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Core Energy Group 2012 April 2012 i
Gas Transmission Costs
April 2012
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Gas Transmission Costs Disclaimer
Core Energy Group 2012 April 2012 i
Terms of Use
This document has been prepared by Core Energy Group Pty Limited, A.C.N. 110 347 085, holder of AFSL 307740 (Core )
for the sole purpose of providing the AEMO with an analysis of the gas transmission costs for eastern Australia as at 1
January 2012.
This document has been prepared on the basis of a specific scope and does not purport to contain all the information that a
particular party may require. The information contained in this document is general in nature and may not be appropriate for
all persons and it is not possible for Core to have regard to the investment objectives, financial situation and particular needs
of each party who reads or uses this document. It must not be distributed to retail investors. The information is not an
invitation to invest or deal in any securities and you should seek independent professional advice before making any
investment decisions.
Core believes that the information contained in this document has been obtained from sources that are accurate at the time
of issue, but makes no representation or warranty as to the accuracy, reliability, completeness or suitability of the information
contained within this document. To the extent permitted by law, Core, its employees, agents and consultants accept noliability (including liability to any person by reason of negligence or negligent misstatement) for any statements, opinions,
information or matter (expressed or implied) arising out of the information contained within this document.
Core Energy Group All material in this document is subject to copyright under the Copyright Act 1968 (Commonwealth)
and international law and permission to use the information must be obtained in advance and in writing from Core.
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Gas Transmission Costs Table of Contents
Core Energy Group 2012 April 2012 ii
Table of Contents
Terms of Use ............................................................................................................................................................................ i
List of Tables and Figures .............................................................. ................................................................ ........................ iii
List of Tables .................................................................................................................................................................................................. iii
List of Figures ................................................................................................................................................................................................. iii
1.
Introduction .................................................................. .................................................................... ......................... 1
2. Background....................................................................................... ..................................................................... .... 1
3.
Scope ......................................................................................................................................................................... 1
4.
Methodology ......................................................................................................................... .................................... 2
5.
Relationship Between Pipeline Costs and Tariffs ............................................................... .................................... 3
5.2.
Illustrative Calculation of Tariff ........................................................................................................................................................ 5
5.3.
Relative Composition of Pipeline Tariffs ......................................................................................................................................... 5
6.
Major Existing Pipelines ....................................................................... ................................................................ .... 7
6.1. Location Overview .......................................................................................................................................................................... 7
6.2. Existing Pipeline Profiles ................................................................................................................................................................. 8
6.3. Cost Projections .............................................................................................................................................................................. 9
7.
Major Proposed Domestic Pipelines ........................................................................ .............................................. 13
7.1.
Location Overview ........................................................................................................................................................................ 13
7.2.
Proposed Domestic Pipeline Profiles ............................................................................................................................................ 14
7.3. Cost Projections ............................................................................................................................................................................ 15
8.
Major Proposed LNG Pipelines ........................................................... ................................................................... 17
8.1. Proposed LNG Pipeline Profiles .................................................................................................................................................... 17
8.2. Cost Projections ............................................................................................................................................................................ 18
9.
New Pipelines ..................................................................... ................................................................. .................... 20
10.
Validation of Capital and Non-Capital Expenditure ............................................................................................. 21
10.1. Capital Expenditure ....................................................................................................................................................................... 21
10.2.
Non-Capital Expenditure................................................................................................................................................................ 24
10.3. Tariffs ............................................................................................................................................................................................ 25
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Gas Transmission Costs List of Tables and Figures
Core Energy Group 2012 April 2012 iii
List of Tables and Figures
List of Tables
Table 6.1: Existing Transmission Pipelines ............................................................................................................ ............... 8
Table 6.2: Existing Pipelines Near Term Planned Expansions ................................................................ .......................... 9
Table 6.3: Existing Pipelines Forward Non-Capital Costs ............................................................... ................................... 10
Table 6.4: Existing Pipeline Tariffs ................................................................ ....................................................................... 12
Table 7.1: Planned and Proposed Transmission Pipelines .................................................................... ............................. 14
Table 7.2: Proposed Domestic Transmission Pipelines Estimated Capital Cost ........................................................... 15
Table 7.3: Proposed Domestic Transmission Pipelines Estimated Non-Capital Costs ................................................. 16
Table 8.1: Proposed LNG Gas Transmission Pipelines................................................................................ ....................... 17
Table 8.2: Proposed LNG Gas Transmission Pipelines - Estimated Capital Cost ............................................. ............... 18
Table 8.3: Proposed Domestic Transmission Pipelines Non-Capital Costs ...................................................................... 19
List of Figures
Figure 5.1: Typical Pipeline Construction Sequence ............................................................................................................ 4
Figure 5.2: Revenue Composition of Transmission Pipelines ............................................... .............................................. 6
Figure 6.1: Existing Gas Transmission Pipelines ................................................................................................... ............... 7
Figure 7.1: Committed and Proposed Domestic Gas Transmission Pipelines ................................................................. 13
Figure 10.1: Capital Cost per Kilometre Proposed LNG Gas Transmission Pipelines ......... ......................................... 21
Figure 10.2: Capital Cost per Kilometre Proposed Domestic Gas Transmission .......................................................... 22
Figure 10.3: Non Capital Costs per km ............................................................... ................................................................. 24
Figure 10.4: Effective Gas Transmission Pipeline Tariff ..................................................................................................... 25
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Gas Transmission Costs 1. Introduction
Core Energy Group 2012 April 2012 1
1. IntroductionThe objective of this report is to present certain projections of gas transmission cost for defined pipelines in east and south
eastern Australia as at 1 January 2012.
2. BackgroundIn March 2012 Core Energy was engaged by AEMO to support the development of six defined elements of the 2012 Gas
Statement of Opportunities (GSOO), including this element; the scope of which is set out below.
3. ScopeThe scope agreed between Core Energy and AEMO for this element of the engagement, as incorporated in the final
executed agreement, is presented below:
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Gas Transmission Costs 4. Methodology
Core Energy Group 2012 April 2012 2
4. MethodologyCore Energy has developed a seven part process to ensure the delivery of accurate/ high quality information to AEMO.
