-ante (date 1) NPVis to be zero.

Davis and Handley suggest one potentialsolution to this problem. That is, bring forwardthe coverage or access determination date sothat it occurs early in the project appraisal anddevelopment or construction stage rather thanafter project success has been observed.

100 For example, if a project involves an outlay of $1 atdate 0, has a required rate of return of r, andgenerates no cash flows until date 2, the requiredcash inflow at date 2 is $1(1+r)2 if the project is tohave a zero NPV. If target cash flows at date 2 are tobe determined at date 1, the appropriate capital basefor use at that date is $1(1+r).


National Economic Research Associates(NERA)

Foundation contracts and ‘greenfields’ gaspipeline developments:experience from the US and otherjurisdictions

Introduction

NERA was engaged to prepare a report on therole of foundation contracts in new gaspipeline developments in various relevantjurisdictions.

The report was required to address thefollowing.

1. Typical foundation contracts established inoverseas jurisdictions. This analysis drewprimarily on experience in the UnitedStates, and to a lesser extent, experiencesin other jurisdictions such as Singapore,Mexico, Argentina, UK etc.

2. Typical construct of a foundation contract.For example, usual terms and conditions,pricing formulae etc.

3. What is the normal relationship betweenfoundation contracts and pipeline capacity(initial and potential) to justify theconstruction of the pipeline.

4. The incidence of most favoured nation(MFN) clauses in foundation contracts andcommon variants.

5. The incidence of provisions for blue skysharing in foundation contracts. Descriptionof typical benefit sharing mechanismsemployed in foundation contracts.

6. Extent of regulatory oversight of foundationcontracts including criteria employed byFERC to determine whether greenfields gaspipelines should be regulated orunregulated. Description of the nature ofregulation applied to greenfields pipelinesby FERC.

7. Use of market based tariffs in establishingfoundation contracts (for both regulatedand unregulated pipelines) and as a basisfor determining third party access prices.

8. Level of security provided in foundationcontracts.

Key findings

NERA’s report focuses on the regulation of thegas pipeline industry in the US, and inparticular, FERC’s regulatory role. FERC hasregulatory oversight for interstate pipelines andmajor interstate pipeline developments. Thisdoes not appear, in NERA’s view, to havehindered the development of the pipelineindustry to an extensive network.

New pipelines and extensions of existinginterstate pipelines must obtain a ‘certificate ofpublic convenience and necessity’ from FERCbefore being built. NERA considers that theapplication of an established set of tests in thisprocess provides the industry with certainty.

Long-term contracts for the proposed pipelineprojects are an important aspect of thecertification process. The contracts underpinthe new investment, sharing the long-terminvestment risks between the pipeliner and theuser. The existence of long-term contractsincreases the likelihood that the pipeliner’sapplication will be approved and a certificategranted. However, they do not guarantee acertificate.

A feature of US contracts between serviceproviders and users is the inclusion of a fixedcharge to recover the investment costs and avariable charge for the marginal costs. NERAnotes that as a result of this approach to tariffsthere are no formal benefit sharing mechanismsor approaches to deal with blue sky. Thiscontrasts with Australia where volume-basedtariffs create the potential for blue sky to occur.

In addition, pipeline contracts in the US do notinclude most favoured nation’ clauses. NERAnotes that the inclusion of these clauses infoundation contracts has the effect of limitingthe capacity utilisation of the pipeline and,consequently, the market will develop moreslowly. The overall efficiency of new pipelineinvestment is likely to be sub-optimal. Incontrast, FERC encourages price discriminationby pipeline service providers with the view toincreasing the utilised capacity of the pipeline.

NERA notes that the code appears to beflexible enough to tackle most of the perceivedproblems associated with new gas pipelinedevelopments in Australia.


Summary of codeprovisions that facilitateregulatory certaintyThis summary is based on an extract ofmaterial from the NERA consultancy, NaturalGas Pipeline Access Regulation, 31 May 2001101

1. Section 2, Due process. Due process isfundamental to regulatory certainty.Section 2 defines the code’s provision ofdue process to the service provider andinterested parties. The service providerreceives a fair hearing, a decision withreasons, rights of appeal, and a transparentprocess. Various parties have complainedabout not being able to examine the actualtariff model of the companies regulatedunder the code, but NERA feels that thereis movement in this direction. Theseprovisions, along with the high level ofdetail specified in the code, protect theservice provider from regulatory caprice.

