Gas resources/reserves classification

Gas market modellingGas Market Study Task Force

Report SH43529 | 15 October 2013

Gas market modelling


Document title: Gas market modelling

Version: Final

Date: 15 October 2013

Prepared by: Richard Lewis

Reviewed by: Michael Goldman

Approved by: Nicola Falcon

File name:

Sinclair Knight MerzABN 37 001 024 095Level 11, 452 Flinders StreetMelbourne VIC 3000Australia

Tel:Fax:Web:

+61 (3) 8668 3000 +61 (3) 8668 3001 www.globalskm.com

COPYRIGHT: The concepts and information contained in this document are the property of Sinclair Knight Merz Pty Ltd (SKM). Use or copying of this document in whole or in part without the written permission of SKM constitutes an infringement of copyright.

LIMITATION: This report has been prepared on behalf of and for the exclusive use of SKM’s client, and is subject to and issued in connection with the provisions of the agreement between SKM and its client. SKM accepts no liability or responsibility whatsoever for or in respect of any use of or reliance upon this report by any third party.

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ContentsAbbreviations............................................................................................................................................................................................. 1Executive summary.................................................................................................................................................................................... 2Key Drivers................................................................................................................................................................................................... 2

Key Findings................................................................................................................................................................................................. 5

1. Introduction.................................................................................................................................................................................. 81.1 The market environment................................................................................................................................................................ 8

1.2 This study...................................................................................................................................................................................... 9

2. Methodology.............................................................................................................................................................................. 102.1 Gas market scenarios.................................................................................................................................................................. 10

2.2 Gas market methodology............................................................................................................................................................. 10

3. Assumptions.............................................................................................................................................................................. 113.1 The eastern Australian Gas Market............................................................................................................................................. 11

3.2 Outlook for gas reserves.............................................................................................................................................................. 15

3.3 Gas production costs................................................................................................................................................................... 17

3.4 Gas transmission......................................................................................................................................................................... 21

3.5 Outlook for gas demand............................................................................................................................................................... 22

3.6 Recent contracts and prices........................................................................................................................................................ 28

3.7 Demand-supply and pricing methodology.................................................................................................................................... 30

4. Projections................................................................................................................................................................................. 344.1 No contract diversion to exports.................................................................................................................................................. 34

4.2 High contract diversion to exports................................................................................................................................................ 42

4.3 Wholesale prices in retail contracts............................................................................................................................................. 45

Appendix A. Terms of Reference - Study on the eastern Australian Domestic Gas Market..............................................................46Appendix B. Gas resources/reserves classification............................................................................................................................. 48

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TablesTable 1 Gas demand and reserves by state, 2012 (PJ) 11

Table 2 Remaining conventional reserves and resources as at 31st December 2012 (PJ) 16

Table 3 Remaining CSG reserves and resources as at 31st December 2012 (PJ) 17

Table 4 CSG well productivity (TJ/day) 19

Table 5 SKM estimates of gas production breakeven costs 20

Table 6 Recent domestic gas supply contracts 29

Table 7 LNG Netback values at Gladstone 32

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FiguresFigure 1 Gas reserves at 31/12/2012 and pipeline flows in 2012, eastern Australia 12

Figure 2 Eastern Australian gas production by basin 14

Figure 3 Eastern Australian gas production by producer 14

Figure 4 Aggregate conventional gas resources and reserves, eastern Australia (PJ) 15

Figure 5 Aggregate CSG reserves, eastern Australia (PJ) 16

Figure 6 ESG Production Costs 18

Figure 7 Carbon price projection ($/tonne, $2013 real) 19

Figure 8 Cumulative gas resource availability vs cost of production 20

Figure 9 Historical transmission volumes South Eastern Australia 21

Figure 10 Base case LNG export demand projection (PJ) 23

Figure 11 LNG Export demand projection scenarios (PJ) 23

Figure 12 Base Case eastern Australian Gas Demand Projections by State (PJ) 24

Figure 13 Base Case eastern Australian Gas Demand Projections by Sector (PJ) 25

Figure 14 Domestic gas demand scenarios 26

Figure 15 Base case reserves availability for new domestic contracts 27

Figure 16 Domestic demand vs existing contracts 28

Figure 17 LNG contract demand functions 33

Figure 18 Projected gas supply LNG, Base Case 34

Figure 19 Projected gas supply LNG, Low Case 35

Figure 20 Projected gas supply LNG, High Case 35

Figure 21 Projected gas supply, eastern Australia domestic Base Case 36

Figure 22 Projected gas supply, eastern Australia domestic Low LNG/Price 37

Figure 23 Projected gas supply, eastern Australia domestic High LNG/Price 37

Figure 24 New upstream contract prices for eastern Australia ($/GJ, $2013 real) 39

Figure 25 New upstream contract prices for Queensland ($/GJ, $2013 real) 39

Figure 26 New upstream contract prices for southern states ($/GJ, $2013 real) 40

Figure 27 Average upstream contract prices for eastern Australia ($/GJ, $2013 real) 40

Figure 28 Average upstream contract prices for Queensland ($/GJ, $2013 real) 41

Figure 29 Average upstream contract prices for southern states ($/GJ, $2013 real) 41

Figure 30 Projected gas supply LNG, High Diversion Base Case 42

Figure 31 Projected gas supply eastern Australia domestic, High Diversion Base Case 43

Figure 32 High contract diversion - new upstream contract prices for eastern Australia ($/GJ, $2013 real) 44

Figure 33 High contract diversion - average upstream contract prices for eastern Australia ($/GJ, $2013 real) 44

Figure 34 Schematic showing gas accumulation types 48

Figure 35 SPE/WPC/AAPG/SPEE resources classification system 50

Disclaimer

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This report has been prepared solely for the Standing Council on Energy and Resources (SCER) and the Gas Market Study Task Force for the purpose of assisting the Task Force to undertake scenario development and modelling of the supply, demand and gas price dynamics of the eastern Australian gas market. Sinclair Knight Merz shall have no liability (other than specifically provided for in contract) for any representations or information contained in or omissions from the report or any written or oral communications transmitted in the course of the project.

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Abbreviations2C (resources) Contingent resources (50% probability of exceedance level)

2P (reserves) Proved and probable (50% probability of exceedance level)

3P (reserves) Proved, probable and possible (10% probability of exceedance level)

AEMO Australian Energy Market Operator

AIG Australian Industry Group

APIA Australian Pipeline Industry Association

APPEA Australian Petroleum Production and Exploration Industry Association

ATP Authority to prospect

CPI Consumer Price Index

CSG Coal Seam Gas

FID Final Investment Decision

GJ Gigajoule(s) (=109 joules)

GSA Gas supply agreement

GSOO Gas Statement of Opportunities

JCC Japan customs cleared

JV Joint Venture

LNG Liquefied Natural Gas

NEM National Electricity Market

PJ Petajoule(s) (=1015 joules)

SCER Standing Council on Energy and Resources

SPE Society of Petroleum Engineers

STTM Short-term trading market

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Executive summaryOn 27 May 2013 the Minister for Resources and Energy, the Hon Gary Gray AO MP, announced that the Australian Government is undertaking a new, comprehensive study of the domestic gas market outlook—“Lifting the lid on Australia's gas markets”. The terms of reference for the Domestic Gas Market Study are reproduced in Appendix A.

SKM has been appointed to provide a report describing its recent scenario development and modelling of the supply, demand and gas price dynamics of the eastern Australian gas market, to assist the Task Force in its role. The appointment is a result of SKM’s non-conforming response to the Task Force’s Request for Quote (RFQ), in which SKM offered to provide a report based on pre-existing scenarios and analysis similar to those requested in the RFQ, with the benefit of potentially providing diversity to the advice received by the Task Force.

The report was initially prepared and released on 28 August 2013 with very limited input from the Task Force. More detailed explanations of some features of the analysis have subsequently been provided to the Task Force in conference. For completeness, this final version of the report documents a number of gas market related events subsequent to 28th August but does not consider their impact on the findings.

The key finding of this report is that there is considerable uncertainty regarding both gas demand, mainly in the export component, and gas supply, with CSG reserves growth slowing and attention moving to shale gas. This naturally results in price projections covering a wide range of levels and timing.

Key DriversEastern Australia has some of the world’s largest coal deposits, containing very significant coal seam gas resources. By 2007, this gas resource had been proved to be commercial in volumes exceeding domestic gas requirements and planning for exports as LNG was initiated.

Figure E 1 LNG Export demand projection scenarios (PJ)

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20142016

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During 2011 and 2012 three LNG projects using CSG commenced construction, with first deliveries scheduled for 2014 and 2015. A fourth project remains in planning and further projects are contingent on their competitiveness with other projects in planning, particularly in North America and East Africa. The range of uncertainty in export volumes is reflected in Figure E 1, in which the Low Case is the production required for current committed projects, the Base Case assumes the fourth project also proceeds and in the High Case one further LNG train is added every two years.

LNG project planning triggered a drive to increase proved CSG reserves and also resulted in consolidation of CSG acreage. Owing to LNG demand, gas reserves available for new domestic gas contracts declined over recent years and are likely to remain restricted for a number of years (Figure E 2). Domestic gas users have experienced difficulty in obtaining new contracts and prices for new contracts are reportedly 50% to 100% higher than prices currently being paid.