Review existing CoreEnergy gas transmission
databases and references
Construct spreadsheetframework to address totalneeds of AEMO, includingall technical assumptions
for each proposed pipelineand relevant existing
pipelines
Submit spreadsheetframework and exampledata to AEMO to confirm
consistent with needs
Conduct thoroughresearch to populate all
cost information bypipeline, working with AWT
Develop and run cash flowmodels to derive
breakeven capital andoperating costs at10% and
0% WACC.
Submit progress reports toAEMO to ensure
satisfaction and submitfinal draft spreadsheet for
review
Prepare draft report,submit for review, finalise
report incorporating AEMOcomments, together with
final spreadsheet andreferences
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Gas Transmission Costs 5. Relationship Between Pipeline Costs and Tariffs
Core Energy Group 2012 April 2012 3
5. Relationship Between Pipeline Costs and Tariffs
The cost of transmitting gas from one point to another is captured by the tariffs charged by pipeline operators to customers.
Generally, pipeline tariffs are reflective of an objective of the pipeline owners to recover the costs of constructing, operating
and maintaining the pipeline, as well as make a return on their investment.
For existing regulated or covered pipelines, tariffs are usually determined on a periodic basis by the Australian Energy
Regulator (AER) through approved access arrangements. The basis of the determination of tariffs is the building block
approach, which applies the net present value (NPV) methodology as permitted by Section 8.4 of the Gas Code, to
estimate the total annual revenue / tariffs that service providers will require over the regulatory period to provide its investors
with a reasonable rate of return commensurate with the business risks involved and to allow the service providers to meet
efficiently incurred costs relevant to providing the regulated services.
The building block approach involves projecting the following types of costs or building blocks for each year of a regulatory
period:
Indexation of the regulatory asset base (RAB );
Return on capital;
Depreciation;
Estimated cost of corporate income tax;
Revenue increments or decrements resulting from the operation of an incentive mechanism; and
Forecast operating expenditure, including unaccounted for gas.
RAB
The RAB serves two purposes:
To establish the asset base upon which a rate of return must be earned in any period; and
To form the basis for calculating the regulatory depreciation charge over any period.
The RAB equals initial asset base plus capital expenditure less regulatory depreciation, plus asset revaluation less
disposals. The initial asset base is based on the capital cost of the infrastructure for a facility, or the commercial fair value,
derived using principles set out in the Gas Code.
The costs incurred in the construction of a transmission pipeline are ordinarily the major contributor to the asset base. The
following figure illustrates the various stages of a typical pipeline construction sequence and hence draws attention the
various cost elements that should be considered in determining the capital cost base for determining the tariff of potential
future pipelines.
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Gas Transmission Costs 5. Relationship Between Pipeline Costs and Tariffs
Core Energy Group 2012 April 2012 4
Figure 5.1: Typical Pipeline Construction Sequence
Source: APA Investor Presentation, Site Visit 2010
In addition to the pipeline construction costs, a number of other capital expenditure items include pigging, pipeline
excavation and inspection and compressor overhauls, are included as capital expenditure items.
Return on Capital
To calculate the rate of return used, it is common practice to use the weighted average cost of capital (WACC) approach
based on the capital asset pricing model (CAPM), to arrive at a post-tax rate.
Regulatory Depreciation
Regulatory depreciation or return of capital to reflect the gradual recovery of capital costs associated with the project.
Regulatory depreciation is calculated on a straight line basis.
Income Tax
Service Providers are subject to Australian income tax at the statutory corporate tax rate. When setting the annual revenue
requirement, the Service Providers effective tax rate is considered, which takes into account the impact of accelerated
depreciation, etc to ensure the correct post-tax rate of return required by investors is achieved.
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Gas Transmission Costs 5. Relationship Between Pipeline Costs and Tariffs
Core Energy Group 2012 April 2012 5
Incentive Mechanisms
Incentive mechanisms are employed to entice the service provider to pursue efficiencies in the delivery of its service to
customers. These incentive mechanisms and are commonly based on outperforming operating expenditure forecasts and
may result in the service provider receiving an increment to revenue in the following Access Arrangement period.
Operating Expenditure
Forecast costs are treated as a pass through item in establishing regulated revenues, and include operating and
maintenance costs, wages and salaries.
One significant uncontrollable cost is unaccounted for gas (UAG), representing purchases of gas in replacement of gas lost
in network, commonly as a result of leaking distribution pipes and inaccuracies in gas meters.
5.2. Illustrative Calculation of Tariff
Customer usage demand forecasts are used to calculate the reference tariffs and also influence forecast capital and
operating expenditure.
Source: APA Group;Access Arrangement Information for Roma to Brisbane Pipeline; 28 February 2007
5.3. Relative Composition of Pipeline Tariffs
From the above overview of the building block approach, it can be understood that the calculated tariffs are reflective of a
number of different cost components as well as a return on investment. It is therefore interesting to see the breakdown of a
calculated tariff to understand the relative contribution of each of those components to the final calculated tariff.
The following figure illustrates the breakdown of the tariffs for the Declared Transmission System (DTS) and Roma to
Brisbane Pipeline (RBP), amongst components return on capital, depreciation, operating and maintenance and taxation.
The figure shows that the relative composition of tariffs is materially consistent between the two relevant pipelines
Year 1 Year 2 Year 3 Year 4 Year 5
Return on Capital 16.17 16.08 15.86 15.62 15.38
Non-Capital Costs 8.31 8.28 8.24 8.19 8.14
Taxation 0.69 0.74 0.79 0.82 0.91
Depreciation 5.85 6.12 6.19 6.32 6.62
Less: Capital Contributions - - - - -
Less: Ancillary Services Revenue - - - - -
Total Revenu e (AUDm) 31.01 31.22 31.08 30.94 31.06
Projected Demand (PJ / a) 51.1 56.5 57.3 57.5 57.7
Calcul ated Tariff (AUD / GJ) 0.55
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Gas Transmission Costs 5. Relationship Between Pipeline Costs and Tariffs
Core Energy Group 2012 April 2012 6
Figure 5.2: Revenue Composition of Transmission Pipelines
Source: ACCC, Revised access arrangement by GasNet Australia Ltd for the principal transmission system, final decision, April 2008; and ACCC, Revisedaccess arrangement by APT Pipelines Ltd for the Roma to Brisbane Pipeline, final decision, December 2006.
