Energy Efficiency Opportunities in Gas Transmission Pipelines and

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1
Table of Contents
1
2
3
Executive Summary ................................................................................................................................... 5
1.1
Background .......................................................................................................................................... 5
1.2
Aims ..................................................................................................................................................... 5
1.3
Gas transmission pipelines ................................................................................................................... 5
1.4
Distribution network losses ................................................................................................................. 7
1.5
Improving information in gas markets ................................................................................................. 8
1.6
Conclusion for gas transmission pipelines and distribution networks ................................................. 8
Introduction ............................................................................................................................................ 10
2.1
Aims ................................................................................................................................................... 10
2.2
The EEO Program ............................................................................................................................... 10
PART A – GAS TRANSMISSION................................................................................................................. 11
3.1
How the trials were conducted .......................................................................................................... 11
3.2
Australia’s gas transmission pipelines................................................................................................ 12
3.3
Gas use and losses in pipelines .......................................................................................................... 13
3.4
Electricity generation ......................................................................................................................... 13
3.5
Gas heating ........................................................................................................................................ 13
3.6
Fugitive emissions .............................................................................................................................. 14
4
Measurement of losses, system use gas, and gas unaccounted for ......................................................... 14
5
How pipeline operators consider energy efficiency in design and operation decisions ........................... 15
6
5.1
Conceptual development ................................................................................................................... 15
5.2
Foundation contracts ......................................................................................................................... 16
5.3
Design stage ....................................................................................................................................... 16
5.4
Pipeline operation .............................................................................................................................. 16
5.5
Increasing pipeline capacity – the compression and looping cycle ................................................... 16
Economics of loss mitigation ................................................................................................................... 17
6.1
7
The long economical life of pipelines and thresholds for investment ............................................... 17
How pipeline operators value losses in design and operation decisions ................................................. 18
7.1
Gas markets ....................................................................................................................................... 18
7.2
Gas contracts ..................................................................................................................................... 20
7.3
Western Australia .............................................................................................................................. 20
8
Estimating pipeline energy use and losses .............................................................................................. 22
9
Economically feasible loss reduction opportunities ................................................................................ 25
9.1
Improving the efficiency of compressor fuel use ............................................................................... 25
9.2
GEA fuel efficiency improvement ...................................................................................................... 26
9.3
Gas-fired heaters................................................................................................................................ 26
9.4
Minor system gas and other .............................................................................................................. 26
9.5
Technological developments ............................................................................................................. 26
9.6
Estimate of overall economic loss-reduction opportunities .............................................................. 26
2
10 Incentives and barriers to reducing energy use and losses ...................................................................... 27
10.1 Regulatory requirements ................................................................................................................... 27
10.2 Safety and technical regulation ......................................................................................................... 27
10.3 Economic Regulation.......................................................................................................................... 27
10.4 Contractual incentives ....................................................................................................................... 28
10.5 Corporate reputation ......................................................................................................................... 29
10.6 Competition ....................................................................................................................................... 29
10.7 Benchmarking .................................................................................................................................... 29
10.8 Opportunities to improve incentives ................................................................................................. 29
10.9 Conclusions ........................................................................................................................................ 30
11 PART B – GAS DISTRIBUTION................................................................................................................... 31
11.1 How the trials were conducted .......................................................................................................... 31
11.2 Australia’s gas distribution networks ................................................................................................. 32
12 Gas losses and energy use in distribution networks ................................................................................ 33
12.1 Operational gas use ........................................................................................................................... 33
12.2 Gas leakage ........................................................................................................................................ 33
12.3 Theft ................................................................................................................................................... 35
13 UAG, measurement and energy loss....................................................................................................... 35
14 How gas distributors consider energy efficiency and fugitive emissions ................................................. 35
14.1 How distributors value gas losses ...................................................................................................... 36
14.2 The carbon pricing mechanism .......................................................................................................... 37
15 Network gas losses and use .................................................................................................................... 37
15.1 Estimating distribution network losses .............................................................................................. 37
16 Economically feasible loss-reduction opportunities ................................................................................ 38
16.1 Operational opportunities – water bath heaters, regulators, main venting, mains pressure management
........................................................................................................................................................... 38
16.2 Technological developments to reduce losses .................................................................................. 39
16.3 Estimate of loss-reduction opportunities .......................................................................................... 39
17 Incentives and barriers to reduce network losses ................................................................................... 41
17.1 Safety and technical regulation ......................................................................................................... 41
17.2 Economic regulation .......................................................................................................................... 41
17.3 The carbon pricing mechanism .......................................................................................................... 43
17.4 Conclusions for the gas distribution sector........................................................................................ 43
18 APPENDICES ............................................................................................................................................ 44
Appendix A - Gas transmission survey form .................................................................................................. 45
Appendix B - Case study: Transmission Pipeline A, high compression density ................................................ 46
Background to the pipeline and losses .......................................................................................................... 46
Business approach to management of losses ................................................................................................ 46
Drivers of loss mitigation ............................................................................................................................... 46
Analysis of pipeline losses .............................................................................................................................. 47
Energy loss management program ................................................................................................................ 47
3
Systems and process ................................................................................................................................ 47
Summary of opportunities identified ............................................................................................................. 49
Future loss reductions .................................................................................................................................... 51
Barriers to loss mitigation .............................................................................................................................. 51
Conclusions .................................................................................................................................................... 52
Appendix C - Case study: Pipelines B and C, low and intermediate compression-density pipelines ................ 53
Background to the pipelines and losses ......................................................................................................... 53
Background to Pipeline B ............................................................................................................................... 53
Background to Pipeline C ............................................................................................................................... 53
Business approach to management of losses ................................................................................................ 54
Drivers of loss mitigation ............................................................................................................................... 54
Barriers to loss mitigation .............................................................................................................................. 55
Detailed analysis of pipeline losses ................................................................................................................ 55
Energy loss management program ................................................................................................................ 56
Opportunities identified ................................................................................................................................. 56
Conclusions .................................................................................................................................................... 57
Appendix D - List of potential loss-reduction opportunities from the US Environmental Protection
Agency’s Natural Gas Star Program ................................................................................................................ 58
Appendix E - Gas distribution networks survey .............................................................................................. 60
Appendix F - Case study: Gas Distribution Network Owner A ........................................................................ 62
Background .................................................................................................................................................... 62
Business approach to management of losses ................................................................................................ 62
Drivers of loss mitigation ............................................................................................................................... 63
Conclusion ...................................................................................................................................................... 63
Appendix G - Case study Gas Distribution Networks Owner B ....................................................................... 64
Background .................................................................................................................................................... 64
Business approach to management of losses ................................................................................................ 64
Drivers of loss mitigation ............................................................................................................................... 65
Conclusion ...................................................................................................................................................... 65
4
1
Executive Summary
1.1
Background
The extension of the Energy Efficiency Opportunities (EEO) Program to electricity and natural gas transmission and
distribution businesses was announced by the Australian Government in July 2011, as part of the Clean Energy Future
package.
This report summarises the outcomes of trials conducted with the gas transmission pipeline and distribution network
sectors, in consultation with an industry working group. Data from these trials will inform the implementation
regulation impact statement RIS for the EEO networks extension.
1.2
Aims
The trials’ aims were to:

establish the extent of energy use and losses in each sector

understand how transmission pipeline and distribution network operators consider and value energy use and
losses in their design and operation decisions

estimate the economic opportunities to reduce pipeline and distribution network energy use and losses

understand the barriers and incentives for pipeline and distribution network operators to minimise energy
use and losses.
The trials had two components:
1.
Pipeline operators and distributors were surveyed on various metrics regarding the energy use and fugitive
emissions of their assets. Data was received for 24 of Australia’s 35 major pipelines, representing 80% of gas
delivered in Australia, and from all seven major distributors, covering ten distribution networks and 89% of
the gas delivered through distribution networks.
2.
Case studies were developed in consultation with two pipeline operators (covering a high-compression
pipeline and two intermediate compression pipelines) and two distributors. These were used to understand
how losses are currently considered and to identify economic loss reduction opportunities.
1.3
Gas transmission pipelines
Australia has 35 major gas transmission pipelines, covering every state and territory, with a combined length of
20,520 km. Based on survey data, it is estimated that in 2011–12 these pipelines delivered approximately 1,404 PJ of
gas.
A key metric for transmission pipelines is system use gas (SUG).
SUG = measured gas use + gas unaccounted for (GUF)
GUF = metering error + unmeasured gas use + fugitive emissions
GUF is also known as unaccounted for gas.
Gas use is typically measured for compressors, which move gas along the pipe, and gas engine alternators (GEAs),
which use gas to generate electricity to power compressor ancillary equipment. Compressors and GEAs are usually
powered by gas drawn from the pipeline. For pipelines with significant compression, compression can account for up
to 95% of SUG. Twenty-one (60%) of Australia’s 35 major pipelines don’t have compression.
Based on survey data, average SUG for all of Australia’s pipelines is estimated to be 12.2 PJ p.a., which is about 0.9%
of gas delivered, with compressor fuel use estimated to be about 80% of this at 9.4 PJ p.a. The remaining 2.8 PJ
consists of metering error, unmeasured gas used to power ancillary equipment and fugitive emissions.
5
Gas meters for pipelines can have errors of between +/- 0.5% and 1% depending on the type of meter and the
measurement conditions. Metering error can easily exceed the fugitive emissions and unmeasured gas use
components of GUF, and can make up the majority of SUG for pipelines with no compression.
Fugitive emissions can’t be directly measured but are estimated to make up only a small component of GUF. They can
occur through valves and instrumentation. Some fugitive emissions can’t be avoided, such as compressor and pig trap
blow downs necessary for pipeline operation and maintenance, or are impractical to reduce, such as venting required
to operate some ancillary equipment.
A summary of energy use and loss indicators based on trials survey data is given in the following table.
ANNUAL GAS TRANSMISSION PIPELINE ENERGY USE AND LOSSES
Based on trials survey data for 2011–12
Total gas delivered
1404 PJ
Total compressor fuel component of total SUG
9.4 PJ
Net non-compressor fuel component of SUG
2.8 PJ
Total SUG
12.2 PJ
(= total compressor fuel + non compressor fuel component)
Total SUG as % of deliveries
0.9%
Estimated economically viable opportunities to reduce energy use in the medium
term
Energy use reduction opportunities as % of SUG
0.9 PJ
7%
Pipelines follow a cycle of compression and looping (pipeline duplication) to increase their capacity. Increasing
compression has a significantly lower capital cost than looping but results in higher energy use. A pipeline increases
compression until the losses reach a level where it becomes more economical to loop.
The case studies show that pipeline operators consider energy efficiency as a key element in their design decisions,
and to varying degrees in operation decisions, depending on incentives—such as whether they pay for SUG and the
extent to which the pipeline is compressed.
The case studies show that where there are direct incentives to reduce SUG—such as the operator paying for SUG—
operators have been proactive and systematic in finding ways to reduce it. Currently there are only two pipelines in
Australia that either pay for all SUG or SUG that exceeds a certain level.
There are also several indirect incentives to reduce SUG. Bilateral contracts between foundation shippers and the
operator underwrite most pipelines, causing commercial pressure. There is competition between some pipelines. The
commercial pressures on pipelines are reflected in the fact that 24 of Australia’s 35 major transmission pipelines are
not covered (not regulated).
The case studies suggest that where there are no direct incentives to reduce SUG, pipeline operators have been more
ad hoc in their identification of energy use reduction opportunities, though it should be noted one of the case study
participants in this situation is in the process of implementing an energy efficiency program.
An estimate of economical energy-use and loss-reduction opportunities
The survey and case studies show that, overall, there is limited scope to reduce pipeline energy use and losses. The
estimated economically viable loss-reduction opportunities in the medium term are 0.9 PJ for all Australian pipelines,
about 7% of SUG and 0.18% of energy delivered.
6
By far the majority of opportunities are associated with compression, but incentives would be needed for many of
these to be realised in addition to what pipeline operators are already doing, such as exposure to the cost of SUG.
There is an opportunity to enhance the incentive structure for pipeline operators to become more systematic in their
approach to energy loss.
It estimated that there are very limited energy-use reduction opportunities for pipelines with little or no compression.
Twenty-one of Australia 35 major transmission pipelines don’t have compression.
Opportunities to reduce fugitive emissions represent a very small proportion of loss-reduction opportunities and the
case studies suggest most are not economically viable.
1.4
Distribution network losses
Australia has 19 natural gas distribution networks operated by seven major gas network operators 1, with
approximately 88,000 km of mains. There are gas networks in every state and territory. In 2011–12 these networks
delivered approximately 380 PJ of gas to over 3.6 million customers.2
A key metric for distribution networks is unaccounted for gas (UAG)
UAG = measurement error + fugitive emissions + theft
The trials survey covered Australia’s seven major gas distribution network operators and 10 of Australia’s largest
networks, representing 89% of gas distributed in Australia. Based on this data, the UAG weighted total for Australia is
estimated to be 3.3% of gas delivered.
ANNUAL GAS DISTRIBUTION NETWORK LOSSES
Based on trials survey data for 2011–12
Total gas delivered
380 PJ
UAG
12.6 PJ
UAG as a proportion of gas delivered
3.3%
Estimated fugitive emissions from leaking mains
4.5 PJ
Leaky mains (% of length of total mains)
8.8%
Estimated economically viable opportunities to reduce losses
0.7 PJ
Economically viable opportunities in addition to current mains replacement programs
Not material
Data from the trials show the majority of losses from distribution networks are the fugitive emissions from leaks in old
mains (pipes). Based on trials survey data, fugitive emissions from leaky mains in Australia’s gas distribution networks
are estimated to be 4.5 PJ p.a.
The case studies show that distributors systematically monitor mains, and that mains rehabilitation and replacement
are their main focus to reduce losses in their networks. Their basic processes typically include managing assets, safety,
operating and leakage, some of which are informed by regulatory requirements or feed into access arrangements.
The data also indicates that during 2008–12, the average proportion of leaking mains for Australia’s distribution
networks dropped from 11.3% to 8.8%. During this time UAG remained static, suggesting that as distributors
rehabilitate leaky gas mains, the remaining leaky mains deteriorate and leak more.
1 The
2
seven gas network operators are Jemena, Envestra, MultiNet, SP Ausnet, ATCO, APA Group and ActewAGL
State of the Energy Market 2012, p. 108 – Australian Energy Regulator
7
Distributors have strong obligations and incentives to reduce network losses. These include:

Safety – this is a primary driver to reduce fugitive emissions. Distributors have to meet jurisdiction technical
standards and the Australian Energy Regulator (AER) is obliged to approve capital expenditure required for
safety or to maintain the integrity of a network

UAG allowance – most states and territories have a UAG revenue allowance for gas distributors based on a
level of economically efficient UAG set by the AER. Exceeding this level incurs financial penalties and keeping
UAG below this level provides a financial gain.

Capital expenditure – distributors can have capital expenditure to reduce leakage (i.e. through mains
rehabilitation) included in their capital base, on which they earn the regulated rate of return.