2. Section 2.21, Timely regulatory rulings.Section 2.21 (subject to 2.22) provides thatthe regulator must issue a final decisionwithin six months of receiving a proposedaccess arrangement, ensuring that theservice provider is not left in limboindefinitely. Six months is a reasonablelength of time, given the long lead timesinherent in gas pipeline investments andtime needed for consultation and dueprocess. Section 2.43 (subject to 2.44)continues this process for appeals andrevisions. Any delays in issuing an accessarrangement final decision is likely to be aconcern for providers of capital. To

Appendix 5

mitigate timing uncertainties for regulatorydecisions regarding greenfields pipelineprojects it is incumbent on projectproponents to pro-actively manageregulatory determination processes toensure regulators are able to promulgatedeterminations within the minimumprescribed timeframe.

3. Section 2.24, Protecting interests. TheACCC, as relevant regulator, is chargedwith the task of balancing the differentinterests of parties affected by the servicesoffered on the pipeline, and the terms andconditions on which those services areoffered. Accordingly, in assessing anaccess arrangement the ACCC mustconsider the interests of the serviceprovider, users, and the public interest.However, it cannot ignore or abrogate theservice provider’s existing contractualobligations. The factors it must consider are(inter alia):

(a) the service provider’s legitimatebusiness interests and investment in thecovered pipeline

(b) firm and binding contractualobligations of the service provider orother persons (or both) already usingthe covered pipeline

(c) the operational and technicalrequirements necessary for the safe andreliable operation of the coveredpipeline

(d) the economically efficient operation ofthe covered pipeline.

4. Section 2.50, Allowance for negotiatedarrangements. Section 2.50 (as well as thepreface to section 8) allows for a variety ofpricing structures. The code allowspipelines and customers to negotiate anyalternative arrangements upon which theyboth agree. ‘The Reference Tariff Principlesare designed to provide a high degree of

101 This summary is based on an extract of material fromthe NERA consultancy, Natural Gas Pipeline AccessRegulation (pp. 14–19). 31 May 2001. This summaryshould not be interpreted as legal advice on theinterpretation, effect or scope of the sections quoted.Should further clarification be required readersshould seek their own legal advice.


flexibility so that the Reference TariffPolicy can be designed to meet thespecific needs of each pipeline system.’102

However, coverage under the code ismeant to limit the exercise of pipelinemonopoly power, by capping pipelines’charges at their efficient costs, inaggregate. Pipelines have great latitude inprice setting, subject to this restriction.

5. Section 3.16(b), Pricing expansions.Section 3.16(b) sets out the pricing policyfor future investments in expansions/extensions (subject to 8.25 and 8.26,discussed below). Thus, when makingcommercial decisions the service providerand its users can know how anyprospective future investments will bepriced.

6. Sections 3.18 and 3.19, Accessarrangement duration. Sections 3.18 and3.19 allow for an access arrangementduration of any period. While five years isthe default expectation, it is explicitly notrequired. Where an access arrangementperiod is longer than five years, theregulator must consider whethermechanisms should be included to addressthe risks of forecasts proving incorrect. Anew pipeline seeking a longer duration(e.g. 10 years) could receive one under thecode’s provisions, provided it cansatisfactorily support its request. A longerinitial access arrangement period may bedesirable to the service provider, as it canprovide greater certainty for a longerperiod of time over the price path thecompany will use for its regulated services.

7. Section 6, Foundation shippers. Thepreface to section 6 recognises theimportance of contractual rights, includingcontracts held by ‘foundation shippers.’103

The code enables these arrangements toproceed without interference.

8. Section 6, Dispute resolution. Section 6 ofthe code sets out a formal disputeresolution mechanism. It provides thepipeline with the confidence that disputeswill be adjudicated in a predeterminedprocess. The code lays out guidelines,restrictions, and a formal procedure for thedispute arbitrator, protecting the pipelinefrom arbitrary, capricious, or confiscatorydecisions.

9. Section 6.15, Guidance for the arbitrator.Section 6.15 of the code requires that thedisputes arbitrator must take into account(inter alia):

(a) the service provider’s legitimatebusiness interests and investment in thecovered pipeline

(e) firm and binding contractualobligations of the service provider orother persons (or both) already usingthe covered pipeline

(f) the operational and technicalrequirements necessary for the safe andreliable operation of the coveredpipeline

(g) the economically efficient operation ofthe covered pipeline.

Under Section 6.15, the arbitrator must alsotake into account ‘the costs to the serviceprovider of providing access.’

10. Section 6.18, Restrictions on decisions.Section 6.18 limits the type of decisions anarbitrator can make, including decisionswhich that impede the rights of existingusers to obtain services, and any decisionwhich that requires the service provider toprovide services or any tariff other than areference tariff.

