Gas Transmission Costs Report

8/11/2019 Gas Transmission Costs Report

1/30

Core Energy Group 2012 April 2012 i

Gas Transmission Costs

April 2012


2/30

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.


3/30

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


4/30

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


5/30

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:


6/30

Gas Transmission Costs 4. Methodology


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


7/30

Gas Transmission Costs 5. Relationship Between Pipeline Costs and Tariffs


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.


8/30



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.


9/30



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


10/30



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


11/30

Gas Transmission Costs 6. Major Existing Pipelines


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.


12/30



6.2. Existing Pipeline Profiles

Key features of these pipelines are summarised in the following table:

Table 6.1: Existing Transmission Pipelines


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


13/30



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.


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


14/30



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^


15/30



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.


16/30



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


* Current publicly available tariff components data unavailable.

24NERA; The Gas Supply Chain in Eastern Australia ; June 2007.


26Jemena website.

27NERA; The Gas Supply Chain in Eastern Australia ; June 2007.

28Epic Energy; MAPS Key Commercial Terms; 2011.

29Ibid.


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


17/30

Gas Transmission Costs 6. Major Proposed Domestic Pipelines


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



18/30



7.2. Proposed Domestic Pipeline Profiles


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


19/30





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


**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.


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**


20/30




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


^ 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)


(AUDm)

Estimated Non-Capital Cost

(AUDm p.a.)^


(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


21/30

Gas Transmission Costs 7. Major Proposed LNG Pipelines


8. Major Proposed LNG Pipelines

8.1. Proposed LNG Pipeline Profi les


Table 8.1: Proposed LNG Gas Transmissio n Pipelines



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.


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


22/30





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.


73Arrow Energy;Arrow Bowen Pipeline Project Environmental Impact Statement;March 2012.

74Ibid.

75AEMO; 2011 Gas Statement of Opportunities


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)


(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**


23/30




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


^ 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.


PipelineLength

(km)


(AUDm)


(AUDm p.a.)^


(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


24/30

Gas Transmission Costs 8. New Pipelines


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


25/30



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


26/30



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


27/30



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.


28/30



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.


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


29/30



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


30/30


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.

Date post:	02-Jun-2018
Category:	Documents
Upload:	armel-brissy
View:	218 times
Download:	0 times

Gas Transmission Costs Report

Documents