Carbon pricing mechanism – the CPM is a cost passed through to consumers but adds in the order of $4/GJ
to the cost of fugitive emissions considered in investment decisions. This increases the proportion of a
network for which mitigation is economically viable.
The only barrier to reducing leakage is persuading the regulator that expenditure is an economically efficient
investment, as required by the National Gas Law (NGL) and National Gas Rules (NGR).
Estimate of economic loss-reduction opportunities for gas distribution networks
The trials show that reducing fugitive emissions from mains is the only viable opportunity to reduce network losses.
Total fugitive emissions from gas mains are estimated to be 4.5 PJ p.a, with a maximum potential of only 0.7 PJ of
these opportunities estimated to be economic to mitigate. Viable loss-reduction opportunities in addition to the
systematic replacement of leaky mains (already being undertaken by distributors) are estimated to be immaterial.
1.5
Improving information in gas markets
One of the aims of the EEO Program is to address information barriers. The trials have shown that such barriers within
pipeline and distribution businesses appear to be minimal.
However, the trials also highlighted a lack of information in the public domain on pipeline energy use and distribution
network losses. Making this information available could improve transparency for market participants, particularly gas
shippers and policy-makers. It could also strengthen incentives for pipeline operators and distributors to seek and
implement improved energy-use and loss-reduction opportunities.
1.6
Conclusion for gas transmission pipelines and distribution networks
The case studies have shown that energy efficiency is a major consideration for gas transmission pipeline operators in
their design and operation decisions, with approaches ranging from a formal energy efficiency program embedded in
the corporate culture, to a more ad hoc basis, depending on incentives and the level of compression.
Extending the EEO Program to transmission pipelines is unlikely to result in the identification of more than limited
opportunities to reduce gas use. Most of these would be for pipelines with significant compression, with very limited
benefit for the 21 of Australia’s 35 pipelines with little or no compression.
Pipeline operators would need an incentive for most of these opportunities to be realised, in addition to what they are
already doing. Ideas include:

options for covered pipelines including SUG as a cost to pipeline operators, rather than shippers, in
regulatory determinations

engaging with pipeline shippers on the issue of SUG and identifying the benefits of pipeline operators
providing SUG in transportation agreements

creating a voluntary loss-reduction scheme that provides an information exchange about pipeline energy-use
reduction opportunities, similar to the US EPA’s Natural Gas Star program, but tailored to Australian industry.
8
Gas distribution businesses have strong incentives to reduce network losses and are systematically rehabilitating and
replacing leaky mains. It is unlikely that extending the EEO Program to distribution networks would find any
economically viable opportunities to reduce losses beyond what distributors are already doing.
Finally, these trials have highlighted the lack of publically available, consistently reported information on annual
transmission pipeline energy use and distribution network losses and trends. This information would improve
transparency for market participants and policy-makers. Ideas include:

presenting distribution network annual UAG figures in the AER’s regular reporting, such as its Comparative
Performance Report for Victorian Gas Businesses and the State of the Energy Market report.

publishing annual SUG for major pipelines on the National Gas Bulletin Board and the State of the Energy
Market report.
9
2
Introduction
2.1
Aims
This report considers the findings of trials with gas transmission pipelines and distribution network businesses for the
extension of the EEO Program to electricity and gas networks. For each sector, the aims were to:

establish the size and nature of gas use and losses

understand how network businesses consider and value gas use and losses in their design and operation
decisions

estimate the potential for economical gas use and loss-saving opportunities

understand the barriers and incentives for networks to minimise losses.
Data from the trials will be used in the implementation regulation impact statement (RIS) for the networks expansion.
The trials were conducted in consultation with an industry working group comprised of representatives from the
Australian Energy Market Operator (AEMO), the Australian Pipeline Industry Association (APIA), the Energy Networks
Association (ENA) and Grid Australia.
2.2
The EEO Program
The EEO Program requires corporations that use more than 0.5 PJ a year to assess their energy use and report publicly
on their energy assessments and the business’s response. The program is designed to address information failures and
organisational barriers within large energy-using businesses, to encourage them to increase their energy efficiency.
The extension of the EEO Program to electricity and gas transmission and distribution networks was announced by the
Australian Government in July 2011, as part of its Clean Energy Future package. Consultation preceding the trials
included:

one-on-one discussions with stakeholders to inform an options paper

release of the options paper, public forums in Sydney and Perth, and a call for submissions

a review of submissions.
The program was to apply from 1 July 2012, but in response to stakeholder feedback that more time was needed to
fully consider the extension, and the need for additional data for the RIS, the Australian Government moved the
commencement to 1 July 2013 (when the network exemption expires), to allow for industry trials and further
consultation.
This report has two sections, each with its own conclusions:

Part A is a discussion of transmission pipeline gas use and losses.

Part B is a discussion of distribution network gas use and losses.
Each section has been written so it can be read independently of the other. A separate report has been published for
trials with the electricity transmission and distribution sectors.
10
3
PART A – Gas transmission
3.1
How the trials were conducted
Australia’s six largest gas pipeline operators have been surveyed about their pipeline energy use (see data form in
Appendix 1). Combined, the data they provided covered 24 of Australia’s 35 major pipelines, including all 14 pipelines
with compression, and 85% of Australia’s pipeline capacity.
Two pipeline operators also participated in the development of case studies: one for the operation of a highcompression density pipeline (Case study A) and one for the operation of a low-compression pipeline and an
intermediate-compression pipeline (Case study B).
The survey data has been used to estimate the extent of energy use and losses in Australia’s pipelines. The case
studies have been used to examine how pipeline operators currently consider energy efficiency and to estimate
economical loss-reduction opportunities.
The survey and case study data were provided on the condition that they are treated as commercial in-confidence by
RET and its consultant, would be used in an aggregated form only, and no pipeline would be identified. As a result, the
case studies (Appendices 2 & 3) are written in generic terms.
11
3.2
Australia’s gas transmission pipelines
Australia has 35 major gas transmission pipelines with a combined length of 20,520 km. In 2011–12 these pipelines
delivered approximately 1,404 PJ of gas. These figures do not include looping3 and pipelines that are part of gas
production facilities.
This report does not consider pipelines currently under construction for three major export liquefied natural gas (LNG)
projects in Gladstone, Queensland. Collectively they will transport upwards of 1,200 PJ p.a. through 1,345 km of major
transmission pipelines supplied by several hundred kilometres of field supply lines and would have a material impact
on any analysis4. These pipelines could simply be considered as extensions of the coal seam gas (CSG) gathering
systems connecting the CSG production facilities to the LNG production and export terminals in Gladstone.
Figure 1: Australia’s major gas transmission pipelines
Source: Great Southern Press, used with permission
3
Looping is the practice of installing a duplicate pipeline alongside the existing pipeline to increase its capacity
4
Sourced from PPO Annual 2012 pp. 40, 42, 52
12
3.3
Gas use and losses in pipelines
Some of the gas transmitted in a pipeline is used in the operation of the pipeline. Gas is recompressed—raising its
pressure to a similar level as when it entered the pipeline—along a pipeline’s length to compensate for the pressure
reduction resulting from frictional drag as the gas flows. By recompressing the gas it is, in effect, ‘pushed along’ by a
compressor station.
Where there is any material use of compression, fuel used to power the compressors will be the largest source of
energy use/loss on a pipeline. Twenty-one (60%) of Australia’s 35 pipelines don’t have compression. A typical pipeline
configuration with associated pressure loss is shown in Figure 2.
Compressor
Compressor
Producer
Delivery
Meter
Station
Meter Station
Pressure
Distance along pipeline
Figure 2: How compression boosts pipeline capacity
3.4
Electricity generation
Another significant use of gas is in generating electricity to run various stations along the pipeline. The majority of
electricity used by a pipeline is generated by gas in the pipeline. Gas is used for electricity generation because
pipelines are typically remote from electricity networks; a pipeline would likely connect to an electricity network in
the rare case that one was close by.
Pipelines have power stations located intermittently along their length. The types of station can vary from large
compressor facilities through to mainline valve sites, scraper stations5, cathodic protection sites and meter stations.
Compressor stations use considerably more electricity than other types, in powering a range of ancillary equipment
such as engine starters, oil pumps, cooling fans, instruments, control and telecommunications systems. Typically,
electricity for compressor stations is provided by gas engine alternators (GEAs). These are small gas-fired power
stations where the generator is powered by a gas engine (the same as a car engine, but fuelled with gas from the
pipeline).
At other sites, electricity consumption is relatively low, either being used to power a small number of instruments and
telecommunications systems or to power systems for cathodic protection to prevent corrosion. On these sites power
is either generated from gas using closed circuit vapour turbogenerators (CCVT) or solar panels.
3.5
Gas heating
Gas is used to fuel water bath heaters, which heat gas at delivery stations to compensate for cooling of the gas as it
passes through pressure regulators, which reduce gas pressure for use in distribution networks and lateral pipelines.
5
Scraper stations are units at which ‘pigs’ are launched and received. Pigs are devices that travel through the pipeline, pushed along by the flow of
gas. There are various pigs with different purposes, such as cleaning, measuring pipe geometry and detecting defects in the pipe wall.
13
When pressure drops suddenly, the gas cools through the Joule-Thomson effect, which can cause the gas to fall below
the design temperature limits of steel used in downstream piping, valves and other equipment. Pre-heating the gas
before it passes through the regulators prevents its temperature falling below a safe level.
3.6
Fugitive emissions
In addition to using gas to power compressors and generate electricity, a relatively small amount of gas is released
into the atmosphere uncombusted. This can arise from a number of sources, such as:

gas used to power instrumentation and controls, such as control valves and gas sampling devices. Historically,
gas has been used because it is a readily available source of pneumatic power and has lower operation and
maintenance requirements than a separate compressed air system

blowdowns6 of pig launchers and receivers, necessary to insert and retrieve pigs7

blowdowns of compressors to protect seal systems8

leakage through valves and valve stems.
4
Measurement of losses, system use gas, and gas unaccounted
for
Gas use measured in pipeline operations includes gas used for compressors, GEAs and waterbath heaters. However,
gas used in scraper traps and compressor blowdowns is not always measured and practice among pipelines varies,
with some having well developed systems for collecting blowdown information and others not.
Other gas loss cannot be easily measured, if at all, such as that for instrument gas use and valve leakage.
Consequently, it is not possible to accurately measure all energy used and/or lost in the operation of a pipeline.
As part of gas accounting, pipeline operators measure the difference between gas received into the pipeline and gas
delivered to gas shippers (retailers and industrial users). This is known as system use gas (SUG).
The unmeasured elements of gas use are called Unaccounted for Gas or Gas Unaccounted For (UAG or GUF);
terminology varies within the industry. GUF has three components: unmeasured use, fugitive emissions and
measurement error. In summary:
SUG = measured gas use + GUF
GUF = metering error + unmeasured gas use + fugitive emissions
Gas meters for pipelines can have errors of between +/- 0.5% and 1% depending on the type of meter and the
measurement conditions. Metering error can easily exceed the fugitive emissions and unmeasured gas use
components of GUF.
The standards for measurement within the gas industry are well understood and the economic limits of accuracy are
well established. The uncertainty in measurement of gas arises because it is inferred and calculated from a large
number of inputs, such as gas composition, temperature, pressure, a primary volume or mass flowrate signal and
density.9 These are used to calculate the volume of gas at standard conditions10 and the heating value of the gas.
6A
blowdown occurs when a section of pipeline or piping, such as around a compressors station, vents gas. This is done to allow maintenance of a
section of pipeline and in the case of a compressor it is done to protect the seals of the compressor when it is not in operation or to allow
maintenance of the compressor station.
7 ‘Pigs’
are devices that move through a pipeline driven by the flow of gas. They have a range of functions including cleaning, measurement of pipe
dimensions and gathering data about the state of the pipe.
8 Typically,
compressor seal systems are designed to operate while the compressor is operating and can be damaged if the compressor is stopped by
gas pressure in the system.
9 There
is a variety of instruments for measuring volume or mass flow. The main instruments are: orifice plate differential pressure, turbine meters,
coriolis meters and ultrasonic
10
Gas volumes are measured at a set of standard conditions 101.325 kPa (abs) and 15oC.
14
These two inputs are multiplied to calculate the energy flow rate, which in turn is integrated to calculate the energy
delivered. The formula for calculating the volume relies on correlations based on research by the American Gas
Association11, that have a degree of uncertainty.
The elements of GUF can’t be directly measured, although reasonable estimates of the unmeasured use and fugitive
emissions elements of GUF are typically of the order of 5% of SUG for highly compressed pipelines and 100% for
pipelines with no compression.
As measurement error can exceed +/-0.5% of pipeline deliveries in some cases, the non-measurement error elements
of GUF can be swamped by measurement error, where measurement error is material.
The measurement uncertainties associated with each input accumulate to give the total measurement error. There is
narrow scope for enhancing the accuracy of the various elements. The main evolution in the industry has been from
orifice plate meters to coriolis and ultrasonic meters, which are inherently more accurate over a wide range of
flowrates and can provide accuracies of +/- 0.5%.
In any event, improving measurement accuracy will not reduce energy use and loss. It will only make it easier to
estimate the level of fugitive emissions, and then only marginally. To the extent that there is scope to further improve
measurement accuracy, the expenditure involved would be better spent focusing on measuring and mitigating the
various components of loss not already measured and mitigated 12.
As a result, SUG and GUF can be useful as broad indicators of energy loss, but care must be taken in interpreting their
meaning in relation to opportunities to mitigate losses.
Measurement of actual losses is best undertaken by identifying each actual and potential contributor for gas loss
through engineering assessment, then quantifying these through directly measuring or estimating them. Once this is
done the various sources of loss can be prioritized (by size) and investigated to estimate the economics of mitigating
them.
5
How pipeline operators consider energy efficiency in design
and operation decisions
5.1
Conceptual development
The gas transmission case studies have shown that energy efficiency is considered by pipeline operators as part of
their standard processes to minimise the long run cost of a pipeline, from initial development through to
decommissioning.
As part of a pipeline’s conceptual development and development of the business case to invest, pipeline proponents
seek to optimise the lifecycle costs of the pipeline. In doing so they will consider the factors that affect the optimum
economic return of the pipeline over a typical economic life of 80 years.
At this stage in a pipeline’s life-cycle, questions of pipe diameter and use of compression (over the whole life of the
pipeline) will be considered. As a rule of thumb, pipelines that have a short build-up of demand to reach a long-term
plateau will reach higher levels of compression from the early stages of the pipeline’s life reflecting those that are
optimal in the long run, at the demand plateau. Where there is a progressive build-up of demand over a long period,
compression will be added. This makes the most of significant economies of scale associated with pipe diameter
needed for ultimate demand, while capturing the benefits of flexibility and deferral of investment in compression.
11 The
most commonly referred to standards used for gas metering internationally are AGA Report 3 - Orifice Plate Meters, AGA Report 7 – Turbine
Meters, AGA Report 9 - Multipath Ultrasonic Meters, AGA Report 11 Coriolis Meters
12 That
is, wherever possible losses should be identified by direct measurement as close to the source as possible, e.g., measurement of gas used as
fuel by compressors, GEAs and water bath heaters. Next, measurements by inference should be made, e.g., measurement of the swept volume of
vessels and equipment from which gas is blowdown and calculating the actual quantity of gas contained before the blowdown by reference to its
composition temperature and pressure.
Finally, using other estimating and measurement techniques applicable to each potential source of use or loss, by reference to manufacturers
documentation (in the case of instrument gas) or by other inferential measurements (as in the case of valve leakage).
15
5.2
Foundation contracts
An essential element in the development phase for a pipeline is the negotiation of long term ’foundation‘
transportation contracts with foundation shippers. These contracts underwrite the commercial viability of a pipeline,
providing the necessary commercial risk management tools for what is a very long lived asset, and providing the basis
on which finance (both debt and equity) for the pipeline are established.
Foundation contract shippers will be large end users, gas producers or wholesaler/ retailers that are well placed to
make the necessary long term commitments needed to underwrite the pipeline. They will also be very capable of
ensuring all of the terms and conditions in transportation agreements are the best that can be negotiated. This will
include shippers having the strategic commercial and analytical skills necessary to determine the lowest sustainable
tariffs, including understanding the optimal pipeline diameter, operating pressure and level of compression.
A recent example of the development of a pipeline is Epic Energy’s QSN link 13 completed in 2008, which connects the
South West Queensland Pipeline (SWQP) to the Moomba Sydney Pipeline and the Moomba Adelaide Pipeline
Systems, joining Queensland’s transmission network to the south eastern states. Epic notes that long term contracts
on the SWQP (of which the QSN link is part) are in place with major Australian energy retailers and gas producers.
5.3
Design stage
At the design stage in a pipeline’s life-cycle, there will be more detailed consideration of measures to reduce
operating costs, such as the selection of technologies and systems. Consideration will be given to the most costeffective and efficient compressor sets, leak-resistant valves, and instrumentation power; with decisions made such as
the implementation of compressed air or electrical systems as an alternative to pipeline gas-to-power instruments.
5.4
Pipeline operation
The operator of Pipeline A (see case study in Appendix 2) demonstrated it has a systematic, business-wide energy
efficiency program that is fully supported by the operator’s management and integrated with its business processes.
In four years, the program investigated 62 opportunities, implemented 10, found 18 not worth pursuing and has 34
awaiting analysis or with a decision depending. The program found loss savings of 5% and the operator estimates up
to another 5% may be possible.
The operator of Pipeline B (see case study in Appendix 3) does not yet have a formalised energy efficiency program
but has considered opportunities on an ad hoc basis. It was not able to advise the number of opportunities it
considered but noted that only one has progressed to the testing phase. This operator is now developing a program to
systematically consider energy efficiency in its asset management planning process. In addition, it has participated in a
state government study to investigate energy efficiency opportunities for a major compressor station.
5.5
Increasing pipeline capacity – the compression and looping cycle
When demand exceeds a pipeline’s capacity, the operator will, where possible, expand capacity. The operator can
increase capacity by adding compression, looping the pipeline or a combination of the two. The trade-offs between
the length and diameter of looping and the amount of compression are major considerations, and new transportation
contracts will be negotiated with shippers, based on the optimal economics of any expansion.
Looping increases the effective diameter of the pipeline, thereby reducing the velocity of gas and consequent
frictional drag, and is the single biggest opportunity to reduce compression fuel use and improve a pipeline’s energy
efficiency. The duplicate pipe is almost universally the same diameter as the existing, or larger, because of the very
significant economies of scale associated with pipe diameter14.
13
See Epic Energy website at http://www.epicenergy.com.au/index.php?id=31, The Australian Pipeliner website
http://pipeliner.com.au/news/epic_energy_commits_to_construction_on_qsn_link/012252/ and Sydney Morning Herald article about AGL’s
agreement with Epic Energy for the construction of the QSN Link at http://www.smh.com.au/news/business/agls-140m-pipeline-deal-to-linkeast/2007/07/13/1183833769302.html
14 Pipeline
capacity Q increases in proportion to diameter D to the power of 2.5 and costs of pipelines increase in proportion to the 0.5-0.6 power.
I.e. Q  D2.5 and Cost  D0.6. Therefore Cost  Q0.24
16
Compared to compression, looping has a much higher capital cost—but greatly reduced operating (lower compressor
fuel use) and maintenance costs. Compression has a lower capital cost but much higher operating and maintenance
costs. Thus, looping becomes viable when its long-run cost, including compressor fuel savings, is greater than the longrun cost of building and operating compressor stations.
Depending on a range of factors, the long-run cost of compression will be less than looping up to a certain compressor
spacing—anywhere from 70–200 km. As fuel costs increase, this spacing will widen. The economics of a typical
pipeline expansion cycle for a pipeline with expectations of long-term growth is shown below..
Figure 3: The compression/looping cycle
There are two current examples of pipeline looping on the public record. The first is Epic Energy’s expansion of the
QSN Link and the South West Queensland Pipeline 15 (known as QSN 3). Critical to these expansions were agreements
with shippers and the optimal sizing and use of compression.
The second is DBP’s expansions of the Dampier to Bunbury Natural Gas Pipeline. The most recent expansion Stages 4
and 5 are well documented as part of DBP’s 2010 Access Arrangement review. 16 These documents set out how DBP
arrived at an efficient and prudent expansion design (looping and compression). In particular, DBP notes 17 in
considering whether it should adopt use of additional midline compression that, ‘Additional compression would also
result in higher operating (fuel and maintenance) costs than would be the case under other possible expansion
options’.
6
Economics of loss mitigation
6.1
The long economic life of pipelines and thresholds for investment
A clear distinguishing feature for pipelines, compared to other commercial assets, is that they are long-lived. Economic
lives approved by economic regulators are typically around 80 years, reflecting the expected time before the cost of
operating and maintaining a pipeline will exceed the long run cost of replacing it. This assumes that demand for
natural gas will remain at around its current level or greater and that there will be a supply of gas at the inlet to the
15
See Epic’s media releases at http://www.epicenergy.com.au/news.php?newsid=54 and http://www.epicenergy.com.au/news.php?newsid=55
16
See details of DBP’s Expansions in its submission to the Economic Regulation Authority of WA at
http://www.erawa.com.au/cproot/8525/2/20100507%20D29662%20DBNGP%20Submission%209%20%20Justification%20of%20Expansion%20Related%20Capital%20Expenditure.pdf
17
Submission 9 - Justification of Expansion Related Capital Expenditure, DBP, p. 61
17
pipeline. Based on the experience in the US, it is likely that Australian pipelines will continue to be economic to
operate and maintain beyond 80 years.
The main consequence of a long economic life is that pipeline operators will consider discounted cash flow returns for
periods of 20 years or more rather than the five to ten years typical of other businesses.
For loss reduction, it can be expected that pipeline businesses would start with opportunities with the fastest payback,
typically four years or less, and then progressively invest in those with longer returns dependent on them meeting the
company’s hurdle rate and available capital. However, the longer investment horizon means that, on the assumption
that hurdle rates are not significantly greater than regulated rates of return, investments that had a payback of up to
eight years could meet the hurdle rate of a pipeline business.
Typically, loss mitigation opportunities will fall into two broad categories, which are those requiring:

