Transport costs and domestic gas prices · Transport costs are a real economic cost of goods...
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Transport costs and domestic gas prices October 2016
Transcript of Transport costs and domestic gas prices · Transport costs are a real economic cost of goods...
Transport costs and domestic gas prices
October 2016
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Table of Contents
1 Executive summary 1
1.1 Summary critique 1
1.2 Conclusions unaltered by market power of GBJV (to the extent it exists) 2
1.3 No compelling evidence that regulation would actually materially reduce
transport costs 3
2 Introduction 5
3 The ACCC’s economic model 6
3.1 ACCC’s assumption that Queensland gas prices ± transport costs determine
range for southern prices 6
3.2 With gas flowing north, lower transport costs are likely to raise southern
gas prices 7
3.3 Notwithstanding northern flows, the ACCC focuses on the buyer’s
alternative due to perceived lack of southern competition 11
4 ACCC economic model with GBJV market power 13
4.1 ACCC model with market power 13
4.2 Cartelisation vs unilateral action by GBJV 15
5 Evidence does not support ACCC contention 19
5.1 Gas flow and GBJV output data does not support ACCC concern 19
5.2 No explicit model of GBJV conduct provided by the ACCC 20
6 Assumed link between LNG netback and domestic prices 22
7 The relevant measure of ‘transport costs’ is shippers’ marginal (not
average) costs 24
7.1 Shippers’ marginal transport costs do not equal their average tariff 24
7.2 Regulation will not necessarily reduce ‘transport costs’ – either marginal or
average 26
8 ACCC Box 8.3 analysis of transport costs and STTM market prices is
flawed 29
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Appendix A Netback price is a long run concept 32
A.1 LNG netback price is not likely to be meaningful short run concept 33
Appendix B Withholding supply more costly absent liquid southern
markets 37
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List of Figures
Figure 1: Supply and demand scenario with northern flows ................................................ 7
Figure 2: Excerpt from section 8.2.2. of ACCC enquiry report ............................................. 9
Figure 3: Capacitytrading.apa.com.au/gasflows.aspx (6/10/16) ....................................... 10
Figure 4: Simplified ACCC model of gas market ................................................................ 14
Figure 5: GBJV restricts supply to southern states ............................................................. 16
Figure 6: GBJV restricts supply to southern states ............................................................ 17
Figure 7: SWQP western haul – firm allocation vs firm MDQ ........................................... 25
Figure 8: SWQP eastern haul – firm allocation vs firm MDQ ............................................ 26
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1 Executive summary
1. Table 6.2 of the east coast gas inquiry shows a one-for-one reduction in the price of
gas in Sydney (AUD$/GJ) associated with a 10% to 50% reduction in gas transport
costs. The ACCC speculates such a drop in transport costs could result from the
imposition of price regulation.
1.1 Summary critique
2. Table 6.2 leaves the reader with the impression that reducing transport costs would
alleviate current pressure on southern gas prices that is currently resulting from high
net demand for gas by LNG exporters (discussed elsewhere by the ACCC Inquiry).
However, this impression is not only inconsistent with the available evidence,
including as described in the Inquiry report, but is also inconsistent with the
theoretical predictions of the ACCC’s own model of how gas prices in southern states
are set.
3. In relation to Table 6.2 the ACCC states:
“Table 6.2 shows the impact of reducing transportation charges payable on
the MSP and SWQP/ QSN on the LNG netback prices in Sydney”
4. This is not an accurate description of what Table 6.2 shows. Table 6.2 shows the
reduction in Sydney prices if, and only if, gas is flowing south from Queensland
(Wallumbilla) to southern states. If gas is flowing north from southern states to
Queensland then the opposite will occur – lowering transport costs will raise
southern gas prices.
5. This is no different to any other market where the profit motive causes goods to flow
from low priced locations to high priced locations. This flow closes the gap in prices
between the locations until the price difference is equal to the cost of transport. That
is, until it is no longer profitable, after accounting for transport costs, to buy the good
cheap in the low priced location and sell it in the high priced location.
6. Consistent with this general principle, the lower are transport costs:
The lower are prices in the high priced location; and
The higher are prices in the low priced location.
7. It is therefore critical to ask which is the (relatively) low price location, southern states
or Queensland? If southern states are the (relatively) low priced location then
lowering transport costs will raise prices in southern states. This makes intuitive
sense. Transport costs are a real economic cost of goods flowing from the low priced
location to the high priced location. The higher is this economic cost the smaller will
be the flow and the more of the good that is retained for sale in the low price location.
2
8. The evidence presented in the ACCC Inquiry clearly suggest that, in fact, southern
states are the (relatively) low priced location and that gas is flowing north from
southern states to the higher priced Queensland market. This is precisely as one
would expect given, as the ACCC itself states: 1
It is uncertain if the rapid growth in the combined demand of the three LNG
projects will be matched by an increase in gas production over the life of the
LNG projects. This has precipitated uncertainty about the future supply-
demand balance in the east coast gas market. This uncertainty has been
exacerbated by GLNG purchasing substantial volumes of gas in the
domestic market over the past five years to supplement production from its
currently inadequate reserves. A large portion of this gas is from the
Cooper Basin which historically supplied the southern domestic
market. These purchases are reducing the volume of gas available to the
domestic market and disrupting gas flows in the southern states. [Emphasis
added.]
9. Given these facts, a reader of the ACCC Inquiry report would be misled if, on
reviewing Table 6.2, they concluded that lowering transport costs would ameliorate
the price rises experienced in southern states due to net demand from LNG exporters.
Quite the opposite is true, lowering transport costs would exacerbate price rises in
southern states driven by high net demand from LNG exporters.
1.2 Conclusions unaltered by market power of GBJV (to the
extent it exists)
10. A reader of the ACCC Inquiry report may take away the impression that this
fundamental conclusion of standard economic analysis is somehow negated by virtue
of the ‘market power’ that the ACCC alleges is being wielded by the largest southern
gas producer, the Gippsland Basin Joint Venture (GBJV).2
The gas users in these states are becoming overly dependent on the jointly
marketed GBJV gas. If their alternative to dealing with the GBJV is to
transport gas from Queensland, southern users may have to pay
considerably more for gas than they are otherwise likely to pay in a
competitive market. This is exacerbated by the high cost of
transportation. [Emphasis added.]
11. However, references to a lack of competition between southern gas producers causing
southern prices to equal Queensland prices plus transport costs (the maximum LNG
1 ACCC, Inquiry into the east coast gas market, April 2016, p. 24.
2 ACCC, Inquiry into the east coast gas market, April 2016, p. 18.
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netback price) are never explained in detail or in the context of a formal economic
model. We develop a formal economic model in this report and find that:
There are strong theoretical reasons to be sceptical about the ability of southern
gas producers (acting in concert or GBJV acting unilaterally) to raise the price of
gas up to the maximum LNG netback price in circumstances;
The evidence reported in the ACCC inquiry suggests that this has not occurred.
12. In relation to the first point, price manipulation would require either a cartel of
southern producers agreeing to restrict supply or GBJV significantly restricting its
own supply at great cost to itself. In relation to the second point, there is no evidence
provided of either outcome and, indeed, the ACCC inquiry states that GBJV sales are
at record levels. Moreover, the fact that we are seeing gas flows from south to north,
as the ACCC Inquiry itself reports, demonstrates that southern producers are not
wielding market power to raise southern prices above Queensland prices.3
13. It follows that the ACCC cannot simply allude to a lack of competition between
producers as a reason to focus on the higher of the two southern state LNG netback
prices. Given gas flows north, the lower of the two netback prices is relevant – and in
that scenario high transport costs actually lower wholesale gas prices in southern
states.
