investigating the case for a second gas pipeline between ... · a second pipeline, the southern nt...

Port Jackson Partners

Investigating the case for a second gas pipeline between the NT and East Coast

Department of the Environment and Energy

21 November 2017

Port Jackson Partners Port Jackson Partners Limited

Level 32, 50 Bridge Street Sydney NSW 2000 Australia Tel: +61 2 9221 2222 Fax: +61 2 9221 2219

ACN: 052 145 392

Investigating the case for a second gas pipeline between the NT and East Coast

1 Executive summary .................................................................................................. 3

2 Terms of reference for this report ............................................................................. 5

3 Industry and market context ..................................................................................... 6

3.1 The East Coast gas market is now connected to international LNG markets, increasing domestic prices .............................................................................. 6

3.2 The East Coast gas market is forecast to have a supply shortfall in 2018, but there is uncertainty as to its magnitude ........................................................... 8

4 State of the Northern Territory gas industry ............................................................ 10

4.1 Onshore gas development still at a very early stage ...................................... 10

4.2 Plans to connect the NT to the East Coast grid ............................................. 11

4.3 Alternative proposals for the NT gas pipeline ................................................ 11

5 Economic analysis of the Southern NT Pipeline ..................................................... 13

5.1 Process to finance and underwrite pipeline investments ................................ 13

5.2 Relationship between size and length of pipelines and project economics .... 13

5.3 Range of scenarios for new gas production in the NT, but development nascent and difficult to predict ....................................................................... 16

5.4 Some important constraints on existing pipeline infrastructure in and around the NT ........................................................................................................... 17

5.5 Approach for modelling the commercial case for the SNP ............................. 19

5.6 Modelling shows SNP economics less favourable than NGP until the northern route reaches a natural constraint ................................................................. 23

Port Jackson Partners 2

5.7 At the volumes required to justify SNP, there are alternative infrastructure expansions to bring onshore NT gas to market ............................................. 26

5.8 Conclusions ................................................................................................... 30

6 Evaluating the national interest case for the SNP ................................................... 31

6.1 An effective gas market should deliver availability, affordability, liquidity and efficiency ....................................................................................................... 31

6.2 The SNP is unlikely to improve market outcomes, particularly in advance of additional NT supply ...................................................................................... 31

6.3 NT gas supplies are unlikely to alleviate short-term price pressures in the southern states .............................................................................................. 33

7 References ............................................................................................................. 35


1 Executive summary

The East Coast gas market is now connected to international LNG markets, resulting in higher domestic gas prices than was previously the case. LNG export contracts have created demand for gas that would otherwise be available for domestic consumption. This is creating concerns over the availability and affordability of gas for domestic Australian consumers on the East Coast.

The Australian Government is investigating options to improve outcomes in the East Coast gas market. One class of options is to expand the East Coast’s gas pipeline network to connect consumers to more sources of gas supply. This report investigates the case for an additional pipeline connecting the Northern Territory’s (NT) existing and prospective gas resources to the East Coast market via the Moomba Gas Supply Hub in South Australia.

Most gas production in the NT is offshore gas exported via an LNG export facility in Darwin – approximately 200 PJ per annum. A second LNG project in Darwin connected to an offshore gas field is currently under construction. In contrast, onshore gas development is in its infancy. Central Petroleum and its joint venture partners currently produce gas from three assets in the Amadeus basin, with production capacities of 16-24 PJ per annum.

Very large onshore contingent resources exist in the NT, primarily located in the Beetaloo Basin. These resources are almost entirely unconventional and of global scale. However, exploration has stalled since the NT implemented a moratorium on hydraulic fracturing of unconventional gas reservoirs. A review of the moratorium will report back by the end of 2017.

With the construction of the Northern Gas Pipeline (NGP), the NT is already in the process of connecting to the East Coast gas pipeline network. The NGP connects the Amadeus Gas Pipeline (AGP) to Mount Isa, where it will connect with the northern end of the Carpentaria Gas Pipeline (CGP) to Ballera. The NGP was selected by the NT government during a competitive process in 2014-2015. The competitive process received four final proposals, two of which proposed the northern route, and two the southern route, connecting to pre-existing gas processing facilities at Moomba. While the Moomba route was unsuccessful, it carried a number of attractions, including better access to more centres of demand on the East Coast, and access to the Moomba-Sydney ethane pipeline that could help commercialise any natural gas liquids.

A second pipeline, the Southern NT pipeline (SNP), has been proposed to improve access for NT gas to domestic users on the East Coast. This report focuses on the commercial and national interest case for building a second pipeline. It outlines the commercial feasibility of that second pipeline, as well as recommendations regarding potential Commonwealth Government involvement in the development of further NT pipeline infrastructure.

Our analysis was conducted using relatively optimistic assumptions for the SNP. This was done so that if our preliminary analysis showed that the SNP was a commercially viable project under these assumptions, we could test the case further to determine at what point more pessimistic assumptions affected its viability.

We examined two scenarios around the timing of construction; one in which the SNP is constructed and flows gas in parallel with the already approved NGP, and another where the SNP is available only after the NGP reaches its initial physical constraint (at


200TJ/d). For comparison, 200 TJ/d (73 PJ/annum) is equivalent to three quarters of the annual production rate from the Otway Basin, or almost equivalent to South Australia’s total gas consumption across all sectors in 2016.

Our analysis was also based on two gas source assumptions. In the most optimistic case, incremental gas production from the NT to the East Coast was split between the Beetaloo and Amadeus gas fields in a 75:25 ratio. In the more realistic case, the ratio was 90:10. It should be noted that even the 90:10 split is optimistic for Amadeus Basin at higher NT volumes.

Even under the most optimistic scenarios, the SNP was unable to deliver competitive transmission costs to Moomba relative to the alternative route via the NGP, CGP and QSN Link until the NT can produce and ship more than 200TJ/day to the East Coast market. In less optimistic scenarios we analysed that tipping point is 300TJ/day or more. This means that the SNP would have no effect on gas market outcomes on the East Coast unless a significant gas discovery is commercialised and sold to buyers in the East Coast markets.

At these large volumes required to justify investment in the SNP, there are alternative paths available to bring onshore NT gas to the East Coast market, including expanding and extending the NGP. A new discovery may even be so large that its natural market once commercialised is LNG exports.

The Beetaloo gas fields are not yet in the development stage; indeed, further exploration is prohibited at this stage due to regulatory barriers. As such, accurately predicting the order and timeline of new gas developments in the NT is difficult. It would be premature for the Government to intervene in the market and develop the SNP in such an uncertain environment. Government should instead consider a more holistic view of the East Coast gas market when contemplating possible interventions.

The first pipeline to connect the NT’s gas supplies to the East Coast gas market is already under construction. This means the constraint for further gas field development is not the lack of pipeline infrastructure. As such, there is a weak national interest case for the SNP, as pipeline access to the East Coast is unlikely to be a constraint on access to market for some years. Instead, new infrastructure could be developed in parallel with upstream development, with the NGP providing an ample 200TJ/day of economically efficient capacity while any new pipeline was being constructed.

In contrast, the immediate constraint for developing the NT’s gas resources at scale is the moratorium on hydraulic fracturing in the NT, which has arrested exploration work on the vast unconventional gas resources in the NT. In the medium-term, and closer to the time where additional NT gas resources are considered probable and commercial, government could take low-cost action designed to expedite the development of necessary infrastructure to connect those resources to the East Coast.

At the time a potential pipeline approached the investment stage, government could consider playing a role in providing competitive tension for potential pipeline developers, similar to the process run by the NT Government that led to the development of the NGP in 2015.


2 Terms of reference for this report

The Australian Government is investigating ways to improve outcomes in the East Coast gas market, including by connecting it to additional gas resources. The Northern Territory (NT) has very large prospective gas resources, and could potentially supply East Coast domestic demand for several decades if these resources were commercialised at scale.

Port Jackson Partners was engaged by the Australian Government to advise on the commercial and/or national interest case for investing in additional gas pipeline infrastructure connecting the NT’s gas resources to Moomba in South Australia.

This report is underpinned by the analysis of publicly available data, data provided to us on a confidential basis, and an extensive series of interviews with industry participants.

This report is underpinned by more detailed analysis that contains substantial amounts of commercially sensitive information.


