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Examination of the current test for the regulation of gas pipelines

APA Submission to Dr Vertigan’s Consultation Paper

19 October 2016

APA Submission to Dr Vertigan’s Consultation Paper

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Contents

PART A – EXECUTIVE SUMMARY 4

1 A critical consultation 4

The context 4 The ACCC’s evidence base has not been tested 4 The ACCC has not established the benefits of a change 6 What are the costs of regulation? 7 Is the current coverage test fit for purpose? 9 The ACCC’s Proposed Test 9 Case for change has not been made 11 Structure of this submission and attached reports 13

PART B – THE ACCC CLAIMS 14

2 The broader context 14

The gas transmission pipeline industry 14 Pipeline operators have invested 15 Pipeline tariffs have not increased in real terms 15 Why have pipeline charges not increased? 16 What the ACCC says about this evidence 17

3 How does the ACCC support its proposed changes? 18

The ACCC inquiry 18 How did the ACCC base its claim of monopoly pricing? 18

4 RORs for incremental projects 20

ACCC claim 20 ACCC relies on selected projects 20 ACCC has used the wrong comparator 20 IRRs are typically higher for incremental investments 21 The regulated return is not an appropriate benchmark 21 SWQP case study 25

5 Pricing of non-firm services are not too high 27

The ACCC claim 27 ACCC’s examples of pricing services over the benchmarks 27 Quantum of revenue from non-firm services is small 28 Shippers currently have access to non-firm services 28

6 ACCC assertions on capital cost recovery and subsequent pricing 29

The ACCC claim 29 Summary of APA position 29 Competitive industries charge based on new entrant costs 29 Impact on investments in new pipelines 29 Distortion of the efficient operation of existing pipelines 30

PART C – IMPACT ON GAS PRICES 31

7 CEG Pricing Report 31

ACCC assertions 31 CEG analysis 32

8 Independent analysts reports 34

Morningstar analysis 34 J.P. Morgan analysis 35

PART D – COSTS OF REGULATION 36

9 What are the costs of regulation? 36

Regulation has costs 36 Adverse impact on investment 36 Adverse impact on innovation 40 Does the 15 year access holiday mitigate this risk? 43 Summary 43

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PART E – THE CURRENT COVERAGE TEST 45

10 What does the coverage test need to do? 45

What does the coverage test need to do? 45 How does the current test work? 45 ACCC’s Proposed Test 46 Current coverage test is sound 47 Current coverage criteria can apply to monopoly pricing 47 Current coverage criteria can be satisfied by non-vertically integrated

service providers 47 Competition and efficiency are inextricably linked 48 Coverage decisions do not support reform to criterion (a) 49

11 ACCC scenarios can satisfy criterion (a) 50

Criterion (a) can apply 50 Scenario A 50 Scenario B 51 Scenarios C and D 51

PART F – THE CASE FOR CHANGE 53

12 Case for change not made 53

Overview 53 Importance of consistency between NGL, Part IIIA and the CCA 53 Costs of adopting the ACCC’s Proposed Test 54 Benefits do not clearly outweigh the costs 56

13 Where to from here? 57

Improving efficiency 57 Industry has led change 58

14 Glossary 59

ATTACHMENT A – Responses to questions in consultation paper 61

ATTACHMENT B – ACCC comments relating to APA 69

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PART A – EXECUTIVE SUMMARY

1 A critical consultation

The context

This submission responds to the Consultation Paper, “Examination of the

current test for the regulation of gas pipelines”, dated 4 October 2016.

APA welcomes this consultation by Dr Vertigan on what are the appropriate

settings for the coverage criteria under the National Gas Law (NGL). It

involves a critical policy decision on how the pipeline industry should be

regulated with implications for other infrastructure in Australia.

The Australian Competition and Consumer Commission (ACCC) is seeking

the hurdle represented by the coverage criteria to be lowered. Further, it

suggests consideration be given to having transmission pipelines deemed to

be regulated from the outset1 and the onus of proof reversed so that

pipelines have to prove they should not be regulated.2

The change in coverage criteria would represent a fundamental change of

the approach to regulation of pipelines which has been in place for 20 years

and which has underpinned billions of dollars of investment. It would also be

a rejection of the approach to access regulation under Part IIIA and the

recent Productivity Commission review and the “root and branch” Harper

Review findings in the Competition Policy Review: Final Report released in

March 2015 (Harper Review). It would impose an untested bespoke regime

which is out of step with access regulation for other infrastructure.

APA operates a mix of fully regulated, light regulated and unregulated

assets. It does not dispute the need for regulation or that full economic

regulation of assets may be appropriate in certain circumstances. However,

a fundamental regulatory change must be based on:

proper evidence;

an understanding of the benefits and costs of the change;

1 ECGI Report, p 140.

an analysis of whether the changes will achieve the desired policy

objectives; and

having regard to the above, an independent assessment of whether the

case for change is established.

This submission considers each of these points. In Attachment A, we

specifically answer the questions put by the consultation paper.

APA does not believe that the ACCC has established a case to justify such

far reaching and bespoke regulation.

The ACCC’s evidence base has not been tested

The background to this consultation is the ACCC’s report on the East Coast

Gas Inquiry (ECGI Report). The ACCC asserts that a large number of

pipeline operators have been engaging in monopoly pricing. This is critical

to this entire consultation and the case for change.

Much of the ECGI report is valuable and provides clarity on the issues

involved. Unfortunately, the main findings of the report in relation to pipeline

pricing are based on misinterpreted evidence or findings that have been

inferred from examples presented out of context. APA and other pipeline

operators were not informed of, or given an opportunity to respond to, these

findings before publication. The ACCC’s evidence base needs to be tested

as part of this consultation to determine if it supports the findings.

Specifically, the ACCC relies on three assertions to support its findings of

monopoly pricing. These are discussed below.

APA rejects ACCC’s assertion that rates of return on incremental

projects are excessive

Most of the projects cited involve small capital works projects to APA

pipelines (representing less than 1.25% of APA’s enterprise value). Three of

the projects were developed as a competitive response and the other three

involved making pipelines bi-directional. The ACCC cites rates of return

(RORs) from Board papers without providing context, namely that the ROR

of a small capital project which takes no account of the very large underlying


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capital investment in the pipeline itself will axiomatically give rise to a high

ROR.

To compound the perception issue, the ACCC makes an “apples v oranges”

comparison which has the effect of making the project returns appear to be

twice as high as they should be against their chosen comparator.

ACCC incorrectly finds pricing non-firm services are too high

The ACCC set out some arbitrary benchmarks for the pricing of non-firm

services and then sought to compare pipeline prices to these. Even so, the

ACCC identified only three instances of pricing of services that did not meet

the ACCC’s benchmarks. Each relate to APA’s pipelines. Two are isolated

instances of historical pricing. The other meets the benchmark as the ACCC

used the wrong forward tariff to do its calculation. For context, and as

provided to the ACCC during its Inquiry, APA’s east coast pipeline revenue

from all available and interruptible services (not just these 3 examples) in H1

FY16 is less than 0.5% of its total annual revenue in the East Coast.

APA rejects ACCC’s assertions on capital cost recovery and

subsequent pricing

The ACCC makes the assertion that two pipelines are charging prices where

the cost of construction of the pipeline has already been recovered and

which are higher than those that would apply if those pipelines had been

regulated. It claims this to be the case for the Carpentaria Gas Pipeline

(CGP). The ACCC appears to hold the belief that prices in any competitive

market would be almost zero where capital was fully paid off. This is not the

case. In a workably competitive market, an income producing asset would

not be charged at almost zero pricing. Just because the capital costs of an

old office building have been recovered does not mean tenants are only

charged outgoings. The ACCC’s incorrect belief leads it to undertake an

analysis which effectively assumes monopoly pricing to make its finding that

pipeline operators are monopoly pricing.

More concerning for APA is the way the ACCC calculated the prices if the

asset were regulated. It assumes all revenue above what it considers to be

an appropriate regulated level of return must be monopoly profit and then

uses that approach to show that there is monopoly profit. The ACCC does

not even attempt to reconcile this approach with the incentive regulation

approach that actually applies to covered pipelines which allows shippers to

earn revenue in excess of the regulated rate of return where they outperform

cost and demand benchmarks, or tariffs which are struck through

competitive processes to build pipelines or price services (such as occurred

with the CGP).

Finally, the ACCC approach is inconsistent with how existing pipelines would

be valued if they became regulated. If the capital base of the CGP was

determined today for the purposes of regulated pricing under the NGL, it

would be hundreds of millions of dollars and certainly not zero. It is

misleading for the ACCC to suggest otherwise unless the ACCC also

intends to bring in a new approach which expropriates all revenue above a

shadow regulated return on previously unregulated or light regulated

pipelines. APA can say with some confidence that this approach would

devastate future pipeline investment.

The evidence is weak

To provide context, the ACCC, under its information gathering powers, had

access to all APA documents and communications, and investigated over

300 contracts and variations from APA alone as part of its Inquiry. It also

required APA to provide communications (including emails, board papers,

notes, reports and so on) between APA senior commercial staff and its

executive over a two year period. The ACCC spent one year looking at the

documents provided, interviewing pipeline operators and market participants

under oath, and investigating market pricing outcomes.

Despite this degree of analysis, the ACCC ‘found’ very few examples on

which to base its claims of monopoly pricing by pipeline operators. In most

cases the ACCC resorts to making claims, inferences and assertions based

on marginal expansion projects, minor revenue items (non-firm services),

and economically flawed claims in regard to “fully paid off” assets to support

a wholesale change to regulation of the pipeline sector.

Part B of this Submission provides a detailed review of the material relied

upon by the ACCC and Attachment B provides a response to the specific

issues raised by the ACCC in relation to APA’s pipelines.

APA has also included with this submission a report by Competition

Economists Group (CEG), “Returns on Investment for Gas Pipelines”, which

analyses the approach of the ACCC in reaching its findings on monopoly

pricing (CEG Returns Report).

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The ACCC has not established the benefits of a change

The ACCC proposition is wrong

The ACCC asserts that high transport charges on some pipelines can affect

gas prices in the southern states even for users that don’t directly utilise

those pipelines. In particular, it claims that (as illustrated by Table 6.2 of the

ECGI Report) reducing transportation charges by 10% to 50% could lead to

a $0.20 to $1.02 difference in the maximum price payable by domestic users

in the southern states.

The ACCC does not provide a formal economic analysis for its conclusion.

APA engaged CEG to prepare a formal economic model to test the ACCC’s

assertion. This is provided by CEG in its report, “Transport Costs and

Domestic Gas Prices” (CEG Pricing Report), and included with this

submission. Part C of this submission sets out that analysis.

The crux of the ACCC’s claim is that gas prices in Queensland are set by

liquefied natural gas (LNG) netback prices and the prices in southern states

are set by reference to Queensland prices with the difference in prices

between the two dependent on transportation costs. The ACCC assumes

that prices in the southern states equal the LNG netback price plus the cost

of transporting gas from Queensland and therefore any reduction in

transport costs will lead to a “one for one” reduction in prices in southern

states.

ACCC analysis incomplete as with northward flows, southern prices

would increase

As CEG shows, the ACCC’s analysis is dependent on which way gas is

flowing. If gas is flowing north, then on the ACCC’s approach the price in

the southern states must be less than the LNG netback price less

transportation costs (or otherwise it is more profitable to sell in the south). In

this scenario, lowering transport costs would raise southern prices, e.g. if

the LNG netback price is $8/GJ and the transport costs are $1/GJ and gas

flows are northward, then the southern price for gas must be equal to or less

than $7/GJ or otherwise it would be more profitable to sell in the south. If

3 ECGI Report, p 93. 4 Morningstar Equity Research, “APA Group: Caught in the ACCC's Crossfire, Greater

regulation is a headwind to longer-term returns”, 14 June 2016, pp 11-13.

transport cost is reduced by half, it now means it has become economic for

Queensland LNG buyers to buy gas in the south at $7.50, thereby raising

the price for southern buyers to $7.50.

The evidence shows that gas flows are increasingly flowing north. APA can

confirm that it has signed a number of gas transportation agreements

(GTAs) to move gas north. It is also evident that the market is contracting

for northern gas flows given that the Moomba to Adelaide Pipeline System

(MAPS) has become bi-directional and can now flow north, the Eastern Gas

Pipeline (EGP) has expanded to allow greater northern flows and the

Moomba to Sydney Pipeline (MSP) has become bi-directional to allow flows

north. The ECGI Report itself noted that over $450M of pipeline investments

had been made to enable more gas to flow from Victoria to New South

Wales and up to Queensland.3

This highlights that there are real issues with the ACCC’s analysis and that it

is overly simplistic (as discussed below).

Note that the two independent research analyst reports reached the same

conclusion:

This represents an increase on what the customer was paying

previously, with the benefits of lower transmission costs accruing to

the gas producer. While this is just one potential scenario, cutting

pipeline returns is not the clear-cut win for domestic gas customers

that it appears at first blush. (Morningstar Equity Research)4

…in the situation of the buyers alternative, reduction in tariffs can

switch the dominant pricing consideration to a netback price and

create a spike in gas prices for Southern users. (J.P. Morgan)5

ACCC model requires GBJV market power or a cartel

How then does the ACCC reach a conclusion that prices will reduce when

their own economic framework suggests they will increase? The ACCC

5 J.P. Morgan, Asia Pacific Equity Research, “Australian Domestic Gas, Cost inflation to drive wholesale gas prices up in all Eastern States”, 10 May 2016, pp 62-64.

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assumes that southern gas markets are not competitive and the Gippsland

Basin Joint Venture (GBJV) is charging:

Queensland customers - the LNG netback price less transportation

costs to Queensland for northern flows; and

Southern customers – the LNG netback price plus an amount equal to

the transportation costs to Queensland (as Queensland gas is their only

alternative and they would have to pay transport costs to have it

delivered).

This requires GBJV to have a high degree of market power. CEG consider

this question and finds this assumption questionable. Even if it did, a

strategy by GBJV to reduce output to increase prices is unlikely to be profit

maximising for GBJV and contrary to the evidence which shows GBJV sales

to be at record levels. The other alternative is that the GBJV and the

southern producers are in a cartel or undertaking coordinated conduct in the

southern market but there is no suggestion of this in the ECGI Report.

The ACCC model is simplistic and not reliable

In reality, the ACCC’s analysis is overly simplistic. It assumes that LNG

producers will switch gas to and from LNG exports depending on the

domestic prices in southern states. The LNG plants represent over $60B of

infrastructure and with long term offtakes – they are designed to run as close

as possible to capacity and will not be left idle for gas to be moved to the

domestic market. It is likely that there will be a wide range of differentials

between the Queensland price and LNG netback prices.

The other fundamental issue is that the ACCC bases its $0.20 to $1.02

difference on average transport costs on the South West Queensland

Pipeline (SWQP) and MSP. However, the SWQP is under long term take or

pay contracts – for contracted shippers transportation is a sunk cost. The

driver for those shippers is the marginal cost of transporting gas (i.e. the very

low variable, throughput cost) between Queensland and southern states, not

the average cost. The transport differential is much less than the ACCC

suggests.

6 Mr Rod Sims, Speech to the South East Asia Australia Offshore & Onshore Conference,

Darwin, 15 September 2016.

In its post-ECGI Report communications, the ACCC focuses on the 50%

reduction in pipeline tariffs and the claimed $1/GJ price reduction.6 It

justifies this position on two points. First, it says older pipelines which have

recovered its costs on the ACCC analysis should only be charging operating

costs (which is very low). However, neither the SWQP nor MSP is one of

the pipelines that the ACCC claims to be “fully recovered”. Second, it relies

on a one sentence comment in Appendix 3 of a 60 page Board presentation

to calculate that the SWQP is earning revenue 70% above what it would

earn if it was regulated. To provide context, the particular page was

addressing regulatory risk and was highlighting that the long term contracts

mitigated against the future risk of regulation as represented by the “back of

the envelope” assessment included.

Importantly, given the context, the assessment was made was using the

regulated rate of return applying in 2015 (~6%), not that which was applying

in 2008 and 2009 during the Global Financial Crisis (GFC) (~10.5%) and

used an 80 year depreciation profile rather than one linked to the remaining

life of the gas fields (which is significantly shorter). It also used rough

expenditure estimates with only notional allocation of corporate costs.

The key point, however, is that it is not legitimate to compare revenue

calculations using today’s rate of return with contractual rates stuck at a

different time (at the height of the GFC) and that were commensurate with

what would have been the prevailing regulatory rates of return imposed at

the time.

Further, the ECGI Report itself recognises that the SWQP tariffs were set in

a competitive process and the “prices and other terms and conditions in

these foundation contracts suggest AGL and Origin both benefited from this

competition”.7

On what basis then should these tariffs be halved?

What are the costs of regulation?

The ECGI Report recognises that the pipeline industry has made significant

investment ($900M in recent years) and offered more innovative services in

7 ECGI Report, page 97.

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response to changing demands.8 We have a regime that is providing the

right incentives in this regard – there is no question that any of the

investments have been gold plated or unnecessary.

The ACCC seeks to lower the threshold in the coverage criteria to provide

for more regulation of pipelines. It is well understood, including by the

ACCC,9 that regulation can impact on the incentives to invest and innovate.