Figure E 2 Base case reserves availability for new domestic contracts

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The domestic gas market is adequately contracted until 2015 in eastern Australia as a whole (Figure E 3). Given that prices under these contracts are, in aggregate, unlikely to escalate significantly, this would appear to offer price protection to most end users until 2016.

It is noted however that the majority of contracts are held by the three major retailers, AGL, Origin Energy and Energy Australia and are not fully allocated to domestic end users, i.e. they buy long and sell short, so there is a possibility of some “domestic” contract gas being diverted to exports, resulting in earlier recontracting at a higher price for the domestic market. Figure E 3 also illustrates our estimates of the volumes currently contracted to end users under term contracts, both directly by producers and indirectly by retailers.




Figure E 3 Domestic demand vs existing contracts

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Key FindingsSKM has projected the price of new upstream gas contracts in each of three demand-supply scenarios based on the alternative LNG demand projections. Prices have been determined using two alternative assumptions regarding existing contracts: 1) that all existing contracts remain dedicated to the domestic market; and 2) that all gas not contracted directly and indirectly to end users is available for diversion to exports and further new upstream contracts are required for the domestic market.

Under assumption 1 above with no contract diversion, new contract prices are projected to rise in all scenarios until LNG development stops or slows, until 2017 to 2020 depending on the scenario (Figure E 4). Similar price patterns are shown in both Queensland and southern states, owing to the interaction of demand and supply from north to south. Section 4.1.2 provides details.

The average price of gas in ongoing1 and new contracts rises more slowly, reflecting the progressive addition of new contracts, with major contract replacement in 2017 and 2018 (Figure E 5). If these average prices were passed through to the wholesale cost of gas in retail contracts, end users would be protected from most of the price rises until 2017.

Figure E 4 New upstream contract prices2 for eastern Australia ($/GJ, $2013 real)

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1 For the purposes of our analysis the prices of ongoing contracts are assumed to be fixed in real terms. The effect of price reviews may result in real escalation as the weight of new contracts in the market increases over time.

2 Weighted average delivered prices




Figure E 5 Average upstream contract prices3 for eastern Australia ($/GJ, $2013 real)

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However a recent report by the Australian Industry Group (AIG) suggests that retail prices will rise significantly from 2014, as if the price protection from ongoing contracts was not there. This outcome can be simulated by projecting prices under assumption 2) above, namely that all gas not contracted to end users is available for diversion to exports and further new upstream contracts are required for the domestic market.

As may be expected, with this assumption, domestic prices for both new contracts and average contracts rise and fall 3 to 4 years earlier than with the “no diversion” assumption (Figure E 6 and Figure E 7). Based on the AIG report, it appears that retailers may be intent on increasing the wholesale component of retail prices as if existing contracts were diverted to exports, regardless of whether they are or not, rather than giving retail customers the benefit of continuing low average contract prices. The AIG report suggests that the retail market is sufficiently short of gas for this to occur.

3 Ibid




Figure E 6 High contract diversion - new upstream contract prices for eastern Australia ($/GJ, $2013 real)

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Figure E 7 High contract diversion - average upstream contract prices for eastern Australia ($/GJ, $2013 real)

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1. Introduction1.1 The market environmentThe eastern Australian gas market entered a period of rapid change some 5 to 6 years ago. The following points trace some of the key factors involved:

Successful commercialisation of CSG in Queensland after 2000 and promotion of exports as LNG to monetise reserves, from 2007, once reserves clearly exceed domestic market requirements

The export value of gas is expected to be much higher than the historical value of domestic sales

The dash to CSG is triggered:

o reserves grow by 8,000 PJ pa through 2008 to 2011

o LNG producers and users buy into the export projects

o Smaller CSG players are consolidated

o 3 LNG projects reach FID in 2011 and 2012, which will triple east coast gas usage from 2016 when they are in production.

Although CSG resources are large, commercial proved and probable (2P) reserves are initially insufficient for standard 20 year export contracts.

o The projects therefore focus on proving up more reserves and refrain from selling any gas to the domestic market.

o Reports of domestic buyers having difficulty securing new gas contracts emerge as early as 2011 in the Queensland Gas Market Review

o Two of the LNG projects also back-up their reserves with volumes of gas purchased from third parties at relatively high, oil-indexed prices.

o This creates the impression that all uncontracted reserves can be sold at elevated prices and producers are reluctant to sell for less.

o There is also an expectation that further LNG projects will absorb more gas

Reports of lack of domestic supply have intensified through 2012 and 2013 and have been rejoined by gas producer statements that gas is available at the right price.

o A number of parties have put forward suggestions to help resolve matters (Grattan Institute, APIA)

o Since late 2011 a limited number of new domestic contracts have been entered, all apparently at higher price levels than previous contracts.

Further recent developments adding to the complexity include:

o It has been questioned whether gas supply capacity is developing fast enough to meet demand in 2015 and 2016 when the bulk of exports are scheduled to start.




o Public opposition to CSG and further regulation of CSG in NSW have halted development there for 3 years and may continue to do so. Three companies have mothballed their NSW CSG projects.

o Export project cost blow-outs have had the two-fold effect of:

Making further east coast LNG commitments less likely in the face of new competition from North America and East Africa

Reducing the value of exports relative to domestic sales

o Issues which SKM believes will increasingly come into focus include timing of price increases in the markets that feed from upstream contracts: the retail market; organised wholesale markets (spot or STTMs); and the NEM.

1.2 This studyThis environment is the principal reason why the Minister for Resources and Energy requested the Domestic Gas Market Study.

This report addresses some but not all of the above issues. Key issues that are addressed include:

Demand projections for export and domestic markets under three scenarios

Supply availability, development potential and cost projections

Demand-supply balance and price outcomes for the three demand scenarios.

Identification of sensitivity of scenario outcomes to assumptions regarding the commitment of existing contracts to the domestic market.

Consideration of wholesale gas prices passed through to retail markets.

Key issues that are not addressed include:

Adequacy of capacity development to meet demand in 2015 and 2016:

o Similar to other long-term demand-supply models, SKM modelling works off reserves available and assumes that once a new supply contract is entered, the supply capacity will be built on-time.

o Detailed daily demand-supply patterns associated with the LNG projects, and their potential to impact domestic supply, are known only within the projects.

For example, ramp gas, which was expected to be available in the lead-up to the start of exports, appears to have been managed through well turn-down and underground storage.

Changes to the market or the nature of transactions

o Higher prices may encourage shorter term contracts, as a means of avoiding the consequences of mispricing, which itself may be the result of limited and infrequent information

Pricing in the organised wholesale markets, namely the Victorian spot market and the three STTMs.

o There is a potential for these markets to become more volatile in response to changes in LNG demand-supply balance from day-to-day, with flow-on effects to the NEM.




2. Methodology2.1 Gas market scenariosThree gas market scenarios, which have been labelled Base, High and Low have been modelled. Base, High and Low refer to both LNG demand and domestic gas prices. The scenarios have been designed to represent a credible range that can be expected for gas prices over the long term.

The Base scenario represents the most likely of these outcomes for the eastern Australian wholesale gas market. It assumes that 2 further LNG trains in Queensland are commissioned in addition to the 6 that are currently committed. The High scenario assumes that LNG production in eastern Australia continues to expand beyond the 8 trains in the Base scenario, and that new LNG trains are commissioned at a steady rate at least over the next decade. The Low scenario assumes that no more Queensland LNG projects are commissioned, other than the 6 that have currently reached committed status and are already under construction.

2.2 Gas market methodologyGas market modelling has been conducted using SKM’s “Market Model Australia – Gas” (MMAGas) modelling tool and associated data. MMAGas represents the market for new long-term gas contracts, the primary form of transaction between gas producers and buyers, as a competitive game between producers with uncommitted 2P gas reserves. The Nash-Cournot game basis of the model enables it to capture both competitive outcomes and outcomes reflecting market power due to limited supply. Competition between producers is based on maximising profits after accounting for production costs and transmission network costs.

Key data includes:

Gas reserves (2P) and resources available for development

Estimated gas production costs, specified in 2 tranches for each producer

Existing gas contract volumes, prices and terms

Gas transmission network structure and costs

Gas demand projections in each market zone

Nine domestic market zones are specified plus one LNG export zone. Exports have a critical influence on domestic outcomes because: a) their scale is projected to be at least twice that of domestic demand by 2016, hence they can reduce domestic supply; and b) their value can be higher than historical domestic gas prices.

Further details of the model and assumptions are provided in section 3.




3. Assumptions3.1 The eastern Australian Gas MarketSKM prepares gas price forecasts based on projected demand-supply balances in eastern Australia. The gas resources and delivery infrastructure in this region are illustrated in Figure 1. This chapter presents details of SKM’s gas market modelling methodology and assumptions.

Eastern Australia (New South Wales, Victoria, Queensland, South Australia, Tasmania and the ACT) has a domestic market estimated at 709 PJ in 2012, supported by substantial conventional and coal seam gas (CSG) reserves – total 2P reserves at 31/12/2012 are estimated at 49,838 PJ. Regional breakdowns of these figures are shown in Table 1 and background information on reserves definitions is provided in Appendix B.