capital expenditure

changes to operating practices.
After looping and replacing low-efficiency compressors with higher efficiency compressors (both unlikely to meet a
pipeline operator’s hurdle rates unless there are other reasons for considering them), capital investments will be
considerably smaller and easier to implement.
The cost of changes to operating practices will generally be relatively small, particularly when compared to
opportunities requiring capital expenditure. This will make changes to operating practice more likely to be
economically feasible and easier to implement. As a consequence, opportunities only requiring changes to operating
practices will tend to be undertaken first.
7
How pipeline operators value losses in design and operation
decisions
The case studies, and consultation with the industry generally, have shown pipeline operators determine the value of
losses from two sources:

economic forecasters with gas price expertise

publicly available information.
Case study participants declined to provide information on the prices they use due to commercial sensitivity.
7.1
Gas markets
Gas prices across Australia are quite variable and public information about actual contracted gas prices is scarce.
However, five east coast pipelines are participants in one of the Sydney, Brisbane and Adelaide short term trading
markets (STTM) and the Victorian Declared Wholesale Gas Market (DWGM), operated by the Australian Energy
Market Operator (AEMO).
The Sydney, Brisbane and Adelaide STTM’s are designed as gross pool markets that require parties shipping gas
through the hubs of the respective markets (acting as gateways to the local markets) to offer gas for sale and/or bid to
purchase at the hub. In practice, they act as a market for imbalances for the transactions of wholesaler/retailers and
other participants. The STTMs are day-ahead (ex ante) markets with later (ex post) adjustments for deviations from
the ex ante forecasts. Prices are determined by resolving offer and bid stacks to determine the equilibrium price.
The DWGM is also a technically gross pool market requiring parties supplying gas into and out of the Victorian
Transmission System (VTS, which covers most of Victoria), rather than a notional hub, to offer gas for sale and/or bid
to purchase gas from the market. Like the STTM, it is effectively a net market for imbalances.
The STTMs and the DWGM provide an indication of what contracted wholesale prices may be, but not a direct
measure of actual costs to wholesalers that sell gas at the hubs. The extent to which the prices revealed by the STTM
and DWGM reflect actual gas prices borne by wholesaler/retailers and the prices paid for SUG is unclear, but they are
18
the best available indication of the wholesale prices in the market and are likely to be good indicators in the medium
term.
The STTM and DWGM prices therefore can help in estimating the cost of SUG, which is likely to be priced based on the
field price without the transportation tariff component. However, STTM prices are set for the city gate delivery points
(i.e. the delivery end of the pipeline). This means in theory they include both a field price component and a
transmission component. In contrast, the DWGM prices are for gas delivered into the Victorian Transmission System
and therefore reflect the price for gas without transportation. It is unclear if there is any effective discounting of
injection prices under the DWGM to allow for transportation differential.
This means that comparison of the two market prices requires an adjustment for transportation costs, which is both
uncertain and beyond the scope of this report. However, prices for SUG can be expected to be less than the STTM
prices for Sydney, Adelaide and Brisbane, but will reflect the DWGM price as SUG is supplied from the DGWM in the
Victorian market.
Table 1: Gas market prices for 2011–12
Average
Average
Quarter
FY 2011
FY 2012
Dec 2012
($/GJ)
($/GJ)
($/GJ)
Sydney STTM
2.91
3.45
6.25
Adelaide STTM
3.22
3.79
5.92
Brisbane STTM
N/A
3.38
5.39
Victoria DWGM
2.45
3.28
5.03
Market
Source: AER, http://www.aer.gov.au/node/456
Graphs of gas prices produced by the AER (Figures 4 & 5) show a clear increase in wholesale prices from March 2012.
This suggests that spot wholesale prices will continue to increase and these prices will be reflected in new contracts
for gas.
Figure 4: East coast gas spot price weekly averages
19
Figure 5: East coast gas spot prices – 2011 and 2012
7.2
Gas contracts
It is likely that wholesaler/retailers will have contracts for tranches of gas, giving them some protection from price
rises. However, it is typical for gas contracts to have price review clauses that allow prices to be adjusted to reflect
current market conditions. As a result, in the medium term it is reasonable to expect that prices in existing contracts
will adjust to reflect prices in new contracts.
Given the current trend it is likely that gas prices will trend towards export parity pricing18, plus any transport
differentials, unless there are significant new supplies of gas on the east coast that will not be ‘soaked up’ by the LNG
producers. The point of convergence is likely to be around the date of start-up of the major LNG projects in
Queensland in 2014–15.
The cost of SUG on the east coast of Australia is likely to be $5.50–6.00/GJ increasing to $7–10/GJ in the next three
years.19
7.3
Western Australia
WA does not have a mandated market mechanism such as the STTM or DWGM, so price information is not readily
available. However, the WA Independent [Electricity] Market Operator has commissioned reports on gas prices in WA
by ACIL Tasman.20 In its March 2012 report, ACIL Tasman concluded that wholesale gas prices are likely to fall within
the range of $5.24–12.08/GJ with a mean of $8.23/GJ.
18 Export
parity pricing, is the gas price a producer could expect to get at the well head if they were producing for export sale. In the case of natural
gas, this is the delivered Liquid Natural Gas (LNG) price less the cost of LNG shipping, liquefaction and storage and pipeline transportation from field
to the liquefaction facility.
19 This
is supported in a report by ACIL Tasman for IPART, DRAFT Cost of gas for the 2013 to 2016 regulatory period, A report on the wholesale cost
of gas for the review for Standard Retailers in New South Wales, ACIL Tasman 22 April 2013.
20
Gas Prices in Western Australia, 2012-13 Review of inputs to the Wholesale Electricity Market, Report prepared for the Independent Market
Operator, ACIL Tasman, March 2012.
20
Where pipelines are required to purchase SUG, it is likely they will be required to pay a margin above the market price
to account for a number of factors, including the small annual quantities relative to the quantities usually contracted
by producers and term risk (i.e. compensation for locking in the price for a fixed term). Based on the ACIL Tasman
report SUG prices would be likely to be in the range $7.50–9.50/GJ
21
8
Estimating pipeline energy use and losses
The following high-level statistics are derived from the survey of pipeline operators and represent 86% of Australia’s
pipelines by length, approximately 85% by capacity, and approximately 80% of total annual gas delivered in Australia.
TABLE 2: Pipeline statistics based on survey results
Survey data (2011–12)
Number of pipelines in survey
24
Total length (not including looping)
17,531 km
Total gas delivered
1,068 PJ p.a.
Number of pipelines with compressors
14
Number of compressor stations
51
Total compressor fuel
9.4 PJ p.a.
Total SUG
11.7 PJ p.a.
Total SUG as % of deliveries
1.09%
Net non-compressor fuel SUG A
2.3 PJ p.a.
Estimates for Australia based on survey data B
1404 PJ D
Total gas delivered
9.4 PJ pa C
Total compressor fuel
Net non-compressor fuel SUG
2.8 PJ pa
Total SUG
12.2 PJ pa
0.9% D
Total SUG as % of deliveries
A The figure for non-compressor fuel SUG includes negative SUG in some cases. Negative SUG arises from measurement error.
B Pro-rated based on the survey data covering 80% of gas deliveries.
C Projections for compressor fuel use are unchanged as the survey captured all 14 of the major pipelines in Australia with
compression.
D The total gas delivered estimate is based on data aggregated from various sources and is not pro-rated from survey data.
Projected total SUG is calculated by total SUG / total gas delivered. It is lower than the survey data estimate as the 11 pipelines not
covered in the survey don’t have compression.
22
Table 3: Pipeline losses and consequent likely extent of loss reduction opportunities
Max
Min
Volume Weighted
average
SUG (% of deliveries)
2.64
-0.33*
1.09
Compressor fuel (% of deliveries)
1.77
0.00
0.88
Non-compressor fuel use SUG (% of deliveries)
0.96
-0.64*
0.22
73
674
325
Loss indicator
Compression density (km/compressor)
*Negative SUG and non-compression SUG arises from measurement error that is a function of meter uncertainty.
The analysis shows a weighted average SUG of 1.09% of gas delivered, with SUG ranging from a low of
-0.33 % to 2.68%. Eight of out 24 pipelines have SUG greater than 1% of deliveries with five of these greater than 1.5%
of deliveries (i.e. three between 1–1.5%). This corresponds to an APIA survey, which estimated energy losses at 1.02%
of through put and that most pipelines have SUG of less than 1% of gas delivered.21 Our data also shows that on
average compressor fuel use makes up 80% of SUG and is up to 90% of SUG at the upper end.
The fact that on average just 20% (2.3 PJ) of pipeline energy use and losses (using SUG as a proxy) is due to uses other
than compressor fuel use, suggests that compressor fuel should be the major focus for identifying loss-reduction
opportunities. This is further underlined by the fact that the next most significant component of loss after compressor
fuel loss is for generation of electricity (i.e. operation of GEAs) associated with the compressor operation. The result is
that for highly compressed pipelines approximately 95% of losses will be due to energy use for compression.
However, the fact that SUG for some pipelines is negative demonstrates the problems with using SUG as an indicator
of losses. Even larger negative values apply when compressor fuel is deducted from SUG. With a range of noncompressor fuel SUG of -0.64 to 0.96%, care must be taken in drawing conclusions about the level of non-compressor
fuel gas use/loss, and even more so when GEA use is also considered.
This high-level analysis is supported by the correlation between compressor fuel as a proportion of deliveries and SUG
as a proportion of deliveries. The following graph shows the linear relationship between compressor fuel use and SUG.
21 APIA,
EEO networks expansion options paper submission, March 2012. 1.02% loss figure based on analysis of 25 pipelines representing 89.4% of
gas consumed in Australia (2009-10).
23
Figure 6: Relationship between SUG and compressor fuel.
The correlation has a good level of fit (r2 = 0.89) and a linear relationship between compressor fuel and SUG as a
proportion of deliveries. The slope of 1.2 indicates that loss increases with a 20% overhead on compressor fuel. This
fits the understanding that there are sources of loss associated with compression other than just compressor fuel.
These include GEA fuel and gas blowdown from compressors.
The vertical intercept provides an estimate of the non-compressor related loss. The scatter around the correlation is
made up of natural variation between SUG and compressor fuel and SUG between pipelines, plus the impact of
metering error. In this respect it should be noted that one pipeline was removed from the analysis as an outlier,
because its SUG was -0.33% (-0.64% once compressor fuel was eliminated).
These results are consistent with the estimates of the break-up of SUG being ~90% compressor fuel, ~5% GEA fuel and
~5% non-compressor-related loss for high compression pipelines.
24
9
Economically feasible loss-reduction opportunities
This report adopts two sources for identification of loss-reduction opportunities:

The two case studies prepared as part of this report.

Opportunities documented in the US EPA’s Natural Gas Star Program (see Appendix 4).22
Based on the case studies, opportunities to reduce energy losses in gas pipelines can be categorised according to the
various sources of loss usage/loss already identified. These are summarised below in approximate order of proportion
of loss:

improving the efficiency of compressor fuel use

improving the efficiency of gas powered electricity generation and use of electricity

avoiding use of gas for operations where more energy efficient approaches are available

reducing venting of natural gas for operational purposes (i.e. compressor blowdowns)