Adverse investment impacts

APA has undertaken investments in both unregulated and regulated

pipelines. Part D of this submission provides a number of case studies and

examples of two key impacts of regulation, namely:

delaying investment – an example includes the well documented

inability for APA to get regulatory approval for the expansion of the

South West Pipeline from the regulator leading to it being delayed for

over 4 years until the next regulatory period, despite there being

demand for the expanded services well before that time.

providing an incentive to size pipelines only to existing demand – an

example includes the expansion to the Victorian Northern Interconnect

where the regulator sought to ‘optimise’ the investment by only thinking

about how to meet existing demand. Using this shorter term focus, it

reduced the requested capital for the project by substituting an

approach that would mean that future expansion of the pipeline would

make the optimised solution redundant. Demand for additional capacity

has since doubled within the regulatory period that the optimised

solution was approved. APA was left in a difficult position as to whether

it built the approved project in a staged approach that meant that later

expansion would make part of that investment redundant, or to pursue

the more efficient (but more expensive for lower demand levels) project

and risk that the regulator considered this to be inefficient.

8 ECGI Report, pp 94-95. APA alone has invested well over a $1B on capital projects in the

last 5 years. 9 ECGI Report, p 137.

The above contrasts with recent unregulated builds for the Reedy Creek

pipeline and Moomba bypass which have been agreed commercially in very

short times to meet immediate demand.

An interesting case study is to compare the SWQP expansions with what

has happened in the coal industry. In APA’s view, the SWQP would not

have been expanded in the timeframes which occurred if it was regulated

and would have left eastern Australia without an essential piece of

infrastructure linking Queensland to the southern states during this critical

period in the lead-up to commissioning of the $60B LNG projects. It would

also remove the incentive for APA to have created additional capacity from

operating SWQP in conjunction with its other pipelines. The SWQP

expansion meant that there was capacity, availability, reliability and flexibility

to support the trebling of gas demand with no infrastructure bottlenecks. In

contrast, the failure to expand coal terminals during the mining boom led to

an estimated $5.5B in lost coal exports.10

Adverse innovation impacts

APA has invested heavily to run its portfolio of assets as an integrated grid

to enable it to gain efficiencies and provide new services. This has included

significant IT investment and creating an Integrated Operations Centre

replacing 5 control rooms. This allows combined operations of its pipelines

and the colocation of operations and commercial staff to integrate customer

services and demands into real time operations.

The Brattle Group11 has quantified the following which could not have been

achieved without taking a “grid” approach to planning and operations:

efficiency savings of $110M in reduced capital expenditure and $7M in

operations cost;

new park and loan services having an economic benefit of $7.5M and

$25M annually; and

10 Brian Robins, NSW coal bottleneck costs $5b in exports (1 July 2008) Sydney Morning Herald <http://www.smh.com.au/news/national/nsw-coal-bottleneck-costs-5b-in-exports/2008/06/30/1214677946060.html>.

11 The Brattle Group, Benefits and Costs of Integration in Transmission / Transportation Networks: An Application to Eastern Australia Gas Markets (2016).

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between $10.5M and $35M in avoided costs through storage services

provided during LNG commissioning.

This does not include the benefits to customers in having one contract

covering multiple pipeline routes and the improved risk allocation for

customers in not having to take pipeline-on-pipeline risks. In Part D, APA

provides some detail on why it would have had no incentive to do this, and

the above efficiency gains would not have materialised, if all its pipelines

were regulated.

Is the current coverage test fit for purpose?

What is its purpose?

The objective for economic regulation of gas pipelines should be the

enhancement of economic efficiency. Regulation should only occur where it

maximises net benefits for the community as a whole. That is, where the

total economic benefits of regulation exceed the costs.

In the context of economic regulation of gas pipelines, that efficiency

objective is embodied in the National Gas Objective (NGO). The focus of

the coverage criteria and, in particular, criterion (a) on a material promotion

of competition in dependent markets, is consistent with the framework

embodied in the Competition and Consumer Act and National Access

Regime, that competition is the vehicle through which efficiency objectives

are achieved. The link between efficiency and competition is explored

further below.

How does the current test work?

Under the National Gas Law (NGL), all the coverage criteria must be

satisfied for a pipeline to be subject to economic regulation. The issues

raised by the ECGI Report relate to criterion (a) which requires “that access

(or increased access) to pipeline services provided by means of the pipeline

would promote a material increase in competition in at least one market”.

It is well established by the National Competition Council (NCC), the

Competition Tribunal and the Courts that in applying criteria (a),

consideration must be had of two limbs. The first limb is consideration of

12 NCC, Declaration of Services: A Guide, February 2013 at para 3.43.

whether the service provider has an ability and incentive to exercise market

power. This has been referred to by the NCC as a “…necessary (although

not sufficient) condition’ of satisfying the test.”12 The second limb is to

consider the effect of access or increased access on competition in a

dependent market.

This approach is reflected in the attached opinion of N J Young QC and C M

Dermody (Young QC Opinion) in which they conclude the inquiry under the

current criterion (a) test involves an assessment of whether there is:

“an ability and incentive to exercise market power (by charging

monopoly prices)”; and

“any use of that market power in [a] way [that is] likely to adversely

affect competition in a dependent market” – such that access (or

increased access) would promote a material increase in competition in

that dependent market.”

Therefore, the ability and incentive to exercise market power and the

consequent impacts on competition in dependent markets are the critical

considerations in the application of criterion (a).

The ACCC’s Proposed Test

The ACCC’s Proposed Test

The new test proposed by the ACCC (ACCC’s Proposed Test) has two

limbs:

does the pipeline have substantial market power and is it likely that the

pipeline will continue to have substantial market power in the medium

term; and

coverage “will or is likely to contribute” to the National Gas Objective.

How then do the two limbs of the ACCC’s Proposed Test compare to the

coverage criteria? In APA’s view, the ACCC’s Proposed Test is a

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reformulation of criterion (a) with the remainder of the coverage criteria

effectively discarded.

The market power limb

The first limb of the ACCC’s Proposed Test involve essentially the same

assessment as the first limb of the current criterion (a). APA notes that

labelling the ACCC’s Proposed Test as the “Market Power Test” label may

incorrectly imply that the current test does not also consider market power.

The ACCC’s concern is that criterion (a) is not designed to address

monopoly pricing, particularly where the businesses involved are not

vertically integrated.

However as noted above criterion (a) clearly takes into account market

power. The Young QC Opinion concludes on the basis of decided coverage

determinations by the NCC and judicial decisions in the Tribunal and Federal

Court, “no difficulty arises in applying criterion (a) to monopoly pricing in

either its present form or in the form set out in the Exposure Draft.”13

It is also incorrect, both as a matter of law and economics, to suggest the

current test cannot apply to non-vertically integrated operators – it has done

so in the past. The propositions are also inconsistent with the views of both

the Hilmer Committee and Productivity Commission.

The NGO limb

There are two primary differences between this limb and criterion (a). First,

it replaces a competition based assessment with a vague efficiency based

test. Second, it lowers the threshold to be satisfied. Each of these points is

discussed below.

13 Young QC Opinion [26]. 14 HoustonKemp, Economic review of proposed amendments to the gas pipeline coverage

criteria: A report for APA (13 October 2016) p 5.

Competition and efficiency are linked

The ACCC’s proposed test is based on replacing a competition assessment

with one that focuses on the NGO (which focuses on efficiency) directly on

the basis that the former is not sufficient.

The ACCC considers criterion (a) uses competition as a proxy for efficiency

but competition and efficiency are not synonymous - the assessment of

competition impacts in dependent markets does not necessarily capture

efficiency gains in those markets which are unrelated to competition. (It

provides four scenarios to demonstrate this which we consider in more detail

below.)

However, as HoustonKemp explains it is a “fundamental underlying principle

of economics that competition and efficiency are inextricably linked. The

incentives that encourage firms to compete with one another are the same

as those that encourage firms to operate and price efficiently. All else equal,

a decision on whether or not to regulate the price of an input product cannot

promote one in the absence of promoting the other.”14

Further, as noted in the Young QC Opinion, “[c]riterion (a) in Part IIIA is

directed at improving the conditions or environment for competition, in order

to achieve the objects of Part IIIA which include the promotion of the

economically efficient operation of, use of an investment in the infrastructure

by which services are provided. That is, competition is not a proxy for

economic efficiency, rather economic efficiency is achieved through

improved conditions for competition…[The] same analysis applies to

criterion (a) in the NGL, i.e., criterion (a) treats the promotion of competition

as the relevant means of achieving the national gas objective.”15

The framework of relying on competition as the mechanism through which

efficiency objectives are achieved is embodied in well-established principles

consistent across the competition provisions in Part IV of the Competition

and Consumer Act 2010 (Cth) (CCA), the National Access Regime and the

current coverage test in National Gas Law. The ACCC’s proposed test

15 Young QC Opinion [29 and 32].

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would constitute a departure from this framework in the case of gas

pipelines.

Lowering the threshold

It is apparent from the ECGI Report that the ACCC considers the coverage

criteria set too high a threshold.

The phrase ‘will or is likely to’ in the ACCC’s Proposed Test would set a

lower standard than that established by the word ‘would’ in criterion (a). This

is supported by the Competition Tribunal’s interpretation of the phrase ‘will or

is likely to’ as importing ‘a standard of likelihood that is equivalent to ‘more

likely than not’”,16 which clearly suggests a lower degree of probability than

the word ‘would’.

The ACCC seeks to strike a new benchmark as to when regulation should

apply which is different to that exhaustively considered in a multitude of

cases and reviews. It does so on the basis that pipelines are monopoly

pricing (to which APA does not agree) and because it believes that the

current test is deficient in capturing such behaviour (which is not the case).

The current test can apply to the ACCC’s scenarios

It is therefore instructive to review the four scenarios where the ACCC says

the current test fails even though efficiency benefits would accrue from

regulation.

They are of course, brief and artificial scenarios, created to demonstrate a

point. The four scenarios are considered in the Young QC Opinion and

HoustonKemp Report. Those reports find that each of the four scenarios

could satisfy the coverage test – both in its current form and if the coverage

criteria were to be amended in a manner consistent with the Federal

Government’s proposed amendments to the declaration criteria in Part IIIA

of the CCA.

Case for change has not been made

In APA’s view, the case for change has not been established.

16 ECGI Report, see p 139 and section 7 generally.

ACCC’s Proposed Test

It has not been demonstrated that the current test is deficient. The

purported deficiencies in the test asserted by the ACCC are not borne out by

the jurisprudence applying the current test. Rather, APA considers the test

remains fundamentally sound as shown by its retention in Part IIIA after the

recent Productivity Commission review and Harper Review.

In contrast, as discussed in Part F, the ACCC’s Proposed Test:

replaces a well understood test with untested criteria – it effectively

discards 20 years of jurisprudence and understanding;

is extremely broad and confers enormous discretion on the decision

maker;

will create significant uncertainty and chill investment - these effects will

be amplified in the context of the current review of the limited merits

review framework, as pipeline owners could face an ambiguous test

with no right of merits review;

lowers the threshold and creates a real risk of overregulation; and

breaks the nexus with the National Access Regime and therefore

forgoes all the benefits of having a uniform test for access across the

economy.

The costs of adoption of the ACCC’s Proposed Test

The costs of adoption of the ACCC’s Proposed Test would be significant

arising from regulatory uncertainty as well as the efficiency cost of

unwarranted overregulation arising from the lowering of the threshold.

Regulatory certainty is critical for infrastructure investment. Westpac warned

that “the regulatory regime is the key element for financiers considering the

risk profile of transmission…business. Ultimately, this influences a

financier’s preparedness to provide finance and the terms at which finance is

made available including price. For Westpac, and indeed most other debt

16 Applications by Public Interest Advocacy Centre Ltd and Ausgrid [2016] ACompT1 [101].

30253978_7 12

providers, this assessment takes into account (chiefly, although not

exclusively) the predictability and stability of the regulatory regime”.17

With respect to debt servicing, Westpac stated that regulatory risk “may

result in an increased cost of debt for the industry and ultimately this could

flow through to consumers”.18

The ACCC’s proposed test would result in the replacement of the current

well-established and understood test, articulated with over 20 years of

jurisprudence, with one that would have to be interpreted and applied in a

vacuum creating significant uncertainty which would adversely affect the

investment environment.

The benefits of change do not outweigh the costs

The ACCC claims that the primary benefits of its test are addressing what it

believes to be monopoly pricing through the greater regulation of pipelines

that are currently not regulated, and that this regulation will materially reduce

gas prices in southern markets.

APA does not believe that the ACCC has made a compelling case in relation

to either of those claimed benefits. The evidence of monopoly pricing which

justifies the change is underwhelming when rigorously tested and the

supposed benefit of lower southern prices from greater regulation is based

on a simplified model which may, but for questionable assumptions, actually

lead to an increase in prices for southern states.

In contrast, the downsides of these changes are significant. Regulation

imposes costs and impacts on incentives to invest and innovate even when

properly imposed under the current regime. The ACCC’s Proposed Test

replaces a regime which APA considers still fit for purpose with one that

creates uncertainty and is out of step with access regulation for other

Australian infrastructure and competition law. It risks over-regulation and

with it, the higher costs and impacts of having underinvestment in

infrastructure.

Where to from here?

17 Westpac, Submission to the COAG Energy Council, Review of the Limited Merits Review

Regime, 3 October 2016.

APA considers the appropriate test remains the coverage criteria and those

criteria should be kept consistent with the changes proposed to declaration

criteria following the recent Productivity Commission and Harper Reviews.

The issue of the correct settings of the coverage criteria should be kept in

context. The Australian Energy Market Commission’s (AEMC) Stage 2 Final

Report - East Coast Wholesale Gas Markets and Pipeline Frameworks

Review provides for a comprehensive and far reaching reform program out

to 2020 and specifically addresses a number of the ACCC’s

recommendations from the ECGI Report. It also recommends biennial

reviews by the AEMC on the growth of liquidity in trading in wholesale gas

and pipeline capacity.

It is unfortunate that the first issue to be considered by policy-makers is a

change to the coverage test to facilitate onerous pipeline regulation rather

than considering whether the detailed reforms already in progress will assist

in developing further liquidity and trade in the gas market.

The ACCC’s Proposed Test is poorly targeted and betrays a mindset of

reverting to regulation as a first response to any perceived issue. APA

considers the best way to improve the efficient operation of the

transportation of gas on the East Coast is through industry led change

guided by regulatory processes and clear policy objectives.

In APA’s view, there is no need to introduce the ACCC’s Proposed Test –

the problem is not established and the costs would be significant.

Instead, the outcomes of the current reform process should be assessed

and the AEMC could be tasked with considering gas pricing outcomes (in

light of the greater transparency) as part of its biennial reviews, the first of

which is in 2018.

18 Ibid.

30253978_7 13

Structure of this submission and attached reports

This submission is made up of the following parts:

Part A – Executive Summary

Part B – Review of the ACCC’s findings in the ECGI Report

Part C – Considers the ACCC’s claims of the impacts on gas prices

Part D – Considers the costs of regulation

Part E – Considers the operation of the current coverage test

Part F – Considers the ACCC’ alternative test and the case for change

Attachment A – Provides a summary response to each of the questions in

the Consultation Paper

Attachment B – Provides a response to the specific issues raised by the

ACCC in relation to APA’s pipelines

The following reports are attached to this submission:

CEG, “Returns on investment for gas pipelines”, October 2016

CEG, “Transport costs and domestic gas prices”, October 2016

HoustonKemp, “Economic foundations of the gas pipeline coverage review”, October 2016 (HoustonKemp Report)

N J Young QC and C M Dermody, APA Group: coverage criteria in the National Gas Law – Opinion, 14 October 2016

The Brattle Group, “Benefits and Costs of Integration in Transmission / Transportation Networks: An Application to Eastern Australia Gas Markets”, 2016

30253978_7 14


PART B – THE ACCC CLAIMS

2 The broader context

Before considering the evidence relied on by the ACCC in detail, it is

important to not lose sight of the broader picture.

The gas transmission pipeline industry

Overview

There are 22 gas transmission pipelines across Queensland, New South

Wales, Victoria, South Australia and Tasmania. These are privately owned

by a multitude of Australian and international companies.19 The industry is

not generally vertically integrated. With the exception of two of the LNG

pipelines, the owners and operators of gas pipelines do not generally have

interests in upstream or downstream gas markets.

Regulation

When the National Gas Code was introduced in 1998 most pipelines were

subject to coverage (i.e. regulation) but as pipeline-on-pipeline competition

developed and the need and costs of regulation was better understood,

coverage has been revoked in many cases and a number of new pipelines

have been built on an unregulated basis. Where it applies, there are two

forms of regulation:

Under full regulation, a pipeline provider must periodically submit an

access arrangement to the regulator for approval, which sets out the

terms and conditions under which third parties can use a pipeline. The

Australian Energy Regulator (AER) assesses the revenue that a

pipeline business needs to recover its efficient costs (including a

benchmark return on capital), then derives reference tariffs for the

pipeline. Six transmission pipelines in Australia are under full

regulation, being the Roma Brisbane Pipeline (RBP), Victorian

Transmission System (VTS), Amadeus Gas Pipeline (AGP), Dampier

Bunbury Pipeline, Goldfields Gas Pipeline (GGP) and the Central

Ranges pipeline in New South Wales.

19 AER, State of the Energy Markets (2016), p 112.

Under light regulation, the pipeline provider must publish access prices

and other terms and conditions on its website. In eastern Australia, the

CGP in Queensland, the covered portions of the MSP, and the Central

West Pipeline in New South Wales are subject to light regulation.

It has been stated that because electricity transmission and

telecommunications networks are effectively deemed to be regulated, gas

transmission networks should be similarly treated. This assumes that gas

networks share the same features of electricity and telecommunications

networks when, in fact, there are important differences:

Access to electricity transmission networks in the national electricity

market is on a non-firm basis where the transmission use of system

service provided is not differentiated. Where there are differentiated

services such as connection or firm services and there is not a

contestable market for such services, they are subject to a negotiate /

arbitrate regime – this is similar to gas.

Telecommunications involves a vertically integrated incumbent – there

is no such structural issue in gas.

