Suppose a monopolist at one level does not integrate vertically. He will
charge the monopoly price to his customers, and that toll will be passed
on to the ultimate consumers. What has already been said shows that the
gaining of a second monopoly vertically related to the first would not alter
price, output or the allocation of productive resources on the second level
monopolized. Therefore, dissolving the vertical integration accomplished
precisely nothing.
Robert H Bork (1954).
‘Accomplishing precisely nothing’:
Requiring joint venture producers to
market their gas separately
A Supplementary submission to the
Energy Market Review
Prepared by Lateral Economics on behalf of ExxonMobil
Gas Marketing
September 2002
i
Table of Contents
Executive Summary
The competitiveness of the market
Scarcity rents and the depletion of natural resources
Would requiring separate marketing of jointly produced gas generate benefits?
The potential costs of mandating separate marketing
iii
iii
v
v
vi
1
1
3
3
Introduction
Is upstream competition weak?
Would requiring separate marketing of jointly produced gas generate benefits?
2
The Australian gas market: Supply, demand and
the competitiveness of the market
The Australian gas market
The South Eastern Australian gas market
Deeper and more liquid markets
6
6
10
13
3
19
The economics of gas discovery and production
4
The Economics of project supply
Why gases are different?
The institutions of deep markets are self organising systems
19
20
20
5
Risking, financing, co-ordinating and sharing production
Joint ventures are a critical means of sharing risk
Risk and the management and optimal depletion of mature fields
Balancing agreements
Water driven fields are harder to balance
22
23
23
26
28
6
The economics of depletable resources
Overview of the economics of the exploitation of depletable
(non-renewable or exhaustible) resources
The implications of different market structures
30
The issue of separate marketing of gas
Opportunities to refute the IC’s approach have not been taken
34
37
7
8
Conclusion
30
31
38
References
40
Appendix One: Derivation of optimal depletion paths for a depletable resource
42
Appendix Two: Some observations about price discrimination
Price discrimination and separate marketing
46
48
Disclaimer
60
ii
Executive Summary
This supplementary submission is provided by Lateral Economics on behalf of
ExxonMobil Gas Marketing. It addresses the question of the marketing of gas
by equity owners of joint venture producers (JVPs). Some gas consumers and
competition regulators have demonstrated some unease with the choice that
co-venturers in petroleum production joint ventures in Australia have made to
jointly market (JM) their gas rather than to market separately (SM).
They claim firstly, that upstream competition is weak in South Eastern Australia.
Secondly, although they appreciate that forcing SM before a market is
sufficiently deep and liquid can add costs and jeopardise new development,
they nevertheless continually suggest that there are benefits in ‘constraining’
co-venturers of mature JVPs to market separately.
This submission takes issue with both claims – though it does so in different
ways. It argues that competition in the South East Australian upstream gas
market has intensified markedly in the last few years and will continue to do so
and that this should form the backdrop against which the difficult trade-offs and
judgements which must be made by competition regulators should be made.
This submission’s second claim about separate marketing of jointly produced
gas is a quite a different kind of argument. It is essentially a logical rather than
an empirical argument. The submission argues that even if the co-venturer in a
JVP enjoyed an unreasonable degree of market power, at best requiring them
to market their gas separately would achieve ‘precisely nothing’. It would do
nothing to reduce whatever market power the JVP had. But requiring separate
marketing would add to costs. The extent to which this would result in a
contraction of production and increase in prices is an open question and would
depend on how the constraint was imposed, and the technical facts of specific
cases. In suggesting that genuinely separate marketing could generate
substantial losses the argument again becomes an empirical one.
The competitiveness of the market
One measure of the competitiveness of the market for natural gas is the extent
to which gas has and is expected to continue to displace other energy sources,
both as a direct energy input and as an input into electricity generation. The
evidence is that:

there has been substantial exploration and development of gas fields;

gas production has grown strongly over the last 20 to 30 years;
iii

gas consumption within Australia has grown strongly over the same
period;

gas has effectively displaced substantial volumes of other energy
inputs and this is expected to continue, and

upstream gas markets are becoming increasingly competitive with
increasing integration of producing regions and markets
Considering these facts and quite apart from more theoretical arguments, it is
difficult to sustain an argument that there has been any substantial impairment
of the operation of the market resulting from JVPs marketing jointly rather than
separately.
Further, the examples used by the proponents of separate marketing tend to
confuse cause and effect. Because, other things being equal, co-venturers in
JVPs prefer to market their take-off separately they do so where markets are
sufficiently deep. As a rule co-venturers in JVPs the world over separately
market those products which can be brought readily to market – the oil and gas
liquids from their JVPs. And where gas markets are deep enough, JVPs also
prefer to market their gas separately – as demonstrated in the United States
market.
Providing sources of demand and supply are substantial and various enough,
and policy settings and physical infrastructure (pipelines) enable the
appropriate market institutions to develop, national gas markets deepen and
gain liquidity and move naturally from ‘project’ or ‘contract’ supply to ‘commodity
supply’.
The things necessary to ensure that separate marketing does not generate
more costs than benefits are those that describe a deep and liquid market.
They include:
1. Multiple buyers and sellers of gas;
2. Means of dealing with divergence between the amount the JVPs are
entitled to take from the JV in production and the amount they are able
to market successfully. These means can come from a combination of
the following:

Liberal balancing, borrowing and banking arrangements
between JV co-venturers;

Low cost means of storing gas within the JV or outside it;

A well developed and deep and liquid ‘spot market’ into which
surplus gas can be sold at not too great a discount.
iv
A deep and liquid market enables producers to rely on the fact that there are
always many consumers available and so if it is produced, gas can be sold.
Though producers and consumers may choose to write long-term take or pay
contracts with each other, they are also aided by a deep and liquid ‘spot market’
into which surplus gas can be sold and from which it can be purchased in the
short-term. The spot market is also useful as a signal to producers and
consumers of gas of the balance between demand and supply in the market.
The differences between the Australian market and those markets to which it is
being compared are manifest. In contrast to the producers in Australia, the
American market is hugely competitive in production. Thus of all the gas
produced by the top twenty producers, only one producer has a share of over
12% - BP at 15.2%. There are many small and very small producers such that
the market share of the top twenty producers is just 58%. The share of the top
50 producers is still below 75%!
Most of the largest gains from deeper, more competitive and liquid markets are
being made in Australia, but realism should temper expectations. Limited by the
size of its population, Australia will never have a spot market in gas of the depth
and liquidity of the spot market in the United States.
Scarcity rents and the depletion of natural resources
There are two aspects to the scarcity rents available to producers of natural
resources. Firstly, rents accrue to depletable resources on account of their
depletability. Secondly, those resources can be developed in a more or a less
competitive way. After resources have been discovered, it is of course possible
to lower their price in the short term by diluting the property rights of their
owners. This is no surprise – just as it would be no surprise if the cost of
certain drugs fell if their owner’s patents were diluted in some way.
Yet ownership of the resource rights along with the right to develop it at a rate
that generates acceptable returns for the owner is the reward which was the
incentive for the owner to explore and develop its exploration and production
leases in the first place.
Would requiring separate marketing of jointly produced gas generate
benefits?
For monopoly rents to be competed away, competitors must compete for each
others’ market share. Yet this cannot happen where the shares of each
marketer are already determined by joint production decisions. In principal, as
Robert Bork argues, in this kind of situation “dissolving vertical integration
accomplishe[s] precisely nothing”.
v
Nor will ‘balancing agreements’ or any other ‘borrow and bank’ arrangements
between co-venturers in JVPs facilitate the competing away of any scarcity
rents controlled by the JVP. For such arrangements require co-venturers not
only to have each other’s permission to move away from balance, but also to
make up any imbalances within a reasonable time.
The potential costs of mandating separate marketing
Requiring separate marketing is likely to accomplish a good deal more than
nothing – by adding risk and cost to an industry where the management of risk
is clearly a critical issue. Exploration, proving, development and production of a
gas field requires access to large amounts of capital and the capacity to spread
risk and to sustain this over many years. JVPs provide the means for spreading
risk and acquiring sufficient capital to underwrite exploration and development.
Development and production must be optimised and coordinated between fields
within a basin each having distinct characteristics in terms of:

the capital cost of proving up and producing;

the quality and mix of the raw hydrocarbons and other substances
produced by the field; and

the amount of gas available and the proportion expected to be
recovered.
And the resource depletion of each field – and the fields within the JVP jointly –
must be technically optimised. Uncertainty as to gas quantities and optimal
production rates remains for a substantial period of time into the production life
of the field and this is particularly so of the ‘water driven’ fields of the Gippsland
Basin. (In addition to adding to risk management tasks, such characteristics
militate against liberality in ‘balancing agreements’ between co-venturers in
JVPs.) For these reasons technical optimisation of the depletion program will
typically have substantially greater impact on the value of the resource than any
value optimisation related to scarcity rent. Wells must be depleted consistently
with customer supply requirements.
From the perspective of the overall economic efficiency of the Australian
economy, the optimal development of a gas basin involves the matching of gas
consumption needs across the market with gas production possibilities across
the basin. In a shallow market most of which remains dominated by ‘project
supply’ joint marketing is necessary to do this efficiently. Preventing it would
lead to missed opportunities to bring gas consumers and producers together. It
would accordingly lead to the development of sub-optimal fields, higher costs,
and so prices from the JVP to the separate marketers.
vi
Policy makers could hardly be congratulated on the result, in which competition
has clearly come to be seen as an end rather than a means. This, more
‘competitive’ state of affairs is likely to involve higher costs and prices – and
lower economic welfare. Ironically increasing competition in the short term
would most likely result in lower expenditures in exploration and development
in the future – ultimately strengthening the market power of incumbent
producers and entrenching higher rather than lower consumer prices.
vii
Small countries often have limited competition in their natural gas markets,
because the markets are not large enough to support efficient operation by a
large number of domestic producers or suppliers. In these countries regulators
should focus on lowering entry barriers rather than on regulating domestic
firms. If entry barriers are low, the threat of entry by … competitors can serve
as an effective check on domestic market participants. Andrej Juris (1998: 7).
1
Introduction
This supplementary submission to the Energy Market Review is provided by
Lateral Economics on behalf of ExxonMobil Gas Marketing. It addresses the
issue of joint marketing (JM) compared with separate marketing (SM) of gas by
firms which are equity holders in a joint venture production arrangement (JVP).
Of particular interest is the question of whether the individual equity holders in a
JVP should – to use the language of a representative of gas consumers – be
‘constrained’ to market gas separately.
ExxonMobil is involved in joint venture production and joint marketing of gas as
one of the Gippsland Basin co-venturers. Given that JVPs generally prefer to
market their products separately (providing markets are deep and liquid enough
to allow them the flexibility to do so), the central policy question is whether
requiring them to do so is likely to harm or help economic efficiency. Put
another way, are the incentives faced by JVPs such that they will choose to
market separately when it is best for economic efficiency, or are they such that
there is a case for policy intervention?
The Energy Market Review (EMR) Issues Paper (2002) draws attention to
questions raised in 1998 by the Upstream Issues Working Group (UIWG)
Report (1998), including marketing arrangements used by gas producers, in
particular the issue of joint or separate marketing by joint venture producers.
The EMR Issues Paper (p.22) posed the following questions:

Since the UIWG report, has the level of competition in the upstream
sector increased and what are the reasons for the change?