3 Industry and market context

3.1 The East Coast gas market is now connected to international LNG markets, increasing domestic prices

The East Coast gas market is connected to international liquefied natural gas (LNG) markets through three export projects on Curtis Island in Gladstone. Exhibit 1 shows that LNG export volumes dwarf domestic consumption.

Exhibit 1

Historically, the East Coast market was insulated from international markets, and domestic gas prices averaged below A$4/GJ. During this period, pricing was based on the cost of extraction, transmission, and some mark-up to cover a return on capital for producers. The international market paid much more, with spot prices above $11/GJ.

In the mid-2010s, LNG export facilities were developed in Queensland and this marked the first time the East Coast was linked with the international gas market and prices. As a result, LNG producers could sell in the more lucrative international market, and Australian consumers, who had previously enjoyed cost-plus prices, now competed with mass LNG importers. Rational producers will sell at the higher price available to them. The price of domestic gas rose up to LNG netback prices (i.e. the LNG price less the cost of liquefaction and shipping). Exhibit 2 shows this trend.

The price of gas in an export-linked market depends on the point of consumption. When an LNG exporter has gas beyond its contracted quantities, it can either sell it internationally (at the LNG spot price) or domestically (at the netback price). The netback price is calculated by taking the spot price (delivered), and subtracting shipping, liquefaction, and transportation for a particular point in the network. In a seller’s market, the cost of that transportation is added to the netback price and in a buyer’s market it is subtracted. Exhibit 3 shows the basis of the gas price paid at the point of consumption, both domestically and internationally.

ANNUAL GAS CONSUMPTION FORECAST

181 178 184 174 172 192 190 190 190 189 188 186 184 182 180 178

212 198 210 195 220 175 122 150 124 124 99 104 115 123 124 129

291 293 301 302 297 280 264 257 255 241 238 238 235 233 230 231

- - - - 5

325

1,006

1,292 1,376 1,428 1,436 1,430 1,430 1,430 1,434 1,429

17 17 18 17 16

16

17

21 26 32 40 45 51 57 63 67

701 685 713 688 710

988

1,598

1,911 1,970

2,016 2,001 2,003 2,015 2,025 2,031 2,035

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

PJ per annum

Source: AEMO National Gas Forecasting Report 2016; PJP analysis

Residential/commercial

Gas powered generation

Industrial

LNG for export

Other

Weak case

Strong case

Total – neutral case

Forecast

2016 FORECAST DATA


Exhibit 2

Exhibit 3

LNG export facilities require large quantities of gas to be commercially viable. Two of the LNG projects in Queensland developed new 2P reserves in the Surat and Bowen basins

0

4

8

12

16

20

2014 2015 2016 2017 2018

WHOLESALE GAS PRICES

* Netback calculated at Japan delivered spot price less A$1.50 per GJ for liquefaction and transport

Source: AEMO; Australian Industry Group; Government of Japan; PJP analysis

A$ per gigajoule

Sydney STTM

ex-post price

3 week moving average

Anecdotal evidence

offers exceed

$15/GJ in 2017

Historic average

contract price

2015 contract price

2016 contract price

Dec-16 offers

Feb-17 offers

LNG spot netback to

Wallumbilla*

Pricing basis Sale type Notes

Contract Spot

Japan DES 11.70 9.50 • Contract prices underwrite large capital cost of LNG train investment

• Assume JCC crude price of US$55/bbl at 16% ‘slope’

• Spot prices closer to marginal cost of production and expected to prevail

while global LNG market is long supply

Gladstone FOB 11.00 8.80 • Deduct A$0.70/GJ in shipping and boil off costs

Wallumbilla

netback

10.30 8.10 • Deduct A$0.70/GJ in liquefaction and pipeline transport costs

Melbourne

netback at city

gate

6.80 4.60 • Deduct pipeline costs from Wallumbilla to Melbourne

• In a buyer’s market, netback price is the ‘seller’s alternative’ – i.e. the

seller’s alternative is shipping gas to Wallumbilla for export

13.80 11.60 • Add pipeline costs from Wallumbilla to Melbourne

• In a seller’s market, netback price is the ‘buyer’s alternative’ – i.e. the

buyer’s alternative is diverting gas from export at Wallumbilla and

shipping it south

BASIS OF GAS PRICE QUOTATION

* Contract prices depicted based on JCC crude price of US$55/bbl * 16% slope

Spot prices depicted based on average of 1H CY17 spot prices delivered to Japan

Forex assumed at AUD:USD 0.75

Source: Bloomberg; Government of Japan; PJP analysis

A$ per gigajoule*

Seller’s

alternative

Buyer’s

alternativeMost relevant for

industrial users in

southern states

ILLUSTRATIVE


to cover their contractual commitments. However, one project – GLNG – requires 3rd party gas to meets those commitments. This creates a net call on gas that would otherwise be available for domestic consumption, further enforcing the connection between international prices and domestic ones.

Regardless, the sheer amount of uncontracted capacity in these projects means that domestic market prices will continue to be influenced by global LNG prices for the foreseeable future.

3.2 The East Coast gas market is forecast to have a supply shortfall in 2018, but there is uncertainty as to its magnitude

AEMO’s September 2017 Gas Statement of Opportunities update and the ACCC’s gas inquiry interim both indicate a high likelihood of gas supply shortfalls in 2018 and 2019, in the absence of redirections from LNG export sales in to the domestic market. Interviews for this report indicated that in the last 12-18 months it has become extremely difficult for industrial and commercial customers to source firm supply commitments – even at netback plus transport prices. The ACCC’s Gas Inquiry 2017-2020 interim report of September 2017 confirms this experience and outlook. This indicates very tight availability of uncommitted supply.

The high variability in LNG demand month-to-month relative to the size of total East Coast demand makes it difficult to forecast the precise quantity of a domestic shortfall. The most recent official forecast is AEMO’s September 2017 GSOO update, predicting a domestic shortfall range of 54-107 PJ in 2018, and 48-102 PJ in 2019. The Australian Government and East Coast LNG export industry soon after signed a heads of agreement in October 2017 requiring the Gladstone LNG exporters to offer sufficient gas to domestic consumers on reasonable terms to address the forecast shortfall in 2018 and 2019.1

The range of outcomes depends on the depth and price of the spot market for LNG exports, and the extent of participation in that market by the LNG exporters. Exhibit 4 demonstrates the influence of LNG exports on the range of forecast outcomes based on data in AEMO’s 2016 Gas Forecasting Report.2

In this environment, gas suppliers may be reluctant to agree to competitive, long term, supply contracts with domestic consumers in case the international market improves and LNG exporters are willing to pay a premium for those gas volumes. This is likely to have generated uncertainty for negotiating new supply contracts, and in writing contracts longer than 12 months. This is problematic for commercial and industrial users that require firm contracts in place to underwrite the economics of their own operations.

1 Heads of Agreement – The Australian East Coast Domestic Gas Supply Commitment, October 2017 2 Note: AEMO’s updated gas consumption forecasts did not include estimates post 2019. AEMO’s 2016 Gas Forecasting Report estimates are shown in Exhibit 4.


Exhibit 4

ANNUAL GAS CONSUMPTION FORECAST — SCENARIO VARIANCE TO NEUTRAL CASE

PJ per annum

Source: AEMO National Gas Forecasting Report 2016; AEMO Update to Gas Statement of Opportunities; PJP analysis

(2) (4) (4) (5) (7) (7) (8) (10) (11)(19) (15) (23) (9) (1) (1) (10) (18) (25)(7) (9) (9)(11) (11) (14) (18) (17) (24)

(278)(233)

(245)(216) (213) (213)

(213) (214)(213)

1 0

(1)

(1) (0) (0)

0 1 2

(305)

(261)(283)

(242) (233) (236)(250) (257)

(271)

2017 2018 2019 2020 2021 2022 2023 2024 2025

2 3 3 4 5 6 7 8 8 (18) 0 (9) (6) (10) 3 19 37 43

7 14 24 25 25 24 24

25 25 132 142

95 91

245 245 245

246 245

(0)

2

4 4

4 4 3

3 2

123

161

118 118

268 281

297 318 324

2017 2018 2019 2020 2021 2022 2023 2024 2025

ResidentialGas power gen.

Industrial

LNG

Other

Total

Weak case Strong case

In strong case consumption from

gas powered generation is

displaced in short term by LNG

AEMO’s updated domestic

shortfall expectation for 2018/2019

ranges between 50-100PJ

2016 FORECAST DATA


4 State of the Northern Territory gas industry

4.1 Onshore gas development still at a very early stage

The majority of the NT’s domestic gas needs are supplied via the NT Government owned Power and Water Corporation. Power and Water Corporation has a take-or-pay contract with Eni Australia for its development in the Blacktip gas field in the Timor Sea. This contract is for 23-37 PJ per annum for a total quantity of ~750 PJ over 25 years.