1.3 No compelling evidence that regulation would actually
materially reduce transport costs
14. The ACCC does not present any compelling evidence that regulation would actually
reduce transport costs. The ACCC appears to base its conclusion largely on the fact:
On two pipelines that have already recovered their construction costs,
pipeline charges were 50–80 per cent higher than a charge based solely on
the cost of recovering the forward looking cost of operating and
maintaining the pipeline.
15. In our view, there is no reasonable basis upon which a regulator would deny any
future return on an asset when that asset is first subject to regulation (i.e., set the
compensation to owners as if the asset at zero value (as if the owners, in fact, owned
nothing of value)).
16. If the ACCC did seek to impose regulation in this manner then it is likely that long
run gas transport costs would rise (not fall). This is because such a regulatory stance
will discourage new investments in pipelines (be they regulated or not). (As thought
3 No retailer/customer with load in Queensland would buy gas in southern states at the Queensland price
plus transport cost and, on top of this, incur transport costs back to Queensland. This would be irrational
given that they could simply buy at the Queensland price (saving two times transport costs).
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experiment, imagine the impact on residential construction if investors perceived
that once a regulator had determined initial investments to have been fully recovered
rents could only cover property maintenance costs.) The ultimate likely impact is that
pipelines become capacity constrained due to lower investment in capacity (on
existing and new pipelines). In this situation, marginal transportation costs would
increase to approach infinity.
17. In this regard, we note that the ACCC refers to the existence of 15-year no-coverage
determination provisions for greenfields pipeline projects as a way of reducing this
risk to incentives for new investment.4 We consider that the ACCC’s signalled
position in the Inquiry, if actually carried out (or perceived as likely to be carried out),
would eliminate any benefits whatsoever from that protection. This is because the
ACCC’s signalled position is that any revenues earned during the ‘holiday’ can be used
by the regulator to justify setting a lower regulatory asset value at the end of 15 years.
This renders any ‘regulatory holiday’ meaningless. In fact, as explained in our
companion report, it would actually create worse incentives than if the pipeline was
regulated from day one.
18. Finally, we note that the ACCC’s estimate of transport costs in Table 6.2 are based on
the average cost of shippers’ take-or-pay contracts with pipelines assuming a 100%
load factor.5 In reality, once a shipper enters into a take-or-pay capacity contract
then, provided the shipper has unused capacity within the contract, their marginal
cost of shipping gas is close to zero. Based on data provided to the ACCC inquiry by
APA, spare capacity is the norm on the SWQP. On this basis, the actual role of
transport costs in price formation in the southern states is likely to be minimal – given
that marginal volumes can be shipped between locations at close to zero cost under
existing shipping contracts.
4 ACCC, Inquiry report, p. 137
5 See footnote 30 on page 35 of the ACCC Inquiry report.
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2 Introduction
19. APA has asked CEG to review the economic analysis that underpins Table 6.2 in the
ACCC’s report “Inquiry into the east coast gas market”. In Table 6.2 the ACCC
presents analysis that purports to show that reductions in gas pipeline transportation
charges, resulting from the application of regulation, would result in equivalent
reductions in prices paid by consumers in southern states.
20. This report has the following structure:
Section 3 sets out a formal economic model that underpins the ACCC
conclusions. This model demonstrates that the ACCC’s focus on the conclusion
that reducing transport costs would reduce gas prices in southern states. The
opposite conclusion holds if, as has been the case, gas has been flowing north
from southern states into Queensland;
Section 4 asks the question as to whether the existence of market power by GBJV
alters this conclusion (as it appears the ACCC may be assuming)? We conclude
that the conclusion holds independent of market power held by GBJV and we
also raise theoretical reasons to be sceptical about the existence to an
incentive/ability of GBJV to raise southern gas prices above competitive levels;
Section 5 notes that much of the evidence the ACCC inquiry reports suggests that
that GBJV has not restricted supply in the way it would have to raise southern
gas prices above competitive levels;
Section 6 provides a discussion of why the ACCC’s reliance on a liquid
Queensland gas market at the LNG netback price is unlikely to be true in practice;
Section 7 provides a discussion of the ACCC’s assumption that short term trading
(STTM) markets are liquid markets. We are instructed that this assumption is
wrong and section 7 steps through the implications of this for the ACCC’s
analysis.
Section 8 discusses why the ACCC’s assumption that regulation will reduce
transport costs is not well founded - either at the level of average costs or, the
more relevant for economic consequences, marginal cost.
21. I have read the Guidelines for Expert Witnesses in Proceedings of the Federal Court
of Australia and confirm that I have made all inquiries that I believe are desirable and
appropriate and no matters of significance that I regard as relevant have, to the best
of my knowledge, been withheld.
Dr Tom Hird
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3 The ACCC’s economic model
3.1 ACCC’s assumption that Queensland gas prices ±
transport costs determine range for southern prices
22. The ACCC describes a market for gas in which there is perfectly elastic demand for
gas in Queensland.6 This assumption is motivated by the fact that the Queensland
gas market is connected to the global energy market via LNG exports. It is assumed,
that gas can be diverted to the LNG export market as soon as prices in southern states
(plus transport costs to Queensland) fall below the Queensland gas price (which is
itself assumed to be determined by global energy markets).
23. The ACCC describes this as the ‘sellers’ alternative’, meaning that southern gas
producers always have the alternative of selling gas into the Queensland market and,
therefore, southern prices cannot fall below the Queensland price less the sellers’
additional transport costs of delivering to Queensland.
24. Similarly, it is assumed that gas will be diverted from LNG exports to the southern
states if prices in the southern states rise above the Queensland gas price by more
than the cost of transporting gas from Queensland to the southern states. The ACCC
describes this as the ‘buyers’ alternative (i.e., buyers will refuse to pay than this for
gas purchased from southern producers).
25. As a consequence of this assumed dynamic, prices in the southern states are bounded
by the value of gas to LNG exporters (the LNG netback price) plus/minus the costs of
transporting gas from/to Queensland. That is, bounded by the sellers’ and buyers’
alternatives of selling/buying to/from Queensland.
26. It follows that the impact of transport costs on prices in the southern states is
ambiguous. Higher transport costs will tend to raise prices in southern states if gas
is being ‘imported’ from Queensland into southern states. By contrast, higher
transport prices will tend to lower prices in Queensland if gas is being ‘exported’ from
southern states to Queensland.
6 This assumption also implies that there is a perfectly elastic supply of gas from Queensland available to
southern state customers at the Queensland price plus transport costs. This is because perfectly elastic
demand in Queensland implies that as soon as the price in southern states exceeds the ‘LNG netback’ price
Queensland LNG exporters will, in effect, divert their gas from LNG exports to southern states.
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3.2 With gas flowing north, lower transport costs are likely
to raise southern gas prices
27. The evidence appears to support a belief that future gas flows will, at least much of
the time, tend to be from southern states north into Queensland. On this basis, it can
be expected that higher transport costs will actually lower the price of gas in southern
states. This is because higher transport costs will tend to discourage “exports” of gas
from southern states to Queensland and, thereby, increase the supply of gas available
in southern states.
28. That is, with gas flowing north it is the ‘sellers alternative’ that is more likely to be
driving southern prices and the sellers’ alternative is lower the higher is the sellers’
transport costs to Queensland. This outcome is illustrated in Figure 1 below which
provides a graphical supply and demand analysis.
Figure 1: Supply and demand scenario with northern flows
29. In Figure 1 the southern gas market would, absent interconnection with Queensland,
be in equilibrium at the intersection of the supply curve for southern producers
(reflecting their marginal costs of supply) and the demand curve for southern
consumers.