Table 1 Gas demand and reserves by state, 2012 (PJ)NSW Victoria SA Tasmania Queensland Total

Demand 158 218 103 18 212 709

2P Reserves 2,663 5,779 2,616 247 38,533 49,838

Source: Demand: AEMO Bulletin Board; Reserves: Oil and Gas Resources Australia; Queensland Department of Natural Resources and Mines; and Producer Estimates

Demand and supply patterns in this market have operated in isolation from other gas markets in Australia and overseas because to date there have been no gas exports from or imports to the region. Recent growth of CSG reserves, to levels in excess of foreseeable domestic demand, has led to construction of a number of LNG export projects which have already begun to change the domestic market, both in terms of the demand-supply dynamics and the nature of the participants, who now include global energy companies such as BG Group, Conoco Phillips, Petronas and Shell, and large offshore gas purchasers such as China Petroleum Corporation, Kogas and PetroChina..

The prospect of exports emerged relatively quickly and unexpectedly, following a long history of perceived excess of demand over local supply and a corresponding history of proposals to import gas from the North West Shelf in Western Australia, from Papua New Guinea and from the Timor Sea. All of these proposals have been deferred because of unforeseen growth in eastern Australian gas reserves and supply, most recently the CSG reserves in Queensland.

All eastern States’ sub-markets except Northern Queensland are now served by multiple basins and/or pipelines. Plans for a pipeline between Moranbah and Gladstone, which would link Townsville to other supplies, have been advanced but construction appears to be contingent upon LNG development in Gladstone using gas from the Moranbah area. Armour Energy and APA have also recently floated the NORGAS project concept of linking Mt Isa to the NT Pipeline to exploit gas in the Carpentaria and Georgina Basins.




Figure 1 Gas reserves at 31/12/2012 and pipeline flows in 2012, eastern Australia




3.1.1 Market transactionsThe dominant transactions in the eastern Australian gas market are long-term gas sales agreements (GSAs) between gas producers and buyers such as retailers, large industrial users and generators. The duration of long-term contracts has covered a wide range, running from 3 years to 15 years in contracts entered over the last decade. There is limited public information on gas contracts but the basic details such as term and average volumes are known for the majority of the significant contracts. Contract prices are less well known but can often be estimated – most contract prices are CPI indexed and undergo periodic reviews to ensure they remain at “market” levels, though without a recognised market price, reviews can be prolonged.

Shorter-term bi-lateral contracts are also used but there is almost no public information about them. In particular, short-term markets have had insufficient depth to support a price index, though we note the very recent start-up of the Argus Victorian Index (AVI), a month ahead index linked to the Victorian spot price discussed below, The AVI hopes to replicate short-term markets in the US and Europe, where many trading hubs have associated benchmark prices, the best known being the Henry Hub in Louisiana. Many longer term contracts in the US are now indexed to the Henry Hub price, overcoming the difficulty of setting long-term prices that remain in line with the market.

Organised spot markets are operated by the Australian Energy Market Operator (AEMO) in Victoria, Adelaide, Brisbane and Sydney for the primary purpose of balancing the transmission/distribution system – the pool price is used to settle injection/withdrawal imbalances. Bidding into the pool is compulsory for all transmission/distribution system users in the pool area, most of whom are retailers buying gas from producers under GSAs. In general the pool bids and prices are determined by the prices set in the GSAs rather than vice versa. AEMO in conjunction with the gas industry proposes to establish a more formal trading hub at Wallumbilla (near Roma), which is likely to see a rapid increase in volumes associated with LNG developments.

The level of gas producer competition has until recently been sufficient to maintain price levels for new GSAs in the south-east and growing CSG production reduced prices in some Queensland sub-markets. Supply pressures resulting from development of resources for export have already led to higher prices in new contracts and this is widely expected to continue.

3.1.2 Gas production history Figure 2 and Figure 3 illustrate historical gas production by basin and by producer respectively. For many years production was dominated by the Cooper and Gippsland basin joint ventures (JVs). After growing to supply the Queensland market in the 1990s Cooper Basin production declined and was replaced by Surat/Bowen CSG in Queensland and Otway Basin gas in South Australia. The use of CSG for export may reverse this process.

The rapid increase in the number of producers after 2000 is largely attributable to the gas reforms introduced in the late 1990s, including third party access to pipelines and the removal of production and retail monopolies.




Figure 2 Eastern Australian gas production by basin

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Figure 3 Eastern Australian gas production by producer

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Esso Gippsland

Source: APPEA




3.2 Outlook for gas reservesThe eastern Australian gas market has grown steadily since the late 1960s, supported by conventional gas reserves that have remained relatively static since approximately 1980 (refer to Figure 4). The past decade however has witnessed rapid growth of CSG reserves, mainly in Queensland, to the extent that by 2008 it was clear that they could rapidly exceed domestic demand provided that a market could be found, otherwise the development may have stalled (Figure 5). Growth continued to 2010 to meet export commitments but has since slowed as the future exporters have switched their resources to developing gas production capacity. (Note: a description of gas reserves/resources classification is provided in Appendix B).

Figure 4 Aggregate conventional gas resources and reserves, eastern Australia (PJ)

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Source: primarily Geoscience Australia.

Note: 2P = proven and probable; 2C = proven and probable but contingent on price obtained.




Figure 5 Aggregate CSG reserves, eastern Australia (PJ)

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Notes: 1P = proven; 2P = proven and probable; 3P = proven, probable and possible.

Breakdowns of the most recent reserves and resources figures by basin and producer are shown in Table 2 and Table 3.Recent drilling results in the Galilee Basin have been disappointing and the participants seem to be moving on, consequently we have excluded the small 2C resources volume for Galilee. 2C resources in general have recently been reducing owing to the introduction of more stringent CSG 2C resources classification criteria by SPE in 2011. There is growing interest in shale resources, with some 2C resources declared in the Cooper Basin.

Table 2 Remaining conventional reserves and resources as at 31st December 2012 (PJ)Basin Joint Venture 2P 2CGippsland, Longford BHPB, Exxon 4,715 3,400Gippsland, Orbost Nexus 147 400Bass Origin, AWE 247 497Otways, Minerva BHPB, Santos 135 50Otways, Geographe Origin, Others 511 300Otways, Casino Santos, Others 272 150Cooper Eromanga Santos, Beach, Origin 2,409 2,500Cooper Eromanga Others 147 1,9001

Surat-Bowen All producers 247 MinorTotal 8,830 7,197

1 Unconventional, mainly shale




Table 3 Remaining CSG reserves and resources as at 31st December 2012 (PJ)Basin Joint Venture 2P 3P 2CSydney AGL1 140 186 46Gloucester AGL1 811 1,103 292Gunnedah Santos/TRU 1,426 2,463 3,531Clarence Morton Metgasco 4282 2,542 2,511Bowen AGL/Arrow 2,422 5,324 2,902Surat APLNG 13,748 16,682 3,825Surat QCLNG 8,732 10,839 2,107Surat/Bowen GLNG 5,784 6,966 1,672Surat Arrow Energy 7,009 10,722 3,713Surat/Bowen Second Tier 837 2,093 1,055

Total 41,338 58,920 21,6541 Since the completion of the analysis in this report, AGL has reduced Sydney and Gloucester resources by a combined 403 PJ, in

response to NSW CSG regulatory changes.

2 Metgasco has placed its Clarence Morton Basin operations under care and maintenance pending the outcome of NSW CSG regulatory changes. Metgasco’s reserves were not considered in our analysis.

The following observations are noted:

Information on 2C resources outside CSG and the Cooper Basin, where there is substantial shale exploration activity, is very limited. It is possible that the resource estimates for Bass and Otway basins are understated and that higher gas prices will stimulate further exploration and resource discovery

SKM has in the past considered CSG Prospective Resources (refer to Appendix B for definition) to potentially become commercial over the study period. However the estimates are extremely large and speculative, and there does not appear to be any reliable information regarding what fraction of them are likely to be commercial, so they are no longer included in our analysis.

Projections of 2P reserves developments are presented in section 3.5.2.1.

3.3 Gas production costs

3.3.1 Costs implied in reserve declarationsInformation regarding gas production costs is not widely disseminated by the production sector in Australia. The production cost for declared reserves can be inferred from the fact that they are commercial, provided that the market price at which the reserves test for commerciality has been conducted is known. For the large majority of reserve estimates this market price is not stated however.

For gas in eastern Australia, where the wellhead market price has always been low in world terms, in the range $3/GJ to $4.50/GJ in real 2013 dollar values, it has until recently been reasonable to assume that commerciality meant profitable at that price level or perhaps slightly above if a price rise was anticipated by the developer. The advent of LNG exports which can sustain higher gas input prices raises the possibility of higher price assumptions and in recent presentations4 Santos has stated that it has booked its first shale reserves, for which the estimated costs of production are $6/GJ to $9/GJ.