LNG exports consume much more gas than the NT’s domestic needs. Darwin has one operating LNG export hub – Darwin LNG – with a second – Ichthys – being built. These ventures are supplied upstream by large offshore gas developments. To provide a sense of scale, the nameplate capacity of Darwin LNG is 3.6Mtpa of LNG or approximately 200 PJ per annum.

In contrast, onshore gas development is in its infancy. Central Petroleum and its joint venture partners produce gas from 3 assets in the Amadeus basin – the Mereenie, Palm Valley and Dingo fields. These provide capacity of 16-24 PJ per annum (45-65 TJ per day). Most recently, Central Petroleum reported 207 PJ of 2P gas reserves across its joint ventures.

There are, however, very large contingent onshore NT resources (mostly unconventional) in the Beetaloo Basin, as Exhibit 5 shows. Exploration into these resources stalled with the NT Government’s moratorium on hydraulic fracturing of unconventional gas reservoirs.

Exhibit 5

CURRENT NT GAS FIELDS AND 2P RESERVES

Blacktip

Bayu-Undan

Alice Springs

Tennant Creek

Darwin

Borroloola

DingoPalm

Valley

Mereenie Ooraminna

Glyde

Katherine

Weaber

Ichthys

Pipeline

Producing field

Discoveries / prospective resource

Source: NT Department of Mines and Energy; NT Geological Survey

TIMOR SEA

* Converted from billion cubic feet to petajoules at a rate of 1:1.056

23,220

- 381

Bonaparte Beetaloo/McArthur Amadeus

Petajoules

2P/2C Reserves, by basin

56,400

188,300

28,000

Bonaparte Beetaloo/McArthur Amadeus

Petajoules

Mid case prospective resources, by basin

Amadeus Gas

Pipeline

Bonaparte Gas

Pipeline

Palm Valley

Pipeline


4.2 Plans to connect the NT to the East Coast grid

The Northern Territory is currently served by three main transmission pipelines, shown in Exhibit 5 above:

• The Amadeus Gas Pipeline (AGP) is a 14” pipeline which runs North-South from Darwin to Mereenie. It supplies gas to the NT from the Blacktip gas field in the Timor Sea. The NT Government’s Power and Water Corporation holds firm capacity rights for almost all the AGP’s capacity. The AGP is owned and operated by APA Group.

• The Bonaparte Gas Pipeline (BGP) runs from Wadeye to the AGP at Ban Ban Springs. It also supplies gas from the Blacktip gas field. The BGP is owned by Energy Infrastructure Investments, which itself is 19.9% owned by APA Group.

• The Palm Valley Pipeline connects the southern end of the AGP to Alice Springs. It is owned by Australian Energy Networks and operated by APA Group.

A fourth major transmission pipeline — the Northern Gas Pipeline (NGP) — is under construction. It will connect the AGP at Tennant Creek to Mt Isa, where it will join the East Coast gas transmission pipeline network at the Carpentaria Gas Pipeline (CGP).

4.3 Alternative proposals for the NT gas pipeline

The NT Government ran a competitive process in 2014-2015 for the NGP and it will be built and owned by Jemena. The NGP was partially underwritten by a sale of surplus gas by the NT Government’s Power and Water Corporation under a take-or-pay contract3. (~31TJ/d) to Incitec Pivot at Mt Isa. This provided a foundation customer for the NGP and minimised underwriting risk to the NT Government.

The NGP’s competitive process considered a short-list of four final proposals: DUET Group and PCPA proposed the southern route (connecting with pre-existing gas processing facilities at Moomba), and Jemena and APA Group proposed the northern route to Mt Isa (shorter, and therefore cheaper to build).

Proponents of the southern route noted several advantages:

• Access to capacity on three transport links – the MSP, MAPS and SWQP – and therefore more optionality to sell NT gas to southern states

• The ability to take advantage of the existing gas processing facilities at Moomba, including liquids extraction trains and the ethane treatment plant

• Access to the Moomba-Sydney ethane pipeline to sell processed ethane, the feedstock for the Qenos ethylene manufacturing facility at Port Botany

However, the process also surfaced a range of difficulties for the southern route, including:

3 A take-or-pay contract is an agreement whereby one party has the obligation of either taking delivery of a product at an agreed upon price or paying a specified penalty to the other party.


• A more complex and lengthy construction process, due to difficulty accessing sand dune terrain and harsh desert climatic conditions

• A more complex land access process, particularly with respect to managing environmental and cultural impact

This study is now focused on whether there is a commercial case for the southern route to Moomba in light of the existing development of the NGP to Mt Isa. In this report, we refer to the southern route to Moomba as the Southern NT Pipeline or ‘SNP’.


5 Economic analysis of the Southern NT Pipeline

5.1 Process to finance and underwrite pipeline investments

Investments in pipeline assets, like any infrastructure with uncertain levels of demand, are inherently risky. This is because the infrastructure’s location is fixed, while the location and capacity demands of future customers and suppliers is highly uncertain.

To mitigate this risk, pipeline owners tend to underwrite initial investments with firm foundation contracts from shippers. Foundation contracts generally allow a customer to reserve a certain portion of the capacity of the pipeline under a take-or-pay contract. They are usually set with tariffs below the pipeline owner’s economic break-even point and reaching that point depends on achieving sufficient scale in the long run (i.e. beyond the foundation contracts).

Despite these commercial risks, the market rarely fails to build pipelines where there is an economic case to do so. These include when a new gas discovery requires access to market, or new centres of demand require access to existing supplies. Some examples of where this has happened in the past include:

• APA and Santos’ Project Development Agreement to commence work towards the development of the Western Slopes Pipeline, connecting Santos’ Narrabri pipeline to the Moomba-Sydney pipeline 400km south

• The Wallumbilla to Gladstone Pipeline, built in 2009 as plans for LNG export facilities in Queensland matured

• APA and Blue Energy’s Memorandum of Understanding for a pipeline to connect projects in Northern Queensland with the existing gas market and pipeline infrastructure

• The planned Reedy Creek Wallumbilla Pipeline that will connect the APLNG facility at Reedy Creek to Wallumbilla

A number of mechanisms exist to encourage investment. Governments can offer incentives or their own foundation contracts, such as for the NGP. They can also provide risk relief to pipeline owners through concessional financing (e.g. through the Northern Australia Investment Fund), or underwriting a portion of the pipeline’s capacity. Financiers can also underwrite deals, either to reduce the initial tariffs or allow larger pipelines to be built up front. Attractive or discounted financing terms can give pipeline operators a longer period of time to offer concessional tariffs that encourage upstream gas development and pipeline demand, without destroying the commercial return expected by the pipeline investor.

5.2 Relationship between size and length of pipelines and project economics

The capital investment for a pipeline is made up of a range of factors, including:

• Steel pipe cost – a function of steel raw materials cost, pipeline diameter and pipeline length


• Compressor stations

• Civil works (trenching, stringing and pipe bending, installation and welding, backfill, project and construction management)

• Land access and management charges

A substantial proportion of these costs is fixed (between 45% and 65%) based on the pipeline route, with no relationship to capacity. However, pipeline diameter is a variable capital cost with a relationship to both capacity and route. Larger diameter pipelines can transport more gas than smaller ones, but also require more capital investment due to the extra steel, compression equipment and earthworks needed to build them.

The initial installed capacity can be supplemented incrementally as the pipeline fills and more capacity is needed. Incremental capacity can be generated in the first instance by installing more compressor stations (most capital efficient), and, when additional capacity from compression alone is impossible (less capital efficient), it can be achieved by ‘looping’ the pipeline – i.e. duplicating some or all of the pipeline. Depending on how much additional capacity is required, a tipping point exists where the most capital efficient option is to leapfrog smaller, incremental expansions and ‘loop’ instead.

The marginal capital cost per unit of incremental capacity tends to be higher for smaller diameter pipelines, as larger diameter pipelines can extract relatively higher capacity increases for the same investment in compression. Exhibit 6 shows how this relationship affects tariffs required for pipeline owners to recoup their investment costs as demand increases. For low transmission rates, a smaller pipeline is more economic than a larger one, although this benefit disappears as demand for more transmission volumes increases. Underwriting, or offering concessional financing, can help overcome situations where a larger diameter pipeline has better overall economic benefits, despite less favourable project economics.