To what extent are the issues that UIWG reported on resolved?

What further reforms, if any, relating to the upstream sector are needed
to achieve appropriately competitive outcomes?
The central concern with joint marketing (JM) appears to be that competitive
outcomes from more open and active energy markets will be compromised by a
1
lack of effective competition resulting from a high degree of concentration in the
marketing of gas. The UIWG (1998; p.29) put it this way:
[T]he UIWG agrees with the argument that separate marketing is more
competitive than joint marketing, and the aim of policy in this area should
be to encourage the separate marketing of gas by individual participants
in a joint venture. By creating price competition between as many
suppliers of gas as possible, separate marketing should result in lower
gas prices.
Nevertheless, the UIWG had some sympathy with the view, made in several
submissions – typically reflecting producers’ views, that parts of the Australian
gas market are currently unable to support separate marketing. This is
because they tend to operate as ‘contract’ or ‘project’ markets, where gas is
only produced to meet specific long-term contractual obligations (1998; p.29).
Where joint venture production is seen as the most efficient way of
undertaking gas developments, the UIWG considers that prohibiting joint
marketing could raise the costs and/or increase the risks of entering gas
production, where separate marketing is not viable.
The ACCC appears to hold a similar view. One might say that it exhibits some
unease with JM, though it also appreciates that forcing SM before a market is
sufficiently deep and liquid can harm economic efficiency, not least by
preventing otherwise viable gas production from being commissioned (see
below). Nevertheless, on occasions the Commission and its predecessor have
acted as if requiring separate marketing of joint producers can improve the
competitiveness of markets. Thus for instance the ACCC’s predecessor
permitted CRA and North Ltd to aggregate their lead and zinc production
facilities in Pasminco providing the original owners of the merged facilities
continued to market separately.
Various submissions to the EMR, particularly from gas consumers and their
representatives have drawn attention to the importance of upstream gas
competition. For example, the Australian Gas Association (AGA) (p. 73-4)
argue that:
1. “[U]pstream … competition is weak” in Central and South Eastern
Australia and,
2. “the greater use of separate marketing of gas from jointly owned fields”
is one of a number of initiatives that would help address this situation.
2
Is upstream competition weak?
The central arguments of this submission take their cue from these two claims.
The first assertion is an important one with which we disagree. There are of
course critical benefits to consumers and to economies from having vigorous
competition between producers of commodities, not least gas. Nevertheless
judgements must still be made about both the degree of competition which is
present and immediately threatened in the marketplace and the optimal policy
responses to any shortfall in competition. As with many areas of competition
policy, judgements about the real state of the market are far from easy for
outsiders and sometimes even for industry insiders.
And even if a judgement is made that the level of competition within some part
of the market is not ideal, policy makers must still strike a difficult balance
between competing considerations. Thus some measures to ensure that there
are more competitors in the gas market could undermine the competitiveness of
energy markets more generally – for instance by increasing risk and/or limiting
gas producers’ access to economies of scale.
The next section of the submission argues that competition in the South East
Australian upstream gas market has intensified markedly in the last few years
and will continue to do so.1 It argues that the area from the Sydney region to
Adelaide in the West and Tasmania in the South is becoming dramatically more
competitive owing to new pipeline developments of the recent past and the
immediate future. However these arguments nevertheless remain ones where
judgements between reasonable people and between different parts of the
industry will continue to differ however much informed discussion might narrow
the differences.
Would requiring separate marketing of jointly produced gas generate
benefits?
It is critical to note that this submission’s second claim about separate
marketing of jointly produced gas is of quite a different kind to its argument
about the intensity of upstream competition. In the context of competition policy
it is an unusually clear-cut argument. The idea that requiring participants in
joint venture production of gas to market their gas separately can stimulate
economically beneficial competition makes intuitive sense. But is it right?
This submission argues that the enthusiasm to ‘constrain’ participants in joint
production of gas to market separately is mistaken. It is not just mistaken in the
We exclude Brisbane from this market as the cost of transporting gas from the Gippsland
Basin to Brisbane is prohibitive and the ‘derivatives’ market is too immature to support swaps.
1
3
sense that many economic proposals are mistaken – because they involve
gains to one party only at greater cost to others in the economy. It is mistaken
in a more fundamental sense. This supplementary submission argues that
even if the co-venturers in a JVP enjoyed an unreasonable degree of market
power, at best requiring them to market their gas separately would achieve
‘precisely nothing’. It would do nothing to reduce whatever market power the
JVP had. But in doing so it would add to costs. The extent to which this would
result in a contraction of production and increase in prices is an open question
and would depend on how the constraint was imposed, and the technical facts
of specific cases.
The claim that the South Eastern Australian upstream gas market is now highly
competitive and will shortly become even more so (Table 1.1) provides an
important backdrop against which it is hoped that the Review will consider its
policy options. The existing and immediately prospective intensity of
competition is certainly a relevant consideration for the review when
considering issues such as the management of acreage and access to
production facilities. But the case for forcing joint producers to market
separately would not be different whatever the degree of competitiveness in the
marketplace.
One way of putting the case is to say that, for monopoly rents to be competed
away, the competitors must compete for each others’ market share. Yet this
cannot happen where the shares of each marketer are already determined by
joint production decisions. This is why in the quote set out on the front page of
this submission, Robert Bork argues that in this kind of situation “dissolving
vertical integration accomplishe[s] precisely nothing”.
4
Table 1.1: Australian Gas Production Fields and Potential Developments
Gippsland Basin
 ExxonMobil: 50%
 BHP Billiton: 50%
Cooper/Eromanga
 Santos: ~40%
 ExxonMobil: ~20%
 Origin: ~13%
 Vamgas: ~9%
 Novus: ~5%
 Bridge Oil: ~4%
 Alliance Petroleum: ~4%
 Basin Oil: ~2%
 Reef Oil: ~2%
PEP153, PEP108
(Onshore Otway)
 Santos: 100%
PEP 154
(Onshore Otway)
 Santos: 90%
 Beach Petrl.: 10%
Minerva
 BHP Billiton: 90%
 Santos: 10%
Yolla
 Origin: 37.5%
 AWE: 37.5%
 CalEnergy: 20%
 Santos: 5%
Patricia Baleen
 OMV Austr.: 40%
 Trinity Gas: 40%
 Santos: 20%
Thylacine
 Woodside: 50%
 Origin: 30%
 Benaris: 20%
Geographe
 Woodside: 55%
 Origin: 30%
 CalEnergy Gas: 15%
Casino
 Santos: 50%
 Strike Oil: 50%
Basker/Manta/Gummy
 Woodside: 100%

North West Shelf Project
(Domestic)
 Woodside: 50%
 BP: 16.67%
 Chevron: 16.67%
 BHP Billiton: 8.33%
 Shell: 8.33%
North West Shelf Project
(LNG)
 Woodside: 16.67%
 BP: 16.67%
 Chevron: 16.67%
 BHP Billiton: 16.67%
 Shell: 16.67%
 Japan Australia LNG:
16.67%
PNG (20/9/02)
 ExxonMobil: ~40%
 Chevron Australia: ~10%
 Oil Search Limited: ~45%
 JPPNG: ~3%
 Mineral Resources ~3%
Bayu Undan
 Phillips: 50.3%
 Santos: 11.8%
 Inpex: 11.7%
 Kerr-McGee: 11.2%
 Petroz: 8.3%
 Agip: 6.7%
Greater Sunrise
 Woodside: 33.44%
 Phillips: 30%
 Shell: 26.56%
 Osaka Gas: 10%
Kipper
 ExxonMobil: ~32%
 BHP Billiton: ~32%
 Woodside: ~21%
 Santos: ~15%
Sole
 Santos: 70%
 Sole: 30%
5
2
The Australian gas market: Supply, demand and the
competitiveness of the market
This section outlines the recent and current state of the Australian and the
South Eastern Australian gas markets and the expectations and forecasts of
some of Australia's leading experts. In doing so it will become apparent that
gas has been increasing its share of the broader and increasingly competitive
energy market – suggesting increasing efficiency and competitiveness relative
to other energy sources. It is also clear that gas on gas competition has
increased markedly, is intensifying and will continue to intensify into the
foreseeable future.
The Australian gas market
The natural gas market in Australia has developed rapidly over the last 30
years. The largest producing basins are Gippsland (Victoria), CooperEromanga (South Australia), and North West Shelf (Western Australia). Each of
these basins is relatively mature. Production from Gippsland and CooperEromanga (approximately 20% and 18% respectively of total production in
2000-01) has been relatively stable over the last 20 years increasing by 11.9%
(5,636Mm3 to 6,304Mm3) and 6.1% (5,435Mm3 to 5,764Mm3) respectively. The
largest field, the North West Shelf (approximately 50% of total production in
2000-01), has seen production increase more than threefold from 3,905Mm 3 to
16,042Mm3, over the same period. Growth in production from the North West
Shelf has been largely driven by a substantial expansion in exports of liquefied
natural gas (LNG).
Over the same period, several smaller basins have contributed to gas supply
with Adavale (adjacent to the Cooper Basin), Amadeus (Northern Territory),
other fields within the Carnarvon Basin (WA), and Otway Basin (Victoria),
contributing increasing volumes. In addition, the small fields of Patricia/Baleen
(Gippsland Basin) and Yolla (Bass Basin) are close to production.
Increased production of natural gas and availability through the exploitation of
reserves within or close to a greater number of states has promoted increased
natural gas consumption across Australia. Since 1980-81, total consumption
has increased significantly in WA (by a factor of 8), Queensland (by a factor of
around 4) and, to a slightly lesser extent, in NSW (by a factor of 1.3). Not
surprisingly, the more established gas markets of Victoria and South Australia,
where natural gas has been available for a much longer period, do not exhibit
the same level of growth over the period.
6
According to projections compiled by ABARE (2001), natural gas consumption
is projected to continue to increase as a component of final energy
consumption and primary energy consumption. ABARE (p. 25) comments that:
Between 1998-99 and 2019-20, the consumption of natural gas in end
use sectors is estimated to increase on average by 3 per cent per year.
With regard to primary energy consumption (figure 2.1), ABARE (p. 43)
observes that:
In 1998-99, coal accounted for 41 per cent of Australia’s primary energy
consumption. Over the outlook period, however, coal’s dominance is
expected to be eroded, with each of the other major primary fuels – oil,
natural gas and renewables – set to grow, on average, at rates
considerably faster than that forecast for coal. The fastest mover is set to
be natural gas (excluding wind and biogas, which are both growing from
a small base), with annual average growth projected at 3.4 per cent a
year over the projection period. At this rate, natural gas’s share of total
primary energy consumption is forecast to increase from 18 per cent in
1998-99 to almost 24 per cent by 2019-20, largely at the expense of
coal.
Figure 2.1: Contribution to primary energy consumption to 2020, Australia –
selected years (petajoules (PJ))
1.00
0.90
Wind energy
0.80
Solar energy
0.70
Hydroelectricity
0.60
Biogas
0.50
Biomass
0.40
Natural gas
0.30
Oil
Brown coal
0.20
Black coal
0.10
0.00
1998- 1999- 2002- 2004- 2007- 2009- 2012- 2014- 2017- 201999
00
03
05
08
10
13
15
18
20
Data source: ABARE (2001; Table G, p. 99).
Analysis of ABARE’s data on a state basis indicates strong growth in natural
gas consumption within all states. Over the period to 2019-20, natural gas
consumption is projected to increase by:
7