3.3.2 Estimates based on LNG project costsMcKinsey and Company have recently released a detailed study of LNG costs in Australia and elsewhere5. Their estimate of CSG production costs is $4.35/GJ, for a typical LNG project, which compares to SKM’s estimate of $3.60/GJ for the GLNG project prior to recent cost blowouts. It is noted that costs for LNG

4 Cooper Basin Unconventional Gas Opportunities & Commercialisation, November 2012, available at www.Santos.com .5 Extending the LNG Boom. Improving Australian LNG productivity and competitiveness. McKinsey & Co, May 2013.



http://www.Santos.com/


supply are higher than for domestic supply owing to the need to drill wells over a period of 2-3 years in advance of first production of LNG.

3.3.3 ESG production costsEastern Star Gas produced a “Scheme Booklet” to advise shareholders in relation to Santos’ and TRUEnergy’s offers to purchase 80% of ESG. The Booklet provides details of capital and operating costs estimated by MHA Petroleum Consultants for various tranches of gas. Our analysis of this data, assuming a 12% breakeven IRR, has yielded the cumulative production cost curve in Figure 6. This covers all of ESG’s current reserves and resources and shows that up to 5,000 PJ could be produced profitably for less than $3.50/GJ in 2011 dollar terms. These costs would be somewhat higher if re-estimated today and expressed in 2013 dollars, especially taking into account the increased constraints on CSG production in NSW. The volume of gas producible at $3.50/GJ is likely to increase in future with further resource appraisal and the more expensive gas, which is mostly in higher CO2 fields, is likely to remain undeveloped.

Figure 6 ESG Production Costs

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Cum Production (PJ)

3.3.4 Well productivityA key factor in determining CSG costs is the rate of production per well. The above costs are typical of wells that produce 0.6 TJ/day to 1.0 TJ/day. Table 4, based on CSG production data released by Queensland Department of Resources and Mines, shows that the three producers committed to LNG exports, APLNG, GLNG and QCLNG, have the most productive wells, with others operating below the optimum rate. It is noted that APLNG has stated6 that some of its fields are operating below capacity and their outputs could be increased by 50%. SKM believes this could also apply to GLNG and QCLNG because they do not currently need all of the output from wells drilled for their LNG projects.

We use this information to fine tune our estimates of relative production costs.

Table 4 CSG well productivity (TJ/day)Producer 2008 2009 2010 2011 2012Arrow Energy 0.25 0.24 0.29 0.26 0.26

6 APLNG CSG Production, May 2013. www.originenergy.com.au



http://www.originenergy.com.au/


Producer 2008 2009 2010 2011 2012Molopo 0.07 0.14 0.20 0.17 0.08APLNG (Origin) 0.73 0.73 0.80 0.90 0.93QCLNG (QGC) 0.65 0.80 0.84 0.73 0.76GLNG (Santos) 0.75 0.75 0.94 0.87 1.00Westside 0.18 0.15 0.15 0.14 0.17

3.3.5 SKM Production cost assumptionsFor the purposes of this study we have assumed gas production costs excluding carbon costs as listed in Table 5. These costs are assumed to be constant in real terms and across the High, Medium and Low scenarios. Costs of production will increase when more costly resources are brought into production. Carbon costs associated with gas production are added on the basis of projected carbon costs and producer specific estimates of gas CO2 content and the volume of gas used in production. For this study a single carbon price scenario has been used (Figure 7). The carbon cost of gas usage is excluded from all of our wholesale price estimates.

Figure 7 Carbon price projection ($/tonne, $2013 real)

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These figures, together with the related reserves and resources estimates, translate into cumulative gas availability as depicted in Figure 8, where they are compared with availability estimates prepared by other consultants7. The wide gap between the estimates prepared by different consultants illustrates the degree of uncertainty in gas costs, particularly for resources beyond the first 50,000 PJ.

SKM’s lower overall resource availability compared to other estimates is most likely due to our taking into account the recent reductions in CSG 2C resource estimates. There is potential for shale gas availability to expand considerably, with current estimates of costs at the top end of SKM’s curve.

SKM modelling does not assume that resources will be developed in strict cost order, as in a least cost of supply approach. Instead, each producer develops its most competitive option in any basin, subject to its competitiveness relative to other producers. Thus if the market price is above $6/GJ at any time, all resources with costs below $6/GJ will be developed to the extent necessary to meet demand at that time.

7 ACIL Tasman. Cost of Gas for the 2013-2016 Regulatory Period. Prepared for IPART, 13 June 2013. (This source also documents the CORE estimates, which were published by AEMO in the 2012 GSOO).




Table 5 SKM estimates of gas production breakeven costsBasin Joint Venture 2P 3P + 2CGippsland, Longford BHPB, Exxon $3.50 $4.50Gippsland, Orbost Nexus $4.00 $5.00Bass Origin, AWE $4.00 $5.00Otways, Minerva BHPB, Santos $4.00 $5.00Otways, Geographe Origin, Others $4.00 $5.00Otways, Casino Santos, Others $4.00 $5.00Cooper Eromanga Santos, Beach, Origin $4.00 $5.00Cooper Eromanga Others $6.00 $6.00Sydney AGL $5.50 $6.50Gloucester AGL $3.50 $4.50Gunnedah Santos/TRU $3.50 $4.50Clarence Morton Metgasco $6.00 $8.00Bowen AGL/Arrow $4.50 $5.50Surat APLNG $3.50 $4.50Surat QCLNG $3.50 $4.50Surat/Bowen GLNG $3.50 $4.50Surat Arrow Energy $4.50 $5.50Surat/Bowen Second Tier $5.00 $6.00

Figure 8 Cumulative gas resource availability vs cost of production

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3.4 Gas transmissionThe existing network of transmission pipelines depicted in Figure 1 in principle enables gas to be transported from any production centre to any major market centre, with the exception of Townsville. Of course in practice there are capacity constraints and difficulties in arranging backhaul but these can generally be overcome where there is sufficient commercial incentive.

Figure 9 illustrates historical gas transmission volumes in South Eastern Australia (NSW, Victoria, South Australia and Tasmania). These volumes add up to the total demand in South Eastern Australia less the small volume supplied from the Sydney Basin, which is not transported on a transmission pipeline.

Figure 9 Historical transmission volumes South Eastern Australia

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Source: Bulletin Board. LL=Lang Lang; SWP = South West PL; LDP = Longford-Dandenong PL; EGP = Eastern Gas PL; MSP = Moomba-Sydney PL

As the cost of gas delivered to the city gate or transmission customer meter is made up of approximately 75% wellhead price and 25% transmission price, when matching demand and supply our focus is more on the wellhead component of supply than transmission and our assumptions regarding pipelines are as follows:

Existing pipelines are “unconstrained”, that is, capacity can be added by further compression or duplication

Pipeline tariffs continue at current levels/escalation rates

Uncommitted new pipelines can be added to the model but their projected throughput must be tested to ensure commercial viability.

In the scenarios analysed for this study uncommitted new pipelines have been included as follows:

Pipelines to convey CSG from the Southern Bowen/Surat basins and from the Northern Surat Basin (Moranbah) to Gladstone for the LNG projects. Pipeline start-up timing is aligned with LNG project timing. Pipeline tariffs are estimated to be $0.75/GJ with CPI escalation.




A modified version of the proposed Queensland-Hunter pipeline, to convey CSG from the Gunnedah and Gloucester Basins north to Wallumbilla and south to Wilton to compete in the broader NSW market. Owing to the delays to CSG development caused by local opposition in NSW, pipeline start-up is assumed to be 2018 in all cases. At throughput rates of 50 PJ/yr the tariffs for both the north and south sections are estimated at $1.10/GJ escalating at CPI. At these tariffs the cost of shipping Queensland CSG from Wallumbilla to Wilton through this pipeline is comparable to the cost of shipping through the existing pipelines: SWQGP-QSNLink-MSP.

The NORGAS pipeline linking Carpentaria Basin gas resources with Mt Isa from 2019. The location of these resources is assumed to result in transmission tariffs of $1.00/GJ.

3.5 Outlook for gas demand

3.5.1 LNG exportsWorldwide, the preferred technology to monetising excess gas8 is LNG production. LNG is a global product that saw rapid growth and high prices during the oil price surge from 2003 to 2008. Since 2007 ten proposals have been put forward to export LNG from liquefaction plants in Eastern Australia with eight proposed for the Queensland coast and one each in New South Wales and South Australia.

Three of the large projects at Curtis Island, near Gladstone, those of BG, APLNG and GLNG, have now passed the final investment decision and their six committed LNG trains, each capable of delivering about 4 million tonnes of LNG per year, are under construction, with first deliveries scheduled in the period 2014 to 2016. The fourth major project, that of Arrow Energy, remains in the planning phase and industry analysts have suggested that it may combine with one or more of the existing projects to improve its economics and their reserves positions. Most of the projects have planning approval for more than two trains.

The remaining Queensland and sole NSW projects have made limited progress since their first announcements, mainly because the most prospective CSG acreage has been captured by the four large projects. The SA project, promoted by Beach Petroleum, would be based on Cooper Basin shale gas, which is still in the early stages of its development.