11. Section 8, Reference tariffs. Section 8specifies the method for setting prices, thecosts that will be examined and how theywill be examined, and a formal process fordoing so. These tariff principles give acompany’s investors considerable certaintyregarding their return on investment. Whilenot guaranteeing revenues, the tariffprinciples ensure that the company has afair opportunity to earn them.

102 Section 2.50 states: ‘For the avoidance of doubt,nothing (except for the Queuing Policy) contained inan access arrangement (including the description ofservices in a services policy) limits: (a) the services aservice provider can agree to provide to a user orprospective user; (b) the services that can be thesubject of a dispute under section 6; (c) the terms andconditions a service provider can agree with a useror prospective user; or (d) the terms and conditionsthat can be the subject of a dispute under section 6.’

103 ‘Because the arbitrator cannot deprive a person of acontractual right, ‘foundation shippers’ contractscannot be overturned by the arbitrator at either theservice provider’s or foundation shipper’s request.’


12. Section 8.3, Form of regulation. Section8.3 allows the service provider twoalternatives for setting prices: a ‘price path’or ‘cost of service.’ The price path approachassures the company of the prices it cancharge for the duration of the accessarrangement (which could be greater thanfive years). The cost of service approachadjusts the company’s prices ‘continuouslyin light of actual outcomes … to ensure thatthe tariff recovers the actual costs ofproviding the service.’ The pipeline decideswhich alternative to propose; thus, it canselect whichever one it deems fits its bestinterests. A service provider wanting a‘hands off’ regulatory arrangement canrequest it while a company wanting greatercertainty of cost recovery can request thatinstead.

13. Section 8.4, Total revenue. Section 8.4provides three alternative methodologiesfor calculating the revenue target. Likesection 8.3, this section offers the certaintyof a cost-of-service-based revenue targetmethodology, including a return on theasset value and an allowance for inflation(section 8.5). The alternativemethodologies—internal rate of return andnet present value—are meant to providethe same result. From the total revenuedetermination, reference tariffs arecalculated to provide that revenues matchcosts.

14. Section 8.12, Initial capital base, Newpipelines. Section 8.12 states that theinitial capital base will be valued by theactual costs of the asset and that thesecosts will be used to set reference tariffs(Section 8.8). These provisions protect theservice provider from the sorts of downwardrevaluations that could result from theapplication of hypothetical or theoreticalasset valuation methodologies. At the sametime they protect customers from theexercise of market power by a pipeline.Still, pipelines and their customers are freeto negotiate other prices, and foundationcustomer contracts remain protected. Theside-by-side existence of these provisions—cost-based prices and the freedom tonegotiate—provides pipeline companiesand their customers with a combination ofregulatory and commercial freedom.

15. Section 8.14, Rolling the asset baseforward. Section 8.14 builds on section8.12, determining the means by which theasset base will be valued at the expiry ofone access arrangement period and thecommencement of a subsequent one.Section 8.14 states that the rolled-forwardasset base will be:

… the Capital Base applying at the expiry ofthe previous Access Arrangement adjusted toaccount for the New Facilities Investment orthe Recoverable Portion (whichever isrelevant), Depreciation and RedundantCapital (as described in section 8.9) as if theprevious Access Arrangement had remainedin force.

In other words, when establishing a newaccess arrangement, the regulator cannotapply an alternative methodology thatwould decrease (or increase) the assetvalue.

16. Section 8.16, Pricing capacity expansions.Section 8.16, along with sections 8.25 and8.26, allows for expansion capacity to bepriced at either: (1) the price level ofexisting capacity, without necessitating areview of access arrangements; or (2) asurcharge to both existing customers andnew ones, where benefits accruesufficiently to existing customers. Allowingfor expansions to be priced at the existingprice level can provide regulatory certaintyto pipelines regarding the price level.Similarly, a predefined set of rules forincreasing reference tariffs at expansionsprovides certainty about how investmentcost recovery will take place.

17. Section 8.19, Speculative investment.Section 8.19 of the code deals withpipeline investments over and above theamount of investment in new facilities thatwould go into the capital base. This sectionallows for the creation of a speculativeinvestment fund that can later be put intothe capital base when these assets arecalled for. Until that time the capitalinvested is held in this account and canaccrue a rate of return on that investment,which will also be collected when theinvestment amount is put into the capitalbase. This regulatory ‘hold account’ is aflexible, powerful provision. A serviceprovider that anticipates future increases indemand beyond current amounts can make


a large investment all at once—takingadvantage of scale and scope economies—without the excess amount of itsinvestment being declared imprudent andwritten down. This is an important provisionfor providing investors with regulatorycertainty. At the same time it protectsexisting customers from paying the costs ofspare capacity.