76.2% in NSW;

82.9% in Victoria;

195.7% in Queensland;

111.5% in WA;

81.7% in SA;

71.3% in the Northern Territory; and

103.6% in Australia overall.
In addition to natural gas contributing an increasing proportion of total primary
energy consumption, ABARE’s projections indicate that natural gas will become
more significant as an energy source for the electricity generation sector. In
1999-00, natural gas comprised around 10% (212.3 petajoules) of primary
energy consumption for electricity generation. This is projected to grow slightly
to 11% (269.2 petajoules) by 2009-2010, and to 16% (452.1 petajoules) by
2019-20.
Although the growth rates for Australia may appear high, they are consistent
with the growth rates compiled by the Energy Information Administration (EIA)
for other similarly developed economies (see Figure 2.2). Australasia includes
Australia, New Zealand, and some US Territories. Australasian natural gas
consumption is projected to increase on average by 2.3% compared with the
United States at 2.1%, and the United Kingdom at 2.5%.
8
Figure 2.2: Projected annual average percent change in natural gas
consumption, 1999-2020
4.5
4
3.5
3
2.5
2
1.5
1
0.5
0
Total Industrialized
Australasia
Japan
Other Western Europe
Netherlands
Italy
Germany
France
United Kingdom
Mexico
Canada
United States
Data source: EIA (2002; p. 184).
The data indicate that natural gas has grown from a relatively minor source of
energy in Australia to a significant energy source in terms of direct energy
inputs, and as a source of energy for electricity generation. This growth has
occurred over a reasonably short period of time and is expected to continue into
the future. An important factor in the development of natural gas over the last
10 years, and the continued development into the future, is that the relatively
closed state-based or regional markets have become more open and integrated
through the construction of major transmission pipelines (see Table 2.1).
Proposed transmission pipelines are expected to contribute to further
integration of markets, and competition within and between markets.
9
Table 2.1: Gas pipelines – assumed capacities in 2002
Pipelines
Existing major transmission pipelines
Moomba (Cooper) to Young
Young to Sydney
Interconnect (north/south)
Moomba (cooper) to Adelaide
Port Campbell (Otway) to Melbourne
Longford (Gippsland) to Melbourne
Longford (Gippsland) to Sydney
Moomba (Cooper) to Ballera/Mt Isa
Wallumbilla (Bowen-Surat) to Brisbane
Palm Valley (Amadeus) to Darwin
Longford (Gippsland) to Tasmania
Dampier (Carnarvon) to Bunbury
Capacity (PJ per year)
Proposed major transmission pipelines
Port Campbell (Otway) to Adelaide
Bayu Undan (Timor Sea) to Darwin
Darwin to Mt Isa/Moomba
Mt Isa to Townsville/Gladstone
Papua New Guinea to Brisbane
152
152
19/8
120
95
420
65
50
38
30
50
200
125
250
200
100
300
Source: Adapted from ABARE (2002; p. 19) and industry announcements.
The South Eastern Australian gas market
The South Eastern Australian gas market comprises New South Wales, Victoria
and South Australia and, very recently, Tasmania. Each is relatively mature
with natural gas being a major energy source for over 30 years. These markets
are served by mature gas fields, to which specific attention has been drawn in
the comments made on joint marketing compared with separate marketing.
Figure 2.3 shows the contribution to total energy consumption for the South
Eastern states for 1998-99 and 1999-00 and projected contributions for various
years up to 2019-2020 derived from ABARE (2001). From 1999-2000 to 201920, natural gas is projected to increase its share from 15% to 20%. Both black
and brown coal are projected to decline in significance. Natural gas is projected
to increase its share from:

10% to 12% in NSW;

17% to 23% in Victoria; and

36% to 42% in South Australia.
10
The relatively low market share in NSW is largely the result of the plentiful
supply of high quality black coal. Despite this the NSW Government has
spoken of future power-stations in NSW being gas fired.2 Nevertheless the
growing share in all markets accompanied with strong investment in exploration
for and development of gas fields is inconsistent with a picture of an industry
seeking to drive up prices by limiting supply.
Figure 2.3: Contribution to total energy consumption (actual and projected) –
New South Wales, Victoria, South Australia
1.00
0.90
Wind energy
0.80
Solar energy
0.70
Hydroelectricity
0.60
Biogas
0.50
Biomass
0.40
Natural gas
0.30
Oil
Brown coal
0.20
Black coal
0.10
0.00
1998-99
1999-00
2004-05
2009-10
2014-15
2019-20
Data source: ABARE (2001; Table E2, pp.91-93)
The data reflect a strong market for gas that is expected to continue to grow
with expanded sources of supply due to increased integration of markets.
Collins and Powell (2002; p. 29) summarise the changes in the Victorian market
(the major South Eastern states market) as follows:
The Victorian gas industry has changed considerably since the
introduction of reform … in 1995. The market has evolved from an
upstream monopoly (Esso/BHP Billiton) dealing with a government
owned downstream monopoly (Gascor) limited to Victoria, to a
disaggregated, privatised and nationally interconnected market with a
large number of participants. The picture now is that of competition, with
many opportunities for new players to participate in the market.
Esso/BHP Billiton is still the dominant producer, however it is expected
2
NSW Premier Bob Carr, ABC Television Lateline, Monday 16 September 2002
11
that within the next five years there will be an additional six gas
producers and the wholesale market will be fully developed.
Further:
Gas can be bought and sold from various sources in the system. Traders
can buy and sell gas from other market participants and producers,
through either commercial contracts or through the wholesale gas market
(the “spot market”).3
The introduction of increased competition is continuing (Collins and Powell p.
35):
The market is currently being opened up for competition, allowing
customers to choose their gas retailer. Contestability was first introduced
to larger customers, and has been progressively introduced to smaller
customers (p. 35). 4
The timetable for customer contestability in Victoria is shown in Table 2.2.
Table 2.2: Victorian gas contestability timetable
Tranche Date
Customer load
1
2
3
More than 500,000
100,000 to 499,999
10,000 to 99,999
5,000 to 9,999
Less than 5,000
4
1 September 1998
1 September 1999
1 September 2000
1 September 2001
October 2002
Number of customers
(% of total load)
35
(25%)
110
(13%)
600
(10%)
600
(2%)
1,400,000 (50%)
Source: Collins and Powel (2002; p. 36)
From 2009, the date of expiry of the final Esso/BHP Billiton contract with
Gascor, the South Eastern Australian market, and particularly the Victorian
market, is likely to be served by a larger number of producers with more
extensive interconnections between different sources of gas supply. This is
expected to create a more open and competitive market that, based on
3
Note however that the derivatives market, which contributes to liquidity is still immature.
In this regard we draw attention to the comments in ExxonMobil’s original submission to the
Energy Markets Review (2002: 2).
4
A … provision of the SPL limits "significant producer" retail sales to customer sites
using more than 500 TJ per annum (largest 35 industrials in Victoria). Through this
provision, smaller customers are denied the choice to purchase gas directly from
significant producers. The SPL restricts competition in the Victorian gas market, and is
contrary to the principles of the National Competition Policy.
12
ABARE’s projections, will continue to grow strongly displacing other energy
sources.
In this context, natural gas is part of a much wider market for energy. Unlike
many commodities – particularly its customer and competitor – electricity – gas
has close substitutes in consumption in virtually all its uses whether the user is
industry, electricity of the final consumer. Moreover particularly in Victoria and
NSW it is competing directly and indirectly against very low cost coal generated
electricity. Consequently, the competitiveness of natural gas should be
substantially judged against the extent to which it has and is expected to
continue to displace other energy sources, both as a direct energy input and as
an input into electricity generation. The evidence is that:

there has been substantial exploration and development of gas fields;

gas production has grown strongly over the last 20 to 30 years;

gas consumption within Australia has grown strongly over the same
period;

gas has effectively displaced substantial volumes of other energy
inputs and this is expected to continue, and

upstream gas markets are becoming increasingly competitive with
integration of producing regions and markets.
Simply considering these facts in the market and quite apart from the
theoretical arguments central to this submission, it is difficult to sustain an
argument that there has been any substantial impairment of the operation of the
market resulting from JVPs marketing jointly rather than separately.
Deeper and more liquid markets
In support of the contention that separate marketing is to be preferred to joint
marketing, the existence of separate marketing in other regions, particularly the
United States, is often cited as a reason of itself for requiring separate
marketing. No discussion is provided of the evolution of marketing in these
other regions, nor is any analytical substantiation given as to why the existence
of separate marketing elsewhere is sufficient evidence of more competitive
markets. Further when making comparisons with the United States it is
important to realise that in the United States:
13
Producers include firms that explore for new gas resources and expand
production from known reserves. The market for wellhead natural gas
purchases is unregulated; that is, producers may negotiate prices and
delivery terms with consumers or with other firms, such as marketers and
LDCs5, for the sale of their products. (EIA, 2001b; p. 2)
Providing sources of demand and supply are substantial and various enough,
and policy settings and physical infrastructure (pipelines) enable the
appropriate market institutions to develop, national gas markets deepen and
gain liquidity and move naturally from ‘project’ or ‘contract’ supply to ‘commodity
supply’. It is argued below that this is an organic or ‘self-organising’ and
cumulatively causative process which policy makers should strive to facilitate,
but which they seek to force at their peril (see Section 5).
It is notable that even in the deepest and most liquid markets longer-term
contracts will always remain a critical part of a market. Where major fixed
investment is involved, risks are shared down the production chain through
long-term contracts where both security of supply and price are more stable
than on the short-term ‘spot’ market. The same kind of thing occurs not only in
similar industries – like electricity, but also in very different markets. For
instance in the market for credit, fixed investment will often be underwritten with
fixed term and fixed interest rate loans. As in the case of the buyers of credit,
buyers of gas typically pay more for a fixed term contract in a deep and liquid
market. In Europe the long-term contract price is around 5 per cent above the
short-term contract price.
As indicated elsewhere in this submission, producers have a preference for
separate marketing as they each have different marketing strategies, niches
and networks. They refrain from separate marketing where the advantages to
them of separate marketing are constrained by the logistical, customer
aggregation and risk management tasks of production within a field.
It is no surprise that the things which are necessary to ensure that separate
marketing does not generate more costs than benefits are those things which
describe a deep and liquid market. They include:
1. Multiple buyers and sellers of gas;
2. Means of dealing with divergence between the amount the JVPs are
entitled to take from the JV in production and the amount they are able
to successfully market. These means can come from a combination of
the following:
5
LDC - Local distribution company
14

Liberal balancing, borrowing and banking arrangements
between JV co-venturers;

Low cost means of storing gas within the JV or outside it;