46%
28%
26%
Revenue composi tion for the DeclaredTransmission System
2008 - 12
Return on Capital
Depreciation
Operating andmaintenance
Tax
48%
21%
29%
2%
Revenue composi tion fo r the Roma toBrisbane Pipeline
2007 - 11
Return on Capital
Depreciation
Operating andmaintenance
Tax
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Gas Transmission Costs 6. Major Existing Pipelines
Core Energy Group 2012 April 2012 7
6. Major Existing Pipelines
6.1. Location Overview
The following map provides an overview of all existing gas transmission pipelines in eastern and south eastern
Australia.
Figure 6.1: Existing Gas Transmission Pipelines
Source: Core Energy Group.
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Gas Transmission Costs 6. Major Existing Pipelines
Core Energy Group 2012 April 2012 8
6.2. Existing Pipeline Profiles
Key features of these pipelines are summarised in the following table:
Table 6.1: Existing Transmission Pipelines
Source: Core Energy Group.
A brief description of each processing pipeline is presented in Attachment 3 to the Item 1 report, Review of Facilities:
Existing and New.
1AEMO; Gas Statement of Opportunities; 2011
2APA Group website.
3Jemena website.
4APA Group website.
5Epic Energy website.
6APA Group website.
7http://www.ghd.com/PDF/NthQldGasPipelin%20ProjectSheet.pdf
8APA Group website.
9Jemena website.
10APA Group website.
11APA Group website.12
SEA Gas Pipeline website.13
AER; State of the Energy Market; 200914
Tasmania Gas Pipeline website.
Pipeline
ExistingCapacity
(TJ / d)
Length
(km)
Diameter
(mm)1
Start Node End NodeRegulation
Status
Carpentaria Gas Pipeline2 108 840 150, 300 Ballera Mt Isa Light
Eastern Gas Pipeline3 268 797 450 Longford Sydney Not Covered
Longford to Melbourne Gas Pipeline4 1,030 174 500, 750 Longford Melbourne Covered
Moomba to Adelaide Pipeline System(MAPS)
5
253 1,185 150, 200,550
Moomba Adelaide Not Covered
Moomba to Sydney Pipeline System(MSP)
6
439 1,300 150, 200,250, 300,450, 850
Moomba Sydney Covered
North Queensland Gas Pipeline7 108 392 254 Moranbah Townsville Not Covered
NSW - Victoria Interconnect8 71 to NSW,
92 to VIC88 450 Wagga
WaggaAlbury Not Covered
Queensland Gas Pipeline (QGP)9 142 627 200, 300 Wallumbilla Gladstone Not Covered
Roma to Brisbane Pipeline (RBP)10
219 438 250, 300,400
Wallumbilla Brisbane Covered
South East Australia (SEA) GasPipeline
11
314 680 350, 450 PortCampbell
Adelaide Not Covered
South West Pipeline12
353 150 500 Iona Portland Covered
South West Queensland Pipeline13
385 937 400 Wallumbilla Moomba Not Covered
Tasmania Gas Pipeline14
129 734 150, 200,
350
Longford Hobart Not Covered
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Gas Transmission Costs 6. Major Existing Pipelines
Core Energy Group 2012 April 2012 9
6.3. Cost Projections
6.3.1. Capital Costs
At the date of this report, the following table provides an estimate of forward capital costs for existing transmission pipelines:
Table 6.2: Existin g Pipelin es Near Term Planned Expansions
Source: Bureau of Resources and Energy Economics; Core Energy Group.
15APA Group website.
16Bureau of Resources and Energy Economics, Mining Industry Major Projects October 2011, November 2011.17
Jemena website.18
Ibid.19
Hastings Diversified Utilities Fund; SWQP Santos Backhaul Contract Announcement.
PipelineExisting Capacity
(TJ / d)Planned Expansion
EstimatedExpansion Timing
Capital Cost
(AUDm)
Carpentaria Gas Pipeline 108
Eastern Gas Pipeline 268
Longford to Melbourne Gas Pipeline 1030
Moomba to Adelaide Pipeline System 253
Moomba to Sydney Pipeline System15
439 5 year program toincrease wintercapacity by 20%.
Prior to winter 2013. 10016
North Queensland Gas Pipeline 108
NSW - Victoria Interconnect 71 to NSW, 92 toVIC
Queensland Gas Pipeline 142
Roma - Brisbane Pipeline17
219 10% capacityexpansion additionalcompressor at Dalbyand duplication of6km
To be completed 2H2012.
5018
South East Australia Gas Pipeline 314
South West Pipeline 353
South West Queensland Pipeline 385 Backhaul 52 TJ / d19
30
Tasmania Gas Pipeline 129
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Gas Transmission Costs 6. Major Existing Pipelines
Core Energy Group 2012 April 2012 10
6.3.2. Non-Capital Costs
At the date of this report, the following table provides an estimate of forward real non-capital costs for existing transmission
pipelines:
Table 6.3: Existing Pipelines Forward Non-Capital Costs
Source: APA Group; Core Energy Group.
* Insufficient publicly available information from which to derive estimates of non-capital costs, e.g. tariffs, etc.^ Non-capital costs as a percentage of revenue were determined, from available information, to average approximately 26%. On this basis, with knowninformation regarding pipeline tariffs, lengths and capacity, non-capital costs were estimated.^^ Non-capital costs were determined as a percentage of revenue (estimated to be approximately 26%) and calculated through an extrapolation of publiclyavailable pipeline tariff data, pipeline length and capacity. These costs are exclusive of marketing and system administration costs.
A closer analysis of the above table identifies that between existing transmission pipelines, even when compared on an AUD
per kilometre basis in order to remove the impact of length on cost, there exists material variances between the non-capital
costs. The following is an analysis of the primary factors giving rise to those variances:
Moomba to Sydney Pipeline ( MSP )
Compared to a number of other similar pipelines, for example MAPS and the Roma-Brisbane Pipeline, the MSP has
relatively lower operating and maintenance costs due to its lower level of compression and fuel usage for compression.