30. As drawn, this point of intersection is below the sellers’ alternative. Consequently,
once the potential for interconnection with Queensland is introduced into the
analysis the price in the southern states rises to be equal with the sellers’ alternative.
The effect of this is that southern consumers reduce consumption relative to what it
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would otherwise have been and southern producers increase production. The excess
supply of gas in southern states so created (QSQ) then flows north to Queensland.
31. This example clearly illustrates how higher northbound transport costs reduce
southern prices.
32. It follows that, if one is attempting to analyse the impact of a change in transport costs
on southern state gas prices it is important to understand whether gas flows are likely
to be northward or southern. If the former then lowering transport costs will, other
things equal, raise southern gas prices.
33. In this regard we note the ACCC’s statement that significant investment has been
made in order to increase the potential for southern gas to flow to Queensland.7
In total, these recent investments are estimated to have cost $900 million,
with over 50 per cent of that investment occurring to enable more gas from
Victoria to flow north into New South Wales and up to Queensland. Of the
projects listed, the expansion of the export capacity of the DTS has involved
the most significant investment, with $260 million reportedly being spent
to expand the export capacity for various shippers over the last 3.5 years.
34. Making such significant investments suggests that market participants believe that
gas will tend to flow north from the southern states a meaningful percentage of the
time. The ACCC explicitly discusses a change in the nature of gas flows from north to
south historically being reversed in recent times.
7 ACCC, Enquiry into the east coast gas market, p. 93.
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Figure 2: Excerpt from section 8.2.2. of ACCC enquiry report
Emphasis added.
35. We also note that the AEMC Gas Bulletin Board Shipper8 list has only Santos, Origin,
AGL Wholesale Gas and GLNG Operations as shippers with contracted capacity on
the SWQP. Notably, the GBJV partners are not listed suggesting that the GBJV
partners are selling their gas in southern locations (typically at the well-head) and, to
the extent that GBJV gas reaches Queensland it is because third party shippers are
transporting it in order to sell it at a higher price.
36. Elsewhere, the ACCC refers to an increased tendency for northward flows affecting
competition between pipelines: 9
8 http://www.gasbb.com.au/Reports.aspx - accessed on 13 October 2016.
9 ACCC, Enquiry into the east coast gas market, p. 93.
10
The increase in the volume of gas flowing north from Victoria is also
resulting in changes in the competitive dynamics with competition
emerging between:
the EGP and MSP via the DTS for deliveries to Sydney and Canberra
the western (SEA Gas/MAPS), central (DTS/MSP) and eastern
(EGP/MSP) routes for deliveries to Moomba.
37. This is consistent with the flows shown on APA’s capacity trading website access on
6 October.
Figure 3: Capacitytrading.apa.com.au/gasflows.aspx (6/10/16)
38. It follows that a reasonable presumption is that lowering transport costs will tend to
raise southern state gas prices, or, at least, will do so in reasonably common market
circumstances.
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3.3 Notwithstanding northern flows, the ACCC focuses on
the buyer’s alternative due to perceived lack of
southern competition
39. Given the facts outlined above, one might reasonably expect that the ACCC, when
analysing the impact of lower transport costs on southern gas prices, would give
equal, if not more, weight to the potential for this to raise southern gas prices.
However, notwithstanding the economic logic of its theoretical framework, the ACCC
gas inquiry report tends to focus on the potential for low transport costs to lower gas
prices in southern states.
40. The ACCC’s focus on scenarios where high transport costs raise southern prices
appears to be based on a belief that there is not sufficient competition between gas
suppliers in southern states. On this basis the ACCC appears to believe that, even if
gas is flowing north into Queensland, southern customers will be charged a price that
is equal to the buyers’ alternative (Queensland price plus southbound transportation
costs).
41. Such an outcome is not possible in a competitive gas market. In a competitive
southern gas market, gas will only flow north if the price in the south is lower than
the Queensland price (and, indeed, lower by more than the costs of transporting gas
to Queensland). If, in a competitive market, the price in the south was above the price
in Queensland no gas would flow north. That is, gas would not flow from where prices
are high to where they are low – that would be profit destroying in a competitive
market.
42. However, the ACCC is clearly envisaging a monopolised southern gas market. 10
As shown in chart 2.4, the cost of transportation between Wallumbilla and
the user’s location is creating a range of possible gas pricing outcomes in
the southern states, encapsulated by the gap between the buyer and seller
alternatives (capped at the buyer’s maximum willingness to pay and with a
floor of the marginal cost of supply). As discussed in chapter 2, the
GBJV is likely to charge domestic users in the southern states a
price approaching the buyer’s alternative in the absence of
genuine competitive constraints. (Emphasis added.)
43. The relevant reference to ‘section 2’ in justification of this view is as follows:
10 ACCC, Enquiry into the east coast gas market, p. 113.
12
The competitive dynamics in the southern states are deteriorating
considerably.
…
In this environment, domestic users and retailers in the southern states are
becoming highly reliant on off-shore gas production from the Gippsland
Basin. The GBJV holds a large portion of the remaining uncontracted low
cost conventional gas reserves in the east coast gas market and is now a key
source of gas available in the short- to medium-term. The GBJV has given
evidence that for 2017 it has sold the highest volume of gas in the history of
the Gippsland Basin. Until these competitive dynamics change, the
GBJV will have the bulk of market share and will hold significant
market power in the southern states. (Emphasis added.)
44. It appears to be on this basis that the ACCC chooses to focus primarily on a scenario
where lowering transportation costs will lower prices in southern states (rather than
the reverse). That is, the ACCC appears to be relying on the assumption that market
power held by GBJV means that southern gas customers will have to pay the ‘buyers
alternative’ based on the cost of importing gas from Queensland in all market
circumstances (even if gas is, or would typically be, flowing north into Queensland).
45. This is precisely how the ACCC introduces its analysis in Table 6.2 on page 115 of the
enquiry report. That table shows a one for one reduction in the delivered price of gas
in Sydney as a result of lower transportation costs (which the ACCC assumes will flow
from regulation). The focus on falling prices as a result of falling transportation costs
is justified on the basis that:
Critically, in an environment where domestic gas users in the southern
states are likely to pay a price approaching the buyer’s alternative, the
maximum price they may have to pay is reduced.
46. ACCC Chairman, Mr Rod Sims, is explicit about this assumption in a recent speech. 11
Gas users in the south will be forced to bargain with the Gippsland Basin
Joint Venture in a market where their only alternative may be to
source gas from Queensland. In this scenario, the Gippsland Basin Joint
Venture will want to price up to the delivered price of this alternative. This
will amount to the LNG netback price at Wallumbilla plus the cost of
transport to ship it south. [Emphasis added.]
11 Mr Rod Sims, Keynote Address: South East Asia Australia Offshore & Onshore Conference, 15 September
2016.
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4 ACCC economic model with GBJV
market power 47. The ACCC does not provide a formal economic analysis of how the GBJV can force
the price in southern states to be equal to the buyers’ alternative – even when this
would not be the case without the GBJV exercising market power. This section
provides such a formal analysis and, in doing so, establishes the necessary conditions
for this to be the case.
48. We conclude in this section that these conditions are unlikely to hold in general and,
in section 5, that the available evidence suggests that they do not hold in fact.
Therefore, we conclude that the ACCC’s focus is misplaced. Lowering transport costs
is likely, if anything, to raise southern gas prices charged by producers.