A well developed and deep and liquid ‘spot market’ into which
surplus gas can be sold at not too great a discount.6
In this context the differences between the Australian market and those markets
to which it is being compared are manifest. In contrast to the producers in
Australia, the American market is hugely competitive in production. Thus of all
the gas produced by the top twenty producers, only one producer has a share
of over 12% - BP at 15.2% (see table 2.3). There are many small and very
small producers such that the market share of the top twenty producers is just
58% and the market share of the top fifty producers is still shy of 75% (EIA,
2001a, see Table B3).
Table 2.3: Top gas producers in the United States
Company name
BP
ExxonMobil
Anadarko
Royal Dutch/Shell
Chevron
El Paso Energy
Burlington Resources
Texaco
Unocal
Devon
Phillips
EOG Resources
Conoco
USX-Marathon
Occidental
Apache
Amerada Hess
Kerr McGee
Ocean Energy
Louis Dreyfus
Production Q2 Share of top
2001 (million
prodn of top
cfd)
twenty
3,550
15.2%
2,580
11.1%
1,651
7.1%
1,604
6.9%
1,529
6.6%
1,501
6.4%
1,314
5.6%
1,237
5.3%
1,047
4.5%
997
4.3%
884
3.8%
867
3.7%
831
3.6%
774
3.3%
607
2.6%
605
2.6%
474
2.0%
459
2.0%
444
1.9%
325
1.4%
Source: Gas Daily, August 17 2001
See the North West Shelf co-venturers’ supplementary submission to the ACCC regarding
authorisation of JM, 17 March 1998, para 3.4(a) for a similar, though not identical list.
6
15
These producers have access to a vast pipeline network consisting of nearly
2.5 million kilometres of piping across the USA. Gas also enters the US
pipeline grid through Canada and Mexico.
Map 2.1: U.S. natural gas pipeline network
Source: US Department of Energy at http://www.netl.doe.gov/scng/trans-dist/ngtd/system.html
Furthermore, when compared with the United States market, the Australian
market is very small (see Figure 2.4). Consumption for Australasia (includes
New Zealand and some Pacific Islands) is 1.0 trillion cubic feet compared with
21.7 trillion cubic feet for the United States.
16
Figure 2.4: Consumption of Natural Gas by Region, Industrialized Countries,
1999
T rillion cubic feet
25
20
15
10
5
0
Australasia
Japan
Other Western Europe
Netherlands
Italy
Germany
France
United Kingdom
Mexico
Canada
United States
Source: EIA (2002; p. 184)
The United Kingdom has much more concentrated production and marketing,
but nevertheless has a much deeper and more liquid market (3.3 trillion cubic
feet in 1999) than Australia with five major marketers (see table 2.4).
Table 2.4: Major natural gas marketers in the United Kingdom
Estimated Sales in Wholesale Market
Producer/wholesaler
Exxon-Mobil
BP
Centrica
Shell
Total/Fina/Elf
%
25.5%
25.5%
20.4%
18.1%
10.5%
(Energy Intensive Users Group, 2002, p. 3)
Again, these producers are connected to consumers – including European
consumers – through an elaborate network of on and offshore pipelines. More
than 30% of total UK gas sales are traded through the daily and monthly spot
markets with a price spread of greater than $4.50/GJ since the beginning of
17
2000. In contrast, South Eastern Australia's only spot gas market (Victoria)
currently accounts for less than 4% of gas sales with a corresponding price
spread of around $0.30/GJ over the same period with the exception of a single
event in the Victorian market in July 2002.
Map 2.2: Natural gas pipeline network - United Kingdom on and offshore
connections
Source: http://www.platts.com/features/northsea/uklib.shtml
Another important factor that distinguishes the Australian market from those of
the United States and the United Kingdom, is the numbers of significant
customers. In the United States there are around 4.5 million commercial
customers and 40,000 industrial customers, along with 500 electric utilities
(EIA, 2000; ppt slide). In the United Kingdom, there are about 381,000 nondomestic customers (Eurogas, 2001). By contrast, in Australia there are only
1,940 commercial and industrial customers (AGA, 2002). This is a clear
18
illustration of the difference in market depth and liquidity between Australia and
other markets with which it is frequently compared.
3
The economics of gas discovery and production
In the sense in which it appears in economic textbooks, the assets from which
gas is produced by production co-ventures enjoy a degree of market power. In
the same way that a pharmaceutical company will invest in research and
development in order to develop a patent, resource companies invest in
exploration to generate economic rents from the resources they discover and
exploit. Exploration is a highly competitive global business, with resources
companies spending hundreds of billions of dollars on exploration and much
more again on development of discovered fields. But considered after the
investment on exploration has succeeded, the company has an asset to which
attaches economic rent – indeed the prospect of rent is the essence of the
incentive to explore and develop.
Investment in resource discovery and development takes place within a
competitive global market where countries fight fiercely to attract scarce capital
and resource investment. Australia must strive not just to maximise the
efficiency with which it uses the resources that are discovered and developed, it
should also seek to facilitate competition between existing producers and new
entrants. But it must do so in a way that fosters continuing investment in
exploration and development. This makes long-term stability, predictability of
rules and rewards for discovery and development of natural resources
paramount – and the context within which competition policy should vigorously
pursue its goals. It is these thoughts that lie behind Juris’ observations about
the capacity for new entry to stimulate competition – quoted at the beginning of
this submission.
4
The Economics of project supply
Wherever the means of getting gas to market are not well developed, natural
gas supply will generally commence with a major project. Major projects almost
always require the equity participation of one of the global petroleum ‘majors’.
With appropriate policy settings the market may deepen and gain liquidity over
time and make the transition from ‘project supply’ towards ‘commodity supply’.
In project supply, production and consumption mirror each other in large
discrete increments. The myriad technical and other risks, and the degree of
fixed costs involved together with the difficulty of transporting gas, explains the
way in which gas markets commence and how they evolve and deepen and
gain liquidity over time. In the absence of a well developed pipeline grid and the
19
institutional infrastructure necessary for liquid markets to develop, substantial
gas supplies can only be brought to market with a chain of long-term take or
pay contracts. These lock in all the players along the supply chain – typically
customers, reticulators, transmitters and producers. Often there is equity
sharing between these parties in the supply chain (reticulators and transmitters
are often the same), and often one or more is owned by the state.
In a mature, deep and liquid market there are multiple large producers with
adequate pipeline capacity to connect them to many independent consumers.
In this scenario consumers have many options as to which producers they
purchase from and producers can market to many different consumers.
Why gases are different?
The reason gas markets take longer to ‘mature’ from project to commodity
supply – and the reason some become deeper and more liquid than others is
ultimately a result of the greater cost of storing gas and transporting it from
producers to consumers. Other hydrocarbon fuels7 are readily stored and
transported as liquids. Accordingly upon production they can be readily
transported by truck, rail and ship to any part of the world. And the ready
capacity to transport them enables pricing to converge rapidly to world
benchmarks net of transport costs.8
Considerable costs are incurred to convert natural gas into liquid form, and
when it is, transport vehicles are expensive special purpose vehicles.
Accordingly if the expense of liquefaction is to be avoided, gas producers must
be connected to their customers by pipelines.
The institutions of deep markets are self organising systems
It follows from what has been said that the potential depth and liquidity of a
market are a function of the following factors:

Size of and distance from each other of major consumption nodes –
and more generally population density;
Methane (CH4) is the primary ingredient of Natural Gas. Ethane (C2H6) which is a minor
constituent of natural gas is a principal feedstock to the plastics industry. Longer alkanes
(CnH2n+2) are either liquids (eg pentane and hexane) at natural pressures, or relatively easily
converted into liquids for storage and transportation (such as butane and propane).
7
8
If prices were not at this point, easy profits could be made by arbitraging these margins.
20

Geology – the proximity of gas production and potential gas production
to consumption.;9

Institutions – properly managed deregulation allows a market to
develop

History – where it has been necessary to award large acreages to
stimulate gas exploration and development, and/or where gas fields
exhibit production interdependencies, gas fields may be unitised or
otherwise jointly developed over a large area.
There is another sense in which history is crucial. Many of the institutions of
liquidity have the characteristics of a self-organising system. There is a degree
of circularity – or through time cumulative causation – in their establishment.
Even in the most propitious of circumstances, a deep and liquid market will take
time to develop as producers and consumers learn to trust the competitiveness
and the predictability of the physical and institutional infrastructure which makes
up the market in gas. And buyers and sellers will participate more in a spot
market where the liquidity it offers provides a degree of security that can
substitute for the security of long-term contracts.
As liquidity and size grows, so too does the attractiveness of the spot market
pool to aggregators and other traders, insurers and those providing derivative
financial products based upon pool prices. And the ‘spreads’ between buyers
and sellers of physical and derivatives contracts also narrows. In turn, this
enhances the security and flexibility with which the pool can be used, and so
attracts more participants.
Because this is a self-organising, cumulatively caused system and it is strongly
efficiency enhancing, it is important that policy does everything it can to
facilitate its emergence and strengthening. It is of course conceivable that
policy could move beyond this point – that forcing the emergence of the
institutions of liquidity could enhance economic welfare. Thus for example, it
would be possible for regulation to prohibit more than a certain proportion of
gas from being sold and bought in long-term contracts. It is conceivable that,
by forcing buyers and sellers into the pool greater liquidity would be generated.
But unless such a move were modest and embraced widely within the industry,
it seems highly likely to do more harm than good with any gains offset by
losses. Losses could be expected to arise whenever participants in the supply
chain took their demand and supply of gas or at least some portion of it
elsewhere – into other industries – or other countries. As noted in Section 2,
Remembering that gas discovery and production is often a byproduct of exploration for and
production of liquid hydrocarbons.
9
21
even in the deepest, most liquid national gas market in the world, United States
major projects do not proceed without long-term contracts in place.
In a number of respects the Australian market has disadvantages in achieving
the level of market depth and liquidity that has already developed in the United
States and that will develop in Europe over time in the wake of the European
gas directive. It has a land mass roughly the size of the United States or of
Europe, with less than a tenth of the population. Most of the largest gains from
deeper, more competitive and liquid markets are being made in Australia, but
realism should temper expectations. Limited by the size of its population,
Australia will never have a spot market in gas of the depth and liquidity of the
spot market in the United States.
A deep and liquid market enables producers to rely on the fact that there are
always many consumers available and so if it is produced, gas can be sold.
Concomitantly, consumers of gas can have confidence that they will always be
able to purchase gas from a producer. Though producers and consumers may
choose to write long-term take or pay contracts with each other, they are also
aided by a deep and liquid ‘spot market’ into which surplus gas can be sold and
from which it can be purchased in the short-term. The spot market is also useful
as a signal to producers and consumers of gas of the balance between demand
and supply in the market – the current marginal cost of production and
consumption.
5
Risking, financing, co-ordinating and sharing production
As has been observed, even in the deepest of markets, major production
development decisions are not made – either for greenfields or even major
expansions of production in developed basins – without long-term lock in of
customers. That is, major developments in the industry are underwritten by
‘project’ or ‘contract’ supply not ‘commodity’ supply. If this is a strong
preference for producers in such markets, in more shallow markets it is a
necessity. The co-ordination of production and consumption that is the essence
of ‘project supply’ is a major exercise to which critical attention must be given
for it underpins the economics of the industry.
A great many things must happen in a co-ordinated way as the supply chain is
only as strong as its weakest link. For a new development:

gas supplies must be discovered and proved up;