Longford to Melbourne Pipeline and South West Pipeline (Declared Transmission System)
The non-capital cost assumptions for the Longford to Melbourne Pipeline and South West Pipeline are derived from costs
incurred and extrapolated over the entire length of the Declared Transmission System (DTS). The inputs into these
estimations were sourced from the access arrangement of the owner, APA Group.
In Cores view, based on discussion on the comparison of the DTS to other transmission pipeline systems taken from
various access arrangement decisions, a primary driver of the higher non-capital costs of the operator, as relating to the
DTS, is the added complexity of the integrated Victorian system due to factors such as grid arrangement and volatility of gas
flow through the system.
20ACCC;Access Arrangement Information for Roma Brisbane Pipeline; March 2007.
21Ibid.
22Ibid.
PipelineCapacity
(TJ / d)
Length
(km)Non-Capital Costs
(AUD / km)
Carpentaria Gas Pipeline 108 840 14,057^
Eastern Gas Pipeline 268 797 30,500^
Longford to Melbourne Gas Pipeline 1030 174 45,270^^
Moomba to Adelaide Pipeline System 253 1,185 17,50020
Moomba to Sydney Pipeline System 439 1,300 10,00021
North Queensland Gas Pipeline 108 392 *
NSW-Victoria Interconnect 71 to NSW, 92 to VIC 88 *
Queensland Gas Pipeline 142 627 11,060^
Roma - Brisbane Pipeline 219 438 12,40022
South East Australia Gas Pipeline 314 680 17,000^
South West Pipeline 353 150 20,655^
South West Queensland Pipeline 385 937 14,000^
Tasmania Gas Pipeline 129 734 12,300^
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Gas Transmission Costs 6. Major Existing Pipelines
Core Energy Group 2012 April 2012 11
Another specific factor relating to the Longford to Melbourne Pipeline is its capacity, being tasked with supplying much of
Victorias indigenous gas; the pipeline has a capacity of approximately 1,030 TJ per day. With increased pipeline diameter to
handle higher volumes of gas throughput, the Longford to Melbourne Pipeline requires higher levels of operating and
maintenance expenditure per kilometre than pipelines of a lesser size and capacity.
Eastern Gas Pipeline (EGP )It should be noted that non-capital costs of pipelines were estimated as a percentage of revenues (approximately 26%)
based on the indicative revenue composition of a number of existing pipelines for which that information was made publicly
available including MAPS, MSP and the RBP.
The EGP can be distinguished from those pipelines firstly by its age the EGP was constructed in 2000, whilst those
aforementioned pipelines were constructed during the late 1960s and early 1970s. Accordingly, the revenue calculation of
those pipelines is likely to comprise a greater non-capital cost component due to the substantially depreciated nature of
capital costs. A newer pipeline such as the EGP on the other hand is likely to be characterised by non-capital costs
comprising a less significant proportion of the revenue calculation relative to depreciation and return on capital.
In further support of this, in its application for coverage of the EGP in 2000, the National Competition Council made
submissions to the effect that the EGP would be characterised by high construction costs and low operating costs.23
In light of the above, the estimated non-capital costs per kilometre for EGP may not necessarily be indicative and should
therefore be construed with care.
Roma-Brisbane Pipeline ( RBP)
It should be noted that this non-capital costs per kilometre figure published by APA Group represents total pipeline length,
rather than route distance. The RBP is unique in the eastern Australian gas market in that it is characterised by extensive
looping almost along its entirety. Although there are some non-capital costs that are dependent on overall pipeline length as
opposed to route length, for example intelligent pigging costs, there are a range of costs that can be shared by pipeline
loops, for example easement patrols. Accordingly the RBP compares favourably to a pipeline such as the MAPS, which has
similar compression requirements, on a non-capital cost per kilometre basis.
23National Competition Council;Application for Coverage of the Eastern Gas Pipeline; June 2000.
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Gas Transmission Costs 6. Major Existing Pipelines
Core Energy Group 2012 April 2012 12
6.3.3. Access Tariffs
At the date of this report, the following table provides an estimate of tariff charges for existing transmission pipelines that are
covered or for which tariff information has been otherwise made publicly available:
Table 6.4: Existing Pipeline Tariffs
Source: Core Energy Group.
* Current publicly available tariff components data unavailable.
24NERA; The Gas Supply Chain in Eastern Australia ; June 2007.
25APA Group website.
26Jemena website.
27NERA; The Gas Supply Chain in Eastern Australia ; June 2007.
28Epic Energy; MAPS Key Commercial Terms; 2011.
29Ibid.
30APA Group website.
31Ibid.
32Jemena website.
33Ibid.
34Ibid.35
AUD0.63 per GJ in 2006 per Epic Energy; Application by Epic Energy to Revoke Coverage of the Moomba-Adelaide Pipeline; 3 May2005. Inflated by CPI ~2.5% p.a.36
AER; State of the Energy Market; 2009.
PipelineCapacity
(TJ / d)
Length
(km)
CapacityCharge
(AUD / GJ)
CommodityCharge
(AUD / GJ)
Tariff AEMC Jan
2007
(AUD / GJ)24
IndicativeTariff
(AUD / GJ)
Carpentaria Gas Pipeline 108 840 * 1.4425
1.44 1.44
Eastern Gas Pipeline 268 797 * Firm: 1.1642
Non-Firm:1.5135
26
1.04 1.16
Longford to Melbourne Gas Pipeline 1030 174 * * 0.23 0.2427
Moomba to Adelaide Pipeline System 253 1,185 0.513928
0.136129
0.55 0.65
Moomba to Sydney Pipeline System 439 1,300 0.832530
0.0469331
0.68 0.88
Queensland Gas Pipeline 142 627 * Firm: 0.8993Non-Firm:1.6128
32
0.90
Roma - Brisbane Pipeline 219 438 0.474233
0.031734
0.05 0.51
South East Australia Gas Pipeline 314 680 * * 0.72 0.7335
South West Pipeline 353 150 * * 0.24 0.27
South West Queensland Pipeline 385 937 * * 0.85 0.96
Tasmania Gas Pipeline 129 734 * * 1.85 2.0036
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Gas Transmission Costs 6. Major Proposed Domestic Pipelines
Core Energy Group 2012 April 2012 13
7. Major Proposed Domestic Pipelines
7.1. Location Overview
The following map provides an overview of all committed and proposed domestic gas transmission pipelines in
eastern and south eastern Australia.