49. This does not imply that we consider that gas transport prices should be set on the
basis of targeting gas supply prices in southern states (or elsewhere). In our view,
this is a largely irrelevant consideration to good policy in terms of the gas
transmission sector. However, it does appear to be a focus of the ACCC inquiry and
subsequent media commentary by ACCC officials. It is purely as a correction to the
economic reasoning underpinning those positions that this section targeted.
4.1 ACCC model with market power
50. The ACCC’s (implicit) model can be described graphically using the simplified supply
and demand framework set out in Figure 1 above. Figure 4 is the same as Figure 1,
however, in Figure 4 southern gas producers restrict supply of southern gas – forcing
southern prices up the southern demand curve until they are equal to the buyers’
alternative of transporting gas from Queensland.
51. The necessary restriction in supply (relative to competitive southern gas output) is
QSR in Figure 4. This restricts overall output to QS
S – at which point the price that can
be charged is equal to the buyers’ alternative of importing gas from Queensland.
14
Figure 4: Simplified ACCC model of gas market
52. Under this strategy, southern gas producers gain additional revenues from the higher
prices (represented by the area ABCD in Figure 4). However, southern producers
sacrifice profits on sales that they would otherwise have made (QSR) - with the
minimum value12 of reduced profits represented by the area of the triangle DEG. This
triangle represents the difference between the price at which the restricted gas could
have been sold (sellers’ alternative) and the marginal cost of production (including
any opportunity cost of production today reducing potential future production).
53. As drawn, the area ABCD is clearly larger than DEG and, therefore, this strategy is
overall profitable for the southern producers. However, as explained in section 7, the
difference between sellers’ and buyers’ alternatives will reflect marginal
transportation costs (not average transportation costs). Therefore, it is not obvious
that this gap will be very large at all (making the strategy less likely to be profitable).
54. In any event, the difficulty with such a strategy, even if it were to be profitable in
theory, is coordination between producers. If supply was restricted to QSS then the
prices that southern producers would be able to earn from selling more to southern
customers would be above their marginal cost by the amount represented by the
distance AE in Figure 4.
12 This is the minimum value because it assumes that all restrictions in supply are sourced from the highest
cost producers. However, in reality the highest cost producers will not be willing to shoulder all of the
responsibility for restricting supply. Consequently, the other cartel members would need to compensate
them with side payments or all producers would have to restrict supply (even low cost producers) which
would make the foregone profits higher than the triangle DEG.
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4.2 Cartelisation vs unilateral action by GBJV
55. The gap between price and cost creates an incentive for suppliers to increase supply
(i.e., to compete). If all southern gas producers are to share in the restriction of supply
then they must enter into a cartel arrangement that specifies each member’s
maximum output. Moreover, once this agreement is made it must be enforceable.
That is, there must be a method by which other members of the cartel can observe
such ‘cheating’ and punish the relevant gas producer.
56. With a homogenous product, if a cartel member cheats the only mechanism for
punishment is typically an increase in supply by other members (pushing down the
market price for all concerned). This makes punishment costly and, if the cheating
cartel member has entered into a long term supply agreement, that form of
‘punishment’ will have little effect on them. In addition, the large number of non-
GBJV producers and their disparate sizes would make the coordination of the cartel
very difficult.
57. The ACCC does not express any concern, at least explicitly, about cartel conduct
amongst southern producers. Therefore, we can assume that the ACCC’s primary
mechanism for the restriction of supply is unilateral action by GBJV. Such a strategy
is potentially profitable for GBJV if its sales represent a large enough proportion of
total southern sales and if the price increase it can initiate is large (i.e., if the Buyers’
alternative price is sufficiently above the sellers’ alternative – again see section 7 for
why this may be unlikely).
58. While GBJV is a large producer in southern states, it is far from a monopolist.
According to Chart 2.3 on page 50 of the ACCC enquiry report the GBJV supplied 55%
of 2015 gas production in the east coast excluding Queensland. This still leaves 45%
of production in the hands of other suppliers. Moreover, given that some of this
production was exported to Queensland, non-GBJV production as a percentage of
total sales in southern states is even larger.
59. Consequently, the GBJV unilaterally restricting its supply of gas to southern
customers would, assuming GBJV is a low cost producer, be an expensive exercise in
terms of the foregone profits for GBJV of the restricted supply. This scenario is
illustrated in Figure 5 below which shows:
GBJV restricting its supply of gas by just enough such that total southern supply
(including supply from of non-GBJV southern producers) is at the point where
the prices in the southern states are just below the buyers’ alternative.
This is illustrated by the intersection of the vertical dotted line (“Supply in the
southern states after GBJV unilateral restriction”) with both:
the southern state demand curve; and
the buyers’ alternative (“PQ+ Transport costs from Q to South”).
16
Figure 5: GBJV restricts supply to southern states
60. If implemented perfectly, GBJV will raise its profits by an amount equal to the area
of the yellow rectangle (equal to the increment to the price of southern sales
multiplied by GBJV’s quantity of southern sales post supply restriction). However,
GBJV gives up revenues with a value equal to the area of the pink rectangle (equal to
the restricted supply (QSR) multiplied by the price that would have been received for
those sales if they weren’t restricted (the sellers’ alternative)).
61. As drawn, the lost revenue is clearly larger than the revenue gain. Assuming GBJV
has low marginal costs of production13 the same will be true of profits (i.e., lost profits
on lost sales will exceed profits gains on the higher priced residual sales). Of course,
there are potential circumstances in which the profit gain could exceed the profit loss
(e.g., if the southern demand curve was steeper and/or the gap between sellers’ and
buyers’ alternative larger.
62. That said, other factors, not modelled in the above static analysis, would suggest that
GBJV withholding supply is less likely to be profitable. Critically, were GBJV to
restrict supply and raise prices in this manner, then most of the benefits flow to its
13 Note that in the context of GBJV withholding supply the triangle EDF no longer represents the lost profits.
This is because the triangle EDF represents lost profits for the industry if the highest cost producers are
the ones who reduce output. It is very unlikely that GBJV would be the only contributor to the industry
supply curve in the region denoted by QSR. At least some of GBJV’s supply withheld will have a cost on
the industry supply curve in the region QSS. That is, GBJV will have to withhold some relatively low cost
production if it were to unilaterally withhold QSR. In fact, given that GBJV is the largest producer the
natural assumption would be that GBJV has the lowest marginal supply cost of all the producers (i.e., that
is why it has expanded its output by more than the other producers).
17
southern competitors who do not have to restrict their own sales to achieve the
heightened prices. As drawn, we have assumed that the non-GBJV producers do not
increase output as a result of the higher prices. That is, we have assumed that they
maintain output at 45% of the total output pre GBJV restriction in supply.
63. This is a very conservative assumption. If non-GBJV producers did increase
production in response to higher prices then GBJV would need to restrict supply by
even more in order to have the same impact on southern prices. In fact, if non-GBJV
suppliers simply expanded along a supply curve with the same slope as in Figure 5
then, even if GBJV withdrew 100% of its supply, then the southern price would not
rise all the way to the buyers’ alternative.
64. This is illustrated in Figure 6 which is the same as Figure 5 except, instead of non-
GBJV supply remaining constant as prices rise, non-GBJV producers increase output
along a supply curve with the same slope as the industry supply curve.
Figure 6: GBJV restricts supply to southern states
65. It can be seen that, as drawn, even if GBJV withdrew 100% of its sales, non-GBJV
producers would expand by a sufficient amount to keep the southern price of gas
below the buyers’ alternative. Clearly this is not a profit maximising strategy for
GBJV.
66. We also note that there are further technical problems with the ACCC’s LNG netback
framework that, when taken into consideration, would make a supply withdrawal
strategy by GBJV less likely to be profitable. We discuss these in sections 6 and 8 and
Appendix B.