production facilities must be accessed or established, and

pipelines must be built for transmission of the gas to existing
infrastructure.
22
Each of these exercises is highly complex in itself. Each requires co-ordination
with government agencies and government approvals. In a shallow market (and
often even in deep and highly liquid markets), risks can only be kept within
reasonable bounds if gas customers are aggregated to meet in advance the
costs and risks of the venture. With a greenfields development negotiations to
aggregate and contract sufficient gas consumers can take five years or
sometimes (as in the case of the Papua New Guinea fields) over ten years.
Joint ventures are a critical means of sharing risk
Despite the enormous size of the companies that underwrite petroleum
exploration, it is remarkable the extent to which they involve themselves in
highly complex joint ventures involving complex legal arrangements specifying
the parties’ respective rights and responsibilities. Joint venture agreements –
frequently running for several hundred pages – are very expensive not just in
terms of the legal arrangements that must be established, and from time to time
arbitrated and litigated. They involve high levels of expense because they
diffuse the source of authority within the management of the joint venture.10
These agreements are then developed as the gas field is developed with equity
shares and sometimes rights and responsibilities evolving with the venture.
The remarkable complexity and expense of this behaviour and the constraints it
imposes on co-venturers – underlines the lengths to which they will go to
manage risk. The conclusion must be that efficient risk management is
inherent to the economics of gas supply.
Risk and the management and optimal depletion of mature fields
It is axiomatic that discovery of resources involves high levels of technical and
financial risk – particularly discovery. Given this, it is critical that policy
decisions after the initial investment remain within the bounds that the original
investors could reasonably anticipate. The Gippsland Basin JVP has sunk of
the order of $16 billion of investment into the Gippsland Basin/Bass Strait oil
and gas project with long time horizons necessary to justify the investment. The
investment was predicated on policy continuing to be stable and prudent for
many years to come.
One party is usually appointed ‘operator’ of the joint venture but other equity owners must
supervise their equity, which duplicates costs, and creates the possibility for dissension within
the joint venture and conflicts of interest between the co-venturers. Joint venture agreements
are usually drawn up very early in the development stage. They typically include decision
making processes and threshold tests that bind the co-ventures for the life of the field.
Subsequent and much later diverging views on market opportunities are bounded by the
original JV operating agreement.
10
23
Further substantial risk taking and the need for careful technical optimisation do
not end with discovery. In particular it is crucial for effective competition within
the gas market that the JVP faces incentives to develop the basin in a way that
is consistent with optimising costs and production from its resource. At the
same time the joint venture in production is being established or extended into
new fields, customers must be locked in to underwrite the continuing
investment involved. The period of five or sometimes more than ten years was
mentioned earlier concerning major greenfields expansions. Even with a preexisting field, a large new contract involves a massive exercise in aligning
logistical, legal, financial and technical needs of producers, sub-contractors and
consumers of gas. Each requires a variety of permits from government
authorities. The whole process – summarised in the diagram below, takes
around two years to complete and only one in four such negotiations are
concluded successfully.
Figure 5.1:
Steps in securing a major gas development
Competing
Sales
Opportunities
Corporate
Capital &
Development
Resources
Competing
Projects
Business
Diversity
Corporate
Capital &
Development
Resources
Capacity
Competing
Projects
Gas
Supply
Forecast
Power Generation
Capacity Gap
Gas
Transport
Developer
Electricity
Transmission
Customer
Customer
Customer
Customer
Customer
Host Site/
Operator
Corporate
Capital &
Development
Resources
Competing
Projects
Competing
Electricity
Supply
Offers
Corporate
Capital &
Development
Resources
Business
Diversity
Competing
Projects
Business
Diversity
In addition, co-ordination and technical optimisation problems abound.
Development and production must be optimised and coordinated between fields
each having distinct characteristics in terms of:

The capital cost of proving up and producing – depending on depth
of gas, location, distance from established production facilities;
24

The quality and mix of the raw hydrocarbons and other substances
produced by the field; and

The amount of gas available and the proportion expected to be
recovered.
And the resource depletion of each field – and the fields within the JVP jointly –
must be technically optimised. Wells must be depleted consistent with customer
supply requirements.
None of the characteristics of a well will be known perfectly in advance and
some will involve relatively high levels of risk both before production is
commenced, and even after this point. Rates of depletion will be subject to
wells’ technical optimal depletion rates. In the case of water driven fields, lifting
gas too quickly can reduce the amount of gas which migrates from throughout
the field to the well-base. Conversely, lifting gas too slowly can lead to water
rise overtaking gas rise. The amount of gas being drawn from two sub-fields
may be interdependent and require joint optimisation. In addition, different fields
may produce different mixes which must be managed through the feeder
pipelines and within the processing plant.
In considering the rate of depletion, technical optimisation of the depletion
program will typically have substantially greater impact on the value of the
resource to ExxonMobil than any value optimisation related to scarcity rent. The
following diagram illustrates the economics of exploiting three fields within a
basin as a highly simplified stylisation of the problems of managing the
exploitation of a mature basin. The optimisation problem is which field to
develop when. The first option – to develop field one – requires little capital
investment and generates gas at relatively high marginal costs from existing
wells. The second option involves significant capital expenditure on a new field,
but relatively low quality and quantity of gas compared with the most capitalintensive option – the development of field three. Yet, assuming that the
market can absorb an amount of gas in excess of Q2 the optimal choice is to
develop field three first.
25
Figure 5.2: Average costs of gas from different fields
Unit Cost
Field One
Field Two
Field
Three
C1
C2
Q1
Q2
Q3
Consideration of these hypothetical developments illustrates the importance of
JVP in spreading risk, aggregating demand and obtaining sufficient capital so
as to enable optimal development. For instance, if marketing were truly
separate and rivalrous, marketers would not share information about the market
or coordinate their offerings to the market. Yet the essence of efficient
marketing in this shallow market is to match buyers with production possibilities
at the wellhead and these cannot be efficiently or effectively determined except
in the aggregate. The optimal resource development is a mapping of
consumption possibilities across the market with production possibilities across
the field.
With so much to co-ordinate, so much investment relying on reducing the level
of risk and uncertainty to a tolerable level, it seems likely that, if co-venturers
were forced to market their gas separately the level of uncertainty would rise
appreciably. The result would be the development of sub-optimal fields, higher
costs, and so prices from the JVP to the separate marketers. This would also
lower gas demand and supply. Given the massive fixed costs in transmission
and reticulation the unit cost of these services is also likely to increase if they
carry lower gas volumes.
Balancing agreements
This sub-section explores the coordination tasks within a mature JVP managing
a basin with the geology of the kind that is found in the Gippsland basin JV is
managing. We explore first the way in which general balancing agreements
work within JVPs to enable the co-venturers greater flexibility in the take-off of
26
the gas. We explain these features, firstly, with regard to the more normal
‘expansion or depletion driven’ wells, and then explain how they might differ in
the case of ‘water driven’ wells such as those produced by the Gippsland Basin
JVP.
In an expansion drive well, it is the pressure of the gas trapped between layers
of rock that drives production. Production commences at maximum flow before
gradually falling as gas expands up the well into production and there is a
commensurate fall in pressure. For the sake of exposition assume there are
two JV parties each with 50% shares in the JVP – as is the case at hand. Once
the well is in production, the JVP will have a preliminary view about how much
gas it will eventually produce. This view becomes better informed over time as
the process of removing the gas generates information about the gas reserve
itself. In the absence of a balancing agreement, each partner owns 50% of the
volume of the gas as it is withdrawn. Where it is viable to market separately,
balancing agreements allow the shareholders in JVPs to draw off the gas to
which they are entitled at differential rates. This is always subject to strong
safeguards that total take off from the well will match equity shares by the time
the production has been depleted. In addition, the costs associated with
extensions to field life are borne by those co-venturers who cause the
extension.
The fact that production must ultimately balance with equity shares implies that
any imbalances in take-off shares along the way must be balanced by equal
and wholly offsetting imbalances by the time a well is depleted. Typically a
balancing agreement will have three stages. In the first and/or second stage the
balancing agreement will allow production to proceed at a rate which satisfies
both the technical needs of optimal resource depletion and the needs of the
partner wishing to take the most gas – subject to some cap. Thus where coventurers are 50/50 a partner may not be able to exceed their own expected
share – of 50%, but the other partner may take off less than their share
(effectively reducing the rate of take-off). Alternatively the balancing agreement
may permit one partner to take off more than their share – say 60% of the gas
produced at the optimal depletion schedule with the other partner receiving
40%.
Either way, in the next phase of the balancing agreement, the shares will be
reversing – to contribute to the balancing of the shares over the life of the field.
In the final phase of the development there is typically no flexibility and
relatively limited production as shares need to be kept in close alignment with
whatever share is required to deliver balance over the life of the well. The
phases are illustrated in an indicative way in the figure below, with the unbroken
27
line representing gas production and the broken line representing the degree of
knowledge about total production from the well.
Knowledge of
well
Rate of production
Figure 5.3: Production and phases of a balancing agreement in an expansion
driven well
Phase 1
Phase 2
Phase 3
Time
From this description it will be clear that the balancing agreement is no panacea
enabling the co-venturers in a JVP to somehow break free from the entitlement
and liquidity constraints of the JVP. Not only is the scope for moving away from
one’s entitlement relatively constrained in the short-term. It must also be made
up over the medium term. It is hard to see much competition between equity
co-venturers in a JVP based on balancing agreements. Firstly, one must be
agreed in advance within a JVP. Secondly to the extent that they permit
deviations in take-off from the JVP, equity shares mean that the over-lifting
partner(s) is in effect borrowing the gas from the under-lifting partner(s). This
comes with the associated obligation to pay it back within the medium term and
so to give up the market share just won.
Water driven fields are harder to balance
Balancing within a water driven field is generally more difficult than balancing
within an expansion driven field. In an expansion driven field, the balancing of
imbalances is typically done as production and pressure fall gradually towards
the end of a gas well’s life. With a water driven field, this process is
dramatically foreshortened. In Bass Strait water is present in many fields and,
as hydrocarbons are extracted from them, rising water maintains the pressure
and provides lift for the gas.
28
Providing it is consistent with technically optimising depletion, this can be useful
for the producer as it provides more consistent pressure to maintain lift for the
gas. However, there are two difficulties with water driven fields. The first is the
need to manage the presence of the water, which can add to cost. More critical
from the perspective of the issue at hand is that total production from water
driven fields is less predictable. The pressure of the gas is an important signal
of gas volume but this is masked by water pressure in water driven wells.
Because water pressure remains high for much longer, it is more difficult to
coordinate and time the exhaustion of one field with commencement of
production from another. Thus balancing production from a well is more difficult
as near certainty about the total production of the well is achieved much closer
to the exhaustion of the well.
Rate of production
Knowledge of well
Figure 5.4: Production and phases of a balancing agreement in a water driven
well
Phase 1
Phase 2 Phase 3
Time
Thus water driven field balancing agreements allow much shorter time periods
where equity holders production offtake rates can deviate from equity shares.
Production offtakes must be re-established at the end of Phase 1 as the
duration of Phase 2 can be unpredictable.
29
6
The economics of depletable resources
Any market power available to producers acting jointly is inherent in the
exploration and production leases they collectively control. It is exercised when
the pricing, extent and/or other terms of gas supply are determined, for the
duration of the supply contract. It can be exercised by joint venturers marketing
jointly and so collectively determining the price and/or quantity of gas they are
prepared to sell. However joint producers can still exercise whatever market
power is inherent in their leases even when marketing separately. They can do
so by determining the quantity and terms on which gas is made available for
(separate) marketing.
Industry Commission, 1995, p.126
Overview of the economics of the exploitation of depletable (nonrenewable or exhaustible) resources
The existence of market power is central to this submission. Yet it is frequently
misunderstood. It is misunderstood for several reasons. Firstly, as has been
argued above, the existence of economic rents is of the essence of any kind of
speculative investment, whether it be to develop a patentable technology, or to
discover natural resources. What looks like monopoly after the event,
nevertheless was a fully competitive process before the original speculative
investment took place. According to the ‘neoclassical’ economic textbook, the
resulting outcome with patentable technology is ‘second best’. This is because,
once the technology has been developed it is ‘optimal’ to sell it at its marginal
cost of reproduction. As we will see below, there is an analogy with depletable
resources. But it is only a limited analogy.
The recognition of the depletability of resources provides important insights for
the analysis of joint marketing (JM) compared with separate marketing (SM) by
equity holders in joint venture producers (JVPs). That is, the perception that
there is some market power associated with ownership of a depletable resource
is correct (as reflected in the assertion by the Industry Commission cited
above). But unlike the case with patentable technology, an economic rent
attaches to the resource because of its natural scarcity – not because its
developer must recover its investment (and its investment in other unsuccessful
ventures). The following discussion is concerned with the key results from an
economic analysis of the optimal depletion path of a depletable resource given
different market structures. Detailed derivation of these results is provided in
Appendix One.
30
The basic attribute of a depletable resource is that every unit extracted and sold
today reduces the amount available to be extracted and sold tomorrow. 11 The
starting point for the economic analysis of depletable resources is what has
become known as Hotelling’s rule (Hotelling, 1931). This rule states that:
For a firm to be indifferent between extracting the resource in the current
period and a future period the price must rise at the discount rate
(Hanley, Shogren and White, 1997; p. 229).
The intuition of this result can be easily understood on the basis that the
amount received in the current period can be invested at the prevailing interest
rate, r such that it will be worth more in future periods. As stated by Perman,
Ma and Mcgilvray (1996; p.143):
If a resource is to be optimally extracted, the Hotelling rule continues to
be a necessary condition for this. … the Hotelling rule is an efficiency
condition which must be satisfied by any optimal extraction program.
The Hotelling rule means that there will be associated with any depletable
resource, an economic cost over and above the cost of provision. This amount
is variously referred to as the opportunity cost, user cost, royalty, rent, net price
or marginal profit. The existence of the scarcity rent is independent of the
competitiveness of markets; that is, existence has nothing to do with market
structure per se.
The implications of different market structures
Different market structures have different implications for the optimal depletion
path of a depletable resource. The market structures considered are perfect
competition and monopoly because, as polar cases, they emphasise the key
variables that influence the outcomes and the differences in outcomes. The
analysis in Appendix One follows that presented in Conrad and Clark (1987).
Determination of the optimal depletion path under both perfect competition and
monopoly depends on two key variables – the market rate of interest r, and the
amount of resource available to be exploited, R. For the competitive firm,
11
This is expressed as follows in BIE (1993; p. 41):
The idea that it is desirable for a natural resource (exhaustible or renewable) to be
managed with regard to its reproducibility characteristics, is based on the theory of the
optimal rate of depletion of natural resource stocks. The theory addresses the problem
of allocating resource use across time. With regard to exhaustible resources, the theory
identifies the optimal conservation level by determining how much should be consumed
now, and how much used in future periods in order to maximise the net social benefit to
society over time. This is referred to as an intertemporal allocation problem.
31
returns are maximised by following Hotelling’s rule – the resource will be
exploited at a rate that allows the price to increase at the market rate of interest
(equivalent to the scarcity rent). Because the monopolist maximises profit by
focussing on marginal revenue, the monopolist will exploit the resource at a rate
that permits marginal revenue to increase at the market rate of interest.
In respect of a competitive market structure, Conrad and Clark (1987; p. 121)
observe that:
[T]he competitive industry initially exploits the resource at a higher rate,
and also ultimately exhausts the resource more rapidly than the
monopolist. This is not very surprising – the monopolist restricts
production so as to maintain a higher price level.
They further note that:
In the simple model … the competitive extraction path is also socially
optimal (in the usual sense), and the monopolistic path is dynamically
inefficient in the sense that current generations could more than
compensate future generations for an increase in current (near term)
extraction and a reduction in social welfare. (p. 122)
This is the analogy with the patent example provided above. A firm with market
power ex post can emerge from a market that ex ante was vigorously
competitive. Thus any economic rent enjoyed by the JVP is properly seen as
the reward which was the incentive for it to explore and develop its exploration
and production leases in the first place. Such an outcome may be ‘second
best’ but, as the ‘theory of the second best’ tells us, the alternative ‘first best’
solution is not attainable. If we did not respect the property rights of the
discoverers and developers of natural resources we would not have more
national resources at a lower price – we would have fewer resources and so
higher prices.
In this context it should be noted that royalties and taxes are imposed on the
production of gas. In the case of ExxonMobil, royalties apply to production from
the Gippsland Basin, and Petroleum Resource Rent Tax is levied at the rate of
40% of revenue after deductions for capital and operating expenditures. This
means that society is sharing at least some of the scarcity rent, thereby
reducing the rent that accrues to producers. It is possible that this fact is
overlooked by other parties, and leads to an exaggerated perception of the
amount of the rents that accrue to producers. Importantly, as concluded by
Perman, Ma and McGilvray (1996; p. 159):
[A] royalty tax or subsidy is neutral in its effect on the optimal extraction
path. However, a tax may discourage (or a subsidy encourage) the
32
exploration effort for new mineral deposits by reducing (increasing) the
expected pay-off from discovering new deposits.
Conrad and Clark (pp.123-124) relax the assumption of zero extraction costs
and demonstrate that, for a well behaved cost function, the competitive
outcome shows that price net of marginal cost rises at the rate of interest. By
comparison, for the monopoly the corresponding condition implies that marginal
revenue net of marginal cost is rising at the rate of interest. As summarised by
Perman, Ma and McGilvray (1996; pp.150-151):
Given