Figure 7.1: Committed and Proposed Domestic Gas Transmis sion Pipeli nes
Source: Core Energy Group.
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Gas Transmission Costs 6. Major Proposed Domestic Pipelines
Core Energy Group 2012 April 2012 14
7.2. Proposed Domestic Pipeline Profiles
Key features of these pipelines are summarised in the following table:
Table 7.1: Planned and Proposed Transmissio n Pipelines
Source: Various and Core Energy Group.
* No specifications publicly available.
A brief description of each processing pipeline is presented in Attachment 3 to the Item 1 report.
37Bureau of Resources and Energy Economics, Mining Industry Major Projects October 2011, November 2011.
38Eastern Star Gas, Coolah to Newcastle Pipeline Preliminary Environmental Assessment.
39ERM; Environmental Assessment Young to Wellington Gas Pipeline; May 2010.
40Energy World Corporation;Annual Report 2011.
41Ibid.
42Galilee Energy;AGM Presentation; November 2010.
43AGL; Gloucester Gas Project Environmental Assessment; November 2009.
44AGL website.
45Origin Energy; Ironbark Project Initial Advice Statement; October 2011.
46NSW Dept of Planning; Liddell Pipeline North South Route Major Project Assessment; June 2009.
47NSW Dept of Planning; Liddell Pipeline East West Route Major Project Assessment ; July 2009.48
Metgasco; The Lions Way Pipeline Brochure.49
Hunter Gas Pipeline; Queensland Hunter Gas Pipeline Environmental Assessment; September 2008.50
Eastern Star Gas; Narrabri CSG Project Preliminary Environmental Assessment; September 2010.
PipelineCapacity
(TJ / d)
Length
(km)Start Node End Node Status
37
Coolah to NewcastlePipeline
38
>400 280 Gunnedah Newcastle Advanced
ERM Wellington Pipeline39
* 219 Young Wellington Advanced
EWC Pipeline (Surat /Bowen)
40
* 350 * Abbot Point / HayPoint
Publiclyannounced
EWC Pipeline (Gilmore /Eromanga)
41
* 550 * Abbot Point / HayPoint
Publiclyannounced
Galilee to BarcaldinePipeline
42
* 80 * Barcaldine Publiclyannounced
Gloucester CSG Pipeline43
40 - 60 95 100 Stratford Hexham Advanced
Hunter Gas ProjectPipeline
44
96 Hunter Valley Newcastle Publiclyannounced
Ironbark Project Pipeline45
50 - 140 440 Tara Darling DownsPipeline
Publiclyannounced
Lidell Gas Pipeline46
47
* 76 Various Mines inHunter Valley
Liddell PowerStation
Publiclyannounced
Lions Way Pipeline48
74 145 Casino Ipswich Advanced
Queensland Hunter GasPipeline
49
230 - 450 825 Wallumbilla Newcastle Advanced
Wallumbilla to GunnedahGas Pipeline
50
* 850 Gunnedah Wallumbilla orQGP
Publiclyannounced
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Gas Transmission Costs 6. Major Proposed Domestic Pipelines
Core Energy Group 2012 April 2012 15
7.3. Cost Projections
7.3.1. Capital Costs
At the date of this report, the following table provides an estimate of forward capital costs for proposed domestic
transmission pipelines:
Table 7.2: Proposed Domestic Transmission Pipelines Estimated Capital Cost
Source: Various and Core Energy Group
* No specifications publicly available.
**Capital cost estimated by Core Energy Group due to lack of publicly available cost estimates. Please refer to subsection 10.1 for basis of calculation.
51Bureau of Resources and Energy Economics, Mining Industry Major Projects October 2011, November 2011.
52Ibid.
53Ibid.
54Ibid.
55NSW Dept of Planning; Liddell Pipeline North South Route Major Project Assessment; June 2009.56
NSW Dept of Planning; Liddell Pipeline East West Route Major Project Assessment ; July 2009.57
Bureau of Resources and Energy Economics, Mining Industry Major Projects October 2011, November 2011.58
Ibid.
PipelineLength
(km)
Diameter
(inches)
Operating Pressure
(MPa)
Estimated CapitalCost
(AUDm)
Coolah to Newcastle Pipeline 280 * * 252**
ERM Wellington Pipeline 219 20.3 15.3 20051
EWC Pipeline (Surat / Bowen) 350 N/A * 58352
EWC Pipeline (Gilmore / Eromanga) 550 N/A * 91653
Galilee to Barcaldine Pipeline 80 * * 72**
Gloucester CSG Pipeline 95 100 18 15.3 50 - 80
54
Hunter Gas Project Pipeline 96 * * 87**
Ironbark Project Pipeline 440 * * 396**
Lidell Gas Pipeline 76 20 1.05 2555
56
Lions Way Pipeline 145 * * 12057
Queensland Hunter Gas Pipeline(QHGP)
825 20 15.3 90058
Wallumbilla to Gunnedah Gas Pipeline 850 * * 765**
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Gas Transmission Costs 6. Major Proposed Domestic Pipelines
Core Energy Group 2012 April 2012 16
7.3.2. Non-Capital Costs
At the date of this report, there had been limited disclosure with regards to estimates of forward real non-capital costs for
proposed domestic transmission pipelines, however on the basis of guidance previously provided by the ACCC
(approximately 2% of replacement cost for uncompressed pipelines); non-capital costs for proposed domestic transmission
pipelines have been estimated and summarized below:
Table 7.3: Proposed Domestic Transmission Pipelines Estimated Non-Capital Costs
Source: Various and Core Energy Group
^ Operating costs estimated on the basis of approximate range from 2.0% of replacement cost for uncompressed pipelines as previously prescribed by the
ACCC as appropriate
59
.
The above figures are intended to be illustrative only and are largely dependent on the capital cost assumptions for each of
the proposed pipelines. Accordingly, with the exception of the Lidell Gas Pipeline, which is a low pressure pipeline and
therefore expected to have materially lower operating expenditure requirements, variances in non-capital cost estimates for
each of the above pipelines is a result of differences in construction cost estimates, which may be a product of timing and
prevailing market conditions, the maturity of respective project plans and due diligence, and various other factors.