Pipeline operators may elect to build a larger diameter duplicate pipeline adjacent to existing infrastructure, instead of identical sized twins. For example, if large incremental gas volumes require passage along an existing pipeline route (beyond that pipeline’s compression capacity), building a larger diameter pipeline could be a more capital efficient option than simply duplicating the smaller, existing pipeline.

The length of a pipeline will also influence the relative economics of diameters because a longer pipeline has similar throughput capacity than a shorter pipeline (of the same diameter), but at a higher capital cost. This means that – in general – longer routes require larger diameters, and more underwritten volume, to offer economic tariffs to shippers and provide a reasonable rate of return to investors.

The SNP would follow a route from the AGP near Alice Springs to Moomba, over approximately 950km. Given the large distance, if large volumes of NT gas are discovered in the future, a larger diameter pipeline will require much more subsequent investment to expand than a smaller diameter pipeline.

Exhibit 7 shows the relationship between a pipeline’s length and diameter in terms of its return on investment for a given tariff. In this example, we assumed a $2/GJ tariff on pipelines operating at fully compressed maximum capacity. The analysis shows that a wider pipeline is needed to deliver a commercial rate of return across a longer pipeline route.


Exhibit 6

Exhibit 7

0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

50 100 150 200 250 300 350 400 450

REALISING PIPELINE ECONOMIES OF SCALE – 1,000KM PIPELINE

* Assumes a 6% pre-tax return on capital and a depreciation period of 35 years

Tariffs calculated by dividing full economic cost (opex + return on capital + depreciation) by utilisation

Source: Industry sources; PJP analysis

A$ per gigajoule

Utilisation

TJ per day

ILLUSTRATIVE

Tariff derived from full

economic cost

12” pipeline

18” pipeline

Shaded area

represents annual

volume risk

Initial tariffs

Smaller pipeline

requires

duplication sooner

Larger pipeline continues

to benefit from economies

of scale as demand grows

0%

5%

10%

15%

20%

25%

30%

0 200 400 600 800 1000 1200 1400

PIPELINE DIAMETER ECONOMICS

* Five year ramp-up period, after which pipeline operates at maximum capacity (pre-looping) in perpetuity

Source: PJP analysis

IRR

Length of NGP: ~600km Length of SNP: ~950km

Length of pipeline (km)

Economics based

on a A$2.00/GJ

notional tariff

12" diameter14" diameter

18" diameter

Notional 15% hurdle rate


5.3 Range of scenarios for new gas production in the NT, but development nascent and difficult to predict

5.3.1 The location of future NT gas developments/discoveries is unclear

Significant uncertainty exists about the location (onshore vs offshore), proximity to existing infrastructure, maturity (greenfield vs brownfield), and type (conventional vs unconventional) of any future gas developments. Furthermore, key inputs around the size, reserves and productivity of such discoveries are unknown, all of which influence where the gas would be sold.

5.3.2 Future development plans for abundant unconventional gas resources are uncertain

The Beetaloo basin has large quantities of shale gas, and is located near both the AGP, and the inlet to the NGP at Tennant Creek. In the event these resources were developed, gas from these fields could consume the NGP’s foundation capacity, underwrite incremental NGP expansions, then underwrite a second pipeline from the NT to the East Coast grid. However, at this stage, these resources are considered contingent resources and not 2P (proven plus probable) reserves.4 Exhibit 8 shows the composition of NT’s onshore gas reserves.

Exhibit 8

4 “Reserves are resources which are commercially recoverable and have been justified for development, while contingent and prospective resources are less certain because some significant commercial or technical hurdle must be overcome prior to there being confidence in the eventual production of the volumes.”; Petroleum Resource Management System

27,783

185,549

183

2,752

27,966

188,301

Amadeus Beetaloo / McArthur

BREAKDOWN OF NT ONSHORE GAS RESOURCES

Source: Northern Territory Geological Survey

Petajoules

Unconventional

Conventional

* Includes, 2C, P50, and mid case potentially recoverable volumes

Conventional

Unconventional


Our discussions with explorers in the Beetaloo Basin indicate that any future exploration of these resources requires hydraulic fracturing which is currently precluded by NT Government policy when applied to unconventional gas resources. At this stage, no further development of these fields can proceed. In 2016, the NT Government announced a scientific inquiry into the effects of hydraulic fracturing of onshore gas reservoirs to help it assess whether or not to lift the moratorium. A final report is expected by the end of 2017.

5.3.3 Size and type of discovery relevant to the logical centre of demand

Resource location is especially crucial for smaller discoveries. If a discovery is relatively small, its proximity to existing infrastructure is important. Reservoirs located far from existing infrastructure require more capital expenditure to reach market, which could lead to higher delivered gas prices than the market can bear, making the discovery uncommercial.

Larger discoveries may be able to absorb the costs to underwrite large infrastructure projects, like pipeline extensions, expansion, or export facilities. In Australia, historically, large discoveries have tended to underwrite LNG export terminals as their offtake volumes exceed the marginal demand for gas domestically. That means that gas from very large discoveries may not use pipelines to domestic markets in favour of more attractive international export opportunities.

The size of discovery also has a critical impact on the likely sales destination. If the volume is too little, the gas can be stranded due to the relatively high infrastructure costs associated with transporting it. If the discoveries are very large, they are more likely to be destined for international export, leaving domestic markets unserved. For a domestic pipeline to make commercial sense, medium sized gas discoveries must be made in appropriate locations to supply a pipeline.

Potential pipeline owners would be hesitant to invest in planning a new pipeline without having at least some certainty over some of these factors. This creates a ‘chicken and egg’ problem, as, without plans for a pipeline, oil and gas companies may not be sufficiently motivated to invest in stranded exploration blocks. Although historically new pipelines in Australia have been built on a commercial basis, the NT Government’s process to build the NGP is an example of where intervention was used to overcome a ‘chicken and egg’ situation.

5.4 Some important constraints on existing pipeline infrastructure in and around the NT

The AGP runs from Alice Springs to Darwin, with a capacity of approximately 100 TJ/d (calculating actual capacity is complex as not all gas enters and exits the pipeline at the same points). Since both NT interconnectors would connect to the AGP, it would need to be augmented to increase its throughput capacity beyond 100 TJ/d. Due to the AGP’s small diameter (mostly 14”), increasing capacity is potentially material, particularly over the longer portion from Tennant Creek to midway between Mereenie and Alice Springs. Transporting gas from far south to the NGP, or transporting gas south to the SNP, would require large capital investments.

The segments of the AGP that require augmentation depend on the volumes of gas being shipped over each segment. Exhibit 9 illustrates which segments are impacted by


gas flows from each combination of Amadeus/Beetaloo basin gas and gas route via the NGP or SNP.

Exhibit 9

The Carpentaria Gas Pipeline (CGP), which connects the NGP at Mount Isa to Ballera, also has constraints. The CGP is not currently equipped to handle bidirectional flow, and only flows north. Modest augmentation is required to upgrade the pipeline to also flow south, and be able to send NT gas to the eastern markets. Once the flow upgrade is complete, the CGP would have an estimated total capacity (north to south) of 175 TJ/day. Exhibit 10 shows the CGP’s capacity for back haul.

Exhibit 10

AMADEUS GAS PIPELINE SEGMENTS AND ROUTING

Darwin and LNG facilities

Tennent Creek

Alice Springs

Beetaloo Basin

Amadeus Basin

1

2

3

NGP

SNP

NOT TO SCALE

A

B

C

D

RouteAGP segment(s)

used

A

B

C

D

1

3

2 3

~350km

~500km

~250km

21

0

20

40

60

80

100

120

140

CGP CAPACITY AVAILABILITY FOR SOUTH HAUL

* 12 months trailing 21 June 2017

Source: APA Group; PJP analysis

Gross nominations

Contracted capacity

TJ per day

CGP forward north haul nominations and contracts, last 12 months* Back haul capacity on CGP

TJ per day

75 72 67

175 172 167

50%availability

75%availability

90%availability

Interruptible

south haul only

Firm south haul

if CGP is reversed

Potential total

south haul capacity

(firm + interruptible)


5.5 Approach for modelling the commercial case for the SNP

To explore the feasibility of the SNP we examined a range of outcomes for NT gas development and transmission.