a particular resource demand function,

Hotelling’s efficiency condition,

an initial value for the resource stock, and

a final value for the resource stock,
it is possible to obtain optimal expressions for all of the variables.
To recapitulate, for a given demand function, the optimal depletion time
depends on the initial reserves and the market interest rate. This is the case for
both monopoly and competition, and in both cases there is a rent associated
with exploitation of the resource. There is a wide range of factors that make the
‘real world’ more complicated than the simplified models presented here
(royalties, taxes, changes in the market interest rate, uncertainty as to stock
sizes and extraction costs, technological changes, etc.). However, these
models do provide a basis for considering the implications of the existence of
market power and the suggestion that separate marketing could in some way
diminish the market power.
Focussing on monopoly, because this is the polar case of market power, and
maintaining the assumption of zero extraction costs, assume that a JVP has
some market power above the scarcity rent of the resource. The issue is: would
requiring separate marketing rather than joint marketing reduce the market
power? In order for this to happen, the fact of separate marketing would need to
be able to influence the market interest rate, r, and/or the total quantity of the
resource, R. Clearly, separate marketing influences neither. The optimisation
problem faced by the JVP remains the same, to maximise the value of the
discounted profits of the resource it jointly controls over time. That is, jointly and
severally, the co-venturers still face the same demand curve, they still have the
same quantity of resource to exploit, and they still face the same interest rate.
Irrespective of the number of co-venturers, the superiority of an apparently
more competitive market structure and outcome from separate marketing is an
33
illusion. That is, the amount of the resource, R, remains the same and each unit
holder has a claim to a proportion of the resource based on a collectively
determined depletion schedule. The scarcity value and rate of depletion remain
unchanged and the result defaults to the monopoly solution.
7
The issue of separate marketing of gas
Early in the process of gas reform in Dec 1994, the TPC (now ACCC) was
considering whether the events to date of gas reform had brought about a
sufficiently material change of circumstances that it should revoke an
authorisation. The authorisation was for “certain co-operative marketing and
production arrangements” of Cooper Basin gas. The report prepared by the
Industry Commission as part of these considerations (1995) was definitive
about one matter. Consistent with the argument in the previous section, it
asserted that any monopoly rent accruing to the co-venturers accrued as a
result of their joint ownership of given gas fields and production infrastructure.
This led the Commission to argue that, however the gas was marketed, any
monopoly rents could be captured by the co-venturers in production through
their joint control of the JVP and in particular their collective determination of
the production schedule from the resource. The JVP can capture the rent to
itself by selling produced gas to its co-venturers at the monopoly price less
some reasonable allowance for the cost of marketing. Alternatively, the JVP
co-venturers can collectively determine production at the monopoly level and
allow the monopoly rent to accrue to themselves at the marketing stage in their
pricing of the scarce resource.
Though it contained some comments about price discrimination, the IC report
dwelt mostly on the case of so called ‘weak monopoly’ power where monopoly
rents are extracted by way of the limitation of supply to a given quantity which is
then sold at a single price uniform to all buyers. Some observations are made in
Appendix Two about the case where there is some degree of price
discrimination. However in the South Eastern Australian upstream market, the
scope for price discrimination is already highly attenuated as a result not just of
legislative requirements in Victoria, but also because of intensifying competition
making the issue progressively more academic. In the case of a uniform pricing
‘weak monopoly’, the IC’s logic is hard to impugn and is supported by the
analytical material presented above.
If one of the separately marketing parties to a joint venture wishes to compete
with the other it can only do so using the gas to which it is entitled by its equity
in the JV. At any given time, it can only sell a higher proportion of the gas than
other partner(s) if they are selling less than their current entitlement. Even if the
JV contains a liberal ‘balancing agreement’ allowing the parties leeway against
34
each other’s entitlements in the early life of the field, it will require them to
balance by the end of the field’s life, or to buy or borrow gas from one another.
It is evident from this that the shareholders of the JVP co-venturers cannot seek
the market share held by other shareholders of the JVP:

Even in the short-term without ‘owing’ other shareholders in the JVP
that market share back within the life of the field; or