Figure 10 illustrates our base case LNG export demand projections – based on the most recent company statements, LNG start-ups are scheduled as follows: BG – mid 2014; GLNG – beginning of 2015; APLNG – mid 2015; and Arrow – beginning of 2018. The “Arrow” trains may be constructed as the third and fourth trains of another project. The total of eight trains is consistent with the projections under the “Planning” scenario in the 2012 GSOO prepared by AEMO but the scheduling is slightly later – the GSOO envisages all eight trains in operation by 2017, but we believe this is no longer feasible and have put it back to 2019.

There has recently been a downward revision in LNG export demand expectations due to the rising cost pressures in the competing Curtis Island projects, coupled with increasing competition from other LNG export projects in planning and under construction in the USA, East Africa, Russia, Canada, Qatar, Papua New Guinea, Western Australia and the Northern Territory. The rising cost pressures suggest that only brownfield expansions of the three projects already under construction will be competitive.

8 Gas that cannot reach a market by pipeline. LNG is currently preferred to conversion technologies such as Gas-To-Liquids, on the grounds that the conversion cost is lower and for as long as LNG prices remain tied to oil prices it will be more profitable.




Figure 10 Base case LNG export demand projection (PJ)

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Our low case LNG projection assumes that neither of the Arrow backed trains are constructed i.e. the total remains six trains. Our high case projection involves construction of further trains at the rate of one completed every 2 years after the second Arrow train. These scenarios, which are compatible with the LNG netback price assumptions discussed in section 3.7, are depicted in Figure 11.

Figure 11 LNG Export demand projection scenarios (PJ)

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3.5.2 Domestic demandFigure 12 and Figure 13 illustrate the base case domestic demand projections. The projections are derived from:




Generation – SKM projections. The prices assumed in this forecast are consistent with the output prices discussed below.

Utility – AEMO 2012 GSOO planning scenario growth rates applied to SKM estimates of 2012 actuals.

The projections imply that domestic gas demand growth will be quite subdued over the next two decades. There are several causes of this:

1) a general decline in manufacturing accentuated by higher gas prices;

2) declining domestic use per household owing to:

a) increasing efficiency of housing stock and appliances

b) competition from solar water heating and reverse cycle electric heating, offset by mandated replacement of off-peak water heating

3) a general downturn in electricity demand which reduces the need for additional generation capacity other than renewable capacity mandated by the RET, also accentuated by higher gas prices and uncertainty over carbon pricing which makes gas-fired generation less competitive.

Figure 12 Base Case eastern Australian Gas Demand Projections by State (PJ)

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Figure 13 Base Case eastern Australian Gas Demand Projections by Sector (PJ)

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High and low gas price case projections have been derived as follows:

Generation – SKM high and low case projections

Utility – Low price case with growth rates at 1.5* AEMO 2012 GSOO planning scenario growth rates applied to SKM estimates of 2012 actuals. The Base Case growth rates are low compared to historical rates so this growth rate is achievable. The High price case has zero growth rates.




Figure 14 Domestic gas demand scenarios

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3.5.2.1 Implications for gas availability

APLNG has proved up sufficient reserves to meet its export requirements for two trains. However GLNG, and to a lesser extent QCLNG, still require additional reserves to meet their second train requirements despite the fact that they have purchased gas under third-party contracts in competition with domestic gas buyers. This has sustained the relative lack of reserves available to support new domestic gas contracts. Nevertheless the focus for all project proponents has moved from reserve development to construction of production capacity, as reflected in the recent slowdown in CSG reserves growth in Figure 5.

Growth in 2P gas reserves for each of the producers considered in section 3.2 is estimated as follows:

Ultimate reserves projections for existing acreage are set at the 3P + 2C level

Annual maximum growth is based on recent actual growth

2P growth projections are varied up to maximum growth depending upon reserves available for new domestic contracts.

Projected gross (prior to production) 2P reserves at maximum annual growth rates are illustrated in Figure 15 – these represent the maximum that could be developed from known resources, including some shale gas in the Cooper Basin, and do not factor in restrictions on CSG development in NSW. This figure also shows the reserves that are committed to Base Case export projects and existing domestic contracts, with the remainder available for new domestic contracts. The reserves committed include a safety margin which is assumed to reduce after the LNG plants start up. A shortage of reserves available for the domestic market in the near-term, especially the period around 2014, is apparent. Most of the reserves available up to 2015-16 are in the Gippsland Basin potentially causing high transmission costs if supplied to distant markets.




Figure 15 Base case reserves availability for new domestic contracts

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3.5.3 Domestic supply requirementsDomestic supply contracts are defined as those contracted by producers to parties other than exporters, such as retailers and end users. The domestic gas market is adequately contracted until 2015 in eastern Australia as a whole (Figure 16). Approximately 4,300 PJ is contracted from 2013 to 2020, 76% of Base Case domestic demand over that period. Given that prices under these contracts are unlikely to escalate significantly, as most gas price reviews are largely backward looking; this would appear to offer some price protection to most end users until 2016.

It is noted however that the majority of contracts are held by the three major retailers, AGL, Origin Energy and Energy Australia and are not fully allocated to domestic end users, i.e. they buy long and sell short, so there is a possibility of some “domestic” contract gas being diverted to exports (refer to section 3.5.2.1), resulting in earlier recontracting at a higher price for the domestic market.

Figure 16 also illustrates our estimates of the volumes contracted to end users, both directly by producers and indirectly by retailers, assuming that most of the latter contracts end by mid-2014. The amount contracted directly to end users from 2013 to 2020 is estimated to be 2,000 PJ, 37% of Base Case domestic demand over that period. Clearly end-users need to recontract several years earlier than retailers and the potential implications of this for retail prices are discussed in section 4.3.




Figure 16 Domestic demand vs existing contracts

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3.6 Recent contracts and pricesNew gas supply availability in Queensland, and indeed across eastern Australia as a whole, is strongly influenced by the targeted export of significant volumes of LNG from Gladstone starting next year. Consistent with Figure 15 potential domestic contract purchasers reported from 20119, when the first project became fully committed, that it was difficult to secure terms sheets for new contracts from gas producers – even those producers who were not directly associated with LNG exports evidently hoped to sell gas for export, at a price well above the historical domestic price, to those such as GLNG whose reserves were below their full two-train requirements.

3.6.1 LNG Third partyWhile the LNG projects will source most gas from their associated producers there are also four third party contracts between suppliers and LNG projects, all of which have been entered at prices linked to oil prices:

1. Santos (and various JV partners) is to supply GLNG with 750 PJ primarily from the Cooper Basin, at 50 PJ pa over 15 years from 2015, delivered at Wallumbilla.

2. APLNG is to supply QCLNG with 640 PJ from jointly owned tenements ATP 648P and 620P in the Surat Basin. The delivery profile is skewed towards start-up, with 190 PJ over the first two years followed by 25 PJ per year for eighteen years.

3. AGL is to supply QCLNG with 60-70 PJ over 3 years from LNG start up in 2014. The gas is a re-sale of Surat Basin gas purchased from QCLNG for AGL’s domestic portfolio.

4. Origin will sell 365 PJ over 10 years to GLNG from its domestic portfolio and uncontracted reserves outside the APLNG JV. Public statements do not state where this gas will be sourced other than it will be from Origin’s “legacy” portfolio of contracts and uncontracted reserves, which we assume means conventional gas rather than CSG. As Origin has very limited uncontracted reserves this means that supply will be diverted from domestic contracts and/or met from development of new resources.

9 Refer to the 2011 and 2012 Gas Market Reviews, available from www.energy.qld.gov.au



http://www.energy.qld.gov.au/


5. Santos and APLNG have agreed to swap gas produced at the Fairview and Combabula fields. APLNG gas at Fairview will be delivered to Santos and vice versa at Combabula.

6. GLNG and QCLNG have agreed to an operational gas sharing arrangement to be facilitated by two interconnections between their pipelines. GLNG and APLNG have entered a similar agreement.

The existence of the third and fourth arrangements highlights the fact that some of the “domestic” contract volumes identified above have been resold to LNG projects.

3.6.2 Upstream domesticTight domestic supply is expected to prevail until at least 2017, by which time the three LNG projects under construction will be operating. The position beyond 2017 will depend primarily upon whether the Arrow Energy LNG or other LNG projects proceed or not and the rate of development of additional gas reserves, including shale gas.

A growing number of domestic buyers have recently secured new wholesale gas supply contracts, however the prices reflect market tightness and are considerably higher than prices typical of contracts entered before 2010 (Table 6). Most of the new contracts also link the gas price to oil prices, which is a feature of the LNG export market. This higher price level is expected to continue at least until 2017 and possibly beyond if additional reserves are more costly to develop.

It is noted that the two most recent contracts were announced after the analysis in this report was completed and have not been taken into account in Figure 16.