To date, the coverage criteria in the NGL applicable to gas transmission

pipelines have been consistent with the declaration criteria under Part IIIA of

the CCA which governs other large infrastructure projects with a similar

industry structure to gas such as railways, ports and airports.

Contracting and customers

Gas transmission pipelines have historically contracted capacity under long

term GTAs on a “take or pay” basis where the shipper must pay for the

contracted capacity even if not used. These take or pay contracts provide

the shipper with certainty of capacity being available and gives the pipeline

owner certainty of revenue to undertake large investments in long life

infrastructure. The East Coast market is dominated by a small number of

large and well-informed gas shippers.

30253978_7 15

Pipeline operators have invested

The current regulatory regime has delivered substantial investment and

innovation as acknowledged by the ACCC:

“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.”20

“Evidence received through the Inquiry indicates that pipeline

operators have responded relatively well to the changing demands

by offering more innovative services (for example, bi-directional

services, peaking transportation services, interruptible services and

premium storage services), shorter-term GTAs and multiple

services across inter-connected pipelines (for example, storage,

compression, redirection and transportation services).”21

This has been done without Government financial support.

Furthermore, the gas infrastructure in the Australian east coast gas market

has historically been characterised by security of supply, reliability and

efficiency. The gas infrastructure in the Australian East Coast gas market

has not experienced pipeline capacity bottlenecks or failures of the kind

seen in other industries, such as coal, as discussed in section 9.2 below.

This high standard has been maintained without the need for full regulation

or reliability and investment oversight which characterises the national

electricity market.

Pipeline tariffs have not increased in real terms

As the following chart from the Department of Industry, Innovation and

Science shows, gas transmission charges have been relatively flat in real

terms year on year since 2002. This is notwithstanding a 65% increase in

delivered gas prices in that time.

20 ECGI Report, p 93. 21 ECGI Report, p 95.

Source: Gas Market Report 2015, Office of the Chief Economist, Department of

Industry, Innovation and Science, p 41.

As shown by the table, and recognised by the ACCC, transmission charges

constitute only 10-15% of the delivered price of gas for retail customers.22 In

fact, the 2015 Gas Price Trends Review report by Oakley Greenwood for the

Department of Industry found that in 2015, the national average retail gas

price was 2.64 c/MJ, of which 42% was the distribution component, 27%

was the retailer component, 23% was the wholesale gas component and

only 8% was the transmission component.23 The ACCC headlines of

monopoly pricing could give the impression that the large increase in

delivered gas prices is due to pipeline charges. This is not the case –

transmission charges are a relatively small proportion of the overall price

and have not increased substantially in real terms. The increases in the

wholesale cost of gas has been driven largely by the introduction of demand

for gas by the LNG projects on the East Coast

In a review of the impact of the ECGI Report, independent research analysts

at J.P. Morgan provide support of this:

…we differ in view with [the ACCC] regards to the effect of pipeline

pricing on the development of new supplies. The chart below

22 ECGI Report, pp 34-35. 23 Oakley Greenwood, Gas Price Trends Review (February 2016), p 154.

30253978_7 16

(Figure 64) shows that while real gas prices have increased on

average by 66% in the east coast, wholesale prices have doubled

as compared to transmission costs which increased only 1%.

The narrative is fundamentally similar across all markets in

Australia - gas price increases have been as a result of wholesale

prices increasing, not as a result of price uplifts from pipeline

operators.

It is difficult to reconcile the above evidence with the ACCC’s findings of

monopoly pricing. As we discuss below, the ACCC is relying on small

incremental projects and ancillary services (rather than the pricing of the

services which provide the bulk of pipeline operator revenue) to justify a

broad reaching conclusion of monopoly pricing by all pipeline services.

Why have pipeline charges not increased?

Over 90% of APA’s east coast transmission revenue was from “vanilla”

transport services in FY15, i.e. providing firm capacity to shippers to

transport gas from one location to another.

In some cases, these prices are subject to regulation. In many cases, they

were set by agreement with the “foundation” shipper when it contracts for

capacity which underwrites a new pipeline or major pipeline build. The

24 ECGI Report, pp 96-97.

ACCC found that due to the competition to build pipelines, foundation

shippers are able to negotiate prices that are not affected by market power.24

In APA’s case, the following diagram shows that for all of APA’s pipelines,

the pricing of the major services are either subject to regulation or the

outcome of competitive processes. In particular, for the:

SWQP - the expansions and duplication of the SWQP were in response

to a competitive process which the ECGI Report recognised benefit the

shippers (see the case study at section 4.6); and

for the CGP, the most recent prices were set via the competitive

process run by the Northern Territory Government to build the North

East Gas Interconnector (NEGI) (expected to connect the Northern

Territory market to the east coast market).

30253978_7 17

Further, the tariff outcomes from the competitive process effectively set the

benchmark for firm transportation tariffs for the pipeline for the benefit of

other users. APA publishes indicative prices for all of its major pipelines

(regardless of regulatory status) on its website. These prices reflect existing

tariffs (mostly negotiated through a competitive process by foundation

customers) and are effectively available to all shippers post build.

What the ACCC says about this evidence

The ACCC has dismissed this evidence as follows:

It has been contended by some pipeline operators that pipeline

charges have only been increasing by inflation. The Inquiry has

found that the prices specified in longer-term GTAs have tended to

only rise in line with inflation, in line with the price escalation

provisions only allowing for a CPI based escalation over the

contract term. However this does not eliminate the potential for

monopoly pricing. Where the initial prices in a GTA are set at

monopoly levels, then increases to these prices at the rate of

inflation will tend to keep these prices at or near monopoly levels.

Where the initial prices in a GTA are set at a level more consistent

with competitive outcomes, these provisions may limit the pipeline

operators’ opportunity to move from competitive pricing levels to

monopoly pricing levels over the contract term. However the

evidence gathered through the Inquiry indicates that pipeline

operators have engaged in such behaviour when entering into new

GTAs, or when some existing shippers have sought an amendment

to their existing contracts to obtain new services. (p 111)

There are a number of points to be made in relation to this statement:

At least for APA’s pipelines, the current tariffs for the primary services

on its pipelines have been set by regulation or competitive processes

(as discussed above). Thus, APA does not agree with the proposition

that initial prices are set at monopoly levels.

The ACCC provides no evidence to support its contention that pipeline

operators have charged monopoly prices at the time of renegotiation or

contract amendment. Considering the number of contracts and

variations that the ACCC reviewed, it is instructive that the ACCC does

not cite a single example where recontracting charges are significantly

above the charges in the initial contract. Indeed, the evidence before

the ACCC from APA would have shown that in the majority of cases,

tariffs drop at renegotiation and renegotiated contracts include

materially more flexibility and services.

Ultimately, despite a 12 month review and forensic examination of pipeline

tariffs, APA notes that the ACCC makes no clear finding and identifies no

evidence that “vanilla” haulage charges are above efficient levels from which

APA earns the bulk of its revenue.

In the remainder of this Part B, APA considers the ACCC’s evidence in detail.

30253978_7 18


3 How does the ACCC support its proposed changes?

The ACCC inquiry

To provide context, the ACCC, under its information gathering powers, had

access to all APA documents and communications, and investigated over

300 contracts and variations from APA alone as part of its Inquiry. It also

required APA to provide communications (including emails, board papers,

notes, reports and so on) between APA senior commercial staff and its

executive over a two year period. The ACCC spent one year looking at

documents provided, interviewing pipeline operators and market participants

under oath, and investigating market pricing outcomes.

Despite this degree of analysis, the ACCC ‘found’ very few examples on

which to base its claims of monopoly pricing by pipeline operators. In most

cases the ACCC resorts to making claims, inferences and assertions rather

than providing evidence.

One would expect that if market power in the pipeline sector were indeed the

problem the ACCC makes it out to be, the ACCC would have been able to

point to more examples, and examples that relate to major revenue drivers

for the pipeline businesses. They simply do not do this, because the

evidence does not exist. Instead, the ACCC focuses on ‘findings’ in relation

to marginal expansion projects, minor revenue items (non-firm services), and

spurious economic claims in regard to “fully paid off” assets to support a

wholesale change to regulation of the pipeline sector.

How did the ACCC base its claim of monopoly pricing?

Specifically, the ACCC relies on three assertions to find ten out of the eleven

pipelines investigated are engaging in monopoly pricing:25

RORs on incremental projects are excessive

Pricing of non-firm services too high

Pipeline charging above operating costs where the ACCC believes that

capital is “fully recovered”


This is APA’s first opportunity to respond to these assertions.

APA has engaged CEG to consider the ACCC’s assertions and the evidence

presented by the ACCC, and found different conclusions to the ACCC based

on economic theory and the evidence. Sections 4 to 6 provide a summary of

CEG Returns Report plus commentary and evidence from APA on each of

the above findings respectively.

In relation to the first two points, APA has a number of concerns with the

way the ACCC has selected and interpreted the evidence. Even so, the

materiality of the issues relied on by the ACCC must be kept in context - the

revenues involved are very small. The net present value (NPV) of relevant

projects are ~1.25% of APA’s enterprise value and available and

interruptible services made up less than 0.5% of APA’s total east coast

pipeline revenue (in H1 FY2016). Despite this, the ACCC is recommending

a fundamental change to regulation that would impact all pipeline services

and investment decisions, without recognition of the associated costs (both

direct and more importantly indirect) of this approach.

In contrast, firm transportation services make up over 95% of APA’s east

coast pipeline revenues in the first half of 2016. As discussed above, the

charges for these services have not increased substantially in real terms

since 2002.

30253978_7 19

In relation to the third point about “older” pipelines charging above operating

costs, the ACCC’s assertions are misleading at best.

First, regulation is intended to mimic the outcomes of a workably competitive

market. In a competitive market such as office property, a tenant does not

pay only outgoings just because the capital costs of the building have been

“fully recovered” (in reality it would be revalued).

Second, the ACCC considers the CGP as one of these pipelines where the

capital has been “fully recovered”. APA recognises that there are many

approaches to pipeline valuations and each will lead to different results but

the ACCC has taken a “back of the envelope” approach which is not

consistent with precedent, the relevant rules or regulatory practice and in

any case, is prejudging the question that it is seeking to answer through its

analysis.

Third, it is a flawed proposition to compare current prices for an unregulated

pipeline by going back in time and assuming what prices would be if the

pipeline had been regulated from its inception. Further, if an “old”

unregulated pipeline was to become regulated, its initial capital base would

not be set at zero and it is misleading to suggest otherwise.

30253978_7 20


4 RORs for incremental projects

ACCC claim

The ACCC claims that pipelines were charging for expansions at above

regulated returns based on analysis of selected projects ranging from $10M-

$120M26 – it is unclear how the selection was made or what proportion of

pipeline projects they comprise.

The projects are set out below – with those projects above the ACCC

benchmark relating to APA identified, which significantly are all incremental

projects.

APA can understand the “sticker shock” of the ROEs cited for its

bidirectional projects but they need to be considered in context.

ACCC relies on selected projects

Before discussing the methodological issues with the ACCC’s approach

discussed in this section, it is important to remember these are generally

small, incremental projects which are building on substantial sunk assets.

For APA, in aggregate these projects (assuming that all the assumptions

embodied in these pre-investment calculations are correct which was not the

case) have an NPV at an 8% discount rate of $220M. For a company that

has an enterprise value of approximately $18B, these projects are not major

drivers of revenue or profit. That is the NPV of these projects, the supposed

26 ECGI, p 105.

excess return, represents less than 1.25% of APA’s enterprise value. At the

very least, it is questionable whether a small number of projects justify a

wholesale change to the regulatory framework.

The pricing of a small sample of projects should not be used to draw

conclusions about the pricing of firm services comprising the bulk of the

services provided and revenue where the evidence is that those prices have

not increased in real terms since 2002. A business may make a high margin

on one item of inventory but care should be taken in translating that pricing

into a broad conclusion of monopoly pricing.

ACCC has used the wrong comparator

The equity returns cited for APA cannot be compared to the AER equity

allowance because they have different gearing/debt assumptions. This is

explained in the CEG Returns Report.

In order to perform an ‘apples for apples’ comparison, the comparison

should be done at the overall project Internal Rate of Return (IRR) level in

which case CEG calculates the AER benchmark return will fall to about 7%

and the APA returns halve. Below is the ACCC Chart 6.1 shown with project

IRR included. This shows a much smaller difference and, as explained

below, it would be expected for the project IRRs to exceed the costs of

capital for incremental projects.

30253978_7 21

IRRs are typically higher for incremental investments

All of the APA projects in the ACCC’s Chart 6.1 involve an incremental build

on existing pipelines, and many are relatively small projects compared to the

values of the existing pipelines that these investments facilitate use on. As

explained in the CEG Returns Report, such incremental projects are likely to

have higher expected returns than the existing assets as a result of

leveraging of both existing assets and accumulated know-how and other

forms of intangible capital residing within the organisation. High returns on

such incremental investments are the norm - even in the most competitive

unregulated market - and do not provide evidence of monopoly pricing.

CEG example of a café

A simple example from the CEG Report illustrates this concept. Consider

a café that is in the position that demand for its services is higher than it

had previously experienced or expected. The café owner concludes that

if she invests $5,000 in a new, larger and faster, coffee machine she can

improve client satisfaction (in terms of reduced average wait time), serve

more customers and increase revenues by $100 per weekday (say, 25

additional coffees). The additional costs, in terms of milk and coffee, may

only be $20 per day. With around 250 weekdays per year this implies an

annual incremental increase in profits of $20,000 and an IRR of 400% on

the $5,000 incremental outlay.

However, the existence of an incremental investment offering a 400%

return does not imply that the café is monopoly pricing. It is simply an

example of a business responding to altered market circumstances by

making an incremental investment (a new coffee machine) that builds on

its prior investments (the entire café fit out) and intangible assets (the

‘know how’ of existing staff and a the development of a client base). The

calculation of a 400% return on the incremental investment is misleading

because it fails to recognise that the return is only available because of

larger and more long-standing investments in both physical and intangible

assets. Precisely the same logic applies to APA’s incremental

investments which are only able to earn any return at all because they

leverage on the existence of APA’s wider pipeline network and its

intangible assets (including its technical and market know-how).

The regulated return is not an appropriate benchmark

APA believes the comparison for unregulated projects against the regulated

rate of return is not appropriate for the following reasons.

First, as discussed in the CEG Returns Report, the ACCC’s interpretation of

its IRR analysis is problematic because all firms, even those operating in the

most competitive industries, will typically only take projects to the Board if

they offer IRRs materially in excess of the weighted average cost of capital

(WACC). Clearly, no projects will be proposed to a Board that have IRRs

less than WACC because such projects are value destroying. Few, if any,

will be proposed that have IRRs equal to WACC because such projects

create zero value for the firm (and negative value once risk, management

time and financing is taken into account). Consequently, a finding that the

forecast IRR on new projects is typically above WACC is unsurprising and is

exactly what would be found looking at board papers from the most

competitive of industries.

Second, the ACCC does not recognise that in developing a project, pipelines

take on a number of risks for an unregulated asset that is not borne by a

regulated asset and would by logic result in returns that are higher than

regulated returns. The following table identifies the risks which pipelines

may accept and the SWQP case study in section 4.6 provides a case study.

Risk Unregulated pipeline Regulated pipeline

Project

development

risk

For each

project that

reaches an

investment

decision,

there are

others that do

not.

The cost of researching

acquisition options,

commissioning market

studies, survey costs,

costs of securing debt

financing and advisers

cost are absorbed by the

business. Therefore, the

returns on an approved

project needs to cover the

costs of those projects

that did not reach final

commercial approval.

On the regulated asset

there is an allowance for

the cost developing the

market.

30253978_7 22

Construction

risk

Construction

completion

and cost risk

Typically at project close

the risk of delivering the

project on time and on

budget rests with the

pipeliner with no or limited

re-openers.

Subject to reasonable

actions by the service

provider construction risk

and overruns are added to

the RAB.

Operating

costs

Pipeliner takes a long term

position on the operating

costs of the asset by

managing the risk of

change in law or technical

standards.

These risks are accounted

for in the revealed cost

methodology for regulated

assets which provides an

opportunity to reset to

actual costs on at least a

5 year basis.

Funding

costs

Pipeliner takes the risk on

funding costs over time. If

funding costs have

decreased since the time

of commitment, it may

appear that the pipeliner is

earning an excess return

but what may be

overlooked is that the

pipeliner has locked

funding costs at the time

of project commitment so

the excess return is

misleading. Further, the

pipeliner bears the

refinancing risk.

Regulated assets are at

least partially protected

from the movements in

funding and refinancing

risks through regulatory

resets.

Third, the ACCC did not refer to the surrounding context and risks of those

projects as articulated in the Board papers. Due to confidentiality, APA

27 DTS refers to the covered Victorian Transmission System that forms part of the declared

wholesale gas market arrangements under the NGL.

recognises this was difficult for the ACCC to do so in the ECGI Report. The

CEG Returns Report provides additional context to that set out below.

Declared Transmission System (DTS)27 expansions

For the three projects shown as “DTS expansion,” the equity IRR figures

quoted in the board papers include expansion works conducted both in the

DTS (South West Pipeline and Victorian Northern Interconnect (VNI)) and

the MSP and the capex and revenues from both pipelines were used in the

calculation so as to be able to develop a service to transport gas Longford /

Port Campbell to New South Wales. However, if the DTS expansions are

considered in isolation and the additional MSP revenue is removed (noting

that a zero cost was allocated in the investment case for using the MSP),

then the equity IRRs (as distinct from returns on equity) reduces:

11.2% to 8.6%

11.4% to 7.1%

19.2% to negative returns.

These projects assumed certain regulatory RORs for the Victorian system as

it is fully regulated. Since the date of these investment decisions, the AER

has reduced the regulatory returns below that assumed rate.