18
67. Of course, Figure 6 is, along with all of the other similar figures, purely illustrative.
We have not attempted to actually estimate the shape of the supply and demand
curves involved. It may be that non-GBJV suppliers face a much steeper increase in
costs as they increase output, at least in the short run. However, the key point is that
the ACCC needs to perform this type of analysis, using real world estimates of costs
and demand, before reaching a conclusion that GBJV has an incentive and ability to
raise price to the buyers’ alternative. Absent such analysis, the ACCC’s statements
that GBJV has an ability and incentive to set southern prices at the buyers’ alternative
is merely speculation. Moreover, it is speculation that is inconsistent with the
available evidence which we survey in section 5.
68. In summary, any unilateral restriction of supply by GBJV to southern customers
would come at a cost to GBJV. It is far from obvious that it could be profit enhancing.
19
5 Evidence does not support ACCC
contention
69. We conclude in this section that the available evidence suggests that southern gas
prices are not being set at the buyers’ alternative. Consequently, it is not correct to
assume that lower transport costs will lower gas prices in southern states. The
opposite is more likely to be the case.
5.1 Gas flow and GBJV output data does not support ACCC
concern
70. The fact that we see gas flowing from south to north (see section 3.2) is evidence that
is inconsistent with the ACCC’s contention that southern prices are being set above
the price of gas in Queensland (i.e, at the buyers’ alternative). If that was the case
then it would imply that shippers/retailers were purchasing higher priced gas in
southern states for the purpose of transporting it to Queensland (incurring additional
transport costs in the process) and selling it at a lower price in Queensland. That is,
shippers/retailers would have to be making a loss (equal to 2 times transport costs)
on all southern gas transported to Queensland.
71. In fact, if GBJV was exercising market power (with the effect of setting prices in
southern states equal to the buyers’ alternative) then the effect of this would be that
there would be approximately zero gas flowing between Queensland and southern
states (in either direction). After all, that is the purpose of the strategy the ACCC
alleges GBJV is undertaking – in effect to restrict supply until prices in southern
states are equal to prices in Queensland after adjusting for transport costs. If GBJV
achieves this then the demand for transport to/from Queensland would largely
disappear.
72. In addition, we note that the ACCC itself states that the GBJV has contracted record
sales for 2017.14
The GBJV has given evidence that for 2017 it has sold the highest volume of
gas in the history of the Gippsland Basin
73. On its face, this appears inconsistent with GBJV withholding supply in order to
generate higher prices.
14 ACCC, Inquiry in the east coast gas market, 2016, p. 50.
20
5.2 No explicit model of GBJV conduct provided by the
ACCC
74. The ACCC’s view of exactly how GBJV is exercising market power is not provided in
any formal analytical sense. However, the following statement is notable:
The gas users in these states are becoming overly dependent on the jointly
marketed GBJV gas. If their alternative to dealing with the GBJV is
to transport gas from Queensland, southern users may have to
pay considerably more for gas than they are otherwise likely to
pay in a competitive market. This is exacerbated by the high cost of
transportation. Increasing the level and diversity of supply, located close to
southern demand centres, will improve the competitive dynamics in the
south and is likely to lead to better pricing outcomes for domestic users.
[Emphasis added.]
75. This statement suggests that:
were there competition in southern states prices would be set at the sellers’
alternative; but
that the lack of “a competitive market” is causing prices to be set at the buyers’
alternative.
76. In section 4 we have provided an analytical model and a description of conduct by
GBJV (or a cartel of southern producers) that could be consistent with both of these
propositions. That model is internally consistent and a number of implications flow
from the model. These include that:
GBJV cannot push prices up from competitive levels without sacrificing sales
(and some profits on the sacrificed sales);
GBJV is not a pure monopoly supplier in the southern states and this materially
reduces the benefit/cost ratio to it of such an action because:
The benefits of higher prices flow mostly to GBJV’s competitors while the
costs in terms of lost profits on restricted sales are 100% borne by GBJV;
The benefits of higher prices are capped by competition from Queensland.
77. Based on this analysis it is far from obvious that GBJV has any incentive to restrict
supply with a view to increasing southern gas prices up to the buyers’ alternative.
This scepticism is strengthened when one takes into account the long term impact of
such a strategy due to the promotion of rival southern producers’ investments in
additional capacity.
78. By contrast, the ACCC provides no such transparent model of the market. The ACCC
appears to be simply assuming that because GBJV is large it has market power and
this market power can, and will, be costlessly used to raise southern prices.
21
79. This is not, in our view, a sound conclusion based on robust economic analysis. In
this regard, we note that it is not enough to point to shortages of supply in southern
states as a justification for GBJV being able to charge the buyers’ alternative. If
naturally occurring shortages in supply create this opportunity then no market power
is being exercised. In order to conclude that market power being exercised, GBJV
must be creating that shortage in supply by artificially restricting its own supply – in
which case GBJV must be sacrificing profits on restricted sales.
80. Moreover, if this strategy was actually being implemented we would not expect, as set
out in section 5, to see:
gas flows from southern states to Queensland;
GBJV having record sales in 2017.
22
6 Assumed link between LNG netback
and domestic prices 81. The ACCC assumes that that the presence of LNG export operations in Queensland
will create an elastic (i.e., very price sensitive) supply of gas:
from Queensland to southern states at a price equal to the LNG netback price
plus transport costs;
to Queensland from southern states at a price equal to the LNG netback price
plus transport costs.
82. That is, the ACCC assumes that gas can be diverted from/to LNG export in large
quantities as soon as domestic prices depart from international energy prices (less
the costs of converting domestic gas to export LNG).
83. This, in effect, creates an assumed ‘dead zone’ for southern prices where there is no
competition from Queensland gas producers. This ‘dead zone’ is the difference
between the buyers’ alternative and the sellers’ alternative depicted in Figure 1, Figure
4 and Figure 5. Within this ‘dead zone’, the price of gas sold to southern customers
will be set purely by competition between southern gas producers – without any
constraint imposed by Queensland (and Northern Territory) gas producers and/or
consumers.
84. In our view, this assumption not accurate. Our expectation is that, consistent with
most such capital intensive projects, providers along the LNG supply chain will have
built little excess capacity into their operations (i.e., above and beyond that paid for
by customers under take-or-pay style contracts). Therefore, the ability of LNG
exporters to respond to low domestic gas prices by exporting more LNG will be
limited by the capacity of the elements of the LNG export chain (including
liquefaction facilities but also carrier capacity and terminal capacity).
85. Consistent with this, the ability of LNG exporters to respond to higher domestic gas
prices will be limited by the need to fulfil contractual obligations (under take or pay
contracts) with their customers. At very high domestic gas prices (relative to
international energy prices) there may be some capacity to renegotiate with
customers to take less LNG (allowing LNG exporters to divert gas to the domestic
market). However, this would only be done, if at all, if the domestic prices in Australia
justified leaving expensive LNG capacity unutilised. There will be a wide range of
price differences (between Queensland gas and international energy prices) where
this is not the case.
86. These issues are discussed in more detail in Appendix A. However, the important
conclusion for analysis of domestic competition is that, in reality, the ‘dead zone’
assumed by the ACCC will not exist (or, at least, will typically not exist). That is, prices
23
in Queensland and southern states will typically be linked by competition between
suppliers in all states for customers in all states.
87. By way of practical example, consider a scenario where domestic (including
Queensland) gas prices are below the LNG netback price (e.g., because the
international oil price is high). Let LNG exporters be operating at full capacity such
that LNG exporters are simultaneously:
unable to absorb additional domestic gas; and
unprepared to divert any export gas for domestic sales.