reducing leakage of gas from pipeline equipment
9.1
Improving the efficiency of compressor fuel use
As identified in the case studies, and is evident from the industry survey analysis, the largest consumer of energy on
pipelines is compression, which takes 80–90% of energy use of the pipelines surveyed. The total compressor fuel
usage for the industry is 9.4 PJ p.a. The thermal efficiency of typical compressor sets 23 (the main method of providing
compression on gas pipelines) is in the range of 20–25%.
The options for improving compressor fuel-use can be broken down into two categories: use of more efficient
compressor-driver units; and operating compressor stations in a more efficient manner.
There is continuing development of compressor technology (including compressor drivers or engines) with associated
improvement in the efficiency of equipment—however, pipeline compressor technology is mature and potential for
further improvements in equipment efficiency is marginal.
While there is some scope for replacing older compressor units with newer more efficient machines, this would have
considerable capital cost. This option is generally only considered if the current units are at or near the end of their
economic life, as the improvement in efficiency using more recent technology is marginal and the cost of new units
and station reengineering that will be required exceeds the reduction in fuel cost.
There is much greater scope for reductions in fuel usage from changes in operation and these changes generally
require little or no capital expenditure, and relatively minor additions to operating expenditure. In the case study of
Pipeline A, 19 possible opportunities were identified. Of these, only three have so far been screened out, three have
been implemented, and five are awaiting review. In the case of the two pipelines in case studies B and C, a major
review has been undertaken for one pipeline regarding a more efficient operating regime for its compressors. The
operational changes identified include strategies to minimise compressor fuel-use and to maintain an ongoing analysis
of it.
Some of the opportunities identified above are a result of the pipelines operating at significantly less than their
capacity and would not apply, or would become less applicable, as utilisation of pipelines increases and they approach
the full capacity of their compressor stations.
22
The Natural Gas Star program seeks to work with the natural gas industry – production, transmission and distribution - on a voluntary basis to
identify opportunities to reduce methane and carbon dioxide emissions. Appendix 4 provides a list of the opportunities based on those developed
for Natural Gas Star.
23
Compressor Stations consist of one or more compressor sets made up of a driver and compressor. In Australia the majority of driver compressor
sets comprise a gas turbine driver with a centrifugal compressor.
25
9.2
GEA fuel efficiency improvement
After compression, the most significant source of energy loss is fuel used to generate electricity in GEAs. For Pipeline A
nine possible opportunities have so far been identified. Of these two have been screened out, two have been
implemented and the remainder are awaiting analysis.
Pipeline B has taken a different tack, undertaking a detailed investigation of the use of waste heat from its compressor
drivers to generate electricity as a substitute for electricity from the grid.
Other opportunities from the case studies revolve around management of the selection of GEAs and their loads and
ensuring GEAs are in good condition.
9.3
Gas-fired heaters
Gas is mainly heated using gas-fired water bath heaters. The Pipeline A case study identified three opportunities to
reduce gas used in heating. Of these, one was screened out and two are awaiting analysis.
9.4
Minor system gas and other
In addition to compressor fuel, GEA fuel and water bath heater fuel, energy can be lost via a range of other
mechanisms including minor electricity use, gas leakage through a variety of routes, gas blow downs, etc. Most of
these involve relatively minor reductions in energy loss.
Pipeline A identified 14 loss mitigation opportunities. Of these, eight were screened out and four are awaiting
analysis. Examples include options to manage gas leakage and venting associated with compressors and their station
pipe work and ancillary equipment.
9.5
Technological developments
Each of the above areas includes some opportunities to use new or different technologies. As identified for
compressor units the technologies used in the pipeline industry are mature and most technological developments are
marginal. Pipeline A identified eight opportunities that involve new or different technology. Of these, five were
screened out, one is suspended for further review and three are awaiting analysis. Renewable energy technologies are
being examined as alternatives methods for minimising gas vented as part of equipment operation.
9.6
Estimate of overall economic loss-reduction opportunities
The case studies have given some insight into energy use and economic loss reduction opportunities for pipelines with
different levels of compression. Overall, the studies have shown that pipelines are operated reasonably efficiently, but
there are some opportunities to reduce losses for pipelines with compression.
For pipelines with compression, compressor fuel and GEA fuel are the largest component of energy use and can be up
to 95% of energy use and losses for highly compressed pipelines. As a result, compressors, ancillary equipment and
their operating regimes are the major sources of loss reduction opportunities.
The case studies also show there are fugitive emissions that can’t be avoided, such as compressor and pig trap
blowdowns necessary for pipeline operation and maintenance; or are impractical to reduce, such as venting required
to operate some ancillary equipment. For pipelines with compression, these emissions are a small component of
losses. For pipelines with little or no compression, they can make up a large proportion. Overall, most opportunities to
reduce these fugitive emissions are not economical, and represent a very small proportion of loss-reduction
opportunities.
Overall, loss reduction opportunities are estimated to be around 0.9 PJ for pipelines using compression. Extrapolated
to 100% of Australian pipelines, this remains about the same. This estimate is based on the correlation in Figure 6, and
a reduction of gas use for compressors of 10%, based on the results of the high-compression pipeline case study.
This estimate is made without detailed information about specific loss-reduction opportunities from the case studies,
such as potential reduction size, implementation costs and economic returns.
26
10 Incentives and barriers to reducing energy use and losses
10.1 Regulatory requirements
Pipeline operators’ responses to energy losses are impacted by their regulatory and commercial situation. There are
two aspects of regulation: technical and economical. The commercial context is created by the contracts between a
pipeline service provider and its shippers.
10.2 Safety and technical regulation
Pipelines transport large quantities of a highly flammable material under very high pressure. For pipeline operators
the first incentive to reduce gas loss is safety and environmental management. In addition to their general corporate
social responsibilities, under their licences pipeline operators are subject to clear safety and environmental
obligations. Minimising leakage and use of gas in operations is part and parcel of these obligations and the nature of
pipeline business.
Technical regulation for pipelines is by legislation in each state and territory. The legislation is similar in each
jurisdiction and calls up AS 2885, the Australian Standard for Pipelines – Gas and Liquid Petroleum. This Standard
covers all aspects of design, construction, testing, commissioning, operation and maintenance of pipelines. Its major
focus is reliability, safety and environmental management. The issue of energy use and losses, while relevant in the
Standard, is not its major focus and is left to pipeline licensees to determine within their regulatory and commercial
contexts.
10.3 Economic regulation
Economic regulation for pipelines arises through the National Gas Law and National Gas Rules, which require the
economically efficient investment, operation and use of pipelines. Typically, this means the efficient costs of design,
construction, operation and maintenance are included in pipeline tariffs.
Where pipelines are regulated (covered under the National Gas Law and National Gas Rules) economic regulation
creates the context for transportation agreements. Under the NGL, there are two forms of regulation—Full Regulation
and Light Regulation. Under Full Regulation, the AER approves an Access Arrangement which contains all the terms
and conditions of access to pipelines, including price. Under Light Regulation, a pipeline service provider may have
non-price terms and conditions of access approved by the AER in a Limited Access Arrangement. However, there is no
obligation to submit a Limited Access Arrangement for approval. The main terms and conditions (including price) must
be published on the service provider’s website.
Access Arrangements, which are approved by the Australian Energy Regulator (AER), or the Economic Regulatory
Authority (ERA) for WA, create a set of reference terms and conditions that are adopted directly, in a majority of
cases, into transportation agreements. Access Arrangements across Australia vary in respect of which party (shipper
or service provider) is responsible for provision of, or paying for, SUG. Many reflect the most typical commercial
practice whereby SUG is to the account of the shipper. A limited number of others include SUG as a cost to be borne
by the service provider or have a cap on SUG to be provided by the shipper.
Under the NGL and NGR, the regulators are required to adopt terms and conditions of access that promote economic
efficiency (i.e. efficient investment in, use and operation of pipelines). 24 This will flow into the treatment of SUG as
follows:

Determining whether it is efficient for SUG (or compressor fuel) to be paid for by a pipeline’s shipper or by
the service provider.

If the service provider is to provide/pay for SUG (or compressor fuel) determining the efficient cost (quantity
and price) for SUG.
24
The requirements on regulators in the NGL and NGR arise in a hierarchy. Under the NGL the regulators must act to achieve the National Gas
Objective (section 23) and set prices consistent with the Revenue and Pricing Principles Section 24). The NGR specify the detailed requirements for
determining the efficiency of costs NGR, in particular Rule 74 (forecasts), Rule 79 (Capital Expenditure) and Rule 91 (Operating Expenditure).
27
Regulators are also required to consider the cost of the carbon. Accordingly, given the requirement to provide for
tariffs to cover the efficient cost of pipeline service providers (including statutory obligations) the regulators have
provided for carbon taxes to be passed through in service provider tariffs in their Access Arrangements. Consequently,
the pass-through of carbon taxes is reflected in transportation agreements for regulated service providers.
Only eight pipelines are under full economic regulation and three are under light economic regulation; 27 of
Australia’s 35 major gas pipelines are not economically regulated.
10.4 Contractual incentives
As identified above, contractual incentives in relation to energy losses for regulated pipelines are determined by the
AER or the ERA. For the 27 Australian pipelines that are not regulated or alternatively have light regulation25 tariffs
and terms and conditions of access are not set by the AER or ERA, but are determined through commercial
negotiation.
Unregulated pipelines are exposed to competition and shippers with significant countervailing market power. This
means that where the regulators do not set tariffs, negotiations with shippers can be expected to deliver similarly
economically efficient outcomes.
The main direct commercial incentives to minimise energy use/gas loss arise from the treatment of SUG and carbon
taxes in contracts with shippers. The results of the survey of pipeline operators show that in the majority of
transportation agreements SUG is provided free of charge by the shipper to the pipeline service provider. That is, the
cost of SUG and carbon taxes lies with the shipper rather than the pipeline operator. However, there also appears to
be an increasing practice of including caps on both SUG and carbon taxes.
Where there is no direct incentive to minimise SUG, transportation contracts typically require (either through general
requirements to operate efficiently and effectively or through requirements specific to SUG) that the service providers
only use SUG that is reasonably required for the operation of the pipeline. So, while there may not be a specific, direct
financial incentive, there is a general obligation to keep SUG to a reasonable minimum. Coupled with this general
obligation is the incentive of effective working relationships with shippers.
Typically, pipelines have a limited number of shippers—fewer than 10 and, for some, fewer than five. Shippers are
usually large listed companies—retailers or major end-users—and bring considerable market power to the commercial
relationship.
The result is for pipelines where SUG is to the account of shippers, while there will not be a direct incentive, there will
be an indirect incentive not to create more SUG than is necessary. Historically, the cost of SUG, with gas prices in the
$2.50–3.50/GJ range, does not appear to have created a significant concern for shippers. With gas prices increasing,
driven by the move to export parity pricing (from $7–12/GJ), shippers may be more motivated to contain the cost of
SUG.
For large end-users, even where energy is a significant component of its costs, adding 0.1% to transportation costs will
be translated to an even smaller proportion of end cost, having only a minor effect on their on profitability. Similarly,
where shippers are wholesaler retailers, even with slim retail margins, in the range of 0.5–7%, the small impact on
transportation cost of around 0.1% will translate in to about a 0.01% improvement in delivered costs to retail
customers. This is approximately 0.1–0.3% profit before tax. In contrast, a reduction of loss by 10% for pipelines will
be a larger proportion of the costs of the pipeline operator representing of the order of 1–2 % of profit before tax.
Two pipelines have been identified for which the cost of SUG is borne wholly or partially by the pipeline service
provider. There is anecdotal evidence that some recent transportation contracts have caps on the SUG to be borne by
shippers. In these cases, the incentive for the pipeline operator to minimise SUG is clear. Every GJ saved represents an
improvement to the pipeline operator’s profitability.
Similar to SUG, carbon tax payable under the Clean Energy Act is, in a majority of cases, passed through to shippers
through the standard provisions of transportation agreements. Anecdotal evidence also indicates that some new
25 Full
regulation involves the pipeline service provider submitting and Access Arrangement for approval, typically every five years. Light regulation
only requires that a pipeline service provider publish prices and terms and conditions on its website, but shippers have the option of seeking dispute
resolution by the AER in the event that they cannot achieve access on terms that they think are fair.
28
transportation contracts include caps on carbon taxes to the shippers account. For the same reasons as for SUG,
shippers can be expected to be quick to scrutinise the pass-through amounts, and not accept them if they consider
them unreasonable.
10.5 Corporate reputation
Operating in an energy-efficient manner and minimising carbon charges is a typical means of meeting pipeline
operators’ environmental responsibilities. This is particularly relevant for publicly listed companies.
10.6 Competition
The Australian pipeline industry has grown rapidly since the mid-1990s. Since that time, in addition to pipelines being
built to serve new markets, they have been built that compete with existing pipelines. Examples are the Eastern Gas
Pipeline (EGP) – which competes with the Moomba Sydney Pipeline (MSP) - and the SEAgas Pipeline – which competes
with the Moomba Adelaide Pipeline System (MAPS).
The fact that these pipelines are, for the most part, uncovered (i.e. unregulated) reflects the fact that markets have
considered the competition between these two pipelines effective. In practice, this means that to the extent that gas
is available at the inlet to these pipelines, the pipelines will compete on the cost of transporting gas to market. This
means that, in addition to transportation tariffs, the additional cost of SUG will be taken into account by shippers
considering their options for getting gas to the key markets of Sydney and Adelaide.
The development of the QSN Link supplying gas to Moomba from the coal seam gas fields of the Bowen and Surat
Basins has reinforced the competitive pressures by making adequate quantities of gas available into the MSP and
MAPS. This is important, because the reserves in the Cooper and Eromanga Basins that had been so significant, are
now in decline.
As a broader competition between gas and other energy types develops, there is added pressure to reduce the
delivered cost and therefore transportation. However, as the wholesale gas price represents between 10–15% of the
cost of delivered gas to a majority of consumers, the relatively small changes in the cost of transportation will have a
minimal impact on inter-fuel competition, particularly when gas and electricity are well known to have low price
elasticities.
10.7 Benchmarking
There is no publically available benchmarking for SUG or compressor fuel for pipelines. Information provided by
pipelines surveyed indicates that some pipelines have caps that act as a benchmark for SUG, typically in the range of
1.5–3%. Others have indicated that they have internal benchmarks of 2%.
10.8 Opportunities to improve incentives
It is also evident that the industry is mindful of energy efficiency but because the incentives for most pipeline
operators are indirect, they have not taken a systematic approach to loss reduction. The loss-reduction potential is not
significant and does not warrant the level of regulatory intervention associated with the EEO legislation. This raises
the question of what fine-tuning of policy interventions might be made that could lead to a broad adoption of a
systematic approach to loss reduction for pipelines.
Actions that would still be effective while involving a low level of intervention include:

increasing market transparency through the publication of annual SUG for each major pipeline on the
National Gas Bulletin Board

strengthening the incentives for regulated pipelines, whereby the Department or SCER made submissions to
the AER determining that including SUG as a cost to service providers will better meet the National Gas
Objective and the Rules

engaging with pipeline shippers on the issue of SUG identifying the benefits of having the pipeline operators
providing SUG in transportation agreements
29

creating a voluntary scheme of loss reduction similar to the Natural Gas Star program but tailored to the
Australian industry. This could be extended to include gas distribution and upstream oil and gas exploration
and production sectors.
10.9 Conclusions
The main source of energy use in pipelines is compressor fuel and associated gas used in running compressor stations
along pipelines, including fuel for GEAs and from gas vented during compressor blowdowns. This represents on
average 80% of pipeline losses. In addition, gas is also lost through a range of miscellaneous uses, such as pipeline
venting, instrumentation, minor power generation and valve leakage. Total estimated energy use and losses for the
gas transmission sector is approximately 12.2 PJ p.a.
The case studies have shown that pipelines consider energy efficiency to varying degrees in their design and operation
decisions, depending on the extent of incentives such as whether they pay for SUG, and the extent to which the
pipeline uses compression.
There is a range of indirect incentives to reduce losses, such as commercial pressure from foundation shippers and
competition between some pipelines that has led to a fairly reasonable level of energy efficiency for pipelines. These
incentives are most useful at the time investment decisions are made, meaning later improvements during the
operational stage will be proportionately smaller. Apart from two pipelines, there are no direct economic incentives to
reduce loss. Where there are direct incentives, they arise through the pipeline operator providing SUG or via a cap on
SUG required to be provided by shippers.
The case studies have shown that where there are direct incentives to reduce SUG, pipeline operators have been
systematic in seeking out opportunities to reduce energy use. Where there are no direct incentives, operators have
been more ad hoc in their identification of opportunities.
The survey and the case studies have shown that, overall, pipelines already run fairly efficiently and there is relatively
narrow scope to reduce energy loss. The estimated economic loss-reduction opportunities in the medium term are
0.9 PJ for all Australian pipelines. By far the biggest opportunities are associated with compression, and there are
estimated to be with few opportunities for pipelines with little or no compression, noting 21 of Australia’s 35 pipelines
do not use compression.
The trials also highlighted the lack of information in the public domain on transmission pipeline energy use and losses
and addressing this could improve market transparency as well as market participant awareness, while strengthening
the incentives to proactively consider energy use loss reduction opportunities.
There is scope to enhance the incentive structure for pipeline operators to become more systematic in their approach
to energy loss. The following actions are proposed for possible consideration:

For covered pipelines, consider options for including SUG as a cost to pipeline operators, rather than shippers, in
regulatory determinations.

Engage with pipeline shippers on the issue of SUG, identifying the benefits of having the pipeline operators
providing SUG in transportation agreements.