18. Sections 8.30 and 8.31, Rate of return.Sections 8.30 and 8.31 of the code set outthe mechanism by which pipeline investorsrecover the costs on an investment—i.e.the rate of return on regulated pipelineinvestments—specifying clearly that themethodology used:

should provide a return which iscommensurate with prevailing conditions inthe market for funds and the risk involved indelivering the Reference Service. (Section8.30)

Section 8.31 specifies, via an example,how this can be carried out to satisfy thecode’s requirements. Specifying the rate ofreturn methodology provides an importantdegree of regulatory certainty to investorsby ensuring that they will not be subject toregulatory hold-up through either anoutright denial of a return on theirinvestment, or of a methodology that failsto reflect the risks inherent in thebusiness—a universal concern of pipelineinvestors. The ACCC/ORG cost of capitalforum (3 July 1998) produced considerablevaluable evidence on cost of capitalprocedures. The conclusions from thatforum have been referenced in manysubsequent regulatory decisions inAustralia, and they provide a reliable basisfor calculating the cost of capital in thefuture.

19. Section 8.32 and 8.33, Depreciation.Section 8.32, on depreciation, sets outrules for the mechanism by which pipelineinvestors recover the costs of aninvestment. Depreciation methodologiesare another means by which investors’money can be put at risk by a badregulatory regime. The failure to specify adepreciation practice, or to specify onethat is vague or subjective, can result inregulatory expropriation of investors’ funds.The code addresses these concerns head-on

by specifying that a regulated asset is fullydepreciated once, and only once, over itseconomic life. In this way the code strikesa balance in which investors recover thecosts of their investments, and customersare protected form the exercise ofmonopoly power.

20. Section 8.43, Discount practices. Section8.43 of the code allows, under certainspecified conditions, for the serviceprovider to extend discounts to price-sensitive customers, and recover theotherwise foregone revenues from its othercustomers. This provision of the codeprovides a means by which efficient usageof the pipeline can be furthered—throughavoiding having a pipeline sit with idlecapacity—while not leaving the pipelinewith a revenue shortfall. In sum, even afterdiscounting to price-sensitive customerswho would otherwise not take pipelineservice, target revenues continue to matchthe pipelines’ costs.

21. Sections 8.47 and 8.48, Fixed principles.Sections 8.47 and 8.48 deal with fixedprinciples. These provide a means ofestablishing certain aspects (structuralelements) of regulatory certainty acrossaccess arrangement periods. In this way aservice provider seeking certain provisionsto be sustained over a long term can do sowithout necessarily having to propose avery long access arrangement duration.

Structural elements specifically include‘the depreciation schedule, the financingstructure, and that part of the rate of returnthat exceeds the return that could beearned on an asset that does not bear anymarket risk.’ These provisions can provideinvestors with long-term regulatorycertainty over how their investment will betreated. The provisions clarify parametersover which the regulator might otherwiseseek to exercise discretion and whichcould leave investors unclear about futureregulatory changes.


Appendix 6

GlossaryACCC Australian Competition and Consumer Commission

access arrangement Arrangement for third party access to a pipeline providedby a pipeline owner and/or operator and submitted to therelevant regulator for approval in accordance with thecode

access arrangement information Information provided by a service provider to the relevantregulator pursuant to section 2 of the code

access arrangement period The period from when an access arrangement or revisionsto an access arrangement takes effect (by virtue of adecision pursuant to section 2) until the next revisionscommencement date

the Act Gas Pipelines Access (South Australia) Act 1997

AGA Australian Gas Association

bare transfer When the terms of a contract with a service provider arenot altered as a result of transfer or assignment of capacityrights

CAPM Capital asset pricing model

COAG Council of Australian Governments

code National Third Party Access Code for Natural Gas PipelineSystems

covered pipeline Pipeline to which the provisions of the code apply

CPI Consumer price index

CPI-X An adjustment that provides an automatic mechanism foradjusting tariffs to take account of ongoing inflation andprovides for the corresponding changes in rates of returnobserved in commercial markets

CWP Central West Pipeline

derogation A legislative exemption from compliance with specifiedobligations set out in the code

Duke Duke Energy International


EGP Eastern Gas Pipeline

Energy Users Energy Users Association of Australia

ED Expected demand

FERC Federal Energy Regulatory Commission

gas code National Third Party Access Code for Natural Gas PipelineSystems

GJ GigaJoule

greenfields pipeline For the purposes of this guideline, a greenfields pipeline isconsidered to encompass both proposed pipelines and newpipelines, the market for the output of which waspreviously non-existent

guideline Greenfields guideline for natural gas transmission pipelines

ICB Initial capital base

MFN Most favoured nation

Mpa Megapascal (unit of pressure)