88. Also assume that gas prices in southern states are lower than those in Queensland
such that gas is being transported north to equalise those prices (after transport
costs). This is the scenario under which the ACCC believes GBJV will have an
incentive to exercise market power and increase southern gas prices up to the buyers’
alternative.
89. However, with LNG exports at full capacity due to high international oil prices the
LNG netback price will be above the Queensland price. Gas producers would like to
produce more and sell it to LNG exporters at the LNG netback price but capacity
constraints prevent this. Queensland and southern gas prices will still be linked by
transport costs but the Queensland price will no longer be fixed by international
energy prices. Now, southern prices and Queensland prices will tend to move
together. An increase in southern prices cannot be achieved without a similar
increase in Queensland prices and vice versa.
90. Now consider a strategy under which GBJV restricts its supply in an attempt to raise
the southern gas price it receives.
In the ACCC model this reduction in GBJV supply has a stronger impact on
southern prices because there is no demand/supply response from Queensland
customers/producers (who are assumed to buy and sell as much gas as they wish
at the LNG netback price).
However, if capacity constraints at LNG exporters exist then a reduction in GBJV
supply will tend to cause an increase in both southern and Queensland gas prices.
Consequently, there will be a supply response from a larger set of producers (i.e.,
including Queensland producers) and a demand response from a larger set of
customers (i.e., including Queensland customers).
91. In the latter scenario GBJV must now influence prices in the entire east coast (not
just the southern states). This means it will have to restrict supply by more for the
same unit increase in prices (because there are more consumers to respond by
reducing demand and more suppliers to respond by increasing supply). This makes
such a strategy less likely to be profitable.
24
7 The relevant measure of ‘transport
costs’ is shippers’ marginal (not
average) costs
7.1 Shippers’ marginal transport costs do not equal their
average tariff
92. In Table 6.2 of the ACCC’s report the ACCC estimates the impact of a 10% to 50%
reduction in “transport costs”. However, the ACCC’s estimate of transport costs are
based on the average costs of shippers’ take or pay contracts with pipelines assuming
a 100% load factor.15
93. This is, very likely, a material overestimate of the marginal transportation costs faced
by shippers in the short term. This is because large shippers already have what
amounts to zero (or low) marginal cost transport tariffs up to their contracted
capacity. Any shipper (or combination of shippers) with spare capacity on routes
between locations would rationally use that to arbitrage between two different liquid
markets in those locations (assuming such markets were to exist).
94. Spare capacity is the norm on the SWQP is illustrated in the following two charts
using data that was supplied to the ACCC Inquiry.
15 See footnote 30 on page 35 of the ACCC Inquiry report.
25
Figure 7: SWQP western haul – firm allocation vs firm MDQ
Source: APA
26
Figure 8: SWQP eastern haul – firm allocation vs firm MDQ
Source: APA
95. It can be seen that there is typically significant excess capacity within the allocations
to existing shippers. This means that the relevant estimate of “transport costs” in the
ACCC’s analysis is much lower than the average costs that is assumed in Table 6.2.
96. Were the ACCC to regulate gas pipelines (such as the SWQP) and the result of this
regulation was to reduce average tariffs it still would not necessarily have any impact
on the marginal costs of transport faced by shippers – which are already well below
the average tariff that they pay. Given shippers will rationally respond to marginal
incentives it is not obvious that such a reduction in average transport costs will have
any impact on gas prices able to be charged by producers.
7.2 Regulation will not necessarily reduce ‘transport costs’
– either marginal or average
97. The ACCC proceeds on the assumption that regulation will reduce average transport
tariffs. However, it has no basis for making that conclusion other than:16
16 ACCCC, Inquiry report, p. 114.
27
One pipeline estimated that it was earning 70 per cent more in revenue than
it believes it would if it was regulated, which would imply approximately a
40 per cent reduction in prices if the firm moved to its estimate of revenue
under regulation.
On two pipelines that have already recovered their construction costs,
pipeline charges were 50–80 per cent higher than a charge based solely on
the cost of recovering the forward looking cost of operating and
maintaining the pipeline.
98. With regards the first point it is unclear on what basis the pipeline made this 70%
estimate and, in any event, what is its relevance? What a firm estimates that a
regulator might do does not form a reasonable basis for a regulator determining what
it would do. (For example, the 70% estimate may reflect a view that a regulator would
likely undercompensate them for their true costs – as indeed the second point
suggests is the ACCC’s intention.)
99. In relation to the second point, there is, in our view, no reasonable basis upon which
a regulator would deny any future return on an asset when that asset is first subject
to regulation (i.e., set the compensation to owners as if the asset had zero value (as if
they, in fact, owned nothing at all)).
100. If the ACCC did seek to impose regulation in this manner then it is likely that long
run gas transport costs would rise (not fall). This is because such a regulatory stance
will discourage new investments in pipelines (be they regulated or not). (As thought
experiment, imagine the impact on residential construction if investors perceived
that once a regulator had determined initial investments to have been fully recovered
rents could only cover property maintenance costs.) The ultimate likely impact is that
pipelines become capacity constrained due to lower investment in capacity (on
existing and new pipelines). In this situation, marginal transportation costs increase
to approach infinity.
101. In this regard, we note that the ACCC refers to the existence of 15-year no-coverage
determination provisions for greenfields pipeline projects as a way of reducing this
risk to incentives for new investment.17 We consider that the ACCC’s signalled
position in the Inquiry, if actually carried out (or perceived as likely to be carried out),
would eliminate any benefits whatsoever from that protection.
102. This is because the ACCC’s signalled position is that, when it comes to regulate a new
pipeline, even if it is 15 years after its initial operation, the ACCC will be prepared to
set the asset value based on an estimate of already recovered construction costs
(accounting for the time value of money). This renders any ‘regulatory holiday’
meaningless because the ACCC is able to use whatever revenues are earned in that
‘holiday’ (plus a return on those revenues) to reduce the asset value for which it will
17 ACCC, Inquiry report, p. 137
28
provide compensation post the ‘regulatory holiday’. In effect, it allows the ACCC to
reach back in time and regulate the pipeline retrospectively. As explained in our
companion report, this not only destroys any value of ‘regulatory holiday’ but, in fact,
creates worse incentives than if the pipeline was regulated from day one.
29
8 ACCC Box 8.3 analysis of transport
costs and STTM market prices is
flawed
103. Separately to the analysis surveyed in previous sections, the ACCC also attempts to
support its view that transport costs are causing higher prices in southern states by
virtue of the analysis presented in Box 8.3. Box 8.3 suggest that transport costs are
limiting efficient gas flows from Queensland to southern states. The ACCC states:18
Pipeline pricing (including secondary pricing), will be a critical factor in
the ability of producers (including LNG projects) to sell gas from
Wallumbilla to domestic markets, for example, Mt Isa but also markets
further south, for example, Sydney. Importantly, the Inquiry considers
secondary pricing to southern markets often extracts more than the price
differentials between, for example, short-term commodity prices at
Brisbane and markets further downstream. This pricing is likely to limit the
utilisation of these pipelines and inhibit the movement of gas to arbitrage
prices between the STTMs. Southern route pricing is also likely to impact
on whether gas goes to domestic users or international buyers (see box 8.3).