59ACCC;Access Arrangement Information for Roma Brisbane Pipeline; March 2007
PipelineLength
(km)
Estimated CapitalCost
(AUDm)
Estimated Non-Capital Cost
(AUDm p.a.)^
Estimated Non-Capital Cost
(AUD / km)
Coolah to Newcastle Pipeline 280 252 5.0 18,000
ERM Wellington Pipeline 219 200 4.0 18,265
EWC Pipeline (Surat / Bowen) 350 583 11.7 33,300
EWC Pipeline (Gilmore / Eromanga) 550 916 18.3 33,300
Galilee to Barcaldine Pipeline 80 72 1.4 18,000
Gloucester CSG Pipeline 95 100 50 - 80 1.3 13,000
Hunter Gas Project Pipeline 96 87 1.7 18,125
Ironbark Project Pipeline 440 396 7.9 18,000
Lidell Gas Pipeline 76 25 0.5 6,600
Lions Way Pipeline 145 120 2.4 16,500
Queensland Hunter Gas Pipeline(QHGP)
825 900 18.0 21,800
Wallumbilla to Gunnedah Gas Pipeline 850 765 15.3 18,000
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Gas Transmission Costs 7. Major Proposed LNG Pipelines
Core Energy Group 2012 April 2012 17
8. Major Proposed LNG Pipelines
8.1. Proposed LNG Pipeline Profi les
Key features of these pipelines are summarised in the following table:
Table 8.1: Proposed LNG Gas Transmissio n Pipelines
Source: Various and Core Energy Group
* No specifications publicly available.
A brief description of each processing pipeline is presented in Attachment 3 to the Item 1 report.
60Australia Pacific LNG; Project Environmental Impact Statement; March 2010.
61Arrow Energy, Surat to Gladstone Pipeline Project Environmental Impact Statement Executive Summary, July 2009.
62Arrow Energy;Arrow Bowen Pipeline Project Environmental Impact Statement;March 2012.
63AEMO; Gas Statement of Opportunities; 2011.
64Bureau of Resources and Energy Economics, Mining Industry Major Projects October 2011, November 2011.
65Blue Energy; Review of Operations AGM Presentation; 11 November 2009.66
Santos; GLNG Project - Envirnmental Impact Statement; March 2009.67
QGC; Queensland Curtis LNG Environmental Impact Statement; July 2009.68
http://www.industry.qld.gov.au/lng/projects-queensland.html
PipelineCapacity
(TJ / d)
Length
(km)Start Node End Node Status
APLNG Pipeline60
1,250 362 Miles Gladstone Committed
Arrow Surat Pipeline61
490 1,000 470 Surat Basin Gladstone Advanced
Arrow Bowen Pipeline62
490 1,000 600 Bowen Basin Gladstone Advanced
Blackwater to Gladstone Pipeline63
274 257 Blackwater Gladstone Publiclyannounced
Central Queensland Gas Pipeline64
55 137 440 Moranbah Gladstone Advanced
Galilee to Export Markets65
* * * Gladstone Publiclyannounced
GLNG Pipeline66
630 - 2100 435 Surat / BowenBasins
Gladstone Committed
QCLNG Pipeline67
1,410 334 Miles Gladstone Committed
Southern Cross LNG Pipeline68
* 400 * * Publiclyannounced
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Gas Transmission Costs 7. Major Proposed LNG Pipelines
Core Energy Group 2012 April 2012 18
8.2. Cost Projections
8.2.1. Capital Costs
At the date of this report, the following table provides an estimate of forward capital costs for proposed LNG transmission
pipelines:
Table 8.2: Proposed LNG Gas Transmis sion Pip elines - Estimated Capital Cost
Source: Core Energy Group, 2012
* No specifications published, however to estimate capital cost, Core have assumed internal diameter of approximately 20 inches and operating pressure of15.3MPa.
**Capital cost estimated by Core Energy Group due to lack of publicly available cost estimates. Please refer to subsection 10.1 for basis of calculation.
69Australia Pacific LNG; Project Environmental Impact Statement; March 2010.
70Estimate sourced from a former project engineer involved in the contract award of the APLNG pipeline contract.
71Arrow Energy, Surat to Gladstone Pipeline Project Environmental Impact Statement Executive Summary, July 2009.
72Bureau of Resources and Energy Economics, Mining Industry Major Projects October 2011, November 2011.
73Arrow Energy;Arrow Bowen Pipeline Project Environmental Impact Statement;March 2012.
74Ibid.
75AEMO; 2011 Gas Statement of Opportunities
76Bureau of Resources and Energy Economics, Mining Industry Major Projects October 2011, November 2011.
77Ibid.
78Ibid.
79Santos; GLNG Project - Environmental Impact Statement; March 200980
Penn Energy; Saipem Wins Gladstone LNG Pipeline Work in Australia; 17 January 201181
QGC; Queensland Curtis LNG Environmental Impact Statement; July 200982
Estimate sourced from a former project engineer involved in the contract award of the QCLNG pipeline contract.
PipelineLength
(km)
Diameter
(inches)
OperatingPressure
(MPa)
ConstructionLabour
(ppl)
Estimated CapitalCost
(AUDm)
APLNG Pipeline69
362 42.0 15.3 800 1,25070
Arrow Surat Pipeline71
470 26.4 * 450 60072
Arrow Bowen Pipeline73
600 42.0 * 693 1,20774
Blackwater to GladstonePipeline
75
257 24.4 * * 321**
Central Queensland Gas
Pipeline76
440 * * 25077
47578
Galilee to Export Markets * * * * *
GLNG Pipeline79
435 36.4 15.3 * 1,00080
QCLNG Pipeline81
334 42.0 10.2 450 1,10082
Southern Cross LNGPipeline
400 * * * 500**
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Gas Transmission Costs 7. Major Proposed LNG Pipelines
Core Energy Group 2012 April 2012 19
8.2.2. Non-Capital Costs
At the date of this report, there had been limited disclosure with regards to estimates of forward real non-capital costs for
proposed LNG transmission pipelines, however on the basis of guidance previously provided by the ACCC; non-capital costs
for the proposed pipelines have been estimated.