Create a voluntary loss-reduction scheme that enables an information exchange, similar to the Natural Gas Star
program in the US, but tailored to the Australian industry.
30
11 PART B – GAS DISTRIBUTION
11.1 How the trials were conducted
The trials with gas distribution networks had two parts. For the first, each operator was asked to fill out a survey (see
the data form Appendix 5) on the various metrics for unaccounted for gas, fugitive emissions and pipeline
remediation, and the trend for UAG from 2001 to 2012.
Responses were received from all seven of Australia’s major distribution network operators. Combined, the data
covered 10 of Australia’s gas networks and 89% of gas distributed in Australia. The data has been used to estimate
distribution network losses and understand where losses occur.
The second part of the trials involved conducting case studies in consultation with two network operators on their
approach to the reduction of gas leakage.
The survey and case study data were provided on the condition that they are treated commercial-in-confidence by
RET and its consultant, would be used in an aggregated form only, and no network operators would be identified. As a
result, the case studies (Appendices 6 & 7) are written in generic terms.
31
11.2 Australia’s gas distribution networks
Australia has 13 natural gas distribution networks operated by seven major gas network operators 26, with
approximately 88,000 km of mains. There are gas networks in every state and territory. In 2011–12 these networks
delivered 380 PJ of gas to over 3.6 million customers27.
Most major cities and towns with populations over several thousand and within a reasonable distance of a gas
pipeline, have a gas distribution network. The expansion to cover such a broad area became possible with the advent
of natural gas and the progressive connection of remote gas fields with major cities and industrial centres.
FIGURE 7: Eastern and central Australia’s gas distribution networks and supply transmission pipelines.
Source: AER, State of the Energy Market 2012, figure 4.1. Used with permission.
26
The seven gas network operators are Jemena, Envestra, MultiNet, SP Ausnet, ATCO, APA Group and ActewAGL
27State
of the Energy Market 2012, p. 108 – Australian Energy Regulator
32
FIGURE 8: Western Australia’s gas distribution networks
Source: ATCO Gas Australia, used with permission
12 Gas losses and energy use in distribution networks
12.1 Operational gas use
Gas leakage (fugitive emissions) is the main source of energy loss in gas distribution systems. Only relatively small
quantities of gas are used to operate a gas distribution system, for water bath heaters (which is measured) and in
some instrumentation (which is not measured). There are some instances of compression being used by gas
distributors in the US, but this is not the case in Australia.
12.2 Gas leakage
The majority of losses from distribution networks are the fugitive emissions from leaks in old mains (pipes). Minor
leakage also occurs from pressure-relief-valves associated with meter regulators, meter connections, and as part of
the venting of mains, necessary to make connections for new mains or when undertaking repairs.
Leakage of gas is not difficult to detect. For safety reasons, technical regulations in each state and territory require gas
to be ‘odorised’ to enable detection by the human nose at very low concentrations. However, measurement of
leakage quantities is difficult and requires isolation of network sections and use of inferential techniques that have
low levels of accuracy.28 Distributors also undertake leakage surveys, which comprise measuring the concentration of
gas just above the ground along the route of the distribution pipes suspected of being leaky.
Australia’s first gas networks were built in the 1840s and 1850s to deliver town gas (a mixture of predominantly
hydrogen and carbon monoxide produced from coal) initially for lighting, then for cooking, heating and hot water.
28
Estimates of leakage rates are made by isolating a section of network and measuring the flow out of the network at a range of pressures.
This enables engineers to infer the leakage component of network flow as distinct from the customer usage element.
33
Mains were constructed from cast iron pipes that were joined using mechanical joints sealed with lead and yarn or
rubber rings. Cast iron mains ran at relatively low pressures (low pressure up to 4 kPa and medium pressure up to
50 kPa) at diameters from 100 mm to 1200 mm.
In addition to hydrogen and carbon monoxide, coal gas contained small quantities of a range of hydrocarbons and, in
particular, aromatic hydrocarbons. It was also saturated with water. These components dissolved into the materials
that seal the joints between pipes.
Cast iron mains leak either through holes as a result of corrosion or through joints where the jointing material has
deteriorated. Joint deterioration increased markedly due to the phasing out of ‘wet’ town gas, to ‘dry’ natural gas
(predominantly methane with small amounts of propane and butane, but lacking the aromatic hydrocarbons) in the
late 1960s and ‘70s. The elimination of water and aromatic hydrocarbons led to the drying out of the jointing
materials, causing them to break down.
Some galvanised steel and unprotected steel pipes were also used in the 1950s and ‘60s. PVC was subsequently used
in some distribution systems, but because of the use of mechanical jointing and the need for PVC pipes to be fixed
lengths, fell out of favour. Galvanised steel and unprotected steel pipes can develop holes as a result of corrosion. PVC
pipes leak through joints where seals have deteriorated.
Modern pipe technologies are almost completely leak free. With the introduction of natural gas and the development
of polymers as reliable engineering materials, the predominant materials used for pipes are now cathodically
protected (from corrosion) high-strength steel (usually operating at high design pressures of 1,000 kPa and above) and
plastics (operating at medium to high pressure (210 kPa and above). The major plastic material used since the 1980s
has been polyethylene (PE), with some use of Nylon 11 by AGL/Jemena. These materials used jointing systems that
fuse the pipe materials, making them leak free. Figure 9 shows the layout of a distribution network.
Our survey has shown that the proportion of a network that has leaking mains ranges from 0% for relatively new
networks, and up to 25% for older networks.
Figure 9: A typical gas distribution network layout using modern materials
34
12.3 Theft
Another component of distribution network losses is theft. Theft occurs where customers bypass meters to avoid
payment for gas. There is little data available on theft and the quantity stolen is unknown. However, feedback from
case study participants indicates distribution businesses don’t have significant concerns about theft, as the required
technical skills are not common.
13 UAG, measurement and energy loss
Gas distribution networks measure unaccounted for gas (UAG), which is the difference between the quantity of gas
entering the network and the quantity leaving the network.
Gas distributors do not use the concept of system use gas (SUG) used in pipelines, because there is only a very small
portion of gas that is used for operations and the majority of it is measured and accounted for. UAG has three main
elements: measurement error, leakage and theft. That is:
UAG = Measurement error + fugitive emissions + theft
Like SUG for transmission, measurement error is a significant element of UAG. However, in the case of distribution the
uncertainties are exacerbated by a number of factors:

Gas measurement is inherently imprecise and even the best meters have measurement errors of +/-0 5%.
Residential meters are allowed to have an error range of +2% and – 3% before needing correction.

The large number of delivery meters, up to millions for large networks. Meters for small users are read only
every quarter or bimonthly.

Adjustments in meter measurement for atmospheric temperature, pressure and elevation are made for all
meters based on a single representative value for a region rather than on the specific conditions measured at
each meter.
The significance of measurement error is evident from typical UAG values for relatively new networks that do not use
the older technology materials. Typically, newer gas distribution systems using only protected steel and fused plastic
(typically built after 1980) have UAG levels of between 1–2%. On the reasonable assumption that leakage and theft
are relatively small components of these UAG figures, this leaves a fairly significant margin of measurement error. By
comparison, UAG can be up to 5% for older systems with high proportions of cast iron, unprotected steel and PVC. The
difference between newer and older networks is accounted for by higher fugitive emissions.
14 How gas distributors consider energy efficiency and fugitive
emissions
The case studies show energy efficiency is considered by gas network operators within the framework of their normal
business processes, as part of minimising the long run cost of developing, building, operating, expanding and
extending their gas networks.
The two case studies show how network operators systematically monitor, rehabilitate and replace leaking mains, as
their primary approach to reducing losses. The basic processes, which reflect accepted good industry practice are, in
part, regulatory requirements, and have the following components:
Asset management plan – The asset management plan sets out the distributor’s processes and policies to manage the
constituent parts of the overall network through their life cycle, from commissioning to decommissioning. This plan
proposes the distributor’s capital (capex) and operational expenditure (opex) to manage all aspects of asset
deterioration and replacement including managing UAG.
The plan is not a regulatory requirement but usually forms the basis, and demonstrates the efficiency, of capex and
opex proposals submitted to the AER as part of the five-year regulatory review of the distributor’s access
arrangement. The asset management plan will have a number of components including leakage management and
mains replacement contingencies. These are recognised best industry practice in managing capital intensive
businesses.
35
Leak management plan – Outlines a distributor’s approach to addressing leaks in the short term, and would also be
part of the Safety and Operating Plan in accordance with AS 4645 that is audited for, or approved by, the jurisdictional
technical regulator. It covers leak detection, categorisation and repair. Leak detection includes systematic surveys of
pipes and acting on reports from the public and emergency services. Information from the leak management plan may
be reported to the jurisdiction technical regulator and the plan feeds into the mains replacement plan.
Mains replacement plan - Aims to ensure public safety is maintained and lays out the most cost-effective long-term
approach to leak minimisation. This plan considers data from the leak management plan, and identifies parts of the
network where remediation or replacement becomes more economical than the costs of leakage and ongoing repairs.
Proposed major mains replacements are based on business cases using a net present value financial analysis. The
economic life is in the order of 50 years for plastic pipes and 80 years for steel pipes—but a 20-year period is typically
used, as the discounted costs (based on previous expenditure and repairs) and benefits become immaterial beyond
this duration.
The plans set out the capital expenditure required to replace and remediate mains and will be used to demonstrate
that the gas network operator’s proposals meet the NGR’s criteria for its capex allowance to be approved by the AER.
The survey and the case studies have highlighted that safety is the primary driver of mains repair, remediation and
replacement. Where safety is not an issue, leaky mains will be remediated or replaced only as it becomes costeffective to do so.
The trials have also shown that the extent to which leaky mains are replaced varies among networks, ranging from
none to around 25% of a distributor’s capex.
One case study participant advised they expect to replace all aged pipe in their two main networks by 2018 and 2021
respectively, requiring a capital expenditure of between $750 m to $1 billion, which has been approved by the AER.
Fugitive emissions associated with leakage from their networks are expected to be considerably reduced, from an
average of around 1.5–3% noting that fugitive emissions are one component of UAG.
In the late 1980s and first half of the ‘90s, another case study participant undertook a major project to rehabilitate
mains in 80% of its network. The distributor has been since been rehabilitating the remainder of its network on an ‘as
justified’ basis.
14.1 How distributors value gas losses
All gas distributors in Australia are either required to purchase gas for UAG or to compensate retailers for the cost of
UAG, where it exceeds a regulated UAG allowance.
Typically, gas network operators will acquire gas through a competitive tender process. As a result, the price paid for
UAG may not be publicly available. In several cases the AER has acknowledged the commercial-in-confidence nature
of the price of UAG and has not made the information available as part of the information published during an Access
Arrangement Review.
The price of UAG will include the cost delivered to the gas network (i.e. the field price and transportation charges) plus
a margin related to the opportunity cost of the gas. The opportunity cost will be the margin that the wholesaler or
retailer could have obtained from another customer that is of the same size or could be traded with another gas
market participant. UAG contracts are likely to be for a minimum of one year and may be for two or three.
UAG volumes typically range from several hundred TJ to several PJ and therefore prices for UAG can be expected to
reflect the margins in gas prices to very large customers, and are of the order of 5% of the delivered gas price to those
customers. This would typically be 10-15% of the cost of gas delivered to a network (city gate cost).
Based on the STTM and DWGM data, the cost of UAG on the east coast of Australia is likely to be in the range $6.50–
7.50 per GJ increasing to $8.50–11.50 per GJ over the next three years. 29 Based on the ACIL Tasman report, UAG in WA
is likely to cost in the range $10–11.50 per GJ.
29
This is supported in a recent report by ACIL Tasman for IPART, DRAFT Cost of gas for the 2013–16 regulatory period, A report on the wholesale
cost of gas for the review for Standard Retailers in New South Wales, ACIL Tasman 22 April 2013
36
By comparison, the UAG prices indicated by the three distributors who provided UAG information in our survey are
consistent with market prices plus a margin of greater than $1 per GJ in some instances, presumably because of a tight
wholesale market.
14.2 The carbon pricing mechanism
Gas distributors are liable under the carbon pricing mechanism (CPM). The National Greenhouse Emissions Reporting
Scheme (NGERS) requires distributors to estimate their fugitive emissions as 55% of a network’s UAG. 30 As a
distributor’s carbon liability is a statutory payment, it is a pass-through cost that is included in network tariffs and so
ultimately paid by retail customers.
However, for the purposes of financial valuation of leakage reduction projects, a distributor will take into account the
carbon price associated with leakage from its network. At the current carbon price of $23 per tonne of CO 2 equivalent,
the carbon cost of gas leakage is $4.15 per GJ31. This will be added to the cost of UAG gas to arrive at a value for
reduced leakage, used in the determining economic viability of leakage mitigation proposals. Thus, the CPM increases
the value of gas in investment decisions in the order of 50%. This can be expected to increase the economically viable
investment in rehabilitation, but the effect on leakage cannot be estimated with the information available.
15 Network gas losses and use
15.1 Estimating distribution network losses
To estimate the level of losses and mitigation opportunities, it is helpful to characterise gas networks in terms of the
proportion of a network constructed from leakage prone material, that is, the extent to which a network’s pipes
comprise cast iron, galvanised and unprotected steel and PVC.
Our survey of gas distributors provided a range of data about gas distribution energy use/loss, summarised in the
tables 4 and 5. Based on the survey, total UAG for Australia is approximately 12.6 PJ and emissions from leaky mains
are estimated to be around 4.5 PJ of this. The remaining 8.1 PJ consists of metering error (i.e. is not leaking gas) and a
small component from venting, theft, land leakage from valves, fittings and ancillary equipment.
Table 4: Summary of surveyed gas distribution networks
10
Number of networks surveyed
Total length of mains
87,017 km
Total gas delivered
380 PJ p.a.
89%
% of total gas delivered by distribution networks
7,630 km
Total length of potentially leaky mains
8.8%
Average proportion of potentially leaky mains
12.6 PJ p.a.
Total UAG (quantity)
3.3%
Average UAG (proportion of deliveries)
4.5 PJ p.a.
Estimated fugitive emissions from leaking mains
Note: Figures are for the financial year ending June 2012.
30 National
Greenhouse and Energy Reporting (Measurement) Determination 2008, Section 3.80. Distribution networks may also use the facility
specific method outlined in Section 3.81.
31 The
carbon cost of fugitive emissions is $4.15/GJ = $23/t x 0.328 te x 0.55 UAG using the standard factors for natural gas CO2 equivalent of 0.328
te.
37
Table 5: Survey results of UAG and leaky mains
Max
Min
Volume
Weighted
average
UAG (% of deliveries)
5.3
0.3
3.3
% of potentially leaking mains
25.3
0.0
8.8
Loss indicator
Analysis of the UAG data shows an observable trend in the reduction in leaky mains, but no commensurate reduction
in UAG. The following table shows changes between 2008 –12.32
Table 6: UAG and leaky mains trends
2008
2012
UAG%
3.3%
3.3%
UAG TJ
12.6
12.6
Leaky mains length(km)
8,791
7,641
Leaky mains (% of total mains)
11.3%
8.8%
Between 2008–12, the length of leaky mains reduced from 8,791 km to 7,641 km (a reduction of 1,150 km or 13%),
and the proportion of leaky mains was reduced from 11.3% of total network mains length to 8.8%. Based on publicly
available information from Access Arrangement reviews33 the main gas network operators invested in excess of $420
million on rehabilitating the leaky mains in their networks during 2008–12.
In contrast, there is no broad industry trend for UAG. In some cases, UAG has remained unchanged even after the
operators have rehabilitated some (but not all) leaky mains, suggesting that the other untreated pipes deteriorate and
leak more so that no overall reduction occurs. In some cases, networks with no leaky mains have indicated increased
UAG, suggesting metering problems. This highlights that measurement error is a significant component of UAG and is
masking some leakage changes.
16 Economically feasible loss-reduction opportunities
16.1 Operational opportunities – water bath heaters, regulators, main venting,
mains pressure management
Other than the replacement of leaky pipes, there are very limited opportunities for gas distribution networks to
further reduce losses.
Meter regulators are a minor, occasional source of leakage and will be replaced at the same time as a meter—typically
every 20 years. To systematically identify and replace them earlier would be uneconomical.
In the case studies, one distributor indicated they reduce pressure in some older parts of their network in non-peak
periods, such as summer, to reduce fugitive emissions. They advised, however, it was not possible to measure how far
emissions were reduced.
Mains venting is an unavoidable part of gas network operation. It usually arises because of third-party interference or
if it becomes necessary when connecting a new section of the network. Case study participants advise the amount of
32 This
33
was the longest period for which survey data was available for all companies
Derived from Access Arrangement Information on the AER and ERA websites
38
gas vented can’t be measured but is estimated to be a very small component of fugitive emissions in older networks.
The cost of capturing and reusing gas vented during planned operations would exceed the value of the saved gas by
orders of magnitude.
Water bath heaters heat gas at transmission pipeline delivery stations to compensate for the cooling of gas as it
passes through pressure regulators which reduce the pressure. When pressure drops suddenly, the gas cools through
the Joule-Thomson effect which can cause the gas to fall below the design temperature limits of steel used in
downstream piping, valves and other equipment. Pre-heating the gas before it passes through the regulators prevents
its temperature falling below a safe level.
Gas heating is essential to the safe operation of the network, so there is little scope to reduce gas used on water bath
heaters. Gas used to operate water bath heaters is measured and therefore is not included in UAG. A large gas
network may have typically not more than 20 water bath heaters and gas use is estimated to very small compared to
network losses.
These areas represent very limited loss reduction opportunities. For networks with relatively high fugitive emissions,
these opportunities are a small component of UAG. For networks with low fugitive emissions, they are still not likely
to be a significant proportion of UAG, and the largest UAG component in many circumstances is metering error.
16.2 Technological developments to reduce losses
Gas network technology is very mature. The most recent improvement of any significance to reduce losses was the
introduction of plastic pipe and cathodically protected steel in the 1970 and 1980s.
As a result of the introduction of these technologies the industry has developed methods to rehabilitate leaky mains
through insertion of a smaller diameter plastic pipe inside the old main, which avoids digging trenches and removing
old mains. The plastic pipe can run at much higher pressure and consequently has greater capacity than the original
pipe.
Customer connections are also rehabilitated using plastic pipe insertion, wherever possible, though meters and
regulators are replaced because they must operate at the higher pressure. However, there are cases where new mains
must be laid, either because a new section of high pressure steel pipe needs to be interconnected because the gas
flow changes, or because insertion is impractical.
The development of boring machines, in use for more than 10 years, has also facilitated mains replacement for
situations where plastic pipe insertion is not practical, and where boring is more economical than trenching.
The evolution of these technologies has gradually improved the economics of mains rehabilitation and replacement,
however most improvements are marginal and unlikely to result in significant increases in the historic rate of
rehabilitation.
16.3 Estimate of loss-reduction opportunities
Data from our survey suggests that, apart from one network, which has a program to reduce its relatively high level of
leakage, the current programs of mains rehabilitation are keeping leakage at a steady level with continued
deterioration of leaky pipes offsetting the leakage reductions associated with annual rehabilitation programs.
In effect, current investments in mains rehabilitation are stopping the increase in leakage that would occur if mains
were not being rehabilitated.
39
Our analysis shows there is a discernible relationship between the proportion of leaky mains and UAG and there is a
weak (r2 = 0.24), but expected correlation between the percentage of leaky mains and UAG as a percentage of
deliveries. The graph below shows the relationship.
Figure 10: The correlation between the proportion of leaky mains and UAG
As expected, this demonstrates that reducing the length of leaky mains will reduce UAG. But the wide scatter also
indicates that UAG is significantly influenced by factors other than leakage, the main one being metering error, as
discussed above. The correlation coefficient (r2) of 0.24 indicates that only 24% of the variation in UAG can be
explained by the proportion of leaky mains. It also suggests that the best estimate (and one subject to reasonable
uncertainty) of the effect of reducing the length of leaky mains from an average of 9% to 0% (i.e. eliminating them
altogether) on UAG would be to reduce UAG to 2.1%; that is by approximately 1.2% of deliveries or 4.5 PJ pa.
The figure of 4.5 PJ p.a. compares with the NGERS estimates of 6.9 PJ. The differences between the two figures
cannot be definitively explained, but points can be made in understanding the differences:

A difference between total fugitive emissions and leakage from mains should be expected as not all fugitive
emissions will arise from leaky mains.