The analysis here relies on a range of plausible but optimistic assumptions for the SNP. This is so that we can test whether there is a reasonable prima facie case for the pipeline. If this analysis were to show a reasonable prima facie case for constructing the pipeline today, we would test that case with more central and pessimistic assumptions.

5.5.1 Simplified NT-East Coast pipeline loop

In the first instance, the modelling is based on a closed pipeline system, bounded by the Amadeus Gas Pipeline (AGP) to the west, the Northern Gas Pipeline (NGP) to the north, the Carpentaria Gas Pipeline (CGP) and QSN link (QSNL) to the east, and the proposed Southern NT Pipeline (SNP) to the south. This allowed for the analysis to include two natural focal points; Ballera as a supply node for Queensland buyers, and Moomba as a supply node for buyers in the south east. Exhibit 11 shows the closed system.

Exhibit 11

5.5.2 Volume

We considered two scenarios for future onshore gas development locations; one where Beetaloo produces 75% of incremental NT gas production for interstate export and Amadeus the remaining 25%, and another where Beetaloo produces 90%, and Amadeus 10%. Exhibit 12 shows both scenarios. The weighting towards Beetaloo reflects the relative scale of resources between the two basins. It also reflects expectations for production at the Amadeus Basin gathered from industry interviews.

In both scenarios/basins, the starting point is 50TJ/day. Beetaloo’s volume includes the 31TJ/day of Blacktip gas currently contracted to be shipped via the NGP.

NORTHERN TERRITORY PIPELINE NETWORK AS A ‘CLOSED SYSTEM’

Amadeus

Gas Pipeline

AGP

Carpentaria Gas Pipeline

CGP

Northern Gas

Pipeline

NGP

Southern NT pipeline

SNP

QSN Link

QSNL

Darwin

Tennant Creek

Mt Isa

Ballera

Moomba

Alice Springs

To QLD

demand

To SA/NSW/

VIC/ACT demand

Beetaloo Basin

Amadeus Basin


The first scenario (75%/25%) can be considered ‘optimistic’ as less AGP augmentation, and thus lower AGP tariffs, are needed to transport those volumes. It also assumes that the Amadeus basin can produce more than 100TJ/day, which industry participants consider highly optimistic.

Exhibit 12

5.5.3 Routing of gas

The origin of gas (either the Beetaloo or Amadeus basin) affects the total transmission tariffs by affecting the pipelines we assume the gas travels through. This impacts the tariffs by:

• Changing the capacity required on the pipelines the gas travels over, the origin of gas changes the profile of capital investment on each pipeline – in effect changing the numerator in the tariff calculation

• Changing the total volume that shares the economic cost of these capital investments – in effect changing the denominator in the tariff calculation

To provide the most favourable outcome for the SNP, we included assumptions that minimised total augmentation costs across the network by carefully prioritising transmission routes depending on origin. As such, the analysis assumes that gas produced from the Beetaloo basin preferentially flows along the NGP, while gas from Amadeus preferentially flows through the SNP. This reduces and delays AGP augmentation costs, particularly for the segment between Tennant Creek and Mereenie/Alice Springs.

NT GAS DEVELOPMENT SCENARIOS

Incremental NT production: 90% Beetaloo / 10% AmadeusIncremental NT production: 75% Beetaloo / 25% Amadeus

0

100

200

300

400

500

600

100 150 200 250 300 350 400 450 500 5500

100

200

300

400

500

600

100 150 200 250 300 350 400 450 500 550

Beetaloo

Amadeus

Beetaloo

Amadeus

TJ/day

* Both cases assume an initial production volume of 50 TJ/d from Amadeus, and 50 TJ/d from Beetaloo (includes Blacktip ToP). Incremental production comes from Beetaloo and Amadeus in

ratios of 75:25 or 90:10

The 75:25 case is optimistic and would provide better economic outcomes for an SNP due to reduced AGP augmentations, while the 90:10 case is more reflective of reality

Initial gas production

from both Beetaloo and

Amadeus is 50 TJ/d

Initial gas production

from both Beetaloo and

Amadeus is 50 TJ/d


Exhibit 13

5.5.4 Pipeline tariffs

Existing pipelines

The existing pipelines along the assumed route include regulated (AGP) and unregulated or lightly regulated (CGP, QSNL) pipelines.

The AGP is modelled using a revenue cap based on the AER’s recent building block revenue model used to approve access. Under this approach, AER determines the required revenues to cover the infrastructure’s efficient costs, then approves a tariff that meet this target.

The unregulated/lightly regulated pipelines are modelled to charge their fixed reference tariffs regardless of volume. Our analysis indicates that these tariffs are already high enough for the pipeline owners to fund incremental capital expansions at a commercial rate of return.

New pipelines

To model the NGP and SNP tariffs, we calculated a ‘full economic cost’ of the pipeline using a method similar to the AER’s building block revenue model. We then calculated tariffs by dividing full economic cost by the volume shipped over the pipeline. To calculate full economic cost, we assume a 6% real pre-tax rate of return on invested capital, depreciation over 35 years, and recovery of all operating expenses.

These assumptions result in tariffs on the lower end of a commercial outcome. Tariffs could be higher if risk averse investors require a higher rate of return, or lower with concessional financing, subsidies, or discounts across the pipeline network. In this respect it is important to note that the COAG Energy Council executed changes to the National Gas Rules in August 2017 implementing a new negotiate-arbitrate framework for access to unregulated pipelines. This framework may reduce the ability for investors to seek outsized returns on pipeline investments.

GAS ROUTING ASSUMPTIONS

Amadeus

Gas Pipeline

AGP

Carpentaria

Gas Pipeline

CGP

Northern Gas

Pipeline

NGP


SNP

QSN Link

QSNL

Darwin

Tennant Creek

Mt Isa

Moomba

Alice Springs

Beetaloo Basin

Routing of Amadeus Basin gasRouting of Beetaloo Basin gas

Amadeus

Gas Pipeline

AGP

Carpentaria

Gas Pipeline

CGP

Northern Gas

Pipeline

NGP


SNP

QSN Link

QSNL

Darwin

Tennant Creek

Mt Isa

Moomba

Alice Springs

Amadeus Basin

1

1

2 2

1


The NGP offers a rolled-in tariff structure that guarantees improved economies of scale are shared with all access seekers. A rolled-in tariff scheme ensures that parties with existing gas transmission contracts over a pipeline will never be worse off as a result of future expansions. That is, real foundation tariffs will not increase under any expansion scenario. If the marginal cost of an expansion results in a lower tariff for new customers than the existing average tariff, the existing tariffs are reduced to reflect the new average cost of capacity. If the marginal cost of additional capacity is above the average cost of capacity, then the existing tariff is not adjusted and only new contracts would incur an extra charge. Our model adopts the NGP’s advertised foundation tariff of $1.4447/GJ for firm forward haul capacity (real 2017).

Our model assumed the SNP would adopt a similar rolled-in tariff structure.

We have not done an NPV calculation on the project, as this would require granular assumptions on the timing of volumes; this would be premature. Rather, our analysis illustrates the breakeven tariff required in a given year for the pipeline to recover its full economic cost for a given amount of volume – including a reasonable rate of return on capital invested. In reality, pipeline operators will smooth this through time and underwrite some volume risk to offer initial tariffs that the industry can sustain, and that are sufficient to provide a long run return on investment when volume increases.

5.5.5 Gas processing charges

Some NT gas fields contain gas that is higher in nitrogen than is standard for the East Coast pipeline network. As a result, nitrogen removal units are required to process the gas to specification before it reaches those pipelines.

Jemena will install one nitrogen removal unit at Tennant Creek, capable of removing nitrogen from 60TJ/day of gas, sufficient to ship 90TJ/day of blended gas to East Coast specifications over the NGP. We modelled a processing charge for this first 90TJ/day.

Gas resources in the Beetaloo basin are understood not to require nitrogen removal. Since our model assumed the Beetaloo Basin was the primary source of gas for future NGP transmission, processing units were not required and their costs were not included.

For the southern route, we have determined that NT gas would be sufficiently blended with Moomba gas to bring nitrogen levels down to East Coast specifications without the need for additional nitrogen-removal processing.