In the long term without their consent ie without buying or borrowing the
gas from them.
As the Commission put it (1995: 123)
In summary, it is not possible for a joint venture participant to initiate
competition for market share of other joint venture participants – except
with their permission.
This is trivial competition for market share that cannot be sustained within the
context of maximising the joint value of production. Thus, to the extent that
those who separately market their entitlements to gas from a JVP compete with
each other it only makes sense for them to compete to add value in marketing.
In a sufficiently deep and liquid market, each of the co-venturers can add value
in marketing on account of their marketing methods and networks spread
across a portfolio of gas production assets. But whatever the level of maturity,
depth and liquidity of the market, it can never make sense for JVP co-venturers
to compete away the scarcity rent of the gas – which is the concern that
appears to drive gas buyers’ call to force separate marketing from mature
JVPs. It is a strange kind of competition that is not for a competitor’s market
share.
Apart from the logical points that are the centre of this submission’s analysis
there is other strong anecdotal evidence that scarcity rents do not adhere to
joint marketing of separately produced gas. Indeed one may surely presume
that the active preference of most co-venturers for separate marketing is
precisely because separate marketing of jointly produced gas does not
dissipate scarcity rent and that it allows them to add value. Thus as is well
known, unless it poses unusual logistical or other problems, equity holders in
JVPs prefer to market their own liquids separately – given the ease with which
they can be brought to market.
Production joint ventures typically assign a right in each partner to own and
separately dispose of their own production entitlement. This is also true of the
Gippsland Basin JVP. The joint marketing from the Gippsland Basin arises from
the free choice of both co-venturers. There is no formal or informal agreement
between Esso and BHP Billiton to jointly market their respective production
35
entitlements from the Gippsland Basin JVP. This occurs as a matter of mutual
convenience in an ongoing way with either party free to market separately
should it wish to do so. In effect, the parties continue to agree to jointly market
each time they sell gas. It is hard to believe that the parties closest to the
decision as to whether or not to separately market jointly produced gas see it as
necessary to the extraction of the scarcity value of the resource. By contrast
the decisions which do affect the scarcity value of the resource are taken at the
production level, and painstakingly and elaborately protected by binding, long
term legal agreements.
Given the preference of co-venturers in the Gippsland Basin JVP for marketing
jointly, and their in principle preference for marketing separately, the conclusion
must be that the kinds of considerations set out in section 5 raise the cost of
separate marketing – with no commensurate benefits. Whether those costs
would be raised by a small or large amount is an open question – and would
depend essentially on the extent to which the putative separate marketing were
permitted to default back towards parallel marketing.
In such a scenario, the joint venture in production would make less profit but
only in a ‘beggar my neighbour’ manner. In fact everyone would be worse off
as the monopoly increased its price to respond to the higher cost of marketing
gas and supply fell in the market. This less efficient outcome is illustrated in the
following diagram where the average and marginal costs faced by the suppliers
of gas rise – to reflect higher marketing costs – with pricing to the separate
marketers so as to capture the scarcity rent accruing to the gas they have
jointly produced. Here the average and marginal costs rise from the unbroken
lines in the diagram to the broken lines in the diagram.
36
Figure 7.1: The economics of separate marketing without price discrimination
PSM
PJM
Cost/Price
MC.
AC.
MR.
QSM
QJM
D.
Quantity
Supply falls from Qjm to Qsm with prices rising accordingly from Pjm to Psm.
Opportunities to refute the IC’s approach have not been taken
The basic insight encapsulated in the quote from Robert Bork at the outset of
this submission does not appear to have been challenged. When it
commissioned the IC report on ‘certain arrangements’ in the Cooper Basin the
(then) TPC was sympathetic to the idea of requiring JVPs to market separately
where possible. It appears to have been largely unmoved by the IC’s
controvertion of its preferences. Some gas customers and their representatives
seem similarly unmoved (See Section One above). Yet none seem to have
dealt with the IC’s straightforward propositions directly, and none have refuted
them.
Even before the sympathetic audience of the ACCC, major gas consumers
have shied away from the opportunity of refuting the Commission's logic or
demonstrating how the market is ready for separate marketing of co-venturers.
The ACCC reported as follows in its recent authorisation of joint marketing in a
North West Shelf project (1998a: 32)
The Commission organised a round table discussion with Western
Power, its consultants and the applicants in an attempt to determine if
the balancing mechanisms proposed had any relevance to the NWS
situation and might facilitate separate marketing.
Unfortunately, Western Power withdrew from the proposed discussion at
the last minute, due to the imminent entry of a price arbitration with the
37
NWSJV. Western Power was not prepared to allow its consultants to
participate in the discussion with the applicants, nor in a private
discussion with the Commission.
In summary, no-one has been able substantively to counter the
applicant’s proposal that separate marketing of gas by the NWSJV is not
currently viable in WA. Given the substantial public benefits associated
with the proposed expansion and the assurance of the applicants that the
expansion will not proceed unless they are authorised to co-ordinate their
marketing, Clause 1 of the proposed authorisation set out below
authorises coordinated marketing by the Joint Venture parties.
Notwithstanding these observations and though it accepted the difficulty of
separate marketing in insufficiently deep and liquid markets, the ACCC made
the following comment in its Submission to the Gas Reform Implementation
Group on Upstream Issues (1988b: 9).
Clearly, where possible, separate marketing is more competitive than
joint marketing and is to be preferred. By creating price competition
between as many suppliers of gas as possible, separate marketing
should result in lower prices and more choices for consumers and users
of gas.
This is an enigmatic comment in the light of our argument above. The ACCC
accepts that where co-venturers do not desire it, separate marketing can
increase costs – to the point of jeopardising substantial investment. Yet it
appears to hold to a faith that separate marketing can intensify competition
against the evidence of reports it has commissioned, but not refuted.
8
Conclusion
In conclusion, the existence of rents arising from the exploitation of depletable
resources is not an indicator of market imperfections but is an attribute of the
greater scarcity of the resource compared with reproducible goods. This
scarcity rent accrues to production, as do any rents that might be attributable to
some market power in the ownership and exploitation of the resource.
However, as demonstrated in earlier sections, the process of exploration,
development, and technical optimisation, of a gas field is complex and requires
substantial, risky initial and ongoing investment.
Generally this expenditure is only undertaken because, if it is successful, some
rents will be realised in production. Where this dynamic underpins the
development of the industry, great care must be taken in distinguishing
between rents ex ante and ex post. Rents may represent no more than a fair
return on the substantial investment across all areas of discovering, developing
38
and exploiting a depletable resource. To that extent, actions that increase costs
ex post are likely to reduce field exploration and development.
Policy makers could hardly be congratulated on a result, in which competition
has clearly come to be seen as an end rather than a means. This, more
‘competitive’ state of affairs involves higher costs and prices – and of course
lower economic welfare. Ironically increasing competition in the short term
would most likely result in lower expenditures in exploration and development in
the future – ultimately strengthening the market power of incumbent producers
and entrenching higher rather than lower consumer prices.
39
References
ABARE (1999), Australian energy: Market developments and projections to
2014-15, ABARE Research Report 99.4, Commonwealth of Australia,
Canberra.
ABARE (2001), Australian energy: Projections to 2019-2020, ABARE Research
Report 01.11, Commonwealth of Australia, Canberra.
ABARE (2002), Australian gas supply and demand balance to 2019-20, ABARE
report for the Commonwealth Department of Industry, Tourism and Resources,
Commonwealth of Australia, Canberra.
ABARE (Various years), Australian commodity statistics, Commonwealth of
Australia, Canberra.
ACCC (1998a), Determination “Application for Authorisation North West Shelf
Project”, Authorisation No: A90624, File No:CA97/19 No: A90624, 29 July.
ACCC (1998b), Submission to the gas reform implementation group on
upstream issues, October 1998.
Australian Gas Association (2002a), Submission to the Energy Market Review:
Keyissues for the Energy Market Review – Responses to Issues Paper,
Canberra, www.energymarketreview.org/submissions.htm.
Australian Gas Association (2002b), Gas Statistics Australia 2001, Australian
Gas Association, Canberra.
BIE (1993), Waste management and landfill pricing: A scoping study,
Occasional Paper 12, AGPS Canberra.
Bork, R. H. (1954). “Vertical integration and monopoly”, University of Chicago
Law Review, vol.22, 1954, pp.157-201 reproduced in Yamey (1973).
Collins, G. and Powell, A. (2002), A Guide to the Petroleum Industry in Victoria,
Department of Natural Resources and Environment, Victoria.
Conrad, J.M. and Clark, C.W. (1987), Natural resource economics: Notes and
problems, Cambridge University Press, Cambridge UK.
Council of Australian Governments (2002), Energy Market Review Issues
Paper, Commonwealth Of Australia, Canberra.
EIA (1995), Oil and gas development in the United States in the Early 1990’s:
An expanded role for independent producers, Office of Energy Markets and
End Use, U.S. Department of Energy, Washington DC,
www.eia.doe.gov/oiaf/ieo/index.html.
40
EIA (2000), The U.S. natural gas industry at a glance, PowerPoint Presentation,
www.eia.doe.gov, (search: presentations).
EIA (2001a), U.S. crude oil, natural gas, and natural gas liquids reserves, 2000
Annual Report, December, Energy Information Administration, Office of Oil and
Gas, Washington, DC.
EIA (2001b), U.S. natural gas markets: Recent trends and prospects for the
future, Office of Integrated Analysis and Forecasting, U.S. Department of
Energy, Washington DC, www.eia.doe.gov/oiaf/ieo/index.html.
EIA (2002), International energy outlook 2002, Office of Integrated Analysis and
Forecasting, U.S. Department of Energy, Washington DC,
www.eia.doe.gov/oiaf/ieo/index.html.
Energy Intensive Users Group (EIUG), 2002. ”Concerns about gas prices and
possible improvements to market efficiency”, Response to DTI Gas
Consultation” 28 February at www.eiug.org.uk/publics/Consultation.pdf.
Eurogas (2002), Annual Report 2000, www.eurogas.org/index2.htm.
ExxonMobil, (2002). “Submission to the COAG Energy Market Review”, 18 th
April.
Hanley, N., Shogren, J.F. and White, B. (1997), Environmental economics in
theory and practice, Macmillan Press Ltd, Great Britain.
Independent Petroleum Association of America (2001), Natural gas production:
Where price controls failed, The Market Succeeded, www.ipaa.org.
Industry Commission, (1995). Australian gas industry and markets study,
Canberra, 6th March.
Juris, A. (1998). “The emergence of markets in the natural gas industry”, World
Bank Working Papers, No. 1895, March 1, World Bank.
King, S. and Maddock, R. (1996), Unlocking the infrastructure: The reform of
public utilities in Australia, Allen & Unwin, NSW Australia.
OECD (2000), International Energy Agency regulatory reform: European gas,
www.iea.org/books/studies/2000/refgas2000.pdf.
Perman, R., Ma, Y. and McGilvray, J. (1996), Natural resource and
environmental economics, Addison Wesley Longman, London UK.
Upstream Issues Working Group (1998), Report of the UIWG to ANZMEC and
COAG.
Yamey, B. S., 1973. Economics of industrial organisation, Penguin, London.
41
Appendix One: Derivation of optimal depletion paths for a
depletable resource
Following the exposition presented in Conrad and Clark (1987; Chapter 3,
pp.117-121):
R is initial reserves;
R(t) is the reserves remaining at time t (R(0) = R);
r is the discount rate assumed equal to the interest rate;
q(t) = D(p(t)) is the demand function;
p(t) is the price at time, t;
p(0) is the price at time 0;
T is the time at which all reserves are exhausted.
Under competition (producers are price takers (they cannot influence price
through independent action)) define the demand function as:
q(t )  D( p(t ))
(1)
Assuming that there are no costs to extraction, the initial reserves will be
exhausted:
T
 q(t )dt  R
(2)
0
At t=T, q(T) = 0 and:
q(T )  D( p(0)e rT )  0
(3)
Equations (1) to (3) determine p(0), T, and the entire time path of extraction.
For example, assume that D() is linear:
q(t )  D( p(t ))  a  bp(t )
(4)
q(t )  a  bp(0)e rt
(5)
q(T )  a  bp(0)e rT  0
(6)
Then:
and
Therefore:
42
ae  rT
b
(7)
q(t )  a(1  e r (t T ) )
(8)
p(0) 
and
Exhaustion of the initial reserves, R, implies:
T
 a(1  e
r ( t T )
)dt  R
(9)
0
Integration yields:
aT 
a(1  e  rT )
R
r
(10)
Given the assumptions, equation 10 determines the time, T, at which the
resource is exhausted.
The monopolists problem differs from that of the competitive firm, in that the
monopolist can influence price through altering the quantity produced.
Maintaining the assumption of zero extraction costs, the monopolist maximises:
Tm
   P(q(t )) q(t )e rt dt
(11)
0
where P(q(t) is the inverse of D(p(t)). Formulating the monopolist’s problem as
an optimal control problem, let R(t) denote remaining reserves so that:
dR(t ) 
 R  q (t ), R(0)  R
dt
(12)
The monopolist’s current value Hamiltonian may be written as:
~
 (t )  P(q(t )) q(t )   (t )q(t )
(13)
and the first order necessary conditions require:
~