The statistical uncertainty (i.e. error) of both measurements means that the actual difference may be more or
less than the 1.4 PJ p.a. indicated.
The estimate based on the correlation of UAG versus length of leaking mains is likely to have a lower level of statistical
uncertainty than the estimate based on the length of the mains and therefore be the better basis for estimating loss
reduction potential.
Analysis of data from the case studies, illustrated in the examples based on this data in Appendix 8 shows that leakage
rates of over 1,600 GJ p.a./km are required to justify mains rehabilitation projects. This is equivalent to between 60
and 260% of deliveries, with average consumption per house hold varying between 20 GJ p.a. (NSW) and 60 GJ p.a.
(Victoria). This high leakage rate strongly suggests that only a relatively small proportion of leaky mains will be
sufficiently leaky to justify the cost of replacing them, unless there is a safety imperative. Given these figures, the
maximum proportion of leaky mains that would be economically viable to replace would likely to be less than 15%34.
That is, the maximum potential economic reduction of leakage (that is, the upper bound estimate) is 0.7 PJ p.a.
However, the actual level may be well less than this.
34
Taking the threshold for mains rehabilitation to be economically viable as 1,600 GJ/km p.a., and the average level of leakage as 150 GJ/km and
assuming that the remainder of leaky mains must have a leakage rate at 40GJ/km (a conservatively low figure), the proportion of leaky mains that
are economically viable to rehabilitate is 7%. Allowing for the uncertainties in the survey data, a maximum figure of 15% is reasonable.
40
Looked at from a different perspective, taking the total length of leaky mains (7,641 km) and using an estimate of
the average cost per km to rehabilitate mains of $250,000 per km, based on our survey data, the cost would be
$1.9 billion. The maximum annual saving in gas would be between $76 million and $112 million based on a gas price
range of $5–$9 per GJ plus carbon tax equivalent of $4.15 per GJ. This represents paybacks of between 16 and 25
years. It is clear from this that wholesale replacement of the leaky mains, in place of the systematic replacement that
is currently being undertaken, would not only be very expensive, but is also clearly uneconomical.
As a result, the estimate of viable loss-reduction opportunities in addition to the systematic replacement of leaky
mains by distributors is either immaterial or non-existent.
Based on recent regulatory reviews, it appears that increasing gas prices and inclusion of the cost of carbon in
business cases has begun to change the economics of rehabilitation and so is providing a basis for increasing the rate
at which gas networks rehabilitate their mains. The price of carbon is a clear market signal that can be expected is
being incorporated into economic evaluations of mains rehabilitation projects.
17 Incentives and barriers to reduce network losses
17.1 Safety and technical regulation
Safety is a strong incentive for distributors to reduce network losses. Safety is the primary consideration in the design,
construction and operation of gas distribution networks and is a key driver for the mitigation of network losses.
National Gas Rule 79 requires the AER to approve capital expenditure for safety reasons (discussed in detail below).
Safety is addressed by technical regulation, provided for by the gas legislation operating in each state and territory.
The legislation in each jurisdiction is similar and largely draws on AS 4645, the Australian Standard for Gas Distribution
Networks. This Standard covers all aspects of design, construction, testing, commissioning and operation and
maintenance of gas networks. Its major focus is reliability, safety and environmental management. As part of the
focus of the Standard on safety matters it includes provisions specific to the management of leakage.
As part of the regulatory processes, network operators are required to prepare and operate by a Safety and Operating
Plan (SAOP) that conforms to AS 4645. A SAOP covers all matters around the safe and reliable operation of a gas
network and includes requirements for management of leakage. The plan and compliance are typically audited and
approved by the technical regulator in each state.
17.2 Economic regulation
UAG Allowance
All but a few minor gas networks are covered (i.e. economically regulated) under the NGL and NGR. The AER is the
regulator in all states and territories except WA, where the Economic Regulation Authority (ERA) is the regulator.
Economic regulation focuses on the economically efficient investment, operation and use of gas networks.
In respect of operating expenditure, Rule 91 of the NGR provides that the regulator is required to approve
expenditure that ‘would be incurred by a prudent service provider acting efficiently, in accordance with accepted good
industry practice, to achieve the lowest sustainable cost of delivering pipeline services.’
Consequently, the regulator must approve an allowance for UAG it determines is efficient. By fixing the UAG
allowance the regulator provides an incentive for the gas network operator to minimise UAG. This operates in the
following manner.
All regulated distributors in each state and territory, except for Victoria, pay for UAG in their networks. In each
network’s access arrangement review, the distributor proposes what it considers is an efficient level of UAG. The AER
(ERA in WA) reviews this proposal and other evidence and approves what it considers to be the economically
efficiency level of UAG and includes that as a UAG allowance, which is included in the calculation of network tariffs. If
the network’s UAG falls below the benchmark, the distributor retains the UAG allowance they don’t use for the fiveyear period of their access arrangement. If the network’s UAG rises above the benchmark, it is a cost the distributor
can’t recover and must be borne by them.
In Victoria, UAG is paid for by retailers, but there is an incentive mechanism under the National Gas Rules which has
the same effect as if the Victorian distributors had to pay for UAG. This is achieved by AEMO setting a benchmark for
41
efficient UAG. Where a distributor exceeds this efficient benchmark it must compensate retailers for the difference
between the benchmark and actual. Where the distributor achieves UAG below the benchmark, retailers compensate
the distributor.
Regardless of which of the above incentive mechanisms is applied, setting a UAG allowance provides a strong
incentive for gas distributors to invest in UAG reduction that delivers a return on investment at or above the regulated
rate of return. There is a significant potential impact on returns from exceeding the regulator’s approved level of UAG.
Capital Expenditure Approval
National Gas Rule 79 specifies that capital expenditure must be:

prudently incurred and efficient

generate a positive NPV

required for safety, the integrity of the network, or to meet demand growth.
As a result, regulators are required to approve capital expenditure that is either necessary for safety reasons or where
the impact of the investment would lead to reduced costs for distribution transportation services.
For loss mitigation driven by safety, this covers rare instances where leakage is so bad as to constitute a public safety
issue, and the gas network operator will seek, and the regulator is bound to approve, expenditure to ensure that
public safety is achieved.
For loss mitigation that is not safety related, to obtain approval for a capital expenditure allowance to mitigate
network losses, gas network operators must provide sound evidence of the economic returns that will result in
reduction in transportation tariffs, demonstrated by numerous examples of such evidence in Access Arrangement
Proposals35.
Gas network operators will undertake, and regulators are required to approve, capital expenditure where the return
resulting from investment in mains replacement and rehabilitation is greater than or equal to the allowed return—the
weighted average cost of capital (WACC)—set by the regulator. Recent decisions estimate the nominal vanilla WACC
at between 7% and 9%. As demonstrated for gas pipelines, projects that meet returns of this level will have paybacks
of eight years or more. Any projects that exceed this level can be expected to be proposed by gas network operators
and approved by the regulators.
This raises the question of whether the main barrier to reducing leakage is persuading the regulator that capital
expenditure to reduce leakage is an economically efficient investment. Recent decisions by the AER in Victoria
involved significant reductions in the allowance for mains replacement capital expenditure. The AER reduced the
allowances in its draft decisions by between 48% and 78%. After the businesses revised their proposed mains
replacement capital expenditure allowances downwards, the AER increased the allowances against its draft decisions,
but these are lower than the business’s revised proposals by between 17% and 37%.36
It is up to the businesses to put forward evidence that will persuade the regulator. However, the regulators have
discretion as to how that evidence is interpreted. In the current environment, where there have been significant
increases in energy prices, the regulators can be expected to exercise their discretion in favour of constraining prices,
by adopting conservative views about capital expenditure allowances.
It is not possible to determine whether the gas network operators or the AER were closer to the actual efficient level
of mains replacement capital expenditure. What can be seen is that the businesses are looking to invest considerable
amounts of funds in mains replacement and will be constrained by the regulator.
35
Two examples are: (1) APT Allgas included its Mains Replacement Strategy in submissions to the AER of its 2010 – 2016 Access Arrangement
Review. Other Gas Network Operators have provided extensive information to support investments in mains rehabilitation (2) MultiNet Gas Access
Arrangement Information 2011–2016, pp. 112–119
36 Final
Decision SP Ausnet Access Arrangement , March 2013, AER, Page 30; Final Decision Multinet Gas Access Arrangement , March 2013, AER,
Page 19; Final Decision Envestra Victoria Access Arrangement , March 2013,AER, p. 23
42
17.3 The carbon pricing mechanism
The CPM provides an indirect incentive to reduce gas leakage by increasing the value of losses used in economic
evaluations of leakage reduction projects in the order of 50%. This in turn increases the proportion of network
remediation that is economically viable.
17.4 Conclusions for the gas distribution sector
The large majority of losses from distribution networks are the fugitive emissions from leaks in old mains (pipes).
Based on our survey data, fugitive emissions from leaky mains on gas distribution networks is estimated to be 4.5 PJ
p.a.
The case studies show that distributors systematically monitor and replace leaking mains and that mains rehabilitation
and mains replacement are their main focus to reduce losses in their networks. Their processes typically include plans
for asset management, safety, and leak management and mains replacement; some of which are regulatory
requirements or feed into access arrangements.
From 2008 to 2012, the average proportion of leaking mains for Australia’s distribution networks dropped from 11.3%
to 8.8%. During this time UAG remained static, suggesting that as network operators repair leaky mains, the remaining
leaking mains deteriorate.
Economically viable loss-reduction opportunities, in addition to the systematic replacement of mains already
undertaken by distributors , are estimated to be immaterial.
Distributors have strong incentives to reduce network losses:

Safety – this is a primary driver to reduce fugitive emissions. Distributors have to meet jurisdiction technical
standards and the Australian Energy Regulator (AER) is obliged to approve capital expenditure required for
safety or to maintain the integrity of a network.

UAG allowance – most states and territories have a UAG revenue allowance for gas distributors based on a
level of economically efficiency UAG set by the AER. Exceeding this level incurs financial penalties and
keeping UAG below this level provides a financial gain.

Capital expenditure – distributors can have capital expenditure to reduce leakage (i.e. through mains
rehabilitation) included in their capital base, on which they earn the regulated rate of return.

Carbon pricing mechanism – the CPM is a cost passed through to consumers but adds in the order of $4/GJ
to the cost of fugitive emissions considered in investment decisions. This increases the proportion of a
network for which mitigation is economically viable.
The only barrier to reducing leakage is persuading the regulator that proposed capital expenditure to reduce leakage
is an economically efficient investment, as required by the NGL and NGR.
A major aim of the EEO Program is to address information barriers to improving energy efficiency within
organisations. The case studies indicate that such barriers within distribution businesses are minimal. However,
research for the trials has highlighted there is no systematic, consistent reporting of network losses and loss trends for
Australia’s distribution networks. Reporting UAG, possibly through the AER’s regular reporting such as its annual
performance reports for Victorian Gas businesses and the State of the energy market reports, would improve
transparency for market participants and policy-makers.
43
18 APPENDICES
A. Gas transmission survey form
B. Case study transmission pipeline A – high compression density
C.
Case study transmission pipeline B – low and medium compression density
D. Natural Gas Star list of loss reduction opportunities
E.
Gas distribution survey form
F.
Case study gas distribution network A
G. Case study gas distribution network B
44
Appendix A
Gas transmission pipeline survey form
Pipeline name
2001
2002
2003
2004
SUG (%)
SUG (TJ/p.a.)
Gas delivered (PJ p.a.)
Capacity (PJ p.a.)
Capacity (TJ per day)
Price ($/GJ)
Cost ($'000)
Total length of pipeline
(km)
Total compressor stations
Mainline length (km)
Mainline compressors
Total compressor power
- available
- at full compression
Compressor fuel (TJ p.a.)
Non-compressor SUG
Compressor density
(Comp. stations/km)
Mainline compressor
Density
(Comp. stations/km)
Regulatory status
Who pays for SUG?
45
2005
2006
2007
2008
2009
2010
2011
2012
Appendix B
Case study: Transmission Pipeline A, high compression density
Background to the pipeline and losses
Pipeline A has been chosen for this case study because it typifies the upper end of the range of compression density
for Australian pipelines, with losses as a proportion of throughput being approximately 2%. The pipeline traverses
remote areas and has a number of supply and delivery laterals. Some of its customers are large gas-users.
In order for it to continue to meet growing demand, it has expanded its capacity in stages using extra compression,
pipeline looping (duplicating the pipeline) and compression debottlenecking to deliver the most cost-effective solution
for each expansion stage.
Because of its relatively high compression density by Australian pipeline standards, approximately 95% of Pipeline A’s
energy losses (comprising energy use and fugitive emissions) are associated with compression; that is, they are a
direct result of the consumption of energy to enable delivery of gas to its contracted capacity.
Table B1: A breakdown of Pipeline A’s energy losses
Source of loss
Proportion of total
loss
Compression
~90%
Gas engine alternators
~5%
Miscellaneous
~5%
Total
100%
In most circumstances gas engine alternators (GEAs) are associated with electricity provision for operation of
compressors. Electricity is used to power ancillaries, such as turbine engine starters, oil pumps, oil and gas cooler fans
etc. Gas used for GEAs can be considered as energy use associated with compression.
The miscellaneous 5% includes fugitive emissions from valves, measuring equipment, blowdowns from compressors
and scraper traps and the like. As a consequence of the high proportion of compression related losses, the main focus
of loss mitigation opportunities for Pipeline A relate to compression and GEAs.
Business approach to management of losses
The business that owns and operates Pipeline A has actively identified opportunities to mitigate losses. Although there
has always been a focus on efficiency, a dedicated energy efficiency program was implemented in 2009 and has
evolved from a centralised approach to one that devolves responsibility for energy efficiency to internal departments
that have responsibility for the operation of the relevant emissions sources and seeks to inculcate a culture of energy
efficiency. This is being introduced in much the same way that companies embed safety, environmental and quality
management in their cultures, systems and procedures.
Drivers of loss mitigation
This business has a number of drivers for adopting a proactive approach to energy losses. These are:

Safety/technical regulatory – Safety provides a strong incentive to minimise gas loss, and minimising fugitive
emissions and SUG is an operational priority. Technical, safety and environmental regulation is provided for
by state legislation. This legislation calls up AS2885 – the Australian Standard for Pipelines , Gas and Liquid
Petroleum, and covers all aspects of the design, construction, testing, commissioning, operation and
maintenance of pipelines. The standard inherently requires the minimisation of fugitive emissions and
venting of any kind.
46

Commercial/economic regulatory – This is a direct impact on the business. Unlike most pipeline operators in
Australia, this operator is required to purchase SUG to operate the pipeline. The pipeline’s tariff is fixed,
based on an amount and cost of SUG set by the regulator. As a result the business has a strong incentive to
improve energy efficiency to increase its profitability. This requirement is contained both in its Access
Arrangement—under which a fixed amount of efficient losses are approved by the regulator and SUG is to be
paid for by the service provider—and also in commercially negotiated transportation agreements.