The projects were also a response to competition from the EGP and APA

was undertaking the expansions to ensure it captured a share of northern

flows and increased the utilisation of the MSP, therefore reducing the

likelihood of the EGP expanding. The following extracts from the Board

papers (being the ones relied on by the ACCC for its equity IRR citations) for

each of the three projects expressly state this:

Although APA has previously carried out a number of VTS

Northern Interconnect expansions, these have been largely to meet

APA’s contracted positions for capacity into NSW. APA is therefore

not currently strongly positioned to be able to capture further gas

supply from Victoria (and therefore into the MSP) to meet the

expected increase in demand, due to in part to limited current

30253978_7 23

available capacity on the VNI and an existing strong competitive

position offered by the Eastern Gas Pipeline (EGP). As proposed

as part of the March Strategy Day, it is therefore strategically

important that APA expands the VNI, albeit at regulated returns, to

strengthen APA’s competitive gas transmission solution on the east

coast.28

The proposed expansion, consistent with strategy, will provide an

expanded firm north bound service between the Victorian

Transmission System and the Moomba Sydney Pipeline, and

reduce the likelihood of a further expansion of the Eastern Gas

Pipeline.29

[The expansion] will provide an expanded firm north bound service

between the VTS and the MSP, capture services currently

contracted by the Eastern Gas Pipeline, and reduce the likelihood

of an Eastern Gas Pipeline capacity expansion.30

MSP bi-directional project

In general, bidirectional projects are unique in the sense that they have

relatively low capital costs but deliver a considerable amount of additional

capacity in the reverse direction. Furthermore, you can obviously only

modify pipelines so that they transport bi-directionally once. The MSP bi-

directional project was undertaken to enable APA to provide new

westernhaul services on the MSP in an environment where contracting for

easternhaul services are declining. The bi-directional project when

considered by itself has a deceptively high project return given the additional

volumes it creates but if the entire asset base of the MSP was considered

and the fact that its overall volumes and revenues would be declining if

these new services were not offered, the overall returns on the MSP are not

28 APA Board Meeting Paper, Item No: 10, Expansion of Victorian Transmission System:

Victoria (21 May 2013), p 2. 29 APA Board Meeting Paper, Item No: 8, Expansion of the Victorian Northern Interconnect (21

April 2015), p 9. 30 APA Board Meeting Paper, Item No: 7, Expansion of the Victorian Northern Interconnect:

Victoria (22 October 2013), p 8. 31 APA Board Meeting Paper, Item No: 9, Bi-Directional Flow on the Roma Brisbane Pipeline:

Queensland (20 May 2014), p 9.

high and may not even recover a return commensurate with that available

under regulation.

RBP bi-directional project

The RBP bi-directional project was partly initiated because a number of

shippers approached APA, seeking access to gas supplies mid-way along

the RBP, which would otherwise be delivered in an easterly direction.

Furthermore, APA recognised the risk that “if APA is unable to provide

westbound gas transportation services on the RBP at a competitive tariff,

then the RBP may be bypassed by others to fulfil this demand, further

increasing the risk of asset stranding”.31 Therefore, in order to provide

western haul services on the RBP as well and to make up for declining

eastern haul services, the APA Board approved the conversion of the RBP

to bi-directional flow in May 2014.32

For this project, return on equity of 159% (or 64% equity IRR) sounds high

but the NPV of the project is only $8.3m - this is a small incremental project

for a pipeline with a regulated asset base of over $450M. It is also worth

noting that the ACCC only quoted the high case returns in the board paper –

the low case had a post tax project return of 5.3%. Further the investment

assumed shippers would contract for specific quantities33 - these forecasts

have not been achieved.34 The capital costs were also higher than APA

forecast, due to scope development, scope change and underestimating.35

This was because there had not been detailed engineering completed before

finalising the estimated costs, while there had also been development

requirements associated with APA’s integrated grid of pipeline assets on the

east coast (East Coast Grid) that were unknown at the time.36 This

demonstrates the point about project risk. APA has taken market and

construction risk and it has not worked out how APA expected.

32 Ibid. 33 Ibid, p 2. 34 APA Board Meeting Paper, Item No: 10, Moomba – Sydney Pipeline and Roma – Brisbane

Pipeline Bi-Directional Flow Projects (23 March 2015), p 4. 35 Ibid, p 1. 36 Ibid, p 1.

30253978_7 24

SWQP bi-directional project

This project involved a $98M modification to the SWQP which involved some

oversizing compared to the contracted volumes and APA taking market risk,

so a regulated return is not an appropriate benchmark. In addition, APA

constructed new compressor stations at Moomba and Wallumbilla at an

additional cost to facilitate the receipt and delivery of the additional quantities

of gas required to actually reverse the flow in the SWQP.

In relation to elements of this project, the ACCC does not report that two of

the shippers were running their own in-house shadow projects and were

more than capable of undertaking the infrastructure development and

operating the asset themselves - but they still chose to contract with APA.

One proponent was also investigating alternative options for gas supply that

would negate its need for bi-directional flow. Further, in September 2013,

APA Board approval was sought for additional capital expenditure of $54.5M

to complete the modification of the SWQP.37 This was largely due to a

widened scope of the SWQP (from supplying just Santos to also Origin

Energy and AGL), as well as significant construction cost increases.

APA built the SWQP expansion at a time of increasing design and

construction costs brought about by the massive investment in LNG

infrastructure. APA has stated that “the original budget was substantially

underestimated as it was based on an early concept design against which it

was not possible to accurately estimate construction and procurement

costs”, while “in addition, there was no ability to get market pricing due to the

limited design” .38 This is another example of project risk in the form of

construction risk.

37 APA Board Meeting Paper, Item No: 11, Easternhaul Project – South West Queensland

Pipeline, South Australia and Queensland (24 September 2013).

38 Ibid, p 5.

30253978_7 25


SWQP case study

The purpose of this case study is to provide context for the contracting of the

expansions of the SWQP. In APA’s view it shows the strengths of the

current regime where parties can commercially agree contracts and risk

allocations to enable timely pipeline development. At the end of the case

study, we also address the issue of how the current returns compare to

regulated returns.

The construction of the pipeline expansion and duplication resulted from a

competitive process which benefitted both parties, as recognised by the

ACCC:39

“In 2007, Epic and APA competed to develop a new pipeline to enable

gas from Queensland to be transported into the southern states. Epic

proposed reversing the flow and expanding the capacity of the SWQP

and constructing the QSN, while APA proposed the construction of a

new pipeline from Wallumbilla to Bulla Park. Epic ultimately won this

contest, with AGL and Origin entering into foundation contracts in 2007

and 2009, respectively. The prices and other terms and conditions in

these foundation contracts suggest that AGL and Origin both benefited

from this competition.

The outcomes of these two competitive processes suggest that

‘competition for the market’ can impose an effective constraint on the

behaviour of new pipelines.”

For the SWQP, it is important to understand the commercial context in which

the pricing and terms were struck and to have regard to the history of the

pipeline and the performance and funding risks assumed by Epic Energy.

Original assumed volumes not realised

The SWQP was originally built in 1996 following a tender process. The

winner, Tenneco took on market risk for uncontracted volumes that had

been assumed in their investment case. While it had long term contracts

with the South West Queensland Cooper Basin Producers, a significant

portion of the MDQ for Incitec’s Gibson island plant expired in 2007 and did

not get renewed, resulting in a revenue loss of ~$11m per annum.


The original Tenneco investment case and any upside was not realised due to CSG

supplying Brisbane and Gladstone and displacing gas from Moomba which would

have used the SWQP. From the mid-2000s the market changed again. From 2008,

the SWQP was subject to a series of extensions (including the QSN link between

Ballera to Moomba) and ultimately the looping of the entire SWQP undertaken by

APA’s predecessor, Epic Energy.

Contracts for QSN link and expansion of SWQP

Epic Energy entered into contracts with AGL in 2006/7 for the construction of QSN

Link (being an extension of the SWQP between Ballera and Moomba) in 2008.

SWQP was a price taker given it was significantly underutilised at the time. As part of

that agreement, AGL also had an option to expand the SWQP.

Subsequently, in 2008, Origin undertook a competitive process to seek proposals for

the transport of its gas from Wallumbilla to southern markets. There were three

competing proposals. Epic Energy proposed expanding the SWQP by looping it.

APA’s proposal was a pipeline development from Wallumbilla to a mid-point location

on the Moomba-Sydney Pipeline. There was also a Hunter Valley pipeline consortium

which proposed a pipeline from Wallumbilla to Newcastle.

Origin Energy selected Epic Energy’s proposal and was able to extract severe

penalties for non-performance from it. At this time, the GFC severely limited access

to equity and debt markets. Epic Energy was able to acquire finance, but had no

option other than to access expensive debt and mezzanine debt/equity markets due

to financing deadlines imposed by Origin. Epic Energy sought additional shippers to

secure the viability of the pipeline looping and was successful as AGL Energy

exercised its option to expand capacity under its foundation QSN Link gas

transportation agreement. As a result, the looping expansion included capacity to

meet Origin’s and AGL’s requirements.

In addition to high financing costs, Epic Energy overcame significant difficulties during

construction to deliver the SWQP looping by the December 2011 deadline. The

Origin gas transportation agreement gave Origin a termination right if Epic failed to

meet target dates. Two once in 100 year flood events disrupted construction,

necessitating a change to beginning construction in the east rather than in the west.

30253978_7 26

Following completion of the looping project, Santos sought reversal of the

SWQP and provision of a competitive tariff to allow Cooper Basin gas to be

supplied to Wallumbilla in direct competition with Coal Seam Gas (CSG)

sourced from the Surat Basin. The parties negotiated a tariff that allowed

this to occur whilst providing a sufficient return to Epic Energy to allow

conversion of the pipeline to bi-directional operation.

In addition, shippers sought additional inlet and outlet compression capacity

at Moomba and Wallumbilla respectively. Shippers ran parallel internal

proposals to install their own compression. Epic Energy was able to

demonstrate that it could provide the compression on more attractive terms

and entered into agreements and undertook the compression projects.

Conclusions

This description shows a pipeline developed in circumstances that are very

different from an assumed monopoly service provider increasing capacity in

a stable and secure demand and cost environment. The ACCC’s assertion

that regulation would deliver a different pricing outcome is correct; this is

because regulation would have led to a different investment option and

timing. As discussed in respect of the costs of regulation in Part D, under a

situation of up front regulation one would expect investment delays through

the regulatory process where the service provider sought to secure up front

regulatory approvals, as well as potentially less capacity being added in

order to avoid there being spare capacity available on the pipeline that was

subject to demand risk.

Apart from this outcome arguably failing to meet the needs of consumers (as

well as failing to deliver the current flexibility to the market that this capacity

provides), building less capacity would likely have led to comparatively

higher average tariffs due to lost economies of scale from the investment.

40 APA Transmission Division, Strategy Session Report (23 and 24 March 2015), pp 9, 100,

103 and 114.

Comparing SWQP tariffs to regulated returns

In the ECGI Report, the ACCC stated a “pipeline is earning 70% more in

revenue than the pipeline operator estimated it would be if it was

regulated”.40 This is a reference to the SWQP. As noted in Part A, the

ACCC has made this calculation based on one sentence in Appendix 3 of a

60 page Board presentation. The particular page was addressing regulatory

risk and was highlighting that the long term contracts mitigated against the

future risk of regulation as represented by the “back of the envelope”

assessment included.

Importantly, given the context, the assessment was made using the

regulated rate of return applying in 2015 (~6%), not that which was applying

in 2008 and 2009 during the GFC (~10.5%) and used an 80 year

depreciation profile rather than one linked to the remaining life of the gas

fields (which is significantly shorter). It also used rough expenditure

estimates with only notional allocation of corporate costs.

The key point, however, is that it is not legitimate to compare revenue

calculations using today’s rate of return with contractual rates stuck at a

different time and that were commensurate with what would have been the

prevailing regulatory rates of return at the time.

In any case, the tariffs of the SWQP were a result of a competitive tender

process, which reflected the risks of the project at the time. It is not correct

to use a regulated rate of return benchmark against such a competitive

project to find that that the agreed tariffs reflect monopoly pricing.

It is worth observing that the outcomes from the NEGI process was similarly

a competitive process, and will lock in a rate of return over a long period of

years that reflect today’s current low rates. We would not expect many to be

seeking a regulated tariff in respect of the NEGI should the prevailing cost of

capital increase during the term of the initial contracts.

30253978_7 27


5 Pricing of non-firm services are not too high

The ACCC claim

The ACCC claims that pipeline prices for as available, interruptible and bi-

directional services are “excessive”.41 The ACCC uses the following

benchmarks to assess pipeline pricing:

Firm forward

haul services

No benchmark as such. ACCC does not find that forward

haul rates are “excessive”.

As available

and

interruptible

services

Firm capacity charge x pipeline load factor (over last 5

years) (p 109)42

Backhaul

services

50% of the (firm) forward haul tariff (p 109)

Bi-directional

services

No greater than the firm forward haul capacity charge (p

109)

(But many of the incremental projects noted by the ACCC

are bi-directional projects)

The ACCC’s ‘findings’ for charges above their benchmarks are marginal at

best in the context of how many contracts, expansions and variations that

they viewed. The ACCC makes the following claims:

(a) only two pipelines were charging for bi-directional services at

above the “benchmark” of the firm forward haul rates and both

were explained satisfactorily (p 110) so these do not support the

ACCC claim;

41 ECGI, p 108. 42 Note that the ACCC’s supposedly appropriate benchmark is effectively unusable for pipeline

pricing. It reflects a floating multiple of the firm rate based on historic utilisation of the pipeline. Historic utilisation is unlikely to be an indicator of future pipeline utilisation in the current changing market dynamics.

(b) only three pipelines were charging for as available and interruptible

services at a benchmark above the load factor x firm forward

haulage rate (p 110) (note, these are APA pipelines);

(c) back haul charges being charged are equal or less than the

benchmark of 50% of firm forward haul rate but there was a recent

allegation of two key pipelines offering the services equal to the

forward haul rate (p 110) (these do not appear to relate to APA).

Again, context is required - the quantum of revenue from these services is

small and, to the extent there is an issue, the new mechanisms for capacity

trading being introduced through the AEMC process will address them.

ACCC’s examples of pricing services over the benchmarks

The three examples of pricing of as available and interruptible services

(secondary services) above the ACCC benchmarks relate to APA pipelines

as follows:

185% of the firm rate – SWQP;

200% of the firm rate – RBP;

350% of the firm rate – MSP.

However, these are not representative examples. The tariffs selected are

exceptions to its general contracting practice in relation to as available and

interruptible services. As noted to the ACCC, APA’s general practice is to

set as available at 120% of firm43 and interruptible at 150% of firm which are

consistent with the ACCC benchmarks referred to above. It should be

remembered that APA is an evolving business that has resulted from

acquisitions and has a number of legacy contracts. APA is continually

reviewing services and tariffs and seeking to standardise them to remove

anomalies which have resulted from particular negotiations.

43 In the RBP Access Arrangement approved in 2012 and the current GGP Access Arrangement, the AER approved an Authorised Overrun rate of 120% the firm tariff. An Authorised Overrun is effectively an as available transport service.

30253978_7 28

In relation to the 350% example, APA accepts this is an exceptional rate

that reflected certain historical factors and is not a feature of MSP

contracts signed today.

The ACCC is comparing rates for as available and interruptible services

against firm rates offered to other shippers as a result of negotiations at

a different time – not contemporaneous supplies. For example, in

relation to the 185% rate on the SWQP:

o The comparison is between the as available price payable by

shipper C for western haul with the firm payable by another shipper

A.

o Shipper A has the lowest western haul rate because it was the first

to commit to capacity (and therefore obtained the lowest cost

capacity).

o Shipper B was next to contract and the cost was higher. Shipper C

pays the same as Shipper B for interruptible services, which is

130% of the firm tariff that Shipper B pays.

o So it is not a case of APA changing the interruptible factor to 1.85

but that the inappropriate firm rate is being considered.

Quantum of revenue from non-firm services is small

APA’s revenues for as available and interruptible services remain very small

in comparison to revenues from other services.

In FY2015, as available and interruptible services accounted for 2% of total

revenues ($10,957,109 of $520,876,721), including 1% on the SWQP, 3%

on the RBP and 2% on the MSP.

In the first half of FY2016, these revenues had fallen further, accounting for

only $2,047,342 of $529,493,584 in total revenues or 0.4%.

As stated earlier, the ACCC has based its case for increased regulation on

isolated observations related to minor items of pipeline revenue which do not

justify a broad finding of monopoly pricing or the imposition of a new

regulatory regime. APA notes that the ACCC sought these contextualising

calculations from APA during the review process, but appears to have

chosen not to emphasise them while making its findings of widespread

monopoly pricing.

Shippers currently have access to non-firm services

APA offers interruptible services to assist shippers to obtain capacity on

pipelines that are fully contracted, as well as to provide capacity to shippers

who choose to acquire non-firm services for the purposes of their own

flexibility on both fully contracted pipelines and pipelines with available spare

capacity.

Shippers can also trade capacity bilaterally via bare transfers or contract

novation, or use APA’s capacity trading service (and web portal) to reduce

transaction costs and complexity of bare trades.

APA is actively engaged with the AEMC in its East Coast Wholesale Gas

Market and Pipeline Frameworks Review and has submitted that for

contracted but un-nominated capacity on pipelines that are fully contracted

(contractually constrained), APA will develop and implement a further

system of auctioning unutilised capacity with an effective pipeline reserve

tariff of zero.

These mechanisms clearly establish that there are multiple sources of non-

firm capacity (via the pipeline operator and other shippers), and the new

auction process is likely to further provide access to non-firm capacity on

fully contracted pipelines at market-determined prices.