5.5.6 Dry gas

Our analysis assumed that gas developed in the NT would be ‘dry gas’; that is, that liquid hydrocarbons would not be present in any discovery. Liquid hydrocarbons (such as ethane and butane) can provide substantial incremental revenue for a gas development if extracted and sold separately from the natural gas (methane) offtake. The ability to extract and commercialise liquid hydrocarbons could potentially offset the difference in tariffs between pipeline routes and the preferred consumption end points.

However, given NT gas exploration is in its early stages, assuming the presence, type and quantity of liquid hydrocarbons would be highly speculative. We therefore don’t consider whether the presence of liquids offset any difference in tariffs between pipeline routes. Assuming a 100% dry gas development mirrors the approach taken by ACIL


Allen in its report to the Scientific Inquiry into Hydraulic Fracturing in the NT on the economic impacts of a potential shale gas development in the Northern Territory (ACIL Allen Consulting, 2017). We also note ACIL Allen’s observation that the most substantial well drilled in the Beetaloo sub-basin to date — Origin Energy’s Amungee NW-1H well — produced dry gas.

We provide further reflections on how the presence of liquid hydrocarbons could affect the infrastructure expansion route for NT gas in section 5.7.4.

5.5.7 Centre of demand

The analysis focused on Moomba as the destination node as it is a hub for gas delivery to New South Wales, Victoria, and Adelaide. It is also the most favourable destination for a southern pipeline. If the SNP is not the most economic NT interconnector with Moomba as the destination, it will be even less favourable when considering more distant hubs.

5.6 Modelling shows SNP economics less favourable than NGP until the northern route reaches a natural constraint

The analysis shows that the economics of the SNP are not more favourable than the NGP’s in its current state under most of the scenarios we explored.

To fairly explore the economics of the northern and southern pipeline routes, we analysed the total transmission tariffs to Moomba across two timing scenarios; one where the SNP is built and utilised concurrently with the NGP and one where the SNP is only developed after the NGP is fully expanded (serial utilisation).

These scenarios provide insights into how the integrated tariffs across the northern and southern routes change as NT gas volumes are divided. In the concurrent scenario, NT gas, regardless of total volume, is split between the NGP and SNP, while the serial scenario only splits NT gas once the NGP’s capacity is fully utilised.

Gas that travels along the ‘northern route’ to Moomba traverses the AGP, NGP, CGP, and QSNL, while the ‘southern route’ uses the AGP and SNP. The total average cost of transporting gas along either route is the sum of average tariffs along that route.

5.6.1 Concurrent utilisation

In scenarios where the NGP and SNP are built in parallel and used concurrently (that is, before the NGP is fully expanded) the southern route only becomes more cost-effective than the northern route once the total export volume out of the NT surpasses ~200 TJ/d, and only if the southern basins produce 25% of the NTs export volumes.5 With the CGP constrained to 200 TJ/d, this means that the SNP is only a viable transmission route once the northern route is at capacity. Under the more likely scenario where the southern basins produce only 10% of the NT’s export volumes, the tipping point to become more cost-effective is further increased to 300TJ/d. Furthermore, diverting gas

5 200 TJ/d is equivalent to 73 PJ per annum, which is 76% of the annual production rate from the Otway Basin, and almost equal to South Australia’s total gas consumption in 2016.


away from the NGP and to the SNP increases the cost of transport, overall, to the interstate markets. Exhibits 14-16 show these scenarios.

Exhibit 14

Exhibit 15

TOTAL TARIFF TO MOOMBA: NGP AND SNP BUILT IN PARALLEL AND USED IN TANDEM

0

1

2

3

4

5

6

7

8

0 100 200 300 400 500 600

Source of gas: 75% Beetaloo, 25% Amadeus (optimistic)

Tipping point at ~200 TJ/d

NGP

SNPNGP without

SNP

NT gas flows

TJ/day

* Beetaloo gas preferentially flows through the NGP, while Amadeus gas preferentially flows through the SNP to minimise AGP augmentation

Assumes swaps between Amadeus and Beetaloo are available


A$ per gigajoule (real 2017)

TOTAL TARIFF TO MOOMBA: NGP AND SNP BUILT IN PARALLEL AND USED IN TANDEM

Source of gas: 90% Beetaloo, 10% Amadeus (realistic)





0

1

2

3

4

5

6

7

8

0 100 200 300 400 500 600

NGP

SNP


NGP without

SNP

NT gas flows

TJ/day


Exhibit 16

5.6.2 Serial utilisation

In alternate scenarios, where the SNP is only developed once the northern route reaches its natural constraint, the economic tipping point occurs between 300 TJ/d and 325 TJ/d, depending on the source of the gas (Beetaloo versus Amadeus). Exhibit 16 shows this scenario.

Exhibit 17

0

1

2

3

4

5

6

7

8

50 100 150 200 250

NORTHERN ROUTE’S INCREASED TARIFF DUE TO COMPETING SNP (75% BEETALO, 25% AMADEUS)


Integrated tariff price, with and without SNP

NGP and SNP

in parallel




NGP alone

NT gas flows

TJ/day

Incremental tariff price along northern route due to SNP

0.00

0.20

0.40

0.60

0.80

1.00

1.20

1.40

50 100 150 200 250

Northern route tariff would be ~$1.00/GJ higher

if both pipelines operated concurrently

NT gas flows

TJ/day

0

1

2

3

4

5

6

7

8

0 100 200 300 400 500 600

NT GAS TRANSPORTED IN SERIES (SNP AVAILABLE ONLY AFTER NGP REACHES EXPANSION CAPACITY)


0

1

2

3

4

5

6

7

8

0 100 200 300 400 500 600


NGP

SNP

NGP

SNP


Source of gas: 90% Beetaloo, 10% AmadeusSource of gas: 75% Beetaloo, 25% Amadeus




NT gas flows

TJ/day

NT gas flows

TJ/day


5.7 At the volumes required to justify SNP, there are alternative infrastructure expansions to bring onshore NT gas to market

The analysis above shows that at least 200TJ/day of gas exports from the NT, and likely much more, would be required to underwrite a southern pipeline route to Moomba. At these volumes, a pipeline to Moomba becomes only one of several viable infrastructure alternatives to bring this gas to market.

If large volumes of NT gas are commercialised, several potential infrastructure expansion paths could ship this gas to the East Coast. Exhibit 17 shows three potential paths.

Exhibit 18

To provide some high-level, indicative analysis on whether there is a clear preference between these expansion paths, we looked at two production rates – 200TJ/d and 400TJ/d – and assumed that all future gas production would be from the Beetaloo basin, given it is the NT’s most prospective large-scale onshore development. Our analysis extended the simplified, closed-loop system to Wallumbilla, including the South West Queensland Pipeline (SWQP). For this pipeline, our analysis is based on the available contract capacity, not nameplate capacity.

For each infrastructure alternative, we examined two destinations as demand nodes – Moomba and Wallumbilla. Moomba would be the natural hub for southern states gas import, while Wallumbilla is a natural hub for gas feeding into Gladstone and Brisbane.

5.7.1.1 Maximise use of existing NGP route

This alternative requires augmentations to the AGP, NGP, CGP and QSNL so that each are capable of flows of up to 400TJ/d to Moomba. Augmentations and/or duplication of the SWQP would be required for delivery to Wallumbilla. We used the AER building block model to determine tariffs across all these pipelines to reflect the capital expenditure required for augmentations and expansions.

ALTERNATIVE INFRASTRUCTURE EXPANSION PATH FOR NT GAS

Bonaparte

Browse

Amadeus

Cooper

Galilee

Surat / Bowen

Sydney Gunnedah

GippslandOtway

Bass

2

Existing pipelines

Proposed pipelines

Gas basin

Georgina

Mt. Isa

1

Canning

Melbourne

Alice

Springs

Tennant Creek

Brisbane

Wallumbilla

3

Maximise use of existing NGP route

• Reverse and expand the CGP to allow up

to 400TJ/day with backhaul

• Modify AGP as required to fully utilise NGP

3

2

1

Build the SNP pipeline

• Modify AGP as required to fully utilise SNP

• Assume NGP does not exist or is fully

utilised without AGP augmentation

Build the Mt Isa to Wallumbilla extension

• Modify/duplicate AGP and NGP as required

to fully utilise new infrastructure


5.7.1.2 Build the SNP pipeline

This option explores the feasibility of a southern NT interconnector. For this analysis, however, we assumed that the NGP would operate at its initial capacity, without augmenting the AGP and CGP (unlike the SNP modelling described earlier in this report). Any augmentations to the AGP would be a result of delivering gas via the SNP. Again, augmentation of the SWQP (including the QSNL) would required for Wallumbilla.