Carbon Price Mechanism – The majority of carbon costs are passed through to shippers (customers) under
regulatory requirements and most commercial arrangements for Pipeline A; however, there is significant
pressure from shippers to provide a transparent account of the business’s carbon liabilities to minimise what
is passed through. A proportion of Pipeline A’s carbon costs are not passed through, providing a further
abatement incentive.
Analysis of pipeline losses
Energy use and losses as a proportion of throughput
Table B2: The history of Pipeline A’s losses
Loss source
Compressor fuel
GEA fuel
Heater fuel
Minor system gas
Total
2001–04
2004–08
2008–12
3.1–3.9%
4.3–5.0%
2.8–1.7%
0.13–0.14%
0.12–0.13%
0.15%
0.027%
0.025%
0.023%
0.5%
0.4–0.5%
0.4%
3.3–4.1%
4.5–5.2%
1.9–3.0%
This profile reflects a natural progression in the life of a pipeline, as the optimal combination of compression and
looping is used to provide the required level of throughput to meet contractual gas delivery requirements. As demand
increases, compressor fuel use as a proportion of deliveries increases (from 3.1 % up to 5.1% of throughput). It
reaches a peak at which point the addition of looping to increase the capacity of the pipeline reduces the compression
required to deliver a given quantity of throughput (the actual compressor fuel usage is very sensitive to throughput
capacity utilisation).
The other, much smaller sources of losses are relatively independent of throughput, and therefore relatively static in
absolute quantity, apart from efficiency improvements, but are decreasing in proportion to load.
Energy loss management program
Systems and process
The operators of Pipeline A have a history of seeking to optimise their running costs. Up to the early 2000s, energy
efficiency, particularly in relation to compressor operations, did not have any greater focus than other operational
matters in determining operational expenditure (opex) and capital expenditure (capex) for the pipeline.
In the mid-2000s the need to maximise pipeline capacity led to a renewed focus on improving the energy efficiency of
compression. With the introduction of the National Greenhouse Emissions Reporting Scheme (NGERS) and the
potential for a price on carbon, Pipeline A progressively became more systematic in its approach to reducing energy
use.
Pipeline A’s response to the need to address energy use and was developed into a formalised company-wide approach
in 2009. This program comprised a systematic process of loss-mitigation opportunity identification, evaluation and
implementation. This program came under a central department responsible for driving energy efficiency.
The program stimulated the key areas of the business to identify energy efficiency opportunities and entering the data
into a central register. The key areas were those with activities relating to the major energy consumption areas,
principally pipeline operation – but also extended to the routine aspects of office energy consumption etc.
47
The process of identification and review of energy efficiency opportunities was overseen by a steering committee of
representatives from across the business, which guided the identification, evaluation and implementation processes
to ensure corporate objectives were being achieved and resources were made available.
The process comprises the following steps:
1.
Opportunity identification – The company’s departments identified potential loss mitigation opportunities
and logged them to a central register.
2.
Screening analysis – A desktop assessment of the economic viability of the proposed loss mitigation
opportunity was undertaken (typically +/- 50% cost and savings estimates). All economic benefits such as
capex and opex savings were considered along with loss mitigation and other benefits. A number of
economic criteria were considered, including net present value (NPV) and internal rate of return (IRR), but
the principal criterion was simple payback, the screening threshold being four years which allows priority to
be given to projects with the best returns.
3.
Steering committee review – The steering committee would determine whether proposed opportunities
should be pursued further through detailed assessment, including high-quality estimates of costs and
benefits, to arrive at a definitive economic/business case evaluation.
4.
Detailed analysis – This provided a more accurate assessment on which the steering committee could make a
decision that an opportunity: (i) was not viable, (ii) should be immediately implemented or (iii) should be
deferred—dependent on whether the economics were marginal and therefore not a priority, or when the
cost benefits could be expected to change in the future, and the opportunity should be re-evaluated
periodically.
5.
Implementation – The steering committee approved viable projects for implementation, depending on capex
and opex requirements and the payback period. Opportunities that only required a small investment and/or
changes in operating procedures with short payback periods, were given priority.
6.
Monitoring effectiveness – Where the costs and benefits of an implemented opportunity could be
quantified, this was tracked and reported periodically. However, because there was no ‘counterfactual’
against which to compare the results, the assessment of the benefits was an informed estimate, which
becomes less reliable over time and as operations became increasingly influenced by other factors.
To embed a culture of energy efficiency, this centralised model was recently replaced with one which devolves
responsibility for identifying and implementing energy saving opportunities to departments and individuals. The
central pipeline efficiency department continues to have a role in facilitating the identification and implementation of
loss mitigation opportunities. The monitoring of effectiveness under the decentralised model is still being developed,
but benefit assessment may be limited to the first 12 months after full implementation of each opportunity, to reduce
estimation uncertainty.
48
Summary of opportunities identified
From 2009 to June 2012 Pipeline A had identified 62 potential loss mitigation opportunities. Of these, 57 related to
pipeline specific efficiency and the remaining five related to more general matters. The table below breaks down the
types of opportunities identified.
Table B3: Loss mitigation opportunities by source
Loss mitigation
Opportunity
Identified
Screened
out
Awaiting
analysis
Have had
detailed
Suspended later review
Implemented
Investigation
(Decision
pending)
Compressor fuel
19
3
6
2
5
3
GEA fuel
9
2
5
0
0
2
Minor system gas
14
8
4
0
0
2
Gas fired heaters
3
1
2
0
0
0
Other pipeline
12
3
8
0
0
1
Other general
5
1
1
0
1
2
Total
62
18
26
2
6
10
The results of the economic evaluations that have been undertaken are summarised in below.
Table B4: Estimated payback period for identified opportunities
Loss mitigation
opportunity
<= 1
week
1–4
weeks
1–6
months
6–12
months
1–4 years
> 4 years
(but viable)
Not viable
Compressor fuel
1
3
2
0
GEA fuel
1
1
1
Minor system gas
0
1
Gas fired heaters
0
Other pipeline
0
1
1
11
1
1
0
2
2
1
0
0
0
6
6
0
0
0
0
0
1
2
0
0
0
0
0
0
2
10
Other general
0
0
0
0
1
0
0
4
Total
2
5
4
1
2
1
12
35
49
No Results
recorded
Each opportunity has been classified as follows:
a
New/different technology
b
Procedures
c
System operating changes
d
Equipment operating changes
e
Change maintenance practices
f
Monitor equipment and System operating changes
g
Substitution
h
Install additional or modify Equipment
i
Other
The opportunities by classification are set out below.
Table B5: Loss mitigation opportunities by classification
Loss mitigation
opportunity
a
b
c
d
e
F
g
h
i
Compressor fuel
1
2
9
1
0
2
0
4
0
GEA fuel
0
0
2
3
2
0
0
2
0
Minor system gas
6
1
1
3
1
0
1
1
0
Gas fired heaters
0
0
2
0
0
1
0
0
0
Other pipeline
2
1
2
2
0
2
0
2
1
Other general
0
0
0
0
0
0
0
5
0
Total
8
4
17
9
3
5
1
14
1
The opportunities classifications for the 9 implemented opportunities are set out below.
Table B6: Implemented loss mitigation opportunities by classification
Loss mitigation
opportunity
a
b
c
d
e
F
g
h
i
Compressor fuel
0
0
1
1
0
1
0
0
0
GEA fuel
0
0
1
1
0
0
1
0
0
Minor system gas
0
0
1
0
1
0
0
0
0
Gas fired heaters
0
0
0
0
0
0
0
0
0
Other pipeline
0
1
0
0
1
0
0
0
0
Other general
0
0
0
0
0
0
0
1
0
Total
0
1
3
2
1
1
1
0
0
50
Examples of particular opportunities, including paybacks and estimated loss reduction as a proportion of SUG, are
provided below.
Table B7: Examples of specific loss reduction opportunities
Opp.
No.
Title
Category
Bias compressor unit operating hours to favour higher
efficiency units
CF
d
0.02
2.8%
Reduce leakage rate through compressor unit and station
vent valves by reviewing leak check and rectification
practices
MSG
e
0.18
2.2%
Where there is a choice of GEA size, operate smallest GEA
capable of handling normal station load
GEA
d
0.01
1.3%
20
Increase pressurised hold time of all dry seals to 30 days
MSG
c
0.25
0.1%
41
Operation of Inlet facilities from mains power with GEA on
standby
GEA
c
0.04
0.2%
11
16
7
Class’n
Payback
(years)
Estimated
proportion
of SUG
All of these examples involve changes to operating procedures and have low implementation cost. It is important to
note that these loss reduction estimates reflect those available under favourable conditions, which in practice are not
always available. As a result the actual level of savings realised by Pipeline A have been lower than in the initial
estimates. Pipeline A is seeking to increase the prevalence conditions favourable to achieving maximum savings.
However, this requires continuous improvement of the operating environment and will take time to achieve.
Given the variability of the conditions affecting the nine implemented projects, Pipeline A estimates the total loss
reduction achieved to date to be approximately 5% of energy use (i.e. SUG). These opportunities are the most viable
and easiest to implement and may be considered ‘low hanging fruit’.
Future loss reductions
It is difficult to estimate future loss reductions for a number of reasons. These include:

The results of the assessments of a significant number of potential opportunities are still to be
completed.

Changes of technology that may make currently unviable opportunities viable or introduce new
opportunities.
The impact of changes in the cost of SUG and the price on carbon, either as a carbon tax or value of carbon credits, is
impossible to predict. The business considers an upper limit for further loss reduction for Pipeline A in its current state
of expansion, considering the high compression character and their relatively sophisticated energy efficiency regime,
to be 5% of losses. Together with the loss reductions already achieved this represents 10% of pipeline losses or 0.2%
of throughput.
Barriers to loss mitigation
Pipeline A could not name any significant barriers to identifying and implementing energy efficiency opportunities.
However, a key reason behind the move towards a more devolved internal energy efficiency framework was to drive a
broader culture of energy awareness and to incentivise managers to allocate time and resources to energy efficiency.
51
Conclusions
Some broad conclusions can be drawn about the nature of the loss reduction opportunities identified so far by
Pipeline A:
 Pipeline A has one of the highest levels of compression in Australia. Approximately 95% of Pipeline A’s energy
use is related to compression. Accordingly, compressor optimisation is the largest potential opportunity to
reduce energy use.
 The pipeline’s energy efficiency program has reduced energy use by approximately 5% in its first 4 years. It is
difficult to estimate the likely future level of economic loss reduction, however the operator considers the
upper limit for additional reductions in energy use in its current state of expansion is 5%. Together with
energy use reductions already achieved, this represents a possible reduction of up to 10% of the pipeline’s
energy use, which is in the order of 0.2% of deliveries.
 Most energy efficiency opportunities have involved operational and procedural changes and have paybacks
significantly less than four years. Only a small number of opportunities identified involve capex requirements
of any significance.
 Pipeline operator A has some strong financial and business incentives to reduce energy use. One of these
incentives is that it pays for SUG.
52
Appendix C
Case study: Pipelines B and C, low and intermediate compression-density pipelines
Background to the pipelines and losses
Pipelines B and C have been chosen for this case study because they reflect the lower end and mid-range of the range
of compression density. They are owned by the same company and apply the same management practices.
Both pipelines have been expanded in stages to meet growing demand for gas in the markets they serve. Pipeline B’s
expansions have been through adding compression alone. Pipeline C’s expansions have involved both additional
compression and some looping.
Background to Pipeline B
Pipeline B traverses a range of terrain including rural, bushland, semi-rural and industrial land and has a number of
delivery points. Some of its customers are large gas users. A significant proportion of its customers are
wholesaler/retailers that supply loads comprising residential, commercial and industrial gas users.
Although Pipeline B is has a relatively low compression density, a significant proportion of its energy use is associated
with compression. In this respect Pipeline B is unusual. This high level of energy use is because gas is compressed at
the inlet to the pipeline due to gas being delivered to the pipeline’s single receipt point at a lower pressure than the
operating pressure of the pipeline. Without this additional compression requirement, its losses would be significantly
lower.
The design decision to compress gas at the inlet to the pipeline is based on being more economical to operate at a
high pressure through a small diameter pipeline than at low pressure through a large diameter pipeline.
Background to Pipeline C
Pipeline C traverses rural land and has two supply laterals, numerous receipt points and a small number of delivery
points at the end of the pipeline. The majority of the gas delivered by this pipeline is for large users with some delivery
for shippers supplying residential and commercial customers.
Pipeline C’s capacity expansions have involved use of looping, because the increase in demand could not be
economically achieved using additional compression alone.
Table C1: Proportion of total energy use and losses
Source
Proportion of total energy use and losses
Pipeline B
Compression
Pipeline C
~92%
~94%
Gas Engine Alternators
~1%
~3%
Miscellaneous
~7%
~3%
100%
100%
Total
In a majority of circumstances gas engine alternators (GEAs) are associated with electricity provision for operation of
compressors. Electricity is used to power ancillaries, such as turbine engine starters, oil pump, oil and gas cooler fans
etc. In effect, therefore, gas used for GEAs can be considered as being loss associated with compression.
With 93% and 97% of energy use associated with compression, the majority of energy use reduction opportunities can
be expected to relate to compression.
It should be noted that even though Pipeline B has a low compression density pipeline its compression losses are
greater than for Pipeline C due to gas compression at its inlet, which requires greater power and therefore fuel
consumption than normal mid-pipeline compressors.
53
Business approach to management of losses
The business that owns and operates Pipelines B and C has a systematic approach to managing its pipelines through
three management system elements:
 focused environmental management approach
 adoption of asset management philosophy to managing its pipelines
 inclusion of energy efficiency as part of its assessment of business cases.
Energy efficiency is embedded in each of these elements. Historically, energy efficiency has been considered on an ad
hoc basis but the business has moved to a more systematic approach to energy efficiency for a number of reasons
including NGERS reporting, the introduction of the Clean Energy Act, and the potential inclusion of pipelines under the
EEO Act and various state environmental policies.
Drivers of loss mitigation
This business has a number of drivers for adopting a proactive approach to energy losses. These are:

Safety/technical regulatory – Safety and environmental management is key part of the pipeline’s
operations. Technical regulation for these pipelines is provided for by the pipeline legislation in the
states they operates in. This legislation calls up AS 2885, the Australian Standard for Pipelines, Gas and
Liquid Petroleum, and covers all aspects of design, construction, testing, commissioning, operation and
maintenance of pipelines. The standards inherently promote the minimization of gas leakage and venting
of any kind.

Commercial – Neither Pipeline B or Pipeline C is covered (regulated). The pipelines’ gas transportation
contracts provide commercial drivers for reducing energy use. The standard contracts for Pipeline B and
Pipeline C have different incentives for energy efficiency due to their different histories: Pipeline B has
never been regulated whereas Pipeline C has. Pipeline B’s transportation contracts require that shippers
provide all system use gas (SUG). This means that the direct incentive to reduce arising from bearing the
cost of SUG is absent. However, Pipeline B is required to manage SUG efficiently.
In contrast, Pipeline C’s standard transportation contracts require its shippers to provide SUG up to a
certain amount. This provides a clear incentive to maintain SUG below this level.

Competition – Both Pipelines B and C are subject to competitive pressure. Pipeline B is one of three
pipelines supplying the same market and shippers can be expected to take the cost of SUG into account
when negotiating gas transportation contracts. To date Pipeline C has been the only pipeline serving its
market, but there are a number of new pipelines being built that can potentially act as competitors,
providing pressure to minimise SUG.

Carbon pricing mechanism – This impact is indirect. While carbon costs are passed through to shippers
under the regulatory framework and most commercial arrangements for Pipelines B and C, there is a
significant pressure from shippers to provide a transparent account of the business’ carbon liabilities and
minimise what is passed through.
54
Barriers to loss mitigation
The operator of Pipelines B and C noted two minor barriers to identifying and implementing loss mitigation
opportunities:

Cost – Where loss reduction opportunities require capital expenditure they will have to compete for capital
based on the business’ hurdle rates and capital priorities.