30253978_7 29


6 ACCC assertions on capital cost recovery and subsequent pricing

The ACCC claim

The ACCC asserted that some pipelines are charging prices where the cost

of construction of the pipeline has already been recovered and which are

higher than those that would apply if those pipelines had been regulated (p

106). The ACCC considers this to be the case for two pipelines, one of

which is the CGP.

Summary of APA position

The basis of the ACCC’s assertion is not fully disclosed. APA does not

agree with the ACCC’s assertion and it does not appear to have been

reached using established regulatory principles, precedent or indeed

compliance with the Rules.

Further, the ACCC’s analysis is wrong when looking at a broader application

of economic principle. There are three core problems with the ACCC’s

approach (as explained more fully in the CEG Returns Report):

Competitive industries charge based on new entrant cost. At no stage

did the ACCC look at whether pipeline operators were charging above

the new entrant cost when reaching its conclusion on monopoly pricing.

As was the case with its use of IRRs, applying the ACCC’s methodology

to determine if a pipeline has recovered its initial capital costs is likely to

result in a finding of full capital recovery and therefore ‘monopoly power’

in the most competitive of markets (e.g., residential and commercial real

estate).

If the ACCC actually imposed pricing on the basis of marginal cost for

pipelines that have “fully recovered” past capital expenditure then this

would inevitably result in the present value of new pipeline investments

being negative – with a consequent damage to new investment

incentives.

The efficient operation of existing pipelines would be impaired.

In relation to the CGP, APA does not agree that its costs have been “fully

recovered” and the competition for the NEGI project has reset the price for

this pipeline through a competitive process.

Competitive industries charge based on new entrant costs

Regulation has the objective of mimicking competitive outcomes. In a

competitive industry pricing is, in equilibrium, determined by the costs that a

new entrant would incur to provide the service. This need bear no

relationship to the costs incurred, and revenues earned, in the past from an

investment. By way of example, rents in a CBD office tower today are tied to

the costs of creating new office space. Rents today are not determined by

how much of the original cost of construction for a specific tower has already

been recovered.

It is in recognition of precisely this fact that regulators, including the ACCC,

have historically set the initial value of regulated assets at the depreciated

optimised replacement cost (DORC) of those assets (and not, for example,

book value).

In a previous assessment of whether current pricing is consistent with

workably competitive markets (e.g. in relation to the coverage of the MSP in

2002), the ACCC compared revenues with replacement costs of the assets.

By contrast, the ACCC inquiry concludes that if specific assets had been

regulated from the date of their inception they would have zero regulatory

asset values – and, consequently, prices would be lower than they currently

are. However, even if this were true, it says nothing about whether current

pipelines are pricing above the levels consistent with contestable markets –

markets in which prices and assets are determined on the basis of

replacement cost.

Further, if the ACCC followed its own historical practice (and that of other

regulators), then even if these asset values were to be regulated today, their

regulated asset value would be set on the basis of depreciated optimised

replacement cost. That is, the zero valuation being posited by the ACCC

would not occur even if the assets became regulated – at least not without a

radical departure from, in APA’s view, sound regulatory precedent.

Impact on investments in new pipelines

If a pipeline were required to set prices based on marginal cost once it had

“fully recovered” their initial investment costs then this amounts to

30253978_7 30

retrospective application of regulation. If put into practice, having

‘unregulated’ status would be meaningless because the ACCC would, once

a pipeline was successful enough, claw back past revenues by, in effect,

using them to set low future prices.

Applying this approach on a pipeline-by-pipeline basis would mean that the

expected return on a new pipeline is negative (i.e., IRR less than WACC). In

effect, the ACCC is proposing to:

regulate down to marginal cost all of the successful pipeline

investments; while

leaving all of the unsuccessful pipelines to suffer losses (in NPV terms).

This would leave the industry as a whole under-recovering its costs.

Equivalently, the expected return on a new pipeline would be negative under

such a regime (assuming that it is less than certain that it will be able to

recover its initial costs). An implication of the above is that it would deter

investments in all but the safest new pipelines.

A safe pipeline investment would be one that had no available spare

capacity (as any upside for pipeline operator from taking a risk on

developing the market would be confiscated) and existing long term

contracts (recovering all of the investment costs) with only very highly credit

worthy counterparties. If the pipeline operator could not achieve these

safeguards the investment would not proceed.

Distortion of the efficient operation of existing pipelines

A pipeline has little incentive to minimise costs or maximise throughput if that

pipeline anticipates that, once the ACCC deems initial investment costs are

“fully recovered”, prices will be regulated equal to marginal cost. Any

benefits that the pipeline would otherwise have achieved by more efficiently

operating their asset will be lost by virtue of bringing forward the date the

ACCC requires the pipeline to lower prices down to marginal cost (lowering

profits by an equivalent present value in the future). Put simply, if a

business expects regulation to retrospectively claw back any benefits from

more efficient operation of their asset they have less incentive to be efficient

in the first place.

Such an approach to regulation would also cause serious problems in the

operation of the market by giving some customers access to existing

capacity (and new increments to that capacity) on some pipelines at

marginal cost while other users (on the same pipeline and on competing

pipelines) have to pay a price that reflects average cost. In particular:

shippers with firm contracts on the pipeline in question would need to

continue to make their contractually binding payments;

the same would be true of shippers on competing pipelines – both for

existing and new incremental capacity on those pipelines.

The effect of this would be that investment in new incremental capacity

would be inefficiently distorted in favour of investment on the pipelines the

ACCC deemed had already “fully recovered” cost – because new users of

that pipeline would not have to pay prices reflecting the true market value of

the underlying assets. Other competing pipelines may then not find it

possible to attract shippers at prices that will allow them to recover their fixed

costs (even if this is defined in terms of their historical costs) because they

are now competing with pipelines only recovering marginal costs.

Similarly, some users may delay usage of the pipeline in order to ensure that

they only ‘join’ once costs have been deemed by the ACCC to be “fully

recovered”. That is, if a pipeline is forecast to fully recover its (ACCC

deemed) historical costs in “t” years’ time then potential new shippers will

expect a significant price drop at that time. This may sway their decision to

delay their entry (and any consequent down/upstream investment) until that

time. For example, consider a gas field owner thinking about expanding

output from their gas field. Other things equal, it would be rational to delay

that expansion “t” years to take advantage of artificially lower transport costs

at that time.

30253978_7 31

PART C – IMPACT ON GAS PRICES

In Part B, we considered the strength of the evidence on which the ACCC made

findings of monopoly pricing on which it justifies it calls for more regulation of

pipelines. In Parts C and D, APA considers the benefits and costs of greater

regulation of pipelines.

In this Part C, APA considers the claims by the ACCC that regulation of pipelines

would provide benefits to customers in Southern Australia through lower gas prices.

APA has engaged CEG to analyse the ACCC’s model on which it relies to find that

regulation would reduce prices (CEG Pricing Report). Starting with an assumption

that regulation reduces transmission pipeline prices, CEG finds that in fact when gas

flows from Southern Australia to Queensland (which is the current predominant flow

direction and is likely to continue), prices in Southern Australia actually increase. This

supports the exact same finding from two independent investor analyses of the

pipeline industry.

This is not to suggest that APA considers inefficient transmission prices to be justified

or desirable. Rather, it calls into question both the analytical framework and the

materiality on which the ACCC claims benefits of regulation when compared to the

costs or regulation considered in Part D.

7 CEG Pricing Report

ACCC assertions

At section 6.4 of the ECGI Report, the ACCC asserts that high transport

charges on some pipelines can affect gas prices in the southern states even

for users that don’t directly utilise those pipelines. In particular, it claimed

that (as illustrated by Table 6.2 of the ECGI Report) reducing transportation

charges by 10% to 50% could lead to a $0.20 to $1.02 difference in the

maximum price payable by domestic users in the southern states, if that

reduction is actually passed through by the shippers.

The ACCC’s conclusions can be summarised as follows:

Gas prices in Queensland are now linked to LNG netback prices.

There is a different pricing dynamic in the southern states created by

the distance separating users and producers in the south from the

Queensland export facilities.

The cost of transportation between Queensland and the south creates

range of possible pricing outcomes in southern states, represented as

the gap between the “buyer alternative” and the “seller alternative”

prices as shown in the Chart 2.4 from the ECGI Report below.

The seller alternative (for southern gas producers) to selling gas to

domestic gas buyers in southern states would be to sell gas to the LNG

projects in Queensland. 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 (assumed to

be the LNG netback price).

The buyer alternative (for southern gas buyers) to buying gas

produced in southern states is to buy gas produced in Queensland. 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 buyer alternative price is therefore equal to the

Queensland price plus southbound transportation costs.

30253978_7 32

The ACCC assumes that GBJV will hold significant market power and is

likely to charge domestic users in the southern states a price

approaching the buyer’s alternative.

Therefore, if the transportation costs are reduced, the buyer alternative

price is correspondingly lowered and prices for southern buyers are

reduced by the amount of the transportation costs.

CEG analysis

CEG was commissioned by APA to review the ACCC analysis above.

CEG’s Pricing Report includes formal economic modelling and illustrates

significant flaws with this reasoning and an oversimplification of gas pricing

dynamics which makes the ACCC’s reliance on it untenable.

High transportation costs would generally lower southern prices

The direction of flows is critical to the ACCC analysis.

If gas is flowing south (i.e. from Queensland), the price in the southern

states must be the LNG netback price plus transportation costs (or

otherwise it is more profitable to export as LNG). In this scenario,

lowering transport costs would reduce southern prices.

If gas is flowing north, then on the ACCC’s approach the price in the

southern states must be less than the LNG netback price less

transportation costs (or otherwise it is more profitable to sell in the

south). In this scenario, lowering transport costs would raise southern

prices, e.g. if the LNG netback price is $8/GJ and the transport costs

are $1/GJ and gas flows are northward, then the southern price for gas

must be equal to or less than $7/GJ or otherwise it would be more

profitable to sell in the south. If transport cost is reduced by half, it now

means it has become economic for Queensland LNG buyers to buy gas

in the south at $7.50, thereby raising the price for southern buyers to

$7.50.

The evidence shows that gas flows are increasingly flowing north (see

evidence in section 3.3 of the CEG Pricing Report). APA can confirm that it


has signed a number of GTAs to move gas north. It is also evident that the

market is anticipating northern gas flows given that the MAPS has become

bi-directional and can now flow north, the EGP has expanded to allow

greater northerly flows and the MSP has become bi-directional to allow flows

north. The ECGI Report itself noted that over $450M of pipeline investments

had been made to enable more gas to flow from Victoria to New South

Wales and up to Queensland.44

ACCC analysis relies on GBJV market power or a cartel

How then does the ACCC reach a conclusion that prices will reduce when

their own economic model suggests they will increase? It appears that the

ACCC assumes that southern gas markets are not competitive and GBJV

(acting unilaterally or in concert with other southern producers) is charging:

Queensland customers - the LNG netback price less transportation

costs for northern flows; and

Southern customers – the LNG netback price plus transportation costs.

The ACCC notes that the southern states are now heavily reliant on supply

from the GBJV45 and in the in the absence of competitive constraints, the

GBJV will hold significant market power.46 While GBJV is a large producer

in southern states, it is not clear that it is a monopolist and has this level of

market power (CEG notes that in 2015, GBJV supplied 55% of gas

production in the east coast excluding Queensland which leaves 45% of

production in the hands of other suppliers).

As shown by CEG, it is unlikely that it would be profit maximising for GBJV

(even if it had market power) to reduce output to lift prices – 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. In any case, this is

not the evidence provided by the ECGI where it found that the GBJV sales

are at record levels.47

The other alternative is an ACCC investigation into a cartel or coordinated

conduct between the GBJV and southern producers. The ACCC spent 12


30253978_7 33

months undertaking the ECGI Report including compulsorily obtaining

document and examining industry participants on oath. The ECGI Report

does not suggest this is the case.

The ACCC model is simplistic and not reliable

CEG highlights a number of assumptions underpinning the ACCC approach

which do not, or are unlikely to, apply in reality. In each case, the impact is

to reduce the “dead zone” between the buyer alternative and the seller

alternative (the area of blue shading in the chart above). This means that

even if the ACCC’s analytical approach was correct, a reduction in transport

costs would have minimal impact on southern gas prices.

First, the ACCC assumes that gas can be diverted from/to LNG export in

large quantities as soon as domestic prices depart from international oil

prices (less the costs of converting domestic gas to export LNG). 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 gas producers and/or consumers.

However, CEG does not consider this assumption to be correct because:

consistent with most such capital intensive projects, providers along the

LNG supply chain will have built little excess capacity into their

operations. 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;

the LNG infrastructure is underpinned by long term offtake contracts so

the ability of LNG exporters to respond to higher domestic gas prices will

be limited by the need to fulfil contractual obligations. There would need

to be high sustained domestic prices to justify leaving expensive LNG

capacity unutilised;

accordingly, there will be a wide range of price differences (between

Queensland gas and international oil prices).

48 ECGI Report, p 114 and Mr Rod Sims, Speech to the South East Asia Australia Offshore &

Onshore Conference, Darwin, 15 September 2016.

Second, the relevant measure of transport costs is the shippers’ marginal

(not average) costs.

The ACCC estimates the impact of a 10% to 50% reduction in transport

costs based on the average prices in shippers’ take or pay contracts with

pipelines assuming a 100% load factor. The relevant pipelines are the

SWQP (western haul) and the MSP.

However, shippers have contracted firm capacity on these pipelines and

therefore their marginal cost of using that capacity is close to zero (i.e.

variable costs only). Those shippers who have spare capacity already have

an incentive to arbitrage between the Queensland and southern markets.

APA can confirm the evidence provided in the CEG Pricing Report that there

is often spare unnominated capacity on the SWQP and MSP.

Therefore, reducing the average tariffs will not impact on the marginal costs

faced by these shippers many of whom have contracted longer term

capacity. Put another way, the “dead zone” to the extent it exists is much

smaller in reality than portrayed by the ACCC. It is not clear that lowering

pipeline tariffs will lead to any impact on southern gas prices in the short to

medium term.

Third, the ACCC justifies its choice of a headline 50% reduction in pipeline

tariffs leading to a reduction of a $1/GJ because of the estimate that the

SWQP is earning 70% more than the revenue if it was regulated. The

ACCC says this would imply a 40% reduction in prices if the pipeline was

regulated.48 This is discussed in section 4.6 - the contracted tariffs for the

SWQP reflect a rate of return that matches the risks borne by Epic Energy

under commercially negotiated tariffs that were struck in a competitive

process at the height of the GFC, and which the ACCC itself acknowledges

provided benefits to the shippers. Regulating the SWQP now would not, in

any case, change those long term contracts.

30253978_7 34

8 Independent analysts reports

Morningstar analysis

The following is extracted from pages 11-13 “APA Group: Caught in the

ACCC's Crossfire, Greater regulation is a headwind to longer-term returns”,

Morningstar Equity Research, 14 June 2016.

“While the ACCC raises some valid concerns with the pipeline industry, it is

unclear that lower pipeline returns will benefit domestic gas users rather than

just boosting gas producer returns. Historically, domestic gas fields and

markets were isolated and insulated from global forces. In the past, prices

were set by local demand and supply, and reducing transmission tariffs

would intuitively lower the cost to purchase gas.49 But construction of an

integrated gas grid and LNG export facilities links the price of gas in each

market on the east coast grid to the global gas market. This changes the

pricing dynamic and means lower transmission costs will not necessarily

benefit domestic gas consumers.

For example, let us say that international customers will pay AUD 8 per

gigajoule for gas from the Gladstone LNG export terminals and it costs AUD

49 APA notes that this assumes that the producer does not retain the rent, or indeed the

retailer.

2 per GJ to transport the gas through pipelines from Moomba to Gladstone.

This would allow a Moomba gas producer to receive AUD 6 per GJ (net of

the pipeline tariff) if selling to an international customer. This sets the price at

which the Moomba producer will sell to a Sydney-based customer at AUD 6

per GJ. Add in the pipeline transmission cost from Moomba to Sydney of say

AUD 1 per GJ, and the Sydney customer would be required to pay AUD 7

per GJ in total, as can be seen in Exhibit 8.

Now assume more aggressive regulation cuts the cost of transmission in

half, to AUD 1 per GJ for the Moomba to Gladstone route and to AUD 0.50

per GJ for Moomba to Sydney. Repeating the exercise, assuming the global

gas price remains AUD 8 per GJ, the Moomba gas producer would now

receive a price of AUD 7 per GJ from international customers (the global

price minus the reduced Moomba to Gladstone transmission cost).

Therefore, the Sydney-based customer would be expected to pay AUD 7 per

GJ to the producer and AUD 0.50 for transmission, a total of AUD 7.50 per

GJ, as can be seen in Exhibit 9.

This represents an increase on what the customer was paying previously,

with the benefits of lower transmission costs accruing to the gas producer.

30253978_7 35

While this is just one potential scenario, cutting pipeline returns is not the

clear-cut win for domestic gas customers that it appears at first blush.

J.P. Morgan analysis

The following is extracted from the J.P. Morgan, Asia Pacific Equity

Research, “Australian Domestic Gas, Cost inflation to drive wholesale gas

prices up in all Eastern States”, 10 May 2016, pp 62-64.

“… our analysis shows that as pipeline prices tend to zero, gas flows will

gravitate towards Curtis Island as netback pricing becomes the dominant

factor.

This occurs as gas flows become unencumbered by cost. Counter intuitively,

higher transmission tariffs on pipelines can help insulate the Southern States

from the effects of netback pricing, and therefore keep prices lower in some

scenarios (namely the ACCC's ‘seller alternative’ scenario).