104. Box 8.3 on page 149 of the Inquiry report proceeds on the basis that there are liquid
prices for gas in not just Queensland but also Sydney and Adelaide. The ACCC
examines daily price differences between Sydney/Adelaide short term trading
markets (STTMs) and the Brisbane STTM. The ACCC argues that:19
The STTM price differentials appears to limit any incentives to re-direct
short-term gas to the Sydney STTM unless the market price difference is
over $2/GJ (see occurrences and magnitude of pricing differences between
regions in the table above)
105. The evidence in support of this conclusion is that prices are seldom in excess of the
ACCC’s estimates of the difference in transport costs between Sydney/Adelaide and
Brisbane – where this is estimated to be 2.0/1.5 $/GJ defined by the ‘as available’
tariff offered by pipelines. (That said, the ACCC’s own presentation of the data does
have STTM prices differing by more than this on a non-trivial number of days (76/160
days for Sydney/Adelaide)).
106. The ACCC infers from this that ‘as available’ pricing is causing the price difference –
raising prices in southern states above prices in Queensland. The ACCC also forecasts
18 ACCC, Inquiry report, page 148.
19 ACCC, Inquiry report, page 149.
30
that this may be a common state of affairs in the future as LNG exporters seek to
divert gas south rather than export it - but are constrained to do so by what it regards
as high ‘as available’ pricing. 20
The amount of gas nominated for LNG usage, that is, from the Queensland
CSG fields was over 2500 TJ/d as at the end of March 2016. This quantity
is much larger than Brisbane market demand (under 100TJ/d in 2016). It
is likely there will be times where the choice for sellers will be between
exporting gas, at LNG spot prices, or selling to users other than in Brisbane
(which can only support a certain quantity of gas). Southern routes costs
(for example, over $3/GJ to Sydney) will be critical to whether domestic or
international users ultimately receive that gas. At lower transport prices,
more gas would be diverted to domestic users.
107. We reiterate here the points made in section 6, namely, that it is not obvious that LNG
exporters can be assumed to be operating with spare capacity such that they would,
at the margin, make a short run decision as to whether to export gas or divert it to
southern states. If, as we suspect is the case, LNG exporters will seek to operate at
full capacity, the short run decision making that the ACCC is envisioning will not
occur.
108. However, putting that aside, the ACCC makes an error in treating STTM prices as
being set in liquid markets for the sale of gas. That this is not the case is
acknowledged on page 88 of the Inquiry report where the ACCC states:
The STTMs and the DWGM are wholesale gas balancing mechanisms
rather than true trading hubs. While a number of participants have
indicated to the Inquiry that the STTMs, in particular, are a useful adjunct
to their gas buying activities, they have limited utility in providing
an accurate indicative price for other market participants or the
wider contracting market. [Emphasis added.]
109. However, inconsistent with its prior recognition that STTM markets are not true
trading hubs, on page 148 of the Inquiry report the ACCC states:
Importantly, the Inquiry considers secondary pricing to southern markets
often extracts more than the price differentials between, for example, short-
term commodity prices at Brisbane and markets further downstream. This
pricing is likely to limit the utilisation of these pipelines and inhibit the
movement of gas to arbitrage prices between the STTMs. Southern
route pricing is also likely to impact on whether gas goes to domestic users
or international buyers (see box 8.3). [Emphasis added.]
20 ACCC, Inquiry report, page 149.
31
110. The Inquiry report goes on, in Box 8.3, to use STTM prices in order to support its
claim that transport costs are causing higher prices in southern states than in
Queensland. However, this analysis is inconsistent with the first statement (from
page 88 of the Inquiry report) extracted above. That is, the prices underpinning this
analysis are not actual liquid prices that reflect actual arbitrage opportunities.
Indeed, the fact that, on the ACCC’s own analysis, the Adelaide vs Brisbane price
difference is above the ACCC’s estimate of transport costs on 160 days a year suggests
that it is not transport costs defining this price difference. The only reason for prices
in two liquid markets to differ by more than the transport tariff is if the pipeline is
congested and gas simply cannot flow. We understand that his is not typically the
case with, for example, low utilisation on the MAPS connecting Adelaide and
Moomba.
111. The limited role of STTMs in providing reference prices for high volume gas trading
was also noted by the AEMC:21
The ex ante price is generally considered to reflect short term imbalances
between daily gas requirements and long term contract positions, as
discussed in section 5.2.2. However, we note that the original STTM design
was probably not developed for the purpose of establishing a reference
price, where the focus was on facilitating transparent and competitive short
term trading of imbalances.
112. These prices actually reflect administrative levels of deviation charges – not prices at
which trading of large volumes could occur. In reality, the vast majority of gas used
by end-customers is purchased under contracts (which span years not days) where an
energy retailer promises to deliver gas at a predetermined price (at least up-to an
agreed quantity). Retailers similarly purchase that gas from upstream suppliers
under long term contracts and use firm capacity rights to deliver that gas to end
customers. In this context, the prices paid for gas (both by end users and by shippers
to upstream gas suppliers) reflect bilateral negotiations that take a view on market
average conditions over the medium term (the term of the contract which is typically
measured in years and not days).
21 AEMC, Stage 1 Final Report, East Coast Wholesale Gas Market and Pipeline Frameworks Review, 23 July
2015, p.92.
32
Appendix A Netback price is a long run
concept 113. The ACCC introduces a model for how pipeline transport costs will determine the
range within which competitively negotiated gas prices will fall at different locations
on the east coast. We consider that this model is an economically logical description
of how prices would be set based on the assumptions that (implicitly and explicitly)
underpin the model. Those assumptions include:
i. That there is a liquid market for gas to be exported from the Gladstone area
where the price is determined by international energy prices less LNG
conversion and delivery costs (the LNG ‘netback price’ at Gladstone) and that
this price is not sensitive to the volume of domestic supply to the Gladstone
area;
ii. That, provided transport capacity is adequate, if LNG netback prices at
Gladstone are:
above gas prices at location X (away from Gladstone)
by more than the transport costs of delivering gas from location X to
Gladstone; then
gas will be diverted to Gladstone from location X until prices at location X
are no lower than the LNG netback price at Gladstone less transportation
costs.
iii. Symmetrically with ii), that, provided transport capacity is adequate, if gas
prices at location X are:
higher than the LNG netback price at Gladstone;
by more than the transport costs of delivering gas from Gladstone to location
X; then
gas will be diverted from LNG export until prices at location X are no higher
than the LNG netback price at Gladstone plus transportation costs.
114. Given these assumptions the ACCC’s model, as described in the discussion around
Chart 2.4 on page 52, is an internally consistent description of the economic forces
determining prices at locations away from Gladstone. With these assumptions it can
be seen that the price at location X must fall within a range that is equal to the LNG
netback price at Gladstone plus/minus transport costs between location X and
Gladstone.
115. While this analysis is presented in the context of an LNG netback price, the same
economic logic applies to any price difference between locations. Namely that such
price differences will be bounded by marginal transportation costs – both from below
33
and from above each price. Of course, in the presence of capacity constraints,
marginal transportation costs can be very high.
A.1 LNG netback price is not likely to be meaningful short
run concept
116. The ACCC model is likely to be a reasonable description of long term economic forces
that tend to link Australian prices to an LNG netback price. In the long run, having
the potential to export LNG from the east coast of Australia does mean that long term
gas prices will be influenced by international energy prices. Specifically, additional
export capacity can be expected to be built (and therefore domestic demand created)
when:
the long run projected international LNG price; exceeds
the long run projected domestic gas price plus LNG conversion and
transportation costs (plus a risk premium).
117. In the long run, investment in LNG export capacity in Queensland will be expected to
raise demand for gas in Queensland and, therefore, raise Queensland prices relative
to other regions. This will tend to increase the flow of gas from southern states to
Queensland (or divert the flow of gas that would otherwise flow to southern states).
As the ACCC analysis notes, long run increase in flows out of southern states (and
price rises in southern states) will tend to be higher the lower are transport costs
(other things equal).