Table 8.3: Proposed Domestic Transmission Pipelines Non-Capital Costs
Source: Various and Core Energy Group
^ Non-capital costs estimated on the basis of approximately 2.0% of replacement cost as previously prescribed by the ACCC as appropriate83
.
The above figures are intended to be illustrative only and are largely dependent on the capital cost assumptions for each of
the proposed pipelines. Variances in non-capital cost estimates for each of the above pipelines is a result of differences in
construction cost estimates, which may be a product of timing and prevailing market conditions, the maturity of respective
project plans and due diligence, and various other factors.
83ACCC;Access Arrangement Information for Roma Brisbane Pipeline; March 2007
PipelineLength
(km)
Estimated CapitalCost
(AUDm)
Estimated Non-Capital Cost
(AUDm p.a.)^
Estimated Non-Capital Cost
(AUD / km)
APLNG Pipeline 362 1,250 25.0 69,000
Arrow Surat Pipeline 470 600 12.0 25,500
Arrow Bowen Pipeline 600 1,207 24.1 40,200
Blackwater to Gladstone Pipeline 257 321 6.4 25,000
Central Queensland Gas Pipeline 440 475 9.5 21,600
GLNG Pipeline 435 1,000 20.0 46,000
QCLNG Pipeline 334 1,100 22.0 65,900
Southern Cross LNG Pipeline 400 500 10.0 25,000
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Gas Transmission Costs 8. New Pipelines
Core Energy Group 2012 April 2012 20
9. New Pipelines
For hypothetical new transmission pipelines of varying lengths, AWT provided Core Energy Group with a number of specific
operating assumptions and pipeline specifications. In addition, Core Energy sourced input information from a number of
other sources. This information was used to construct detailed economic models to analyse the cost of constructing and
operating new transmission pipelines, as well as the cost of gas transmission through these pipelines, having relevant
consideration of returns on capital, depreciation and taxation.
The following table details the specifications of the modelled pipelines:
Source: AWT; Core Energy Group
A full list of references for AEMO information purposes only is included in the spreadsheet titled Item 3 Input Sheet.
Generally, given identical specifications with the exception of length, an increase in length should result in the gaining of
some economies of scale. However, in the present case, given the substantial length differential between the two
hypothetical pipelines, the maintenance of pressure is of significance.
In the modelling process, the longer pipeline was assumed to also have a larger diameter and thicker walls than the shorter
pipeline. Generally, pipelines of larger diameter will experience lower degree of pressure loss due to friction than those of
lesser diameter.
Had the diameter and wall thickness specifications of the pipelines been consistent, the longer pipeline would demonstrate
much more significant pressure loss from inlet to outlet, possibly requiring the addition of compressor stations, which are an
additional cost component.
The result of the above considerations is an increase in the relative capital and non-capital cost estimates for the longer
pipeline compared to its shorter hypothetical counterpart.
PipelineLength
(km)
Diameter
(inches)
Capacity
(TJ / d)
OperatingPressure
(MPa)
Non-CapitalCost
(AUD / km)
Capital Cost
(AUDm)
Capital Cost
(AUDm / km)
A 1,000 12 39.2 15.0 21,893 1,033 1.03
B 500 10 34.1 15.0 18,600 400 0.80
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Gas Transmission Costs 8. New Pipelines
Core Energy Group 2012 April 2012 21
10. Validation of Capital and Non-Capital Expenditure
10.1. Capital Expenditure
As a part of AEMOs 2011 National Transmission Network Development Plan (NTNDP), a cost analysis of building gas and
electricity transmission infrastructure was undertaken, resulting in the provision of indicative cost estimates for gas
connections over three distances:
At 100 km, gas connection costs AUD60 120 million;
At 250 km, gas connection costs AUD150 305 million; and
At 500 km, gas connection costs AUD305 610 million.84
The following figures illustrate those capital costs per kilometre of pipeline that have been calculated by Core and those
previously published by AEMO, compared to a number of proposed pipelines for which estimated capital expenditure
information has been made publicly available. Figure 10.1 covers LNG gas transmission pipelines and Figure 10.2 covers
proposed domestic gas transmission pipelines:
Figure 10.1: Capital Cost p er Kilo metre Proposed LNG Gas Transmis sion Pipelines
Source: Various; Core Energy Group.
84AEMO, National Transmission Network Development Plan, December 2011
0.00
0.50
1.00
1.50
2.00
2.50
3.00
3.50
4.00
APLNGPipeline
(Contract
Award)
QCLNG
Pipeline
(Contract
Award)
GLNGPipeline
(Contract
Award)
ArrowBowen
Pipeline
CentralQLD
GasPipeline
EWCPipeline
(Gilmore/
Eromanga)
EWCPipeline
(Surat/Bowen)
ArrowSurat
Pipeline
Capital Cost (AUDm / km)
Uncontracted
Projects Ave:
AUD1.25m
/
km
Contracted
Projects Ave:
AUD3.02m
/
km
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Gas Transmission Costs 8. New Pipelines
Core Energy Group 2012 April 2012 22
Figure 10.2: Capital Cost per Kilometre Proposed Domestic Gas Transmission
Source: Various; Core Energy Group.
In Figure 10.1, some of the LNG pipelines, namely those relating to the APLNG, GLNG and QCLNG projects had awarded
engineering and construction contracts to service suppliers at the time of this report. Accordingly, due to greater certainty
around cost estimates (taken from contract values), these were distinguished from other proposed LNG-related pipelines,
whose cost estimates were taken at an earlier stage of planning and therefore likely to be less accurate by virtue of depth of
planning and due diligence undertaken. Some key points to be taken from an analysis of this data include:
Average capital cost per kilometre for contracted LNG pipelines is AUD3.02m;
Average capital cost per kilometre for uncontracted LNG pipelines is AUD1.25m; and
With early planning stage estimates for a number of the proposed LNG-related pipelines, there is room for significant
upside risk with regards to the construction cost of pipelines as they progress along the planning lifecycle towards final
investment decisions (FID). Comparing similar projects such as the Arrow Bowen pipeline against the APLNG and
QGLNG pipelines, there is room for substantial inflation of final costs.
In Figure 10.2 illustrates the publicly released cost estimates of a number of proposed domestic gas transmission pipelines,
and alongside these, indicative cost estimates from the NTNDP and Core / AWTs estimated costs for new transmission
pipeline installations.