In its report, the ACCC outline two pricing dynamics which can create a

range of potential pricing scenarios:

[extracts definitions of buyer alternative and seller alternative from ECGI

Report]

In our analysis, while we do acknowledge the possibility of the buyer

alternative scenario, we do not consider it to be the base case as we believe

sufficient supply alternatives exist presently and into the foreseeable future.

We acknowledge the requirement to increase the competitiveness of the

wholesale gas market to support the domestic industrial sector. However, we

believe the better way to achieve this goal is to pursue more transparent

pricing and encouraging investment in upstream supply diversity rather than

impose further regulation on the pipeline industry.

We believe, when put in context of the sellers alternative, should the ACCC

impose full regulation on presently uncovered pipelines, the impacts on gas

prices would still be negligible in the best case (Figure 64) – assuming

pipeline tariffs halve as a result of regulation, gas prices for customers would

only drop 5%. However, in the situation of the buyers alternative, reduction

in tariffs can switch the dominant pricing consideration to a netback price

and create a spike in gas prices for Southern users.

Figure 65: Components of average 2015 East coast gas price

Furthermore, taking the most extreme scenario of full pipeline regulation,

regulated pricing would only impact existing customers as bilateral contracts

roll off, or if they were seeking additional access.

Thus the impacts of such a move would firstly have very negligible

immediate impact on pricing, but more importantly, have detrimental long

term impacts on pipeline owners which could result in underinvestment in

infrastructure in the long term. Such a move could result [in] the opposite of

the intended effect of encouraging additional gas exploration and production.

30253978_7 36

PART D – COSTS OF REGULATION

9 What are the costs of regulation?

Regulation has costs

While Part C considered the claimed benefits of regulation in reducing

Southern Australian gas prices, this Part D considers the cost of regulation.

It is well accepted that regulation imposes costs beyond the direct burden of

managing regulatory obligations. The most significant of these are on

investment and innovation.

Adverse impact on investment

In the ECGI Report, the ACCC noted:50

regulation has the potential to deter investments in pipelines;

the potential for new investment to be regulated may cause investors to

delay constructing a pipeline until future prospects of the pipeline

become more certain; and

regulation may result in investors attempting to accelerate the recovery

of capital.

APA operates both regulated and unregulated pipelines and so can provide

first hand evidence of how regulation can impact pipeline investment. The

impacts go well beyond those given such cursory consideration in the ECGI

Report and have real implications for the operation of the market and

efficient investment.

First, regulation leads to delays in investment to match regulatory timelines.

A key example of delayed investment as a result of regulation is the

expansion of the South West Pipeline ($37M capex forming part of the

DTS).

50 EGCI Report, pp 136-7. 51 Australian Competition and Consumer Commission, Revised Access Arrangement by

GasNet Australia (Operations) Pty Ltd and GasNet (NSW) Pty Ltd for the Principal Transmission System (30 April 2008), p 46.

This project was delayed due to the regulatory process where the ACCC

rejected APA’s proposal for expansion during the 2008-12 access

arrangement period as it considered that the demand for the expansion was

not established.51 During the period, the necessary demand not only

developed, but did so at an earlier time (the project was originally forecast

for 2012, whereas demand was sufficient to support the project by 2009).

Despite the demand, having had the project explicitly rejected by the

regulator during the period, APA was not in a position to take a risk on

proceeding with the project without further regulatory approval. The AER

ultimately approved the project in the following access arrangement period

(2013-17), and due to project lead times and time for construction, the

project was only commissioned in Q2 2015 (+5 years from and recognised

market need). This was considered and documented by K Lowe Consulting

for the AEMC.52

In a similar vein, it would be expected that regulation of the SWQP at the

time of its investments in expansion would have delayed those expansions

in order to achieve up front regulatory certainty of approach (discussed in

the case study further below). Indeed, regulation may have meant the

investments did not proceed at all (and certainly, as discussed in the second

point below, would have meant that there was no spare capacity), as a

regulated rate of return that reflected a de-risked pipeline would not have

adequately compensated the business for the risks associated with the

investment in new capacity.

In contrast to the cumbersome regulatory process described above, APA

was able to develop an unregulated pipeline, Reedy Creek to Wallumbilla

Pipeline ($80M capex), in a competitive process in a quick timeframe to

meet shipper needs to access the domestic gas market via gas sales at

Wallumbilla. The project from inception to commissioning will be less than 3

years.

Similarly, in relation to the Moomba bypass (a project to bypass Moomba

processing plant by directly interconnecting the MSP and SWQP) for

52 K Lowe Consulting, Gas Market Scoping Study: A report for the AEMC (July 2013) pp 114-5.

30253978_7 37

southern gas to access northern markets will be completed within 9 months

from agreement with customer to completed project (expected 1 Jan 2017).

Secondly, regulation incentivises the pipeline operator to avoid the demand

associated with spare capacity by sizing pipelines and expansions to meet

only the existing contractual demand. Spare capacity is usually taken into

account when setting regulated tariffs, and must be sold if the pipeline

operator is to recover its costs. This is a form of demand risk discussed in

more detail below.

The regulatory risk associated with spare capacity ultimately limits scope for

market development and growth as it increases the overall costs of

expansion due to missed opportunities to capitalise on available economies

of scale. It is instructive that the regulator also pushes the business towards

investments that do not allow the subsequent realisation of economies of

scale. This provides a key indicator of the projects that the regulator will

consider to be prudent and efficient, steering the regulated business away

from project options that maximise efficient construction and expansion as

would occur if they took a longer term view of market demand.

As an example, the AER’s 2013-17 regulatory decision in relation to

expansion of the VNI sought to ‘optimise’ the investment option for the

access arrangement to directly match the current known demand with the

lowest cost options for meeting that specific demand. This involved limiting

the amount of looping of the pipeline, and instead re-rating of part of the

pipeline for increased pressure. This contrasted with APA’s proposal, which

sought to reduce the overall costs of investment in new capacity over the

longer term by proposing a looping only project (as it is inefficient to re-rate a

pipeline that is later looped), taking into account the likely future markets

needs for additional capacity. APA argued that investing in this fashion was

in the long term interests of consumers.

Through its shorter term focus, the regulator ultimately approved significantly

less expenditure for the project than sought by APA.53 However since that

decision, demand for additional capacity on the VNI has effectively doubled.

APA is now faced with a regulatory decision that endorses an approach that

would be less efficient under the current demand scenario than the approach

that the regulator explicitly rejected. This creates significant regulatory risk,

53 AER, Access arrangement final decision: APA GasNet (Operations) Pty Ltd 2013-17 Part 2:

Attachments (March 2013), pp 47-55.

and one option for APA to mitigate this risk would have been to seek an up-

front regulatory decision on the new capital. APA’s only past experience with

this process was under the former National Gas Code, where the upfront

approval process took almost 6 months.54 Embarking on this process would

have significantly delayed investment in new capacity that was critically

required by the market to support the new LNG facilities. Demand for

additional capacity was also changing rapidly, and this type of dynamic

situation is not well suited to a regulatory approval process.

The following excerpt from the relevant APA board paper shows that these

issues were at the forefront of decision-making on this project:

While APA is not required to complete the SWP or VNI projects as

approved by the Australian Energy Regulator, deviations from the

Regulator’s previous approval would need to be prudent and

efficient (as determined by the Regulator). Inclusion of the project

into the regulated capital base (as well as realisation of expected

regulated revenue) is therefore principally subject to achieving

volumes as forecast, and for the capital expenditure solution being

the most efficient and prudent option for the volumes actually

realised.

The AER paid particular attention to the SWP/VNI project in its

access arrangement decision, ensuring that the capital option it

approved was the most efficient and prudent for the volumes

forecast at the time. In contrast, the capital projects proposed in

this paper are designed to deliver the most efficient option taking

account of potential longer term demand (in particular the proposal

to undertake more looping in place of an upgrade in maximum

allowable operating pressure). Should the additional demand to

support this decision not be realised in the current access

arrangement period, APA faces a potential stranding risk for the

54 ACCC, GasNet Australia Major System Augmentation – Corio Loop, Final Decision, (June 2006).

30253978_7 38

incremental expenditure associated with its longer term demand

investment solution.55

APA ultimately decided to face regulatory risk and proceed with an

alternative project that delivered more capacity at lower per unit cost to meet

projected future (but not yet realised) demand. This was necessary to

effectively compete with the EGP expansion option. As the regulatory period

is still underway and the AER has not yet made a decision on the efficiency

or prudency of this investment, APA is therefore yet to learn whether the

regulator will accept its decision of appropriate investment in the regulated

VTS.

55 APA Board Meeting Paper, Item No: 10, Expansion of Victorian Transmission System:

Victoria (21 May 2013), p 7.

30253978_7 39


CASE STUDY - SWQP AND COAL TERMINAL EXPANSIONS

The SWQP and what happened with the lack of investment in coal

terminals during the mining boom provides an interesting case study.

The background to the expansions of the SWQP have been discussed

above in section 4.6. In APA’s view, the expansion of the SWQP would not

have occurred at the time it did if it was regulated, and may have been sized

differently. The risks taken on by Epic Energy in the construction and

financing could not have been commercially justified under a regulated

return which assumed a much lower risk profile and the speed and process

of negotiation would have been much more difficult in a regulated context.

This would have left Eastern Australia without a critical link during the market

upheavals caused by LNG. APA invites policy makers to consider the

inefficiencies in the gas market if Queensland and Southern markets were

only weakly interconnected and the potential costs to the $60B LNG industry

in particular.

In the coal industry, lack of infrastructure development resulted in severe

coal export bottlenecks during the resources boom that began in 2004. In

2008, inadequate rail and port infrastructure investment resulted in an

infrastructure capacity shortfall of 21 million tonnes of coal per annum in the

Hunter Valley Coal Chain. This was predicted to reach 30 million tonnes by

2012. 56 At the time, 30 million tonnes of coal had an estimated value of

US$4.5B.57

56 Brian Robins, NSW coal bottleneck costs $5b in exports (1 July 2008) Sydney Morning

Herald <http://www.smh.com.au/news/national/nsw-coal-bottleneck-costs-5b-in-exports/2008/06/30/1214677946060.html>.

57 Ibid. 58 ACCC, Dalrymple Bay Coal Terminal Pty Limited – revocation and substitution – A91060-

A91062, Australian Competition & Consumer Commission Public Registers <http://registers.accc.gov.au/content/index.phtml/itemId/799718/fromItemId/401858>.

The capacity shortfall led to lengthy ship queues at Newcastle Port, requiring

the introduction of port capacity rationing systems that were approved by the

ACCC between 2004 and 2008.58 In December 2008, the New South Wales

Government proposed long-term contracts to underpin investment in

terminal infrastructure, triggers requiring new capacity to be built on demand,

and proposal for a fourth coal terminal at Newcastle Port.

Similar issues arose at the Dalrymple Bay Coal Terminal. Due to capacity

shortfalls, the demurrage costs for queueing ships in 2005 were estimated at

$550M, with $1B in coal sales forgone.59 A queue management system

overseen by ACCC was authorised in December 2005 to manage the

number of ships waiting to load coal. 60

Both examples demonstrate the importance of appropriate investment

incentives to ensure that all elements of the supply chain can meet demand.

The capacity rationing and queue management systems had a significant

economic cost, and only significant expansion investment in both ports has

alleviated the capacity shortfalls.

59 BHP Billiton, Iron Ore Submission to National Competition Council – Attachment D: Effects on Investment in Infrastructure as a Result of the Multi-User Nature of a Production System and Access Regulation, National Competition Council, <http://ncc.gov.au/images/uploads/DERaFoSu-032.pdf>.

60 ACCC, ‘ACCC proposes to deny authorisation of the queue management system at Dalrymple Bay Coal Terminal’ (Media Release, 23 February 2009), <https://www.accc.gov.au/media-release/accc-proposes-to-deny-authorisation-of-the-queue-management-system-at-dalrymple-bay>.

30253978_7 40


Adverse impact on innovation

An often understated impact of regulation is in relation to the diminished

incentive to innovate and the impact on dynamic efficiency. It was noted in

section 1.4 that the ECGI Report acknowledged that pipelines had

developed new and innovative services in response to changing demand

brought about by LNG.

The following table provides a high level overview of the incentives to

innovate in a regulated and unregulated world. We then provide two case

studies showing that if regulation applied, it would have meant the loss of

tens of millions of dollars in efficiency benefits from the East Coast Grid and

lower capacity on the SWQP.

Impact of regulation on innovation

Without regulation With regulation

Pipeline service providers responsive to

needs of specific users

Operators will meet specific user needs

by developing contracts, market-to-

market services, and managing capacity

in a dynamic way to maximise

throughput without risk of regulatory

appropriation.

For example:

o the lean gas re-direction service

was designed to meet the needs of

a shipper at Wallumbilla to ensure

that only lean gas is injected into

shipper pipeline.

o APA’s hub services product at

Wallumbilla involves securing flows

through Wallumbilla using a

combination of compression,

redirection and linepack to

increase hub capacity.

Pipeline service providers responsive to

the regulatory timelines and an “assumed”

user

The regulator shapes service offerings

based on a conservative pipeline-by-

pipeline approach to service development

and capacity management.

For example:

o 1 in 20 capacity standard in the VTS

imposes a security of supply

standard that is suitable for domestic

customers in harsh winter conditions

on all users, including commercial

users that could otherwise tolerate a

lower security standard in return for

lower tariffs.

o Reference service on the RBP meets

majority customer requirement to

secure broader Australian Standard

gas.

Without regulation With regulation

Standardisation where this has clear

efficiency benefits.

Scope for bespoke terms and services

where sought by customer to meet

specific customer/market needs – e.g.

lean gas redirection.

APA development of standard-form Gas

Transmission Agreement Terms and

Conditions to assist customer

negotiation and trading between parties.

Standardisation driven by regulatory

process

Development of reference service through

regulatory process, standardised ‘average’

terms applying to all customers.

Commonality of some terms/parameters

may exclude some parties from market

participation – minimum parcels may

exclude micro retailers; standardised

prudential requirements may not suit all

participants.

Response to market needs is rapid

Ability to fine tune services or introduce

new services to meet market needs as

they arise.

For example:

o Implemented new notional trade

point to support operation of

Moomba hub over very short

timetable, as well as new joint

venture allocation service to

support trading at Moomba hub.

o APA commercial decision to wave

all future intraday nomination

charges for all customers supports

market development and meets

shippers’ developing trading needs

across electricity and gas markets.

More intraday nominations

(facilitated by removal of charge)

means APA has commercial scope

to benefit through increased

utilisation of pipelines and

providing higher value (contract)

service to shippers.

Response to market needs is slower

Change must be made through regulatory

process. The regulator determines in the

5-yearly regulatory cycle what users

require and only then pipeline service

providers change services. In contrast,

over a 5-year period APA will have 55

Board meetings at which new contracts,

capacity or services can be endorsed.

Market and regulatory agencies not

incentivised to respond to the needs of

prospective users, e.g. slow pace of

change to the Victorian Declared

Wholesale Market in face of known

shortcomings.

Regulated returns determined by regulator

based on all revenue received from all

regulated services – decision to ‘wave’

intraday nomination charges would be a

regulatory rather than commercial decision

with direct negative impact on returns as

lost revenue from intraday nominations

may not be ‘picked up’ through increased

utilisation as this may be confiscated

under prevailing regulatory decision.

30253978_7 41

East Coast Grid case study – innovation leading to efficiencies

APA engaged The Brattle Group, an international economic and financial

consultancy firm, to analyse and calculate the efficiency benefits arising from

APA’s development of the East Coast Grid achieved by operating and

contracting its pipeline portfolio on an integrated basis rather than pipeline

by pipeline.

For the reasons discussed in this section below, there would have been little

incentive to do this if all the individual pipelines were regulated and majority

of the efficiency benefits found by The Brattle Group would not have been

realised.

The East Coast Grid has been developed since APA’s acquisition of Epic

Energy in December 2012. By taking a whole of grid approach to operations

and contracting, APA has been able to operate its pipeline assets in Eastern

Australia as an integrated grid, allowing shippers to move gas across key

routes in Eastern Australia using only APA’s pipelines, whereas previously it

would have been necessary to contract with at least two pipeline owners.

APA’s main pipeline assets are now operated from the Integrated

Operations Centre (IOC) in Brisbane. Established in 2015, the IOC allows

APA to take a “grid” rather than an “asset” perspective on its operations, and

also brings together operational staff and commercial staff in one location.

Prior to opening this new control room, APA’s pipeline assets were operated

from a group of five separate control rooms in Western Australia,

Queensland, New South Wales, Victoria and the Northern Territory. The IOC

brings several benefits; most obvious to shippers is that new services are

being offered that require real-time integrated operations across several

assets, and that require close collaboration between operations and

commercial staff.

The following is a summary from The Brattle Group’s report, Benefits and

Costs of Integration in Transmission / Transportation Networks: An

Application to Eastern Australia Gas Markets (2016).

Integrated ownership has allowed APA to operate the grid more

efficiently than multiple independent owners, i.e., at lower overall

61 The Brattle Group, Benefits and Costs of Integration in Transmission / Transportation

Networks: An Application to Eastern Australia Gas Markets (2016), p ii.

economic cost, with an estimated cost saving of over $110 million of

investment, as well as up to $7 million per annum in operating costs.61

Integration has also allowed APA to provide park-and-loan services

(storage services) that could not have been provided by independently

owned pipelines. The Brattle Group estimates that park-and-loan

services provide an economic benefit of between $7.5m and $25m

annually. Park-and-loan was also used extensively during the

commissioning phase of the LNG facilities in Queensland, creating an

economic benefit of between $10.5m and $35m in avoided costs in

2015.62 The shipper alternative in this case would have been flaring.

Integration has brought important service quality improvements for

customers. For example, APA offers a single standard-form

transportation agreement that covers access to all of its Eastern

Australian pipelines, reducing transaction costs associated with

obtaining access to multiple pipelines. Under this new transportation

agreement, imbalance charges are significantly lower than those

traditionally charged on a single-asset basis, and force majeure

arrangements are more favourable in that if force majeure is called on

one asset it would excuse shipper reservation payments on all up- and

down-stream assets.