Table 6 Recent domestic gas supply contractsBuyer Seller Date

EnteredInitial Wellhead Price

Annual Volume

Term Indexation

Xstrata AGL Nov 11 $6/GJ 13 PJ 2013-2023 CPIMMG Origin Dec 11 $6/GJ 3 PJ 2013-2019 Rising to $9/GJUnknown Santos Feb 13 Towards $9/GJ Low 2015-2018 UnknownOrigin Beach

PetroleumApril 13 $6-9/GJ 17 PJ 2015-2022 Oil price linked

Lumo BHPB-Esso May 13 Unknown 7 PJ 2016-2018 Oil price linkedOrigin BHPB-Esso Sep 13 $5-7/GJ 48 PJ

Ave2014-2022 Oil price linked

Orica BHPB-Esso Nov 13 $5-6/GJ 14 PJ 2017-2019 Oil price linkedSource: Media releases

3.6.3 RetailThe upstream contracts listed in the above table represent a small percentage of the total eastern Australian market and several do not start until 2015 or later. The average upstream contract price is therefore expected to remain reasonably steady through 2013 and 2014 and rise through 2015 to 2020 (refer to SKM’s actual projections in Figure 27 and Figure 28) so upstream prices do not appear to provide any reason for retail prices to rise significantly in the short-term.

Nevertheless there is now evidence that retail contract prices paid by business gas users are likely to rise in parallel with new upstream contract prices. In July 2013 the Australian Industry Group released the results of a survey of businesses in eastern Australia, with a majority in Victoria, covering prices they were




being offered for new gas contracts10. Based on the substantial number of survey respondents (61), SKM infers that the majority of businesses were seeking contracts with retailers rather than upstream contracts.

The majority of respondents were at the time of the survey seeking new contracts but:

10% were not getting any offers

32% were not getting “serious” offers

26% received an offer from only one supplier

32% had offers from more than one supplier

The average price offered to businesses seeking contracts for two years or less and starting in 2013 was $5.12/GJ whereas the average offered to all others was $8.72/GJ. We assume these exclude network costs and the carbon price. Clearly retailers intend to push retail prices up in advance of rises in the average upstream contract price, as if they had sold all their contracted gas to export projects and had to re-contract at higher prices, as discussed above.

Whether retailers sell their existing contract gas to export projects or to the retail market at an increased price, they will generate windfall profits from 2014 to approximately 2017, after which the windfall will transfer to gas producers.

3.7 Demand-supply and pricing methodologyThe demand-supply balance and price projections for this study have been derived using SKM’s proprietary model MMAGas (Market Model Australia – Gas) which replicates the essential features of Australian wholesale gas markets:

A limited number of gas producers, with opportunities to exercise market power

Dominance of long term contracting and limited short term trading

A developing network of regulated and competitive transmission pipelines

Domestic demand driven by gas-fired generation and large industrial projects.

Strong influence of LNG exports on supply availability for the domestic market.

MMAGas has been developed over a period of ten years, to provide realistic assessments of long term outcomes in the Australian gas market, including gas pricing and quantities produced and transported to each regional market including LNG:

The “gas market” in MMAGas is the market for medium to long-term contracts between producers and buyers such as retailers or generators

MMAGas combines information on gas demand and committed contracts to estimate the demand for new contracts as described above

The PJ/yr capacity of each producer to supply new contracts from its available uncontracted 2P reserves is based simply on reserves available divided by contract term

Allocation of new GSAs in each market zone to gas producers is based on the assumption that each producer seeks to control its volumes and prices to maximise its profit (revenue less cost of production) subject to constraints imposed by its competitors and its capacity to produce

10 Energy Shock the gas crunch is here. Australian Industry Group. July 2013.




This competition between producers is represented as a Nash-Cournot game with the role of buyers replicated by modelling the activities of an arbitrage agent. Transmission costs are treated as production cost inputs, so the profit in each market zone is the volume times delivered price less delivered cost.

A gas producer in MMAGas is generally a joint venture controlling major resources, such as the Cooper Basin JV (Santos, Beach and Origin Energy). Some resources effectively controlled by a JV but not part of it are added to the JV’s resources, such as the Kipper field in Gippsland, part owned by Santos, which is outside the BHPB-Exxon JV. Others however are not, for example the part of the Fairview field not owned by GLNG is not considered as part of the GLNG JV’s reserves.

Gas producers, i.e. the JVs, are assumed to make joint sales and to compete fully with other JVs, even when the JVs have some common ownership. This may overstate the level of competition, however in practice this is offset by additional competition created by separate selling within some JVs.

MMAGas outputs have been benchmarked against gas production and transmission flows reported by AEMO on the “Bulletin Board” and against new GSA prices wherever such information becomes available. Model parameters for the current implementation have been estimated so that its outputs replicate negotiated contract price and volume outcomes over the past seven years. It is noted that historical contract prices have covered a narrow range relative to potential future prices and MMA recognises that, as with all approaches to projection, MMAGas ability to accurately project results outside of its development data range is not guaranteed. The projections made under any specific set of assumptions should not be regarded as absolutely precise, even though they are expressed as a single set of numbers.

One of the most critical assumptions in MMAGas is that negotiations for new contracts take place four years before the contracts start, to enable new capacity to supply contracts to be constructed. This is consistent with market behaviour to date, ensures that all uncontracted reserves can be considered for new contracts and thereby leads to the lowest prices consistent with the concentration of reserve ownership. The availability of reserves for new domestic contracts is affected by LNG project reserves requirements as described in section 3.2.

The current implementation of MMAGas represents the eastern states market as up to twenty separate producers competing in nine separate domestic market zones plus one LNG export zone.

3.7.1 LNG contract demand function The influence of LNG prices on domestic prices is specified via the LNG contract function, which specifies the value available to producers from supplying LNG projects. Gas supplied from the projects’ own reserves are considered pre-contracted and only the incremental project requirements are competed for (where project JV reserves are insufficient), such as the contracts supplied by Santos and Origin to GLNG.

The LNG demand function assumes that gas producers and liquefaction owners share in the LNG netback value at Gladstone, or at the gas field, depending on the point of sale. The netback value is the delivered price of LNG less the costs of liquefaction and shipping. Netback value can be calculated using short or long-run costs – as the impact being estimated in this study is that on long-term domestic gas contracts, long-run marginal costs are appropriate. Netback value will also vary between LNG projects, however as we are unable to differentiate between the costs/revenue of the various projects, a single value is used in this study.

The delivered price of LNG depends primarily on the price of crude oil (using the Japan Customs-cleared Crude (JCC) measure, also known as the Japan Crude Cocktail) and the $US/$A conversion rate, and secondarily on the link between LNG prices in $US/mmbtu and the JCC price in $US/bbl. For this study we have used a direct linkage without a cap or floor, namely LNG Price = 0.15 * JCC price. This formula is believed to apply to GLNG contracts11 and implies that at $US100/bbl oil, the LNG price is $US15/mmbtu.

11 GLNG Project FID, 13 January 2011, and Santos Investor Presentation, March 2011, both available at www. Santos.com




For oil price scenarios we refer to the Energy Information Administration “Annual Energy Outlook 2013” and use the average values up to 2020 for their Low, Reference and High scenarios.

Based on recent estimates12, including escalation, SKM estimates that liquefaction plus shipping costs are approximately $US6.85/mmbtu for brownfield projects (additional trains at existing projects, which is the most likely basis of expansion). The resulting netback values for three scenarios are shown in Table 7.

Table 7 LNG Netback values at Gladstone Low Scenario Medium Scenario High scenario

JCC price ($US/bbl) $75.00 $105.00 $140.00

LNG delivered value ($US/mmbtu) $11.25 $15.75 $21.00

Exchange rate ($US/$A) $0.80 $0.90 $1.00

LNG delivered value ($A/GJ) $13.33 $16.59 $19.91

LNG Netback value ($A/GJ) $6.48 $9.74 $13.06

For the purposes of constructing the LNG demand function it is assumed that the purchaser will not be prepared to pay more than the netback value at Gladstone for gas delivered to Gladstone, because a higher price would render the LNG project uneconomic, i.e. effectively demand for LNG contracts is zero at delivered prices above netback. It is also assumed that GSA sellers will be unwilling to sell at a price below their cost of production plus transmission to Gladstone, which for typical CSG producers would be in the range $4/GJ to $5/GJ. A value of $4.65/GJ is assumed in all modelling. The LNG demand function used in the Nash-Cournot model assumes that forecast demand is met at a price mid-way between these extremes, as illustrated in Figure 17.

12 Extending the LNG Boom: Improving Australian LNG Productivity & Competitiveness, McKinsey & Co, May 2013.




Figure 17 LNG contract demand functions

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Refer to text for explanation

3.7.2 Further assumptionsA further key assumption in regard to modelling the demand-supply balance and future prices of gas in eastern Australia is the number of competing gas producers and the gas resources available to them. The number of producers competing in the eastern Australian gas market is currently modelled as the 18 joint ventures represented in Table 2 and Table 3. It is noted that up to now transmission costs have presented a barrier to producers competing in all nine zonal markets, however higher gas prices may enable low cost producers to compete in all markets.

Future reserve additions and changes in uncontracted reserves of the producers are projected using MMAGas. MMAGas can also accommodate changes in industry structure such as gas reserve additions in new provinces, market entry by new producers and reductions in the number of producers due to mergers or takeovers. However these changes are not calculated within the model but must be input as data – our base case assumption is that the number of producers remains static and only their resources and costs change.