NCC National Competition Council

NERA National Economic Research Associates

NPV Net present value

OffGAR The Office of Gas Access Regulation, Western Australia

Part IIIA Part IIIA of the Trade Practices Act 1974

PCCM Project cost containment mechanism

PJ PetaJoule (equal to 1 000 000 GJ)

PTRM Post tax revenue model

queuing policy A policy for determining the priority that a user, orprospective user has, as against any other user, orprospective user, to obtain access to spare capacity

reference service A service that is specified in an access arrangement and inrespect of which a reference tariff has been specified inthat access arrangement

reference tariff A tariff specified in an access arrangement ascorresponding to a reference service and which has theoperation that is described in sections 6.13 and 6.18 of thecode

ROE Return on equity


reference tariff policy A policy describing the principles that are to be used todetermine a reference tariff

revisions commencement date The date upon which the next revisions to the accessarrangement are intended to commence

revisions submissions date The date upon which the service provider must submitrevisions to the access arrangement

service A service provided by means of a covered pipelineincluding:

(a) haulage services (such as firm haulage, interruptiblehaulage, spot haulage and backhaul)

(b) the right to interconnect with a covered pipeline(c) services ancillary to the provisions of such services

but does not include the production, sale or purchasing ofnatural gas

service policy A policy detailing the service or services to be offered.

service provider The person who is the owner or operator of the whole orany part of the pipeline or proposed pipeline

shipper An alternative term generally used in this guideline todescribe an existing user of the pipeline

SFV Straight fixed variable

TJ Terajoule (equal to 1 000 GJ)

TPA Trade Practices Act 1974

Vanilla WACC The nominal weighted average of the cost of equity anddebt to the business before any adjustments for taxes andchange in the general level of prices

Vanilla WACC = E/V.Re + D/V.Rd

Where Re is the post-tax cost of equity determined by theCAPM formula and Rd is the pre-tax nominal cost of debt.

WACC Weighted average cost of capital


Related publicationsACCC, Access regime—a guide to Part IIIA ofthe Trade Practices Act, November 1995.

ACCC, Draft statement of principles for theregulation of transmission revenues, May 1999.

ACCC, Access undertakings—a guide to PartIIIA of the Trade Practices Act, September1999.

ACCC, Access arrangement by AGL Pipelines(NSW) Pty Ltd for the Central West Pipelinefinal decision, June 2000.

ACCC, Post tax revenue handbook, October2001.

The Brattle Group, Third-party access to naturalgas networks in the EU, March 2001, p. 24.

Commonwealth of Australia, Gas Reform TaskForce 1996, National Third Party Access Codefor Natural Gas Pipeline Systems.

Davis, K and Handley, J, Report on Cost ofcapital for greenfields investment pipelines,February 2002.

Macquarie Bank Limited, Issues for debt andequity providers in assessing greenfields gaspipelines, March 2002.

National Economic Research Associates,Regulation of tariffs for gas transportation in acase of ‘competing’ pipelines: Evaluation offive scenarios, Sydney, October 2000.

National Economic Research Associates,International comparison of utilities’ regulatedpost tax rates of return in: North America, theUK, and Australia, Sydney, March 2001.

National Economic Research Associates,Natural gas pipeline access regulation, Sydney,May 2001.

Appendix 7

National Economic Research Associates,Foundation contracts and ‘greenfields’ gaspipeline developments: Experience from theUnited States and other jurisdictions, Sydney,March 2002.

Office of the Regulator General, 2003 Reviewof Gas Access Arrangements, ConsultationPaper No. 1, May 2001.


Contacts

ACCC Infocentre(for all business and consumer inquiries)

infoline 1300 302 502

websites http://www.accc.gov.au

http://www.forums.accc.gov.au

Regulatory Affairs DivisionJoe Dimasi (03) 9290 1814

Gas BranchKanwaljit Kaur (02) 6243 1259

Electricity GroupMichael Rawstron (02) 6243 1249

Transport and Prices Oversight GroupMargaret Arblaster (03) 9290 1862

Telecommunications GroupMichael Cosgrave (03) 9290 1914

Media liaisonLin Enright (02) 6243 1108

General publications queriesPublishing Unit, Canberra(02) 6243 1143Email: [email protected]

1. Summary Draft greenfields guideline for natural gas ... ACCC... · Moreover, according to the...

Documents

Transcript of 1. Summary Draft greenfields guideline for natural gas ... ACCC... · Moreover, according to the...