As discussed in this section below, if all of APA’s pipelines were regulated,

APA would have had no incentive to operate the assets in an integrated

fashion. Therefore, the efficiency benefits outlined above would not have

crystallised.

How would this grid based investment be treated under the regulatory

regime?

The benefits of integrated asset operation identified by The Brattle Group

would not be available under regulation as APA would not have had

incentive to pursue them. As detailed below, APA most likely would have

been penalised for these investments under current regulatory approaches

and assumptions.

62 Ibid.

30253978_7 42

The most obvious way that regulation curtails innovation is that it curtails the

upside available to the business from risky efficiency-improving investments,

while at the same time making the business bear all the costs of investments

that do not deliver the expected efficiency improving results. This is

because the regulator expects investments in innovation to be funded out of

efficiency gains, which are ultimately returned to customers (after a five year

period), while the business bears the costs of investments that do not deliver

gains for the same five year period.63 The incentive is said to be reciprocal

in this respect, however it clearly penalises the business for failure more

than it rewards the business for success, and it can only incentivise the most

low risk low cost investments in efficiency and innovation.

The APA decision to move to integrated asset operation was neither low

cost nor low risk for APA. For example, the IT project delivery risks

associated with the IOC were in themselves very significant, and the scope

of potential asset operation efficiencies were largely unknown, and APA

believes some may be still to be uncovered. In addition, the benefits of

integrated asset operation are likely to be unevenly shared across APA’s

pipelines, as some pipelines may have more opportunity to benefit from

integrated asset operation.

A further way in which regulation would not have supported APA’s

investments in integrated asset operation relates to the asset by asset

process of regulation.

A key feature of integrated asset operation is to look beyond the ‘target’

pipeline (where capacity is sought) to uncover ways that additional capacity

can be provided at lower cost. In practice, this means that the least cost

option to increase capacity on the target pipeline could be through

investment on an adjacent pipeline.

The regulatory regime views assets on a stand-alone basis. Investments in

new capacity must be justified by increases in demand on the pipeline, or

they are not considered as efficient investments. The practical outworking of

the integrated asset operation approach under a regulated regime is that:

63 This is a high level description of the operation of the “Efficiency Benefit Sharing Scheme” in

operation for many of APA’s regulated pipelines.

for the target pipeline, the regulator will observe increased capacity (and

associated demand/throughput) with no investment, leading to a lower

average regulated tariff; and

for the adjacent pipeline where investment occurred, the regulator will

observe expenditure that is not supported by additional demand on the

pipeline, and will therefore not approve the expenditure for inclusion in

the asset base.

The service provider is clearly left worse off for having provided pipeline

service in a more efficient manner through integrated asset operation. The

obvious outcome of this is that the pipeline operator does not pursue these

opportunities and shippers ultimately face higher costs, with less capacity

being provided to the market.

SWQP case study – creating additional capacity

APA operates SWQP as part of an integrated grid, using capacity (linepack)

available on interconnecting APA pipelines to support services provided on

the SWQP, where short term demand can be very high. This grid approach

effectively increases the amount of contracted capacity available on the

SWQP, as well as its daily operational capacity (that is, its ability to offer

short term capacity in response to demand spikes).

Economic regulation creates an obligation on the service provider to offer

the reference service on all spare capacity. This involves regulator

knowledge of the capacity of the regulated pipeline, and the degree of spare

capacity. Under economic regulation, the service provider has an incentive

to seek to avoid demand risk being imposed by the regulator. The demand

risk can come from two main sources:

the regulator over-stating the firm capacity of the pipeline; and/or

the regulator imposing demand forecasts that are too high/do not reflect

the future demand of the pipeline.

Because of demand risk, the service provider has limited incentive to look for

ways to deliver additional capacity on the pipeline in the long or short term

30253978_7 43

by looking at options to utilise capacity on adjacent pipelines (as APA does

as part of its grid operating approach). This is because additional

throughput on a pipeline (including daily or short term throughput that

depletes linepack) can be used by a regulator to determine a higher pipeline

capacity for firm services in the long term. If this were to occur, the service

provider would face significant risk of not being able to deliver firm services,

and therefore face non-delivery penalties from contracted shippers. In

addition, short term throughput can also lead the regulator to assume

unrealistic longer term demand forecasts, increasing the demand forecasting

risk for the pipeline operator. These incentives that arise from regulation

work to reduce capacity available to the market in both the long and short

term.

Compounding these negative incentives on available capacity, economic

regulation can mean that the service provider does not benefit from seeking

increased throughput as these financial benefits are confiscated under the

regulatory regime, for example, through rebate mechanisms or because

those services are declared as reference services. This is most likely to

occur where the service provider has developed a market for a new service

which becomes significant, but which is then declared a rebateable service

by the regulator. All (or most) benefits from developing a new service or

market are then lost to the service provider, thereby decreasing incentives to

offer new services. This has obvious negative impacts on innovation in

service delivery.

Does the 15 year access holiday mitigate this risk?

While the ACCC acknowledged many of the risks above, it asserted that

these were addressed by mitigants in the existing regulatory regime.64 The

primary mitigant is the 15 year no coverage mechanism.

However, there are aspects of the no-coverage regime that mean it is not an

effective mitigant to the risk of undermined investment incentives. In

particular:

64 ECGI Report, pp 8 and 137-38. 65 CEG Pricing Report, p 29.

the prolonged and invasive process for making an application including

far-reaching disclosure requirements with potentially commercially

sensitive material;

the regime only applies to greenfield investment, but the majority of

development in transmission pipeline infrastructure is ‘brownfield’

expansions and improvements to existing pipelines; and

the 15-year length is too short given the significant investment involved

in greenfield pipeline development.

Out of approximately eleven uncovered pipelines completed since 2006,

only four applications for a no-coverage determination have been made, and

only one of those applications (QCLNG pipeline) was made ahead of any

meaningful development.

However, as CEG point out in the CEG Pricing Report, the 15 year holiday is

meaningless if, as signalled by the ACCC, that when it comes to regulate a

pipeline, the ACCC will be prepared to set the asset value based on an

estimate of the already recovered construction costs (accounting for the time

value of money).65

Summary

In the following Part E, APA considers the operation of the existing coverage

regime and the ACCC’s proposed regime. Prior to doing so, APA makes

two critical points.

First, more pipeline investment and innovation is required due to the need to

develop more gas reserves.

“Without further and extensive investment in currently undeveloped

gas reserves, there may be significant unfulfilled demand on the

east coast…Additional development would be required to produce

enough gas to fully use the production capacity of the LNG

trains.”66


30253978_7 44

“Gas transmission pipelines are a key part of the gas supply chain.

Further development of the eastern Australian gas market would

require further investment in gas transmission pipelines. The

consequences of barriers to efficient investments and other

inefficiencies in transmission markets could be significant.”67

Given the conventional gas basins are declining and all three LNG projects

reaching full production, there will be a need for further pipeline investment

to connect new gas sources and innovation to deal with more dynamic gas

flows and management of gas if an LNG plant has an outage.

Second, regulation is not a costless exercise.

It follows that there must be a high degree of confidence that the benefits of

the ACCC’s change in the coverage criteria outweighs any impacts on

incentives on pipelines to invest and innovate.

67 Ibid, pp 17 and 115.

30253978_7 45


PART E – THE CURRENT COVERAGE TEST

10 What does the coverage test need to do?

What does the coverage test need to do?

The objective for economic regulation of gas pipelines should be the

enhancement of efficiency. In particular, regulation should only occur where

it maximises net benefits for the community as a whole. That is, where the

total economic benefits of regulation exceed the costs. These principles are

widely accepted as a matter of economic theory and were endorsed by the

Hilmer Committee and the Productivity Commission in the context of their

consideration of access regulation and gas market policy reform.68

In the context of economic regulation of gas pipelines, that efficiency

objective is embodied in the NGO. The focus of the coverage criteria and, in

particular, criterion (a) on a material promotion of competition in dependent

markets, is consistent with the framework embodied in the CCA and National

Access Regime, that competition is the vehicle through which efficiency

objectives are achieved. The link between efficiency and competition is

explored further below.

As a gateway to the regulation of pipelines under the NGL, the coverage

criteria should only be triggered in circumstances where there are net

economic efficiency benefits of regulation. In those circumstances, the NGO

would be achieved.

How does the current test work?

The ACCC states that the hurdle posed by the coverage criteria (particularly

criterion (a)) is too high and that the criteria are not directed towards the right

market failure (which the ACCC considers is monopoly pricing).69 However,

68 Hilmer Committee, National Competition Policy Review (1993) p 27 (Hilmer Review);

Productivity Commission, Examining Barriers to More Efficient Gas Markets: Research Paper (2015) (PC2015) pp 29, 117, 123, 131 and 133-4; Productivity Commission, National Access Regime: Inquiry Report (2013) (PC2013) pp 7-8, 100, 105-6 and 221.

69 ECGI Report, pp 129-30. 70 The jurisprudence around criterion (a) has developed predominately in the context of the

declaration criteria under Part IIIA of the CCA, which is substantively the same as criterion (a) of the coverage criteria.

the ACCC moves to this conclusion based on a consideration of the words of

criterion (a) without any meaningful consideration of how those words have

been interpreted and applied judicially, 70 administratively by the NCC,71 and

in policy reviews including by the Productivity Commission and the Harper

Review.

Criterion (a) of the pipeline coverage criteria in section 15 of the NGL requires:

“that access (or increased access) to pipeline services provided by means of the pipeline would promote a material increase in competition in at least one market (whether or not in Australia), other than the market for the pipeline services provided by means of the pipeline”

Under the current judicial interpretation of criterion (a), the test will be

satisfied if the service provider is a monopoly that exerts monopoly power

and the service is a necessary input for effective competition in the

dependent market.72 Similarly, the Productivity Commission’s 2013 report

following its Inquiry into the national access regime has noted that criterion

(a) of the national access regime applies to service providers with an ability

and incentive to charge monopoly prices, which can lead to allocative

inefficiency and restrict competition and investment in dependent markets.73

In formulating its recommendations for declaration under criterion (a), the

NCC enquires into market power and specifically whether the service

provider “has the ability and incentive to impose terms and conditions of

access that result in the extraction of monopoly returns, such as by charging

monopoly prices….”74

Thus, as the Young QC Opinion concludes, the inquiry under the current

criterion (a) test involves:

71 See for example the NCCC decision National Competition Council, Application by Virgin Blue for Declaration of Airside Services at Sydney Airport: Final Recommendation, November 2003, 62.

72 Application by Glencore Coal Pty Ltd [2016] ACompT 6 (Glencore) [112] – [113]. See also Sydney Airport [91].

73 Productivity Commission, National Access Regime, Inquiry Report No. 66, 25 October 2013, 84.

74 National Competition Council, Application by Virgin Blue for Declaration of Airside Services at Sydney Airport, Final Recommendation, November 2003, 62 [6.105].

30253978_7 46

“an ability and incentive to exercise market power (by charging

monopoly prices)”;75 and

“any use of that market power in [a] way [that is] likely to adversely

affect competition in a dependent market” – such that access (or

increased access) would promote a material increase in

competition in that dependent market.” 76

Therefore, the capacity and incentive to exercise market power is a critical

component in the application of the current coverage criteria (particularly the

application of criterion (a)).

ACCC’s Proposed Test

The ACCC has recommended changing the current coverage test under the NGL to the following test proposed by the ACCC:77

the pipeline in question has substantial market power and it is likely

that the pipeline will continue to have substantial market power in

the medium term; and

coverage will or is likely to contribute to the achievement of the

National Gas Objective).

The NGO under the NGL is “…to promote efficient investment in, and

efficient operation and use of, natural gas services for the long term interests

of consumers of natural gas with respect to price, quality, safety, reliability

and security of supply of natural gas.”78

How then do the two limbs of the ACCC’s Proposed Test compare to the

coverage criteria? In APA’s view, the ACCC’s Proposed Test is a

75 Young QC Opinion, [26]. See also National Competition Council, Declaration of Services: A

guide to declaration under Part IIIA of the Competition and Consumer Act 2010 (Cth) (2013) [3.38] – [3.49], especially [3.43].

76 Young QC Opinion [26]. See also National Competition Council, Declaration of Services: A guide to declaration under Part IIIA of the Competition and Consumer Act 2010 (Cth) (2013) [3.38] – [3.49], especially [3.43].

reformulation of criterion (a) with the remainder of the coverage criteria

effectively discarded.

The market power limb

Similarly to the current criterion (a), the first limb of the ACCC’s Proposed

Test for coverage turn upon whether the service provider for the relevant

pipeline holds and will continue to hold market power. All authorities as to

the interpretation of the current criterion (a) (as noted in section 10.2 above)

establish that no change is necessary to achieve a focus upon the holding of

market power and its impact upon competition in dependent markets, and

thereby overall economic efficiency impacts.

The NGO limb

There are two key differences between the current test and the ACCC’s

Proposed Test lie in the second ‘limb’ of the test.

First, the ACCC replaces a competition assessment with a vague efficiency

based assessment using the NGO. As discussed further in section 10.7, this

constitutes a departure from the well accepted principles of the access

framework that have applied across the economy since the Hilmer

Committee established those principles. Those well accepted principles are

in accord with the competition assessment tests for regulatory intervention

across Part IV of the CCA, and each review of the National Access Regime,

leading up to and as reflected in the Federal Government’s exposure draft

for amendments to Part IIIA (Exposure Draft).

In particular, while criterion (a) has regard to whether access (or increased

access) would promote a material increase in competition in a dependent

market, the ACCC’s Proposed Test considers whether coverage ‘will or is

likely to’ contribute to the achievement of the NGO.79

77 ECGI Report, p 138. 78 Section 23, NGL. 79 HoustonKemp, Economic review of proposed amendments to the gas pipeline coverage

criteria: A report for APA (13 October 2016) pp.12-13.

30253978_7 47

The phrase ‘will or is likely to’ in the ACCC’s Proposed Test would set a

lower standard than that established by the word ‘would’ in criterion (a) –

both in its current form and if the coverage criteria were to be amended in a

manner consistent with the Exposure Draft.80

This is supported by the Competition Tribunal’s interpretation of the phrase

‘will or is likely to’ as importing ‘a standard of likelihood that is equivalent to

‘more likely than not’”, which clearly suggests a lower degree of probability

than the word ‘would’.81

Determining whether something ‘will or is likely to contribute to the

achievement of the National Electricity / Gas Objective’ in the context of

revenue and price determinations under the NGL82 and National Electricity

Law (NEL) has been described as a “protean” task.83 The Tribunal has

noted that in this context, there may be several possible decisions that will,

or are likely to, contribute to the achievement of the NGO / National

Electricity Objective (NEO).84 This is because consideration of the NEO /

NGO requires balancing of various factors, including price, service quality,

reliability and safety factors.

Current coverage test is sound

In concluding that the current coverage criteria are unsuitable and need to

be changed, the ACCC contends that the criteria (particularly criterion (a))

are not designed to address monopoly pricing85 and are inappropriate for

regulating natural monopolies that are not vertically integrated.86 The ACCC

also claims that ‘competition and efficiency are not synonymous’.87

For the reasons set out below, each of these contentions is incorrect and the

current test for coverage is sound and capable of applying in appropriate

circumstances. This is supported by decided coverage and revocation

applications and by the Young QC Opinion and the attached report by

HoustonKemp.

80 ECGI Report, see p 139 and section 7 generally. 81 Applications by Public Interest Advocacy Centre Ltd and Ausgrid [2016] ACompT1 [101]. 82 See e.g. ss 28(1)(a), 28(1)(b)(iii)(A) and 259(4a)(c) NGL. 83 Applications by Public Interest Advocacy Centre Ltd and Ausgrid [2016] ACompT 1 [71]. 84 Applications by Public Interest Advocacy Centre Ltd and Ausgrid [2016] ACompT 1 [90]. 85 ECGI Report pp 10, 121, 128 – 134.

Current coverage criteria can apply to monopoly pricing

APA’s views in relation to allegations by the ACCC of monopoly pricing by

pipeline owners are discussed in Part B. However, if the ACCC’s

contentions about monopoly pricing were to be accepted for the purposes of

analysing the application of criterion (a),88 it is evident that criterion (a) as it

is currently drafted is capable of applying to monopoly pricing in appropriate

circumstances:

The economic problem of monopoly pricing was one of the key

considerations behind the recommendation of the Hilmer Committee to

introduce an access regime. The Committee’s final report

acknowledges that “[a]n "essential facility" is, by definition, a monopoly,

permitting the owner to reduce output and/or service and charge

monopoly prices…”89

A service provider’s ability to exert monopoly power (including through

monopoly pricing) is directly relevant to the assessment of criterion (a).

This position is even clearer following the Competition Tribunal’s

decision in Glencore, which was handed down after the ACCC released

its ECGI Report.

As Young QC Opinion concludes on the basis of decided coverage

determinations by the NCC and judicial decisions in the Tribunal and Federal

Court, “no difficulty arises in applying criterion (a) to monopoly pricing in

either its present form or in the form set out in the Exposure Draft.”90

Current coverage criteria can be satisfied by non-vertically integrated service providers

It is clear, contrary to the ACCC’s contentions in the ECGI Report,91 that the

criteria for declaration in Part IIIA (and, by logical extension, the coverage

86 ECGI Report, pp 129, 132-4. 87 ECGI Report, p 130. 88 ECGI Report, pp 10, 121, 128 – 134. 89 Hilmer Review, p 239. 90 Young QC Opinion [26]. 91 ECGI Report, pp 129, 132-4.