The modelling assumes that all producers with uncontracted reserves who are not engaged in building reserves for export will compete to sell to the domestic market. In view of the difficulties currently being experienced by domestic buyers in engaging producers in discussions about long-term domestic gas contracting it is legitimate to question when producer interest in the domestic market will return. In the Low and Medium scenarios this would most likely be no later than 2014 to 2015 by which time the LNG opportunity would be seen to be diminishing and uncontracted reserves would start to build. In the High Scenario it could be later, in which case more restricted competition could lead to higher prices than projected in the following sections.




4. ProjectionsIn this study we recognise the possibility that some gas from existing domestic contracts could be diverted to supply export projects, thereby accelerating the need for new domestic contracts.

As our modelling is not at this stage adapted to large scale contract diversion, we have captured this in two extremes: one in which there is no diversion; and one in which all contract gas that is not already contracted to end-users is available for diversion. The following two sections present the demand-supply-price outcomes for each of the three LNG scenarios under each of these assumptions about contract diversion.

As noted in section 3.5.2.1, the second alternative is equivalent to 2,300 PJ of domestic contract gas being available for diversion to exports. This is possibly more than the export projects will need and the actual outcome is likely to be in between the extremes. Nevertheless, as discussed in section 3.6.3, there are signs that retail pricing will be as if the second alternative was occurring.

4.1 No contract diversion to exports

4.1.1 Economic demand-supply balance Gas supplied for LNG in the Base, Low and High LNG cases is illustrated in Figure 18 to Figure 20.

Figure 18 Projected gas supply LNG, Base Case

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Figure 19 Projected gas supply LNG, Low Case

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Figure 20 Projected gas supply LNG, High Case

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While most of the LNG supply is from Queensland CSG, the most critical differences between the cases are in the volumes from other sources. The Base Case includes Cooper Basin supply already contracted plus Gippsland supply at about 50 PJpa via swaps or backhaul and very small volumes of NSW CSG. In the Low case only the Cooper supply is present but in the High case all three are present in larger quantities, including Cooper Basin shale which becomes economic in this case.




Eastern Australian domestic gas supply has increasingly been sourced from Queensland CSG (Figure 2) but in the Base Case supply from this source is essentially flat owing to its role in LNG supply (Figure 21). Supplies from NSW CSG and the Cooper Basin are projected to increase despite regulatory concerns, while supplies from the Otway and Gippsland Basins are projected to decrease. The Otway Basin decline is due to limited resources whereas the Gippsland decline is due to projected commitment of 50 PJ/yr to export.

In the Low LNG/Low Price case (Figure 22) greater availability of Queensland CSG (due to the Arrow LNG project not proceeding) and Gippsland gas (none is exported) reduces the demand for NSW CSG and Cooper gas.

In the High LNG/High Price case (Figure 23) lower availability of Queensland CSG and Gippsland gas (more exported) and constraints on supply of NSW CSG and Cooper gas lead to persistent high prices and demand being reduced to below the initial level forecast.

Figure 21 Projected gas supply, eastern Australia domestic Base Case

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Figure 22 Projected gas supply, eastern Australia domestic Low LNG/Price

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Figure 23 Projected gas supply, eastern Australia domestic High LNG/Price

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4.1.2 Upstream gas price projectionsGas price projections for eastern Australia as a whole and Queensland and Southern Australia separately are presented in Figure 24 to Figure 29. All prices are weighted averages for gas delivered to zonal hubs




(i.e. including transmission costs) and are expressed in real $2013 terms. Two prices are presented for each point:

The estimated price of new 15-year gas contracts starting in a particular year (Figure 24 to Figure 26).

The estimated average price over all gas contracts delivering gas in any year (Figure 27 to Figure 29).

At all delivery points new contract prices are expected to rise to 2017, most sharply in the High LNG case, where it reaches over $10/GJ. The prices fall after LNG growth either stops (2017 in the Low LNG case and 2019 in the Base Case) or slows (2019 in the High LNG Case) and more of the gas reserve growth becomes available for domestic supply. The new contract price patterns are reasonably similar in Queensland and the Southern States, with a slightly quicker rise in Queensland.

Average contract prices reflect the progressive addition of new contracts to the aggregate contract portfolio, at higher prices. Longer contracts in southern states defer significant price rises until 2017 reflecting the substantial recontracting that occurs in that year.

It is noted that retailers are typically paying the average contract price and it might be thought that retail price rises would be delayed until 2016 or 2017. However the AIG report discussed in section 3.6.3 suggests that retail prices will rise from 2014 and the possible mechanism for this is presented in the following section.




Figure 24 New upstream contract prices for eastern Australia ($/GJ, $2013 real)

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Figure 25 New upstream contract prices for Queensland ($/GJ, $2013 real)

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Figure 26 New upstream contract prices for southern states ($/GJ, $2013 real)

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Figure 27 Average upstream contract prices for eastern Australia ($/GJ, $2013 real)

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Figure 28 Average upstream contract prices for Queensland ($/GJ, $2013 real)

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Figure 29 Average upstream contract prices for southern states ($/GJ, $2013 real)

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4.2 High contract diversion to exportsIn this set of analyses the modelling is executed as if 2,300 PJ of gas in domestic contacts that is not already committed to end users is passed back into the hands of producers to be sold at current market prices to exports or the domestic market.

4.2.1 Economic demand-supply balance The LNG supply pattern in the Base Case is quite similar to the No Diversion case, with more Queensland and NSW CSG and less Gippsland gas because it is less competitive.

Figure 30 Projected gas supply LNG, High Diversion Base Case

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The domestic supply differs from the No Diversion case in many ways however:

The total volume is reduced in the short-medium term because of the higher price compared to the No Diversion case (see next section).

CSG and Cooper volumes are substantially reduced

Otway volumes are initially reduced but are higher after 2020

Gippsland volumes are higher almost throughout




Figure 31 Projected gas supply eastern Australia domestic, High Diversion Base Case

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4.2.2 Upstream gas price projectionsFigure 32 and Figure 33 below present the corresponding High Diversion price outcomes. As may be expected with high contract diversion, domestic prices for both new contracts and average contracts are very similar to the No Diversion prices in pattern but rise and fall 3 to 4 years earlier. The upturn in prices after 2027 is due to earlier exposure of domestic buyers to production of costlier resources than without diversion of contracts.

A feature of these projections is that because existing contracts are assumed to have been shortened, the new contract and average contract prices rise in parallel through 2014 and 2015, though the new contract prices reach a higher peak before falling back to the average price level.




Figure 32 High contract diversion - new upstream contract prices for eastern Australia ($/GJ, $2013 real)

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Figure 33 High contract diversion - average upstream contract prices for eastern Australia ($/GJ, $2013 real)

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4.3 Wholesale prices in retail contractsAs discussed in section 3.6.3, it appears that retailers may be intent on increasing the wholesale component of retail prices as if existing contracts were diverted to exports, regardless of whether they are or not, rather than giving retail customers the benefit of continuing low average contract prices. The AIG report suggests that the retail market is sufficiently short of gas for this to occur.

Given the shorter duration of retail contracts we believe it is most likely that the wholesale component of retail prices will be closer to the new contract prices rather than average contract prices, though in this situation the differences are limited. Wholesale prices on average will therefore be similar to those depicted in Figure 32, which shows that for contracts starting in 2014 the predicted wholesale prices have a range from Low to High of $7/GJ to $9/GJ, which covers the $8.72/GJ figure reported by AIG. The predicted range is $7.50/GJ to $10.50/GJ in 2015, after which it falls, stabilising at $6.30/GJ to $8.90/GJ after 2018.




Appendix A. Terms of Reference - Study on the eastern Australian Domestic Gas Market

Background

Australian gas markets are undergoing a significant period of development. In particular, the eastern Australian gas market is undergoing a period of substantial transformation, with the development of Coal Seam Gas (CSG) and the associated creation of an east coast Liquefied Natural Gas (LNG) export industry.

Once the LNG plants come into operation (expected from 2014) there will be a massive increase in demand for gas in the eastern Australian market, with total demand forecast to rise from 697 petajoules per annum (PJ/a) in 2012 to 1,395 PJ/a in 2015 and 2,386 PJ/a in 2020 (Gas Statement of Opportunities 2012). The Commonwealth’s National Energy Security Assessment and follow up consultation with industry indicated that this increase in demand could lead to a period of tightening between the demand for and the supply of gas from around 2015.

While the LNG industry is helping to expand Australia’s gas market by bringing on new gas supplies and greater pipeline infrastructure, the timing of these activities and the increasing exposure to international markets is creating considerable uncertainty in relation to the availability and cost of domestic gas. Specific uncertainties include the extent, duration and significance of any potential tightness in gas supply in the eastern market in the critical period between 2015 and 2020 and how any tightness will manifest itself, in particular the degree of contracting risk faced by consumers.

Current information on the gas market is limited, with information gaps around forecast domestic supply of gas, particularly given the commercial sensitivities. Some major industrial users of gas have reported they are unable to secure domestic gas supply contracts during this period at any price. Others are reporting being offered short term contracts at much higher prices than existing contracts. While many gas producers are reporting that they are willing to sign gas contracts but it is a question of price and term. There is also limited information about the relationship between international and domestic supply conditions and pricing and how this interaction will play out over time.