(14)
 P()  P' ()q(t )   (t )  0
q(t )
~

(15)
  r (t ) 
0
R(t )
43
~

R 
 q(t )
 (t )
(16)
The expression P() + P’()q(t) is marginal revenue denoted as MR(t). Now,
equation (15) implies that:

r

(17)
that is, the current value shadow price rises at the rate of interest. By equation
(14), the current value shadow price is equated to marginal revenue at each
time, t. Therefore:
MR (t )
r
MR (t )
(18)
This implies that the monopolist extracts the resource so that marginal revenue
raises at the rate of interest. This result is obtained without assuming any
special price path compared with the competitive case.
Assuming that the monopolist faces a linear demand curve as was assumed for
the competition analysis (equation (4)), the inverse demand curve is:
a q (t )

b
b
p (t ) 
(19)
and the monopolists marginal revenue schedule is:
MR (t ) 
a 2q (t )

b
b
(20)
~
 (t )  0 implies that q(Tm) = 0. Evaluating equation (14) at t = Tm given the
inverse demand curve implies:
a
  (Tm )
b
But
(21)
 (t )   (0)e rt and
 rTm
 (0) 
ae
b
 (t ) 
ae r (t Tm )
b
 (Tm )   (0)e rT .
m
From
equation
(21),
, yielding:
(22)
44
Setting equation (20) equal to equation (22), using the result from equation
(14), and solving for q(t) yields:
q(t ) 
a
(1  e r (t Tm ) )
2
(23)
The condition on total reserves gives:
Tm
 q(t )dt 
0
aTm a(1  e  rTm )

R
2
2
(24)
To compare the exploitation profiles of the competitive and monopolistic
industries, let Tc denote the competitive exhaustion date and Tm denotes the
monopolistic exhaustion date, then:
(1  e  rTc ) R
Tc 

r
a
(25)
and
Tm 
(1  e  rTm ) 2 R

r
a
The function T 
(26)
(1  e  rT )
is an increasing function of T, so it follows that:
r
Tc < Tm
Comparison of equation (23) and equation (8) also shows that:
qc(0) > qm(0)
45
Appendix Two: Some observations about price discrimination
Based on the analysis presented in the body of the submission, there is no
obvious reason why there is a tendency to focus on separate marketing from
mature fields is a key issue for upstream competition. It is possible that the
explanation lies in concerns that the market power of JVPs is sufficiently
pronounced to facilitate extensive price discrimination. In turn, this has the
associated inference that price discrimination is inefficient – that it damages
economic welfare.
To the contrary, especially early in the life of a gas market, price discrimination
can be critical to bringing it into existence. In fact the Australian gas market is
now becoming sufficiently competitive that the issue of price discrimination is
somewhat academic. Price discrimination is undermined by genuine inter-basin
competition for the sale of gas and this is now taking place in South Eastern
Australia. This competition reflects existing or prospective pipeline capacity
linking South Eastern Australia (including the Brisbane, Sydney, Adelaide,
Melbourne and Hobart markets) to Minerva, Thylacine and Geographe, Yolla,
Gippsland and Cooper Basin gas fields – and there is the prospect of sales
from Northern and Western Australia.
As a result there is virtually no price discrimination in any of the NSW gas
contracts serviced from Longford. Gascor in Victoria takes 80% of Longford’s
gas. Intensifying competition has now put paid to whatever scope existed for
price discrimination by Esso in the Victorian market. In fact even if price
discrimination were possible within the market, Esso is prohibited from price
discriminating with Victorian customers by the Significant Producer Legislation
which itself restricts its direct access to gas customers.
This having been said, it seems appropriate to explore the issues analysed in
the sections above in the case where JVP co-venturers choose to market jointly
and to price discriminate. Price discrimination is widely practiced and, as was
accepted in the Hilmer report, is critical to the efficiency of many industries
where fixed costs are a substantial share of total costs.
It allows the owner of an asset to sell the products or services of that asset to
customers at differential prices depending on their willingness to pay. Thus a
higher per unit contribution to the fixed costs of operation can be made by those
firms who need its output most while a lower contribution can be made by firms
who are more indifferent. Thus for instance a cement factory might choose to
burn used tyres instead of natural gas, whereas another buyer – for instance a
peak load power station in a residential area – has no such easy or cheap
choice. Accordingly the peak load electricity generator would be prepared to
46
pay a higher price for the gas. Thus, in the absence of the kind of competition
between producers which is coming to characterise the South East Australian
market, or any opportunity for firms receiving lower gas prices to on-sell to the
higher price customers, price discrimination can occur.
Apriori there is no way of deciding whether this price discrimination is more or
less efficient than selling at a single price. On the one hand if this level of
discrimination – or the expectation that it may be possible – were necessary to
have funded the original investment then it will be strongly efficiency enhancing.
On the other hand in practice price discrimination can never be perfect. Thus
the higher price to the peak load power generator is likely to depress its output
a little from its optimal point, though the gas seller has the incentive to make the
price discrimination match the buyer’s gas demand as accurately as possible.12
In passing it is worth noting the asymmetry of this result. If it is efficiency
impairing, it is likely this is a relatively small effect as those paying the highest
prices are doing so precisely because they are the least price sensitive. On the
other hand, if it is efficiency improving, interfering with price discrimination could
prejudice the viability of the gas development itself. The shallower the market
which is being robbed of this new source of supply, the stronger the efficiency
costs of preventing the development.
In the diagram below, price discrimination enables a producer to charge the
least price elastic customers the most. It enables them to meet most of the
fixed costs of the development and also enables the producer to sell gas right
down to a price which is close to marginal cost – to the most price sensitive
customers. Thus a price discriminator will produce to the level Q pd whereas the
same producer constrained to sell at a single price can only produce to the level
Qsp.
Several things may be noted from the diagram.

Output is lower without price discrimination as more of the fixed cost must
be imposed upon more price sensitive customers.

The ‘consumer surplus’ which would be available to the customers with the
least price responsiveness with a single price is captured by the price
discriminator. This may be necessary for project viability. In the diagram,
the Demand curve lies above the average cost curve where marginal
revenue equals marginal cost (MR=MC). This is for the sake of illustration
for production is never viable at a single price at any point where demand is
not greater than average cost. Price discrimination relaxes this condition.
It could do so by giving the buyer marginal price reductions as the buyer’s demand
expanded.
12
47
Projects become viable whenever sufficient consumers can be aggregated
to share between them the fixed costs of the project – in addition to the
variable costs that will be charged to all consumers. This could be the case
where the demand curve lay everywhere below the average cost curve.

It follows from the above condition, that the efficiency of price discrimination
is also important. Something that interferes with the efficiency of price
discrimination can reduce the level of output from the project and/or
threaten its viability.
Figure A2.1: Production from a field with and without price discrimination
Cost/Price
PSP
MC.
AC.
MR.
QSP
D.
QPD
Price discrimination and separate marketing
Assume that a JVP were able to exercise some price discrimination in the
market. What would be the effect of forcing the co-venturers in the JVP to
market separately? It would appear at first blush that constraining joint
venturers in production to market gas separately would undermine price
discrimination. Thus if BHP Billiton and Esso were each purchasing their gas
from the joint venture in production at Longford on equal terms, it seems likely
they would compete most vigorously with each other to sell gas to the
customers paying the highest prices.
They would each offer to sell the gas to these customers at lower prices than
their rival until they were no longer higher prices.13 According to this scenario
In economic jargon, they are Bertrand competitors responding to each other’s conduct in the
market by adjusting their price. (Cournot competition – adjusting to one’s competitor by
13
48
and ruling out game theoretic strategic interaction for the sake of the analysis,
the higher prices would all converge to a single price. It would be the lowest
price that was viable in marketing and firms that had been receiving prices
below this price would face price rises to this price. If price discrimination had
been implemented efficiently in the first place, this would lead to lower gas
consumption amongst users previously paying lower prices – though those
previously paying higher prices would presumably increase their consumption
somewhat.
This single price outcome would certainly lower returns to the gas producers
and marketers compared with their initial returns. In a shallow market that
permits some price discrimination, it seems likely that this tendency towards a
single price outcome would reduce efficiency as it would prevent the efficient
sharing of the fixed costs of future exploration and production.
In fact however even here, the joint venture in production can price its gas to
the separate marketers to frustrate this one price outcome. In principle it can
retain all the rents it accrued before its co-venturers were forced to market
separately. It can do so by selling the gas at prices that fall with total sales so
as to shadow the demand curve as illustrated in the diagram.
The joint producers make the gas available to the joint sellers to purchase at
the price and quantity they consider can be achieved from the highest paying
customer (less a nominal margin for marketing). This price is given by the
intersection of the demand curve and the price axis and a quantity of gas equal
to Q1 is sold at this price, whereupon the price falls to P1 until it falls to P2 at Q2
and so on. Note, the price of the gas to gas marketer A at any level of output is
a function of the total output not of sales to that particular marketer. As can be
seen, it is only viable to purchase the most expensive gas for sale to the
highest price customer. Accordingly the joint venture in production has both
directed gas to that customer and ensured that it receives the best price it can
for that gas (less a nominal margin for marketing) – and so on down the
demand curve.
changing the level of one’s production – is ruled out as the separate marketers share the one
source of product from the JVP.)
49
Figure A2.2: Pricing to maintain JV market power
As is the way with this kind of reasoning, the tools used are simplified and the
examples may seem somewhat strained. It is not claimed that this price
discrimination at the production stage would unfold in a seamless way as
indeed it does not in real life, even with joint marketing. It seems likely that
there would be more difficulties accurately price discriminating in this way than
is possible with joint marketing.
The claim made however, is that as the joint venture in production sought to
capture what rent it could with this pricing behaviour, there can be no
presumption that the errors that the crudeness of its method forces upon it
would be efficiency enhancing. Even if price discrimination were harming
efficiency, poorly practiced price discrimination could not be expected to harm it
less – and could well harm it more. It would further impede the efficient
transmission of signals from gas consumers to gas producers which is the
essence of efficient marketing. It could prejudice the viability of projects – which
would generate gas demand and also projects to generate gas supply – the
development of fields.
There would also be efficiency losses where:

sellers sought a particular price and either wrongly judged buyers’
willingness to pay, or

either buyer or seller engaged in strategic behaviour which did not reduce
its costs in the short-term, but was designed to improve its bargaining
position over the longer term.
50
Of course as the efficiency of price discrimination degrades, where the joint
venture producers are kept further away from their ultimate customers, some
buyers will a receive a gas price which is a little lower than they would have
achieved with more accurate price discrimination through joint marketing. On
the other hand this inaccuracy will lead to other gas buyers being asked to pay
more than they are prepared to pay. They will substitute away from gas, or not
expand production in each case lowering economic efficiency and output.
51
Disclaimer
The material in this report reflects Lateral Economics' best judgement in the
light of information available to it at the time of preparation. It is intended for use
in representing our client's interests, and the public interest in good public
policy. It is not intended as a basis for commercial decision making of any kind.
Commercial decisions should not be made on any information presented in this
document and Lateral Economics accepts no responsibility for any such
decisions whatsoever without further reference to Lateral Economics.
52