118. In the ACCC’s model the price at Gladstone is assumed to be determined by readily
observable international energy prices less LNG conversion and transportation costs.
However, even if there was spare capacity for LNG export, creating the capacity to
absorb additional units for export at some version of a LNG netback price, there are
only a small number of potential providers of ‘conversion and transportation’ services
and one cannot necessarily assume that it is competitively supplied at marginal cost
(or even at average cost).
119. Moreover, if those export facilities are capacity constrained and operated at capacity
then one can expect the domestic price of gas delivered to Gladstone will not be set in
a liquid market with prices based on the LNG netback calculation. The ACCC
recognises these issues elsewhere in the report but describes them as likely to be
temporary:22
While this is likely to be the predominant situation, circumstances may
occasionally arise that will result in domestic prices in Queensland being
temporarily delinked from the LNG netback prices (Box 2.2)
22 ACCC, Inquiry report, page 45.
34
…
Such a scenario could arise, for example, if the LNG projects have already
sourced sufficient gas reserves that can be developed economically to fill the
trains. In this environment, the domestic prices in Queensland may
temporarily delink from the LNG netback prices, as the LNG facilities have
no spare capacity to spur their demand for gas. In this case, domestic gas
can now only substitute for gas already being supplied to the LNG facilities
and so the price is likely to be shaped by the marginal cost of gas production
until additional LNG capacity is commissioned. If LNG price expectations
are high enough, this will send a signal to the LNG producers to expand
existing LNG plant capacity or build an additional train. If either of these
situations occur this will increase demand for gas to be supplied to the LNG
facilities and likely lead to a return to pricing shaped by LNG netback.
However, investments in LNG production are lumpy, high cost and
generally require long lead-in times. There is also considerable uncertainty
about future oil and LNG prices, which could delay the supply response. So
any return to LNG netback pricing may not be automatic.
120. We agree with the analysis set out above with the exception that we regard the use of
the term ‘temporary’ to be misleading/inappropriate. For the reasons well explained
in the above quote, the domestic prices in Queensland will, at any given time, almost
certainly be ‘delinked’ (i.e., different) to a price estimated based on an LNG netback
calculation. There will be a long run tendency for domestic prices to be pulled in the
direction of a LNG netback level. However, precisely for the reasons set out in the
last three sentences of the above quote, this is purely an influence on long run
dynamics.
121. In reality, the level of domestic prices in the short term will never be equal the LNG
netback calculation except purely by coincidence. This is because in order for the
ACCC’s short run conception of the LNG netback price to be relevant, LNG exporters
must be able to, in response to differences in domestic and international prices,
increase/decrease exports in the short run. In reality, LNG producers will not have
the flexibility to do so.
122. Consider a situation where international energy prices exceed domestic prices plus
“LNG conversion costs”. In order for LNG exporters to increase exports beyond their
current capacity they must make investments that are “lumpy, high cost and
generally require long lead-in times” and these investments will be made not based
on current international energy prices but based on long run estimates of “future oil
and LNG prices” about which there is “considerable uncertainty”. Therefore, even if
domestic gas prices were below the prevailing LNG netback price LNG producers
could not respond by increasing exports within a period of at least several years.
Moreover, any increase in capacity of LNG export facilities would not be based on a
comparison of prevailing domestic and international prices but would be based on
35
the expected level of these prices over the life of the necessary investments (i.e., many
decades).
123. Consider a situation where international energy prices are lower than domestic prices
plus “LNG conversion costs”. In order to export less they must not have contractual
commitments to supply at their capacity to international customers. However, we
would expect that the construction of the LNG conversion infrastructure and
associated downstream transport infrastructure (LNG carriers and LNG terminal
capacity in the importing country) will be underwritten by take or pay contracts.
Indeed, the ACCC notes that the “the LNG projects require significant volumes of gas
in order to meet these contractual commitments.”23 Therefore, even if domestic gas
prices were above the prevailing LNG netback price it is not obvious that LNG
producers would have the capacity to respond by reducing exports.
124. Moreover, even if we assume that LNG exports are able to respond to low
international relative to domestic gas prices, the “LNG conversion” costs (which are
deducted from international energy prices to arrive at the “LNG netback” price)
would not be the same in each scenario. The effect of this is that there is a potentially
very wide band for the difference between international and domestic energy prices
where the LNG netback price has no effect on domestic prices – even in the long run.
125. This is because, where LNG investors must expand exports in response to high
international energy prices “conversion costs” include the full costs of adding new
capacity in the downstream supply chain (including a risk premium consistent with
the decade’s long payback time). In the case of a reduction in exports to less than
capacity these “conversion costs” would reflect the marginal opportunity cost of
already sunk infrastructure – which may be close to zero for at least some elements
of the supply chain.
126. Nonetheless, consistent with the ACCC’s view that departures from Netback
calculation are temporary, the ACCC analysis around Chart 2.4 and Box 8.3, treats its
model as applying in the short run. In contrast to the ACCC’s statement, we consider
that short to medium term domestic market conditions will typically (and potentially
exclusively) be delinked from any concept of a short run LNG netback price.
127. In summary, we consider that the ACCC’s LNG netback logic is sound in terms of
describing general forces for price setting in the long run. However, it is less clear to
us that the LNG netback price is a well-defined concept that can be assumed to anchor
analysis of short run prices, and price differentials, on the east coast. This means that
prices in locations in the east coast cannot generally be conceived of as equal to an
LNG netback price in Queensland plus/minus transport costs.
128. That said, the conclusion that price differences between locations are bounded by
transport costs between locations is still sound. It is simply that an LNG netback
23 ACCC, Inquiry report, page 42.
36
calculation is unlikely to provide a useful guide to prices in Queensland except in a
very long run sense.
37
Appendix B Withholding supply more
costly absent liquid southern markets 129. The analysis presented in the main body of this report can be thought of as occurring
in the short run or in the long run. A short run supply restriction strategy is likely to
be most profitable because restrictions in supply can be timed to only apply in periods
when the price would otherwise be at the sellers’ alternative. When the price would
naturally be at the buyer’s alternative there is no need to restrict supply because
southern prices would already be at their maximum. By contrast, a long run supply
restriction is less likely to be profitable because it involves restricting supply in all
periods - even when prices would already be at their maximum. In such, periods price
reductions are profit destroying.
130. However, implementing a short run supply restriction strategy requires a liquid spot
market in southern states where the GBJV can vary the amount sold as market
conditions dictate. Contrary to some positions the ACCC takes, we understand that
no such liquid market exists and that, instead, gas is typically sold under contracts
that last more than a year.
131. In reality, the vast majority of gas used by end-customers is purchased under
contracts (which span years not days) where an energy retailer promises to deliver
gas at a predetermined price (at least up-to an agreed quantity). Retailers similarly
purchase that gas from upstream suppliers under long term contracts and use firm
capacity rights to deliver that gas to end customers. In this context, the prices paid
for gas (both by end users and by shippers to upstream gas suppliers) reflect bilateral
negotiations that take a view on market average conditions over the medium term
(the term of the contract which is typically measured in years and not days).
132. This means that GBJV will not be able to alter its supply into southern markets on a
day-by-day basis – restricting supply only when prices would naturally fall below the
buyers’ alternative. Consequently, a restriction of supply to southern states may have
to be implemented on a medium to long term basis by simply signing fewer long term
gas supply agreements with southern customers than would GBJV otherwise have
signed. If so, then the cost of restricting supply will be larger still because supply will
be restricted in all market conditions – including when there is no price gain (because
prices would have been at the buyers’ alternative in any event) and only a volume loss.