This Study will help address this information asymmetry and inform Government’s decision making with respect to effective resource management and development of both the domestic and LNG market. Specifically, the Study aims to provide analysis of the expected gas demand-supply situation and identify potential constraints on domestic supply availability over the period 2015-2020 and its consequences for the price of gas. International linkages will also be considered.

Gas Market Study Objective

The Study will be a joint project between the Department of Resources, Energy and Tourism and the Bureau of Resource and Energy Economics. The objective of the Study is to produce a comprehensive report on Australia’s gas markets, the state of play and barriers to domestic gas supply, focusing on eastern Australia but including analysis of the operation of the West Australian gas market. It is intended to provide a comprehensive view of the level of activity and competitive structure within the domestic supply industry covering tenement holders, upstream producers, pipeline owners/managers and shippers. It will also seek to estimate the current level of demand, price for gas and volumes of both short and long-term gas contracts. Importantly, it will also explicitly consider linkages between these domestic gas market variables and international markets and thereby facilitate exploration of the impact on the domestic gas market of alternative international market scenarios.

The Study will utilise a scenario approach to identifying market trends over the period 2013-2023, to provide a clear picture of the demand-supply situation in the eastern Australian gas market over the 10 year period with a particular emphasis on the period of 2015-2020.




In addition, the Study will seek to identify the potential constraints on domestic supply availability. This may include physical barriers (eg pipeline constraints) or non-physical (eg regulatory barriers) and the implications of competition with international gas demand and supply. An array of potential policy responses to mitigate any identified constraints and options to assist in improving the market dynamics to respond to emerging price signals will also be considered.

Study Scope

Building on an understanding of the developments in Australia’s gas markets over the previous two decades, the Study will include scenarios over the time period 2013-2023 drawing on the following data:

gas reserves;

gas production rates;

gas market demand (including but not limited to short and long-term gas contracts);

pipeline capacity;

wholesale and retail gas market prices; and

state and federal government regulatory and policy settings regarding gas field developments.

As the supply and demand dynamics of the eastern gas market are interlinked with the export LNG market, the Study and scenarios will consider market trends for the international gas market, especially in the Asia-Pacific region.

The scenario-based Study will also need to account for the following market conditions:

general macroeconomic environment;

LNG project developments;

conventional, shale, tight and CSG gas development and production rates; and

gas market infrastructure developments.

Stakeholders and Consultation

It is proposed an industry reference group be set up comprising relevant stakeholders, particularly gas users and producers, to put their views, experience and expectations about the development of Australia’s gas markets forward. Other Commonwealth agencies and state and territories governments will be kept informed throughout the project’s development.

Timing

The project is expected to commence mid 2013 with a final report to be completed by the end of 2013. The report would be made public by the Minister for Resources and Energy in consultation with the Prime Minister.




Appendix B. Gas resources/reserves classification13

B.1 Natural gasNatural gas is a blend of hydrocarbons, principally methane, and inert gases found in sandstone, carbonate and shale reservoirs and in coal seams, at depth in the earth’s crust. Gas is frequently categorised as conventional (sandstone and carbonate reservoirs with good porosity and permeability and therefore free flowing) or unconventional (low permeability reservoirs or tight gas, shale gas and coal seam gas or CSG and needing additional stimulation to flow to the surface in commercial quantities14). In Australia CSG is currently the dominant unconventional gas though shale gas commenced production in 2012. There is now general acceptance of the concept that conventional gas originated in unconventional accumulations, as illustrated in Figure 34.

Figure 34 Schematic showing gas accumulation types

From a discovery and production perspective conventional and unconventional gases are different – a single well can discover or confirm a large conventional field but unconventional fields are more extensive and need to be tested at regular intervals. Downstream of the processing plant gate however, in transmission, distribution and end-use, there is little distinction other than small differences in heating value and the two are virtually interchangeable.

Liquid hydrocarbons such as oil and condensates are found in the same types of reservoirs as natural gas, sometimes in association in the same reservoir - the term petroleum is used to cover all naturally occurring

13 This section is based substantially upon section 1.1 of “Petroleum Resource Management System” published by the Society of Petroleum Engineers, the American Association of Petroleum Geologists, the World Petroleum Council and the Society of Petroleum Evaluation Engineers, 2007.

14 Also known as coal seam methane (CSM) and coal bed methane (CBM). CSG, CSM and CBM are terms used for gas recovered by drilling into coal seams from the surface. The term coal mine methane (CMM) is generally used to refer to gas recovered from coal seams in association with coal mining.




mixtures of hydrocarbons in the gaseous, liquid, or solid phase. This has had a very material impact on gas discovery as much conventional gas has been discovered in the search for more valuable oil. However there are no liquid hydrocarbons with CSG and all CSG is found by deliberately searching for coal seams from which it can be extracted economically.

B.2 The exploration and production sectorExploration and production (E&P) sector participants seek to discover, market and produce hydrocarbons. Apart from some involved solely with CSG, most are multi-product firms and many sector decisions are based upon multi-product considerations. Many of the products, including natural gas, are sold into both domestic and export markets.

Petroleum results from geological processes and is found in underground reservoirs or coal seams at depths ranging from several hundred metres for the latter up to several thousand metres for the former. Rights to underground resources vest in the relevant jurisdictional government, or the Commonwealth where they are in Australian territorial waters.

The jurisdictions generate or collect pre-competitive geological information regarding potential petroleum resources and regularly call for bids from participants for permits to explore defined exploration lease areas. Permits are awarded on the basis of participant commitments to explore by means of seismic surveys and by drilling wells. A hydrocarbon discovery may be converted into either a production lease, if development is to proceed immediately, or a retention lease15, if production is not at that time commercially viable but is expected to become so within 15 years. Retention leases are granted for periods of 5 years, after which they can be renewed, and authorities can require lessees to re-evaluate the commercial viability of petroleum production in a lease area once during the term of a lease. Permits that are unsuccessful are relinquished and may be retendered.

The above aspects of offshore E&P are governed by the Petroleum (Submerged Lands) Act (PSLA, Commonwealth), with similar jurisdictional legislation governing onshore E&P. National policy is determined by the Ministerial Council on Mineral and Petroleum Resources (MCMPR). Resource extraction in Australia is generally subject to royalty payments in addition to income tax – offshore petroleum resources are subject to the Petroleum Resources Rent Tax (PRRT) and onshore resources are subject to both jurisdictional royalty regimes and PRRT - royalty payments are deductible expenses under the onshore PRRT.

Producers market gas domestically to buyers such as retailers, generators and large industrial users. The structure of these transactions is determined by the participants, with almost all being long-term arrangements that lock-in prices and quantities with limited flexibility for a number of years.

Once petroleum has been discovered, the scale and quality of the resource must be estimated. Resource evaluations focus on those quantities that can potentially be recovered and marketed by commercial projects. A petroleum resources management system provides a consistent approach to estimating petroleum quantities, evaluating development projects, and presenting results within a comprehensive classification framework.

The Society of Petroleum Engineers (SPE) resources classification system evolved out of international efforts to standardize the definitions of petroleum resources and how they are estimated. The system is now in common use internationally within the petroleum industry.

The estimation of petroleum resource quantities involves the interpretation of volumes and values that have an inherent degree of uncertainty. Interpretation considers both technical and commercial factors that impact the project’s economic feasibility, its productive life and its related cash flows.

The term “resources” is intended to encompass all quantities of petroleum naturally occurring on or within the Earth’s crust, discovered and undiscovered (recoverable and unrecoverable), plus those quantities already

15 Queensland does not have separate retention leases. Retention is managed under the Authority to Prospect (a potential commercial area). However, the concepts of retention are the same as other States.




produced. Further, it includes all types of petroleum whether currently considered “conventional” or “unconventional.”

Figure 35 is a graphical representation of the SPE/WPC/AAPG/SPEE resources classification system. The system defines the major recoverable resources classes: Production; Reserves; Contingent Resources; and Prospective Resources, as well as Unrecoverable petroleum.

Figure 35 SPE/WPC/AAPG/SPEE resources classification system

The “Range of Uncertainty” reflects a range of estimated quantities potentially recoverable from an accumulation by a project, while the vertical axis represents the “Chance of Commerciality”, that is, the chance that the project that will be developed and reach commercial producing status.

Resources and reserves estimates for newly discovered fields are based on the geological and geophysical information gathered during the discovery process, combined with engineering and economic factors relating to commerciality. For fields in production, reserves are re-estimated using production data. While there are some variations in approach, there are generally accepted methods of estimating discovered resources. The undiscovered resource potential of a region is a quantitative assessment of the potential to discover a stated level of new reserves if (further) exploration were to take place in the region. In contrast to assessment of discovered resources, there are no universally accepted methods of assessing undiscovered resource potential.

From a commercial perspective the 2P reserve category is crucial, because it is generally the level of reserve security required to underwrite long-term gas sales contracts that provide sales volume and revenue security for reserve developments. For this reason 2P reserves estimates receive more scrutiny than other figures and 2P data is more readily available than data for other classifications.



Gas resources/reserves classification

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