With the exception of the proposed Lidell Gas Pipeline, which is a low pressure pipeline and therefore having substantially
different specifications to the other pipelines, the average construction cost estimate for these proposed pipelines was
approximately AUD 900,000 per kilometer.
These estimates are consistent with the NTNDP indicative estimates; however this may be primarily due to the basis of
estimation to arrive at those NTNDP values. The NTNDP indicative cost estimates were noted to have been based on
publicly available information regarding a number of gas transmission pipeline projects commissioned over the past five
years, including, but not limited to:
Bonaparte Gas Pipeline;
Corio Loop (DTS);
QSN Link (SWQP); and
0.00
0.20
0.40
0.60
0.80
1.00
1.20
Queensland
HunterGas
Pipeline
ERM
Wellington
Pipeline
LionsWay
Pipeline
Gloucester
CSGPipeline
LidellGas
Pipeline
NTNDP100
km
NTNDP250
km
NTNDP500
km
NTNDP500
km
Compressed
1,0
00kmNew
Pipeline
500kmNew
Pipeline
Capital Cost (AUDm / km)
Proposed
Domestic
Projects Ave:
AUD0.90m
/
km
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Gas Transmission Costs 8. New Pipelines
Core Energy Group 2012 April 2012 23
Young to Wagga Looping Pipeline (MSP).
The construction of the above-listed projects commenced during the period between 2006 and 2008. At the time of this
report, since that time, with the exception of the 2008 year during which commodity prices surged before collapsing in the
aftermath of the global financial crisis, steel prices have increased on average approximately 25 percent (at an approximate
CAGR of 5 percent)85
and domestic labour costs in the gas sector have increased approximately 20 percent (at an
approximate CAGR of 4 percent)86.
A similar approach was taken by AWT in arriving at assumptions for the construction and operation of new pipelines. That is,
drawing on recent examples of completed transmission pipeline capital expenditure programs.
Accordingly, as was the case with proposed LNG-related pipelines, there is a resulting risk that actual construction costs for
proposed domestic gas transmission pipelines may greatly exceed current estimates.
85US Bureau of Labor Statistics; Producer Price Index Data; 1967 2012.
86Australian Bureau of Statistics; Labour Price Index Data.
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Gas Transmission Costs 8. New Pipelines
Core Energy Group 2012 April 2012 24
10.2. Non-Capital Expenditure
The following figure illustrates the calculated non-capital costs per kilometre of pipeline:
Figure 10.3: Non Capital Costs per km
Source: Core Energy, APA Group
Figure 10.3 above illustrates that the non-capital cost outputs from Core / AWTs modelling of hypothetical new are
comparable with cost measures for existing transmission pipelines. The indicative non-capital costs are also consistent with
previous statements by the Australian Competition & Consumer Commission (ACCC) that pipeline non-capital cost should
be in a range of 2 percent of replacement cost for uncompressed pipelines and 5 percent of replacement cost for
compressed pipelines87
.
Please refer to section 6.3.2 above for detailed commentary regarding the variances observed amongst non-capital costs of
existing transmission pipelines.
87ACCC;Access Arrangement Information for Roma Brisbane Pipeline; March 2007
0
5,000
10,000
15,000
20,000
25,000
30,000
35,000
DTS MoombaAdelaide
DampierBunbury
MoombaSydney
GoldfieldsGas
RomaBrisbane
AmadeusDarwin
1000kmNew
500kmNew
Non Capital Costs(AUD / km)
Average:
AUD17,400
/ km
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Gas Transmission Costs 8. New Pipelines
Core Energy Group 2012 April 2012 25
10.3. Tariffs
The following figure illustrates the calculated gas transmission tariff per gigajoule per kilometre. In calculating the tariffs for
the hypothetical new pipelines, the building block method was applied, making allowances for non-capital costs, regulatory
depreciation, taxation and a return on capital. The specific assumptions are included in the aforementioned spreadsheet
titled: Item 3 Input Sheet.
Figure 10.4: Effective Gas Transmis sion Pip eline Tariff
Source: Core Energy Group; APA Group; ACCC.
An analysis of the results illustrated in the above figure shows that the calculated transmission costs for new pipelines
appear to be reasonable compared to the costs of existing transmission pipelines. Reasons for variance include:
The Tasmania Gas Pipeline is an outlier with a low level of utilization relative to available capacity, requiring increased
revenues on a gigajoule per kilometre basis;
The Longford to Melbourne Pipeline and South West Pipeline form part of the DTS and therefore are expected to incur
greater operating costs by virtue of the added complexity of that system resulting from grid arrangement and volatility of
flow;
The SEAGas and Eastern Gas Pipelines are newer pipelines, constructed in the past 10-15 years, and are therefore
likely to be more comparable to the hypothetical new pipelines in terms of cost structure and also depreciation
adjustments; and
The MSP and MAPS have lower tariff charges indicative of older age and therefore lesser depreciation and return on
capital contributions to the tariff calculations.
Other specific contributing factors to the calculated hypothetical pipeline tariffs being higher than existing pipelines include:
Some contingencies assumed in input assumptions for construction and non-capital expenditure; and
The modeled pipelines have a relatively low throughput capacity given their length. Pipeline length is a significant driver
of capital and non-capital costs, and therefore in this case there is a potential skewing of the output transmission coststowards the high side.
0.0000 0.0010 0.0020 0.0030
Eastern Gas Pipeline
Moomba to Adelaide
Moomba to Sydney
South East Australia
Tasmania Gas Pipeline
South West Pipeline
Roma to Brisbane Pipeline
Longford to Melbourne
1000km Hypothetical
500km Hypothetical
(A$ per GJ.km)
WACC Component Depreciation Component O&M Component
Taxation Component Tariff - Extrapolated at 2012
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Gas Transmission Costs 8. New Pipelines
The majority of the comparative pipelines are substantially aged, resulting in a largely depreciated asset base upon
which the depreciation and return on capital components of the tariff are calculated. The hypothetical pipelines on the
other hand would be newly constructed at higher material and labour costs than the comparative pipelines at their time of
construction. This has resulted in an increased contribution from depreciation and return on capital components on the
required revenue and resulting access tariff.
Recommended