5.7.1.3 Build the Mount Isa to Wallumbilla extension

This scenario requires augmentations to the AGP and NGP, and associated tariff increases. We also modelled the capital expenses required to build and augment the NGP extension to give associated tariffs for a 1200km pipeline from Mount Isa to Wallumbilla.

5.7.2 Centre of demand is the most important factor to cost-effective expansion

Exhibit 19 shows a high-level indicative analysis of potential tariffs for the three infrastructure expansion paths. The analysis led to two conclusions. The first is that the SNP (being a direct route from fields that access the AGP to Moomba) could be the most cost-effective transmission option to deliver gas to the southern markets (New South Wales, Victoria, and South Australia), but only at high NT export rates. This is consistent with our previous findings. The second is that an NGP extension from Mount Isa to Wallumbilla would be the most competitive of the three alternatives, under both export volume scenarios (200 TJ/d and 400 TJ/d).

Exhibit 19

ESTIMATED TARIFF FROM NT TO MOOMBA AND WALLUMBILLA: NT EXPANSION ALTERNATIVES

To Moomba To Wallumbilla


* All NT gas production is assumed to have come from the Beetaloo basin

Source: AEMO; NT Government analysis; PJP analysis

3.30

2.50

3.30

3.90 4.10

3.90

Alternative 1 Alternative 2 Alternative 3

4.20 4.00

2.90

5.50

6.80

4.30

Alternative 1 Alternative 2 Alternative 3

400 TJ/d

200 TJ/d

400 TJ/d

200 TJ/d

Most

competitive

Most

competitive

INDICATIVE


5.7.3 Alternatively, a large NT discovery could underwrite additional NT export infrastructure

It is possible that a large enough development could underwrite a new LNG export terminal in the NT. Based on the size of recent LNG projects in Australia, a rough estimate is that 500-800TJ/day would be required– significantly more than what is needed to underwrite a new pipeline to Moomba. If the economics of an onshore gas project requires significant scale to be economic, it could be that a new LNG export terminal would be the most commercially attractive destination for significant volumes of NT gas, with the economics of scale reducing the cost of production for additional gas to be sold to the East Coast market.

5.7.4 The presence of natural gas liquids could influence the relative economics of transport for producers, but it is far too early to predict how

As noted in section 5.5.6, we have not factored the value of incremental value of natural gas liquids. It is possible that the discovery of ‘wet gas’ could favourably impact the transport economics of some routes over others. This would occur if a particular route offered favourable economics for access to liquids extraction and processing facilities, as well as end demand for natural gas liquids. These factors could more than offset a difference in pipeline tariffs between routes.

The Moomba gas hub houses liquids extraction and ethane treatment plant. We understand this plant has spare capacity at the time of writing. The Moomba hub also connects to two natural gas liquids pipelines to transport natural gas liquids to a point of sale: the Moomba to Port Bonython Liquids Pipeline, and the Moomba to Sydney Ethane Pipeline. These factors would advantage scenarios 1 and 2 shown in Exhibit 18 in a wet gas development scenario, as these scenarios provide the most direct access to these facilities and pipelines at Moomba.

Nonetheless, predicting the relative economics is complex. How natural gas liquids could change the preferred infrastructure expansion path depends on a range of factors:

• The amount and type of natural gas liquids present. For example, a large amount of natural gas liquids may warrant in place liquids extraction, whereas a smaller amount may favour utilisation of infrastructure at Moomba.

• The place of end demand for liquids extracted from NT gas. This could be to existing centres of demand accessed via the Moomba gas hub: the export terminal at Port Bonython via the Moomba-Port Bonython pipeline, or the Qenos ethylene manufacturing facility at Port Botany via the Moomba-Sydney ethane pipeline. Alternatively, end demand may originate from a new source, such as a new investment in processing and storage terminals or downstream manufacturing.

• The direction and size of physical gas flows on existing infrastructure, such as the Carpentaria Gas Pipeline, affecting the ability to transport ethane in the gas stream to liquids extraction plant at Moomba

At this embryonic stage of gas exploration in the NT, it is far too early to predict the impact of any one of these factors, let alone the possible permutations of all three. As


such, our conclusion is that that the possibility of a wet gas play in the NT does not obviously favour any particular infrastructure expansion path.

5.7.5 It is very hard to predict the most commercially viable or efficient path in advance of commercialisation of significant reserves

Our high level analysis of the economics of expansion paths outlined above is based on a limited range of scenarios. In reality, there are myriad possible gas production outcomes, which makes it difficult to predict which solution is most commercially viable or economically efficient this far in advance. This is due to the system’s ever-changing capacity constraints and the associated augmentation costs to increase throughput of planned and existing pipelines.

Three uncertainties make pre-empting a preferential infrastructure expansion option very difficult at this stage of NT gas development:

1. Uncertainty on the supply side: the amount of gas that can be commercialised, its location, and the pace of growth profile of that gas.

2. Uncertainty on the demand side: the volume, location and volume ramp-up profile of potential demand from the NT relative to other gas developments in Australia or offshore

3. Physical capacity of existing infrastructure: the future physical capacity of existing infrastructure downstream of the NT that can interconnect with a second NT pipeline

If Government were to play a role in selecting or influencing the next piece of pipeline infrastructure to connect the NT’s gas volumes to the rest of the domestic market, it must take a view on the optimum destination – Moomba, Wallumbilla, or elsewhere. The optimum destination would be a function of the expected integrated tariffs and expected demand.

Furthermore, without a clearer understanding of the extraction costs of future gas field developments, the price of NT gas delivered to the East Coast market may or may not be competitive with gas sources located closer to the market (see Exhibit 20).

Finally, investing in such infrastructure today would carry significant risk of substitutes. This could happen if, for example, the New South Wales and/or Victorian State Governments lift their moratoria on developing local unconventional gas resources.


Exhibit 20

5.8 Conclusions

A second NT interconnector would be a viable investment only if sufficient gas volumes existed within the NT for interstate export (and demand for that gas at the delivered price). The proximity of that gas to existing and proposed infrastructure plays a role in the relative economics of a second interconnector.

At the large volumes required to justify a southern NT pipeline to Moomba, several alternative infrastructure expansion options could follow from the commercialisation of those volumes. At this stage, it would be premature to take a view on which of these is most commercially viable, or most likely to produce efficient market outcomes.

5.00 5.50

4.50

6.50

5.00

2.00 0.30

4.10

3.40 5.50

7.00

5.80

8.608.20

8.80

9.60 9.90

10.50

Narrabri Gippsland Bowen Walloon NT Gas

GAS – DELIVERED COST TO MELBOURNE

* Assumes NT gas can be delivered at NGP maximum capacity of CGP (200TJ/d)

Source: Core Energy; AEMO; COAG; Ignite Energy; QLD Government Reserves; ACCC; PJP analysis

A$ per gigajouleExtraction cost range

Cost of

extraction

Tariffs


6 Evaluating the national interest case for the SNP

6.1 An effective gas market should deliver availability, affordability, liquidity and efficiency

To evaluate whether there is a national interest case for the SNP beyond the commercial viability of the pipeline, we consider it would have to deliver broader economic benefits to East Coast gas market outcomes.

We define a dynamic, functioning domestic gas market as one which exhibits the following outcomes:

• Availability – i.e. sufficient supplies of gas to satisfy domestic demand

• Affordability – i.e. the market can provide gas to users at prices that do not destroy or undermine economic activity

• Liquidity – i.e. the market is sufficiently transparent and liquid for consumers and producers to transact as frequently as required

• Efficiency – i.e. the market is efficiently able to match supply and demand to produce rational economic outcomes

New pipeline infrastructure can support gas market outcomes by providing physical market access for additional sources of gas supply – improving the availability outcome. In general, providing access to more sources of supply will also improve the liquidity outcome of a market by enabling more counterparties to transact (although this is a difficult outcome to measure in a gas market that largely transacts confidentially, outside of open spot markets). Pipelines can also provide more affordable or efficient market access for existing gas supplies, improving the affordability outcome.

An efficient gas market would provide appropriate incentives for investors to construct pipeline infrastructure to ensure gas supply and demand can be met. Conversely, pipeline infrastructure investments that are not based on an underlying commercial need do risk producing perverse, inefficient market outcomes – particularly if they are subsidised or access is provided on a concessional basis. This can manifest by diverting gas from more productive uses to less productive uses.