Cultural – The operator is focused on reducing costs, but the specific focus on energy efficiency is an
emerging one. Recent changes to its policies, business processes and priorities are leading to a business
culture that is becoming more aware of the importance of energy efficiency as part of its environmental
policy and asset management practices.
Detailed analysis of pipeline losses
Table C2: Pipeline B – Energy use and losses as a proportion of throughput
Loss source
2010
2011
2012
Compressor fuel
1.49%
1.23%
1.42%
GEA fuel
0.01%
0.01%
0.01%
Heater fuel
0.13%
0.14%
0.13%
Minor system gas
0.00%
0.00%
0.00%
Total
1.63%
1.328%
1.56%
Table C3: Pipeline C – Energy use and losses as a proportion of throughput
Loss source
2010
2011
2012
Compressor fuel
0.88%
1.59%
1.91%
GEA fuel
0.04%
0.09%
0.08%
Heater fuel
0.07%
0.06%
0.06%
Minor system gas
0.01%
0.00%
0.01%
Total
0.99%
1.74%
2.05%
This profile for pipeline C exhibits the addition of compression and looping in 2009 followed by increased in
demand in 2011–12. The other sources of loss are relatively independent of throughput, and therefore
relatively static in absolute quantity (apart from efficiency improvements), but have reduced in proportion
to load.
55
Energy loss management program
Systems and process
The operator of Pipelines B and C has three elements in its management systems to address energy efficiency.
Environmental management
The business maintains a dedicated corporate environment team, in addition to employees with responsibilities for
environmental management within individual business units. This team’s mandate includes providing strategic focus
and identifying and implementing energy efficiency opportunities across the entire business. One team member is
dedicated to carbon reporting, reduction and energy efficiency.
In 2009–10 a comprehensive energy efficiency assessment was completed for the largest compressor station on
pipeline B as part of the relevant state government’s EREP (Environment and Resource Efficiency Plan) compliance
program. The finding was there were no commercially viable opportunities.
Asset management
The business develops asset management plans that are reviewed annually and updated to obtain an optimum return
on the investment over their economic life of its pipelines. Asset management plans consider a range of elements,
including operational, maintenance and risk management strategies 37.
Energy efficiency has historically been an embedded, but ad hoc, part of the asset management planning and
implementation. This process is being updated to include a systematic consideration of energy efficiency
opportunities through a rolling list of opportunities that is updated annually. This leads to engineering assessments of
the opportunities and, where they meet the business’ financial criteria, making investments (both capital and
operating). This process will be included in full for the asset management plan for the year ending March 2014.
Business case assessment
The business applies a disciplined business case process for project development, involving investment decision
‘gates’. The process for business case assessment is being upgraded to ensure systematic consideration of energy
efficiency opportunities. As part of its business case development each business case (or gate) will be required to
include an assessment of energy opportunities for a particular project.
Opportunities identified
Because the operator’s approach to date has been ad hoc, rather than systematic, it does not yet have a
comprehensive list of loss reduction opportunities. However, it has considered some significant opportunities as
follows.
Compressor co-generation
This opportunity consisted of the addition of heat recovery from one compressor turbine driver exhaust to generate
electricity. The feasibility investigation showed energy savings equivalent to approximately 5% of the gas fuel to one
compressor, which represents about 2% of compressor fuel use. The project financial evaluation shows the
investment will not generate a commercial return in the current environment and the business is investigating the
possibility of obtaining a government grant to make the project viable.
Compressor station operation cycling
The business has evaluated reducing compressor fuel by running its compressors in a cyclic fashion rather than steady
operation for one of its pipelines. This allows the compressors to work at their most efficient state (i.e. at high power
output) and then be shut down rather than operating steadily at lower power and resulting lower efficiency.
The business has undertaken the first stage of evaluation by running computer modelling. These estimate loss
reductions of up to 0.6% of gas delivered depending on how close to the pipeline operates to its maximum capacity.
37
PAS-55 is a publicly available specificationn on Asset Management published by the British Standards Institute. This document sets out an
internationally accepted approach to asset management and asset management planning
56
The closer to capacity it is the less the savings available. The business is now preparing to test the proposed change to
cyclic operation. If successful, the practice may be applied to the other pipeline.
Meter station upgrade
The business has evaluated the benefits of improving the accuracy of its meters. The result of this would be the
reduction of the GUF component of SUG. While this project would not reduce energy use, it would allow the business
to better assess the level of energy use and losses within the pipeline.
This opportunity involved evaluation whether to upgrade some or all of the existing meters stations, including the
adoption of ultrasonic meters in place of orifice plate meters. The business case recommended the upgrade of the
most problematic meter station with the expected improvement in GUF by 20% or 0.1% of gas delivered.
Conclusions
Some broad conclusions can be drawn about the nature of the loss reduction opportunities identified for Pipelines B
and C:
 The business has identified two significant opportunities to reduce use. One was not economic and the other
is being tested. One opportunity was identified to improve metering accuracy.
 The operator is introducing systems to systematically look for energy efficiency opportunities in its asset
management planning and project development processes.
 The overall energy use reduction opportunities for Pipelines B and C have not been assessed but based on
those investigated so far, the operator is of the view that the opportunities are not likely to be significant.
57
Appendix D
List of potential loss-reduction opportunities from the US Environmental Protection
Agency’s Natural Gas Star Program
Gas transmission – technology/practice
Replace gas starters with air or nitrogen
Install electric motor starters
Reduce gas venting with few compressor starts and improved ignition
Reducing gas emissions from compressor rod packaging systems
Test and repairs pressure safety valves (PSV)
Reducing emissions when taking compressors off-line
Eliminate unnecessary equipment and/or systems
Install automated air/fuel ratio controls
Inject blowdown gas into fuel gas system
Replace compressor cylinder uploaders
Install electric drives on compressors
Replace wet seals with dry seals in centrifugal compressors
Convert gas driven chemical pumps
Convert gas pneumatics to instrument air
Convert gas pneumatics to electrical controls
Convert gas pneumatics to mechanical controls
Conduct directed inspection and maintenance at remote sites
Directed inspection and maintenance at City Gate Stations
Directed inspection and maintenance at compressor stations
Composite wrap for non-leaking pipeline defects
Perform valve leak repair during pipeline replacement
Using hot taps for in-service pipeline connections
Recover gas from pipeline pigging operations
Using pipeline pump-down techniques to lower gas pressure before maintenance
Use inert gases and pigs to perform pipeline purges
Options for reducing gas emissions from pneumatic devices
Reduce frequency of replacing modules in turbine meters
Redesign blow-down systems and alter emergency shutdown practices
Install flares
Test and repairs pressure safety valves (PSV) (mainly meters/ meter sets)
Eliminate unnecessary equipment and/or systems
Convert NG driven chemical pumps
Convert gas pneumatics to instrument air
Convert pneumatics to electrical controls
Convert pneumatics to mechanical controls
58
Gas transmission – technology/practice
Insert mains with plastic pipe
Composite wrap for non-leaking pipeline defects
Perform valve leak repair during pipeline replacement
Using hot taps for in-service pipeline connections
Recover gas from pipeline pigging operations
Using pipeline pump-own techniques to lower gas pressure before maintenance
Use inert gases and pigs to perform pipeline purges
Options for reducing gas emissions from pneumatic devices
Reduce frequency of replacing modules in turbine meters
Increase frequency and application of walking survey of pipeline
Install excess flow valves
59
Appendix E
Gas distribution networks survey
Distribution Network Name
2001
Actual UAG (%)
Regulator or AEMO benchmark UAG allowance (%)
Fugitive emissions component of actual UAG (%)
Actual UAG (TJ)
Actual fugitive emissions component of UAG (TJ)
Gas delivered (PJ)
Price paid for UAG ($/GJ)
UAG Cost ($'000)
Total length of mains (km)
Length of leaky mains (km)
Proportion of leaky mains (%)
Estimates of leakage rates per customer (GJ/customer)
Estimates of leakage rates per km and/or per customer
(GJ/km)
60
2002
…….
2011
2012
Additional Data
km
Current break up of leaky mains by materials (km):
- cast iron
km
- unprotected steel,
km
- galvanised steel or iron
km
- PVC
km
- other
km
If possible, please provide the range of fugitive emissions (TJ) experienced (high and low)
across the leaky parts of the network and the average for the whole of the leaky part of the
network.
TJ/pa
Please provide estimates of pipe rehabilitation costs per km and/or per customer
- per km
$/km
- per customer
$/cust
Cost savings that may accrue to the distribution business from pipe rehabilitation, including:
- Reduction in main repairs to leaky pipes
$,000
- Reductions in removal of water
$,000
-Any other saving the business thinks is pertinent
$,000
Forecasts of future UAG costs ($/GJ)
$/GJ
Please describe any other sources of leakage (e.g. relief valves on filter regulators, main
blowdown for construction/maintenance) and feasibility of leakage reduction.
N/A
Please comment on existing incentives and barriers to reduce leakage: regulatory, carbon tax,
other
N/A
Any other information a network business considers may be relevant to the study
N/A
61
Appendix F
Case study: Gas Distribution Network Owner A
Background
Gas network owner (GNO) A is one of Australia’s largest gas distributors, delivering gas to over a million consumers,
with gas distribution networks in multiple jurisdictions.
Like all Australian gas networks, GNO A’s networks operate solely through the gas pressure differential from the
inlet (the receipt point from a transmission pipeline) to its many outlets (delivery points). GNO A’s networks do not
use compressors (i.e. external energy) to assist the flow of gas.
However, energy is lost from leakage or fugitive emissions, primarily from gas leaks from pipes and fittings. As for all
gas networks, fugitive emissions for GNO A arise in numerous places where there are fittings or joints—but by far
the most significant source of leakage is from pipes (or mains) constructed using older technologies and materials,
such as cast iron, unprotected steel and galvanised iron or steel.
GNO A’s major distribution networks have over 2,000 km of mains built from these older technologies, making up
between 5–14% of each network’s length of mains. GNO A calculates Unaccounted for Gas (UAG), of which leakage
is a significant component, for each of its networks. UAG varies between networks, currently being in the range 0.5–
5.3%, reflecting the proportion of the network that is made up of older leak prone pipes.
Business approach to management of losses
GNO A, like all Australian gas distributors prior to the extraction of natural gas, monitored and addressed leakage
over many decades, performing repairs to mains on an as-needed basis. Similarly for all Australian distributors, GNO
A embarked on a pipe replacement program following the move from town gas (which was produced from coal and
had a relatively high moisture content) to natural gas, in order to reduce leakage from its networks that increased
significantly due to the impact of much drier natural gas on pipe joints.
GNO A manages leakage as part of its Asset Management Plan, which sets out the processes and policies in place to
manage the constituent parts of the network through their life cycle (from commissioning to decommissioning). The
Asset Management Plan is also typically approved by the jurisdictional technical regulator for each network, and is
scrutinised by the AER during the regulatory Access Arrangement reviews that govern GNO A’s networks.
GNO A’s Asset Management Plan has a well-established mains replacement plan for each of its networks. These
plans aim to replace mains in a way that ensures public safety and meets the criteria for capital expenditure, applied
by the AER. While the mains replacement plan represents the economically efficient longer term solution to leak
minimisation, in the short-term GNO A maintains a leakage management plan. The jurisdictional technical regulator
approves the leak management plan for each network.
Monitoring UAG and managing/minimising leakage from its networks is a significant element of GNO A’s operating
expenditure (around 20%). Detailed assessment of UAG by network and sub-network, internal reporting and
reporting to the technical regulator of the number of leaks detected and repaired, is an integral part of the continual
assessment of network integrity and safety. Areas prone to higher levels of leakage are elevated in priority for mains
replacement.
GNO A’s mains replacement plan will see all aged pipe in its two major networks replaced by 2018 and 2021
respectively. This program is a major undertaking, involving capital expenditure of between $750 million and
$1 billion, with approval by the AER. On completion of these programs, the emissions associated with leakage for
GNO A’s networks are expected to be considerably reduced. This is expected to reduce UAG. For example, in GNO
A’s leakiest network, UAG is expected to be reduced from over 5% to 2–3%, noting that emissions from leakage are
only one component of UAG.
62
Drivers of loss mitigation
GNO A has a number of drivers for adopting its program of loss-reduction through mains renewal. These are:
Safety and technical regulation – GNO A’s networks are covered by jurisdictional technical and licensing legislation
and regulations, which include public safety requirements and Australian Standard AS 4645 Gas Distribution
Networks. AS4656 includes management of leakage. In relation to its major network, the jurisdictional technical
regulator enforces GNO A’s adherence to its mains renewal program. In relation to GNO A’s second largest network,
the jurisdictional technical regulator has made it a licence condition that the GNO reduce its UAG annually, in order
to provide a regulatory incentive for the GNO to maintain its mains renewal program and reduce leakage.
Economic Regulation – Under the National Gas Law and Rules, GNO A’s networks have incentive mechanisms
whereby it carries the benefits of outperforming its UAG benchmark or the cost of underperforming against its UAG
benchmark. This provides strong incentives to reduce leakage, which can be a significant component of UAG. It is
also allowed to include economic (i.e. efficient and prudent) capital expenditure to reduce leakage in its Access
Arrangement.
Carbon tax – While carbon taxes are passed through to consumers under the regulatory arrangements, there is
significant pressure on GNO A to minimise its costs and thereby its charges to retailers, as gas must compete
increasingly with other fuels, including renewable energy. GNO A therefore has a significant incentive to minimise
the business’ carbon liabilities and thereby minimise the cost that is passed through to consumers.
Corporate reputation – This impact is indirect and relates to the other drivers. The company sees good energy and
carbon management as a part of meeting its environmental responsibilities. This is also relevant for the business’s
publicly listed shareholders and potential investors.
Conclusion
GNO A manages its fugitive emissions on a safety and economic basis through systematic leakage management,
Mains Replacement and Asset Management Plans, similar to practices used by the rest of the gas distribution
industry. Its networks have varying lengths of old technology, leak prone mains with corresponding high levels of
UAG and leakage. It has strong incentives to reduce leakage through its economic and technical regulatory regimes,
including UAG benchmarking, and has a systematic approach to leakage reduction that includes a plan to replace all
of the old mains in its two biggest networks by 2018 and 2021 respectively. This will significantly reduce the leakage
component of UAG in its networks, and is expected to reduce UAG. For example, in GNO A’s leakiest network UAG is
expected to halve from over 5% to 2–3%
63
Appendix G
Case study: Gas Distribution Network Owner B
Background
Gas network owner (GNO) B is a major Australian gas distributor. Like all Australian gas distribution networks, GNO B’s
networks operate solely through the gas pressure differential between the inlet (receipt point from a transmission
pipeline) to its many outlets (delivery points). GNO B’s network does not use compressors (i.e. external energy) to
assist the flow of gas.
However, gas is lost from operation, primarily via fugitive emissions from pipes and fittings. As with all gas networks,
but by far the most significant source of leakage for GNO B is from pipes constructed using older materials, such as
cast iron, unprotected steel and galvanised iron or steel. These materials comprise 1.6% of the total length of GNO B’s
network.
Unaccounted for gas (UAG) is the difference between the metered quantities of gas entering and leaving a network.
Metering error and leakage are by far the most significant components of UAG. The remaining factors are at least an
order of magnitude less than these two. They are: gas used in network operations such as water baths at pressure
reduction points; pipe purging for maintenance; pipe ruptures from third-party interference.
There is almost no scope for economic reduction of these non-leakage factors of UAG; either because they are
essential to the operation of the network, or because, in the case of metering error, there are many meters involved
and the cost of improving accuracy is large. Over the last 10 years, UAG for GNO B’s total system has varied between
1.9–2.6 %, which is consistent with the relatively small proportion of the network length that is made up of older leakprone pipes.
It should be noted that while metering error is a component of UAG, it does not constitute leakage from the network.
The metering error and leakage components of UAG can’t be differentiated accurately and vary between networks.
For GNO B, actual fugitive emissions are roughly estimated to be around 0.5–1.1% compared with total UAG of 1.9–
2.6%.
Business approach to management of losses
GNO B, like all Australian gas distributors over many decades prior to the use of natural gas, monitored and addressed
leakage from mains on an as-needed basis. The move from town gas (manufactured from coal or oil), which was ‘wet’,
to natural gas which contains essentially no moisture, led to a significant increase in leakage from its network arising
from the impact of natural gas on pipe joints, such as the drying out of lead-yard seals and degradation of rubber ring
seals. In response, GNO B embarked on a program of replacement/repair that focused on whole network areas.
GNO B adopted a technology whereby, wherever possible, mains are replaced by inserting old pipes with new smaller
plastic (polyethylene or nylon 11) pipes operating at much higher pressures.
In the late 1980s and the first half of the 1990s, GNO B undertook a major project to rehabilitate mains with a step
change in effort and investment. This involved replacing over 80% of its leak-prone networks. Since that major project
was completed, GNO B has been progressively rehabilitating the remainder of its network on an as-justified basis. It
also monitors leakage throughout the network to assess whether leakage is arising in pipes built using modern plastic
technology.
GNO B has a program of systematic leakage assessment through capturing leakage information from two sources:

publicly reported leaks

leakage surveys.
This information is captured on GNO B’s works management IT system. This information is analysed for trends and
correlated with local UAG measurements to identify areas of GNO B’s network that may need rehabilitation.
64
Any decision to proceed to rehabilitation of part of a network, instead of ongoing maintenance of leaks as they occur,
is made in the context of GNO B’s asset management planning, which includes a mains rehabilitation framework. That
framework takes into account factors such as reductions in maintenance and operating costs arising from mains
replacement, opportunities for building capacity, and risk assessments. These are then applied in developing business
cases that are approved through GNO B’s financial approvals process.
GNO B adopts a long-term view of managing leakage including mains replacement as part of its five-year capital plans
and long-term Asset Management Plan. In this respect it is important to note that GNO B consider the economic lives
of their mains to be in the order of 50 years for plastic and 80 years for steel. GNO B submits its five-year plans to the
AER in the course of each five-yearly review of its Access Arrangement. The submission includes GNO B’s proposed
allowance for UAG (including leakage) and the basis of its estimates, and its proposed capital expenditure
requirements for mains rehabilitation to manage UAG at the proposed level.
Currently, mains rehabilitation accounts for around 5% of annual capital expenditure. The proposals are reviewed by
the AER.
Drivers of loss mitigation
GNO B has a number of drivers for adopting its program of loss reduction through mains renewal. These are:
Safety and technical regulation – GNO B’s networks are covered by jurisdictional technical and licensing legislation
and regulations, which include public safety matters and call up the Australian Standard AS 4645 – Gas Distribution
Networks. This includes management of leakage. As part of the state technical regulator’s requirements GNO B
prepares a Safety and Operating Plan, which includes management of leakage, which must be audited for compliance
with the Standard. Conformance to the Safety and Operating Plan is also audited. Both audits are provided to the
technical regulator.
Economic Regulation- UAG Benchmarking – GNO B’s Access Arrangement, approved by the AER under the National
Gas Law and Rules, includes an incentive mechanism whereby GNO B retains any savings it makes by outperforming
its UAG benchmark or carries the cost of underperforming against the benchmark. This provides a strong financial
incentive to reduce leakage, which is a significant component of UAG. The AER also allows capital expenditure to
reduce leakage, provided it is efficient and prudent, when reviewing GNO B’s Access Arrangement.
Carbon tax – While carbon taxes are passed through to consumers under the regulatory arrangements, there is a
significant pressure on GNO B to minimise its costs and thereby its charges to retailers, as gas must compete
increasingly with other fuels, including renewable energy. GNO B therefore has a significant incentive to minimise the
business’s carbon liabilities and thereby minimise what is passed through.
Corporate reputation – This impact is indirect and relates to the other drivers. The company sees good energy and
carbon management as a part of meeting its environmental responsibilities. This also is relevant for publicly listed
shareholders and potential investors.
Conclusion
GNO B has developed comprehensive processes—comprising of a leakage management system, a mains rehabilitation
justification framework and asset management plans—for identifying and economically addressing gas leakage in its
network. These practices are similar to other participants in the gas distribution industry.
Safety is the primary driver for managing its leakage, but existing regulatory arrangements are also a strong incentive
for GNO B to continue to reduce leakage, where it is financially sound to do so.
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