6.2 The SNP is unlikely to improve market outcomes, particularly in advance of additional NT supply

Putting aside the commercial case outlined in section 5, we consider whether the SNP could improve any of the four market outcomes outlined above. For the SNP to improve the availability and affordability of gas in the East Coast gas market, one would need to believe:

4. That there is insufficient supply to fulfil East Coast domestic demand at prices that do not destroy that demand


and

5. That there is a sufficient volume of NT gas available – and in the right places – to make the transport economics viable and

6. That the existing infrastructure would be incapable of delivering those NT gas volumes to demand centres as cost-effectively as the alternate pipeline

With respect to the first point, the supply/demand balance in the East Coast is highly uncertain – even in the short term. LNG consumption is the single largest driver of modelled variability in the AEMO forecast of the supply-demand balance. Variance in LNG production, which is a function of the international LNG price, significantly overwhelms the shortfalls forecast in the ‘neutral’ case presented by AEMO.

Exhibit 20 shows the precariousness of these forecasts. It compares AEMO’s most recent gas demand forecasts of LNG exports with actuals over the first half of 2017. Monthly downward variation between the forecasts and the actuals exceeds the largest forecast supply shortfall in AEMO’s neutral case in its 2016 forecast of 2017 demand.

Exhibit 21

With respect to the second point, there is still significant uncertainty around the location and volumes of future NT gas development. The NT has few producing onshore fields, with production in the Amadeus basin declining over the last decade. Large contingent resources exist in the Beetaloo basin, but remain undeveloped partially due to the Territory’s moratorium on exploration and development of unconventional resources.

With respect to the final point, our analysis shows that the SNP is not cheaper than the NGP if it is built and utilised in parallel with the NGP, as seen in Exhibit 22. Furthermore, if the pipeline is built before the NGP is fully utilised, it could increase the tariffs on offer via the NGP for the first 200TJ/day of gas shipped from the NT to the East Coast.

GAS DEMAND FOR GLADSTONE LNG EXPORT: VARIANCE TO NEUTRAL FORECAST CASE

5

11

14 13 13

10

3

(3)

(8)

(10)

(16)

Jul-16 Aug-16 Sep-16 Oct-16 Nov-16 Dec-16 Jan-17 Feb-17 Mar-17 Apr-17 May-17

Source: AEMO Energy Supply Outlook June 2017; AEMO Update to Gas Statement of Opportunities; PJP analysis

Petajoules per month

For relative scale,

average supply-

demand shortfall

forecast by AEMO

= ~4-8PJ per month


Exhibit 22

In fact, Exhibit 22 shows that construction of the SNP in advance of sufficient demand could deteriorate the efficiency of the gas market. Until NT gas volumes exceed 200TJ/day constructing the SNP has the potential to increase tariffs on the existing infrastructure (the NGP) relative to not building the SNP. This is because it would encourage gas flows to bifurcate across two underutilised pipelines.

6.3 NT gas supplies are unlikely to alleviate short-term price pressures in the southern states

In assessing whether NT gas can alleviate price pressures in the southern states, it is necessary to consider the full cost of gas delivered to East Coast consumption centres. It is difficult to estimate the full extraction cost for the majority of NT gas supplies that are several years from development.

To visualise this point we assume a central estimate of A$5/GJ for newly developed large scale onshore NT gas based on discussions with industry. These are preliminary estimates, as the state of exploration in the Beetaloo Basin is still in very early stages.6 We have also estimated transmission costs to major demand centres in the southern states using our NT pipeline tariff modelling and published indicative tariffs for existing pipelines.

Exhibit 23 summarises this analysis and shows that NT gas is not likely to be as competitively priced as alternatives. Even at very high production rates (350 TJ/day) to provide scale benefits across the NGP and potential SNP, NT gas supplied via the SNP is likely to cost more than alternatives.

6 In discussions with industry we have heard potential ranges of full breakeven costs (including a provision for return on capital) ranging from A$3.50-7.00/GJ

0

1

2

3

4

5

6

7

8

0 100 200 300 400 500 600

TARIFF TO MOOMBA: NGP AND SNP BUILT IN PARALLEL AND UTILISED IN TANDEM


Source of gas: 90% Beetaloo, 10% AmadeusSource of gas: 75% Beetaloo, 25% Amadeus

0

1

2

3

4

5

6

7

8

0 100 200 300 400 500 600


NGP

SNP

NGP

SNP





NGP without

SNP

NGP without

SNP

NT gas flows

TJ/day

NT gas flows

TJ/day


Exhibit 23

It is possible, however, that NT gas supplies could displace demand for gas at other locations at the margins. For example, gas sales from Victoria to Queensland might be displaced by gas sales from the NT to Queensland, with the Victorian gas sold to Victorian customers instead. However, it is difficult for such displacement to provide price relief at centres of demand in the short-term, as gas sales and pipeline transportation contracts tend to be written as medium-to-long-term take-or-pay agreements, making it difficult to realise the incremental transport cost savings from displacing demand.

0

2

4

6

8

10

12

0 500 1,000 1,500 2,000

Weak case

~1730

SA

QLD**

LNG

NT

VIC

NSW

2021 SUPPLY CURVE FOR EASTERN AUSTRALIA INCL. NT 350TJ/DAY – STRONG CASE

Source: AEMO Gas Statement of Opportunities 2017; ACCC; PJP analysis

Production

PJ p.a.

Production cost

$ / GJ

* Total transport costs have been calculated based on the following assumptions: (i) all East Coast gas is transported to Moomba as the endpoint; (ii) the gas is transported using the

cheapest available pipeline route; and (iii) suppliers receive a 20% tariff reduction as a bulk volume discount.

** Queensland gas supply category excludes LNG produced in Queensland for export

Extraction costs

Transport to Moomba

AEMO demand range in

2021Strong case

~2225

AP

LN

G 2

P

Und

eve

lop

ed

VIC

Offsho

re

2P

De

velo

pe

d

QC

LN

G 2

P

Und

eve

lop

ed

GL

NG

2P

Und

eve

lop

ed

Co

op

er

2P

De

velo

pe

d

Even in strong case,

forecast is for a market

in disequilibrium

(supply < demand)

2017 FORECAST DATA


7 References

ACCC. (2016). Inquiry into the east coast gas market. ACCC.

ACCC. (2017, September). Gas Inquiry 2017-2020 Interim Report. ACCC.

ACIL Allen Consulting. (2017). The economic impacts of a potential shale gas development in the Northern Territory.

AEMO. (2016). National Gas Forecasting Report. AEMO.

AEMO. (2017). Energy Supply Outlook for Eastern and South-Eastern Australia. AEMO.

AEMO. (2017). Gas Statement of Opportunties. AEMO.

AEMO. (2017, September). Update to Gas Statement of Opportunities. AEMO.

APA. (2016). APA Investor Day. APA.

APA. (2017, June). Trading Summary Information. APA Capacity Trading. APA.

Australian Government. (2017). Heads of Agreement - The Australian East Coast Domestic Gas Supply Commitment.

COAG Energy Council. (2015). Coal Seam, Shale and Tight Gas in Australia: Resources Assessment and Operation Overview 2015. COAG Energy Council.

Core Energy Group. (2015). Gas Production and Transmission Costs. Core Energy Group.

Core Energy Group. (2016). Cooper-Eromanga Basin Outlook | 2035. Core Energy Group.

Ignite Energy Resources Limted. (n.d.). Gippsland Gas | Ignite Energy Resources. Retrieved from Ignite Energy Resources: http://www.igniteer.com/gippsland-gas/

Japanese Ministry of Economy, Trade and Industry. (2016 - 2017). Spot LNG Price Statistics. Spot LNG Price Statistics. Japan: Ministry of Economy, Trade and Industry.

Munson, T. (2014). Petroleum geology and the potential of the onshore Nothern Territory. Northern Territory Geological Survey, Report 22.

Productivity Commission. (2015). Examining Barriers to More Efficient Gas Markets. Canberra: Australian Government.

Queensland Government. (2017, January 19). csg-production.xlsx. Coal seam gas production data. Queensland, Australia.

Queensland Government. (2017, January 4). csg-reserves.xlsx. Coal seam gas reserves. Queensland, Australia.

The Australian Industry Group. (2017). Energy shock: No gas, no power, no future?

investigating the case for a second gas pipeline between ... · a second pipeline, the southern nt...

Documents