30253978_7 48

criteria under the NGL), can be satisfied by service providers that are not

vertically integrated:

There have been several examples of the criteria being satisfied in

relation to non-vertically integrated service providers. This includes

certain services at Sydney and Melbourne airports and, more recently,

at the Port of Newcastle.92

The Australian Competition Tribunal has observed that “…the provisions

in Pt IIIA of the Act are not limited in their application to a vertically

integrated organisation...” 93

The NCC’s Declaration Guidelines advise that “…it is possible that

criterion (a) may be satisfied where the service provider is not vertically

integrated into a dependent market(s)…”94

Reviews of the National Access Regime by the Productivity Commission

have also found the criteria capable of applying in the absence of

vertical integration.95

Specifically in the context of the NGL coverage criteria, it is evident that

policymakers contemplated the application of the criteria in the context of

vertical separation within the gas industry, which further supports the

conclusion that the coverage criteria were designed to apply to vertically

separated, as well as vertically integrated, service providers.96

Moreover, under the current formulation of criterion (a), it is sufficient for

access to promote a material increase in competition in any other market,

including a market outside Australia. This is a low threshold97 and does not

92 See NCC Past Applications Register available at: http://ncc.gov.au/applications-

past/past_applications. 93 Re Review of Freight Handling Services at Sydney International Airport (2000) ATPR ¶41-

754 [11]. 94 National Competition Council, Declaration of Services: A guide to declaration under Part IIIA

of the Competition and Consumer Act 2010 (Cth) (2013) [3.17]. 95 Productivity Commission, Review of the National Access Regime: Inquiry Report (2001)

(PC2001) p.148; PC2013, p 84.

restrict the application of the coverage criteria to only vertically integrated

service providers.

Competition and efficiency are inextricably linked

APA also submits that the ACCC’s contention that ‘competition and

efficiency are not synonymous’98 in the context of criterion (a) is incorrect.

Indeed, as HoustonKemp has identified, it is a ‘”undamental underlying

principle of economics that competition and efficiency are inextricably

linked”.99

Moreover, parliaments have adopted competition as the mechanism for

promoting economic efficiency in the context of access regulation across the

economy for more than two decades. As explained in the Young QC

Opinion, competition is the chosen vehicle for promoting economic

efficiency, both under the National Access Regime in Part IIIA of the CCA

and the gas access regime under the NGL:

“[C]riterion (a) in Part IIIA is directed at improving the conditions or

environment for competition, in order to achieve the objects of Part IIIA'

which include the promotion of the economically efficient operation of,

use of and investment in…infrastructure…That is…economic efficiency

is achieved through improved conditions for competition”.100

The assessment under criterion (a) “is consistent with the object of the

CCA, which includes to enhance the welfare of Australians through the

promotion of competition.”101

“Importantly, the promotion of “efficiency”…is not an object to be

pursued in and of itself. Rather, as made clear in the objects of Part IIIA,

promotion of the economically efficient operation of, use of and

96 Department of the Parliamentary Library Information and Research Services, Natural Gas: Energy for the New Millennium Research Paper (1998) pp 7-8.

97 See Professor Allan Fels AO, Submission to the Productivity Commission Inquiry into the National Access Regime (March 2013) p 50.

98 ECGI Report, p 130. 99 HoustonKemp, Economic review of proposed amendments to the gas pipeline coverage

criteria: A report for APA (13 October 2016) p 5. 100 Young QC Opinion [29]. 101 Young QC Opinion [30].

30253978_7 49

investment in…infrastructure…is undertaken in order to promote

effective competition in upstream and downstream markets. This

promotion of competition then links to the broader object of the CCA

which, as noted above, is to enhance the welfare of Australians.” 102

“The same analysis applies to criterion (a) in the NGL, i.e., criterion (a)

treats the promotion of competition as the relevant means of achieving

the national gas objective.”103

Similarly:

The Hilmer Committee recognised that “[c]ompetition policy is not about

the pursuit of competition per se. Rather, it seeks to facilitate effective

competition to promote efficiency and economic growth…”104

The Productivity Commission has noted that “[c]ompetition is not an end

in itself but plays a crucial role in promoting economic efficiency and

enhancing community welfare.”105

The Australian Competition Tribunal has also explicitly linked

competition with efficiency in interpreting criterion (a).106

Coverage decisions do not support reform to criterion (a)

The ACCC has pointed to the decided pipeline coverage cases as evidence

that the threshold for coverage (particularly the threshold set by criterion (a))

102 Young QC Opinion [31]. 103 Young QC Opinion [32]. 104 Hilmer Review, p xvi. 105 PC2015 p 29. 106 The Tribunal has previously outlined the test under criterion (a) in the following terms “…[w]ill

the act…increase the constraints on the market power of sellers or, more directly, will it increase their rivalry in a way that will produce greater efficiency? If the answer is in the affirmative, the act will promote an increase in competition…” See Re Fortescue Metals Group Ltd (2010) 271 ALR 256 [803] and [1061].

107 ECGI Report p 129, footnote 170. 108 See NCC Past Applications Register available at: http://ncc.gov.au/applications-

past/past_applications.

is too high.107 However APA’s analysis of decided pipeline coverage cases

reveals the following:108

Eight gas revocation applications have been unsuccessful. This means

that the coverage criteria were found to continue to be satisfied in each

of those cases.

In many of the cases in which criterion (a) has not been satisfied, at

least one other criterion has also not been satisfied. The ACCC is

therefore incorrect to single out criterion (a) in its assessment of how the

criteria operate in practice.

Other factors were also at play in some cases where the coverage

criteria were not satisfied.109

Moreover, while it is evident that criterion (a) will not be satisfied in every

instance, this is not symptomatic of shortcomings with the criteria as the

ACCC contends.110 To the contrary, this is an indication that the criteria are

fulfilling their purpose, and acting as a ‘filter’ to ensure that pipelines are only

subject to regulation where appropriate. As noted recently by the

Productivity Commission, the Hilmer Committee “intended for the [r]egime to

be applied sparingly”.111

109 For example, in the SEPS decision which the ACCC refers to in the ECGI Report (see pp. 101, 118 and 129) the Minister concluded that competition would be promoted by a new entrant in one of the identified dependent markets. However Beach Energy was the only potential new entrant to the relevant market at that time but Beach wasn’t in a commercial position to do so. If Beach had been in a position to enter, the Minister would likely have determined to cover SEPS. Similarly, a key factor in the decision to revoke coverage of the Wagga Wagga natural gas distribution network was the New South Wales Government’s decision not to remove retail price regulation for gas. Prior to the decision being made with respect to retail price regulation, the NCC in fact recommended that the Minister decide not to revoke coverage on the basis that the NCC was satisfied that all of the coverage criteria were satisfied (if retail price regulation for gas were removed).

110 See generally, ECGI Report section 7.2.1. 111 PC 2013, p 221. See also Hilmer Review p 248.

30253978_7 50


11 ACCC scenarios can satisfy criterion (a)

Criterion (a) can apply

In the ECGI Report, the ACCC gives four specific stylised scenarios (ACCC

Scenarios) 112 (set out further below) which it considers would not satisfy the

existing NGL pipeline coverage criteria; even though the ACCC contends

that there would be efficiency benefits from regulating the behaviour of the

pipelines in the scenarios. The ACCC contends that this is largely due to the

hurdle posed by criterion (a).113

APA considers that each of the ACCC Scenarios can satisfy criterion (a) –

both in its current form and if the coverage criteria were to be amended in a

manner consistent with the amendments to the declaration criteria in Part

IIIA that have been proposed by the Federal Government114 (see section

12.2 for more details).

Before considering the scenarios in detail. APA notes the following in

relation to the ACCC Scenarios:

In general, the four scenarios given by the ACCC are artificial and highly

stylised, focus on very particular dependent markets and provide limited

information.

In the ACCC Scenarios, the ACCC implies that the promotion of

competition, and therefore criterion (a), will only be satisfied if access is

likely to result in an increase in the number of competitors. This is

fundamentally incorrect – the jurisprudence clearly shows the relevant

inquiry is whether the opportunity or environment for competition would

be promoted, not that more competitors must result from coverage.

As Young QC Opinion concludes, “the ACCC Examples do not provide

a useful illumination of whether the ACCC Market Power Test would

bring about better outcomes relative to the current formulation of

criterion (a) or the Exposure Draft formulation of criterion (a). This is

because many other facts would be relevant and necessary before a

112 ECGI Report, pp 130-1. 113 ECGI Report, pp 130-1. 114 Cl 44CA(1)(a) Competition and Consumer Amendment (Competition Policy Review) Bill

2016.

determination could be made as to whether coverage of the pipelines in

the examples is desirable.”115

The ACCC’s conclusions based on the scenarios therefore “amount to

no more than unsubstantiated assertions”.116

APA’s analysis of the ACCC Scenarios is supported by the Young QC

Opinion and section 3.2 of the attached report by HoustonKemp. Key

aspects of the legal opinion and HoustonKemp’s report are set out below.

Scenario A

In analysing Scenario A, the Young QC Opinion identifies two important

assumptions underpinning the ACCC’s conclusion that the elimination of

monopoly pricing could benefit consumers in the region. These are:117

that tariffs paid by retailers would be lower if the services provided by

the pipeline were regulated; and

that retailers would pass those lower tariffs through to consumers.

115 Young QC Opinion [34]. 116 Young QC Opinion [34]. 117 Young QC Opinion [37].

Scenario A The elimination of monopoly pricing on a pipeline that is used by two

retailers to supply gas to a regional area may not give rise to any

change in competition in the retail market (for example, because the

scale of the market may be too small to attract any other

competitors) but could still benefit consumers in the region if the

cost savings are passed on.

30253978_7 51

While noting that “[i]t is not clear from the facts that either of these

assumptions would be borne out”, 118 the Young QC Opinion nevertheless

concludes that Scenario A “would likely satisfy criterion (a).”119

Moreover, the Young QC opinion states that “it is not necessarily to the point

that other competitors may not enter, since improving the conditions for entry

itself may promote the environment for competition.”120 The HoustonKemp

Report similarly confirms that “it is not the case that an increase in

competition requires an increase in the number of competitors.”121

Further the HoustonKemp Report points out that cost savings “would only be

passed on to consumers if rivalry between the incumbent firms is increased.

Competition is the mechanism through which savings are passed on to

consumers…”.122 The HoustonKemp Report also notes that if the reduction

in tariffs is not passed through, there would be no efficiency benefits.

Rather, there will merely be a wealth transfer from the pipeline owner to the

retailers.123

Scenario B

In concluding that “there does not appear to be any reason why the present

formulation of criterion (a) or the Exposure Draft formulation would not apply”

118 Young QC Opinion [37]. 119 Young QC Opinion [35]. 120 Young QC Opinion [35]. 121 HoustonKemp, Economic review of proposed amendments to the gas pipeline coverage


to Scenario B, the Young QC Opinion again notes that “[t]he fact that there

may be no increase to the number of competitors is not to the point…the

relevant question Is whether there is any improvement to the condition or

environment for competition”.124

Similarly, HoustonKemp’s report concludes that it is “likely that the pipeline

in the second scenario described by the ACCC would also meet the existing

coverage criterion (a)” and notes that “the ACCC appears to equate a

‘material increase in competition’ with an increase in the number of

competitors…”125

Scenarios C and D

122 HoustonKemp, Economic review of proposed amendments to the gas pipeline coverage criteria: A report for APA (13 October 2016) p 7.


124 Young QC Opinion [39]. 125 HoustonKemp, Economic review of proposed amendments to the gas pipeline coverage


Scenario B Restricting a pipeline operator’s ability to effect a wealth transfer

from producers can also be expected to result in efficiency

improvements in the upstream market, but may not have any effect

on the level of competition in this market if it results in existing

producers carrying out more exploration and supplying more gas

into the market. In this example, there would be an efficiency

improvement and an improvement in consumer welfare but no

change to the level of competition.

Scenario C Eliminating monopoly pricing on a pipeline that is used to supply a

mining company competing in a global commodities market that is

already workably competitive could result in greater investment by

the mining company (that is, because the risk of hold up is reduced)

and increase the volume of commodities it supplies into the market.

If the mining company is a lower cost operator, then the increase in

supply would displace higher cost suppliers and the equilibrium

commodity price would fall. In this example, restricting a pipeline

operator’s ability to engage in monopoly pricing would result in an

improvement in economic efficiency and consumer welfare but

would have little to no effect on competition if the market is already

workably competitive

30253978_7 52

The Young QC Opinion concludes that there is insufficient information to

form a view as to whether criterion (a) would apply in Scenario C or D.

However, in respect of Scenario C, the Young QC Opinion indicates that

both the current formulation of criterion (a) and the Exposure Draft

formulation would apply if it is assumed that the relevant pipeline has market

power and that the gas transportation services are a necessary input for

effective competition in the markets in which the mining company is

active.126 Moreover, in respect of Scenario D, the Young QC Opinion

highlights the overly simplistic and artificial nature of the ACCC’s Scenarios

by indicating that “[i]t is likely that the pipeline is supplying a number of

customers, as opposed to one industrial customer’ and that ‘[m]ore would

need to be known about the other users and potential users, and the state of

competition in downstream markets.” 127

In concluding that the pipeline in Scenario C would likely satisfy existing

criterion (a), HoustonKemp disagrees with the ACCC’s assessment that

there could be a reduction in the commodity price with little to no effect on

competition if the market is already workably competitive, noting that “the

very process by which commodity prices would be reduced is through

increased competition.”128 Similarly, in concluding that criterion (a) would

also likely be satisfied by Scenario D, HoustonKemp notes that there is “no

economic basis from which to contend that expansion in the market has

126 Young QC Opinion [42], [45]. 127 Young QC Opinion [45]. 128 HoustonKemp, Economic review of proposed amendments to the gas pipeline coverage


been encouraged and prices have been reduced but that the intensity of the

process of rivalry (i.e, competition) has not also been increased.”129

In both scenarios, the ACCC implies that competition cannot be improved in

a market that is already ‘workably competitive’. However, it is difficult to

reconcile the dependent market being ‘workably competitive’ and at the

same time one participant being able to effect a lower equilibrium price.


Scenario D

In a similar manner to the previous example, restricting a pipeline

operator’s ability to engage in monopoly pricing on a pipeline that is

used to supply an industrial customer that competes in a workably

competitive market in Australia could result in greater investment by

that company in its facility and greater output. While this may not

give rise to any change in the level of competition in the market,

there would still be an efficiency improvement and if the industrial

customer is a lower cost producer, it could also result in a reduction

in prices for that product, which would benefit consumers.

30253978_7 53


PART F – THE CASE FOR CHANGE

12 Case for change not made

Overview

As demonstrated in the preceding sections, the ACCC’s arguments for

changing the coverage test do not hold. In particular:

The current coverage criteria are fulfilling their purpose, and acting as a

‘filter’ to ensure that pipelines are only subject to regulation where

appropriate – that is, in circumstances where there are net economic

efficiency benefits.

The capacity and incentive of pipelines to exercise market power is

already a critical component in the application of the current coverage

criteria (particularly the application of criterion (a)). Thus, there is no

regulatory failure in relation to the assessment of, and regulatory action

to address, the exercise of market power.

The ACCC Scenarios do not support the ACCC’s contention that the

ACCC’s Proposed Test would bring about better outcomes relative to

the current formulation of criterion (a) or the Exposure Draft formulation

of criterion (a).130

Since the Hilmer Committee’s review of competition policy in 1993, three

Productivity Commission reviews have given extensive and robust

consideration to the criteria in the context of the National Access Regime

under Part IIIA of the CCA and the gas access regime in the NGL. These

reviews have culminated in the following reports:

The Productivity Commission’s 2013 National Access Regime Inquiry

Report.

130 Young QC Opinion [34]. 131 Harper Review, p 72. 132 The ACCC itself has previously acknowledged that access arrangements for the gas market

were “…developed to be consistent with part IIIA…while addressing the specific needs of the

The Productivity Commission’s 2004 Review of the Gas Access Regime

Inquiry Report.

The Productivity Commission’s 2001 National Access Regime Inquiry

Report.

Importantly, none of these reviews recommended any substantial departures

from the wording of the regime that was originally outlined by the Hilmer

Committee.

More recently, The Harper Review Panel’s ‘root and branch’ review

observed that the various access regimes “…appear to be achieving the

original policy goals identified by the Hilmer Review…”131

Importance of consistency between NGL, Part IIIA and the CCA

The consistency between the current pipeline coverage criteria under the

NGL and the declaration criteria under Part IIIA of the CCA is intentional.132 It

is important that consistency is maintained.

Both the criteria themselves and the relationship between the National

Access Regime and industry-specific regimes have been subject to

extensive consultation and rigorous analysis. APA contends that gas

pipelines are not sufficiently different to other types of infrastructure (such as

ports, airports or railways) to warrant departure from a framework that

maintains consistency with the National Access Regime.

In recommending a general access regime over industry-specific regimes,133

the Hilmer Committee observed important similarities between access and

related issues across the key infrastructure industries and considered the

development of a common legal framework offered the benefits of promoting

consistent approaches to access issues across the economy and for

expertise and insights gained in access issues in one sector to be more

readily applied to analogous issues in other sectors.134 The Harper Review

gas industry.” See ACCC submission to Productivity Commission, Review of the Gas Access Regime: Inquiry Report (2004) (PC2004), p 31.

133 Hilmer Review, p 266. 134 Hilmer Review, p 248-9.

30253978_7 54

Panel recently observed that the various access regimes “…appear to be

achieving the original policy goals identified by the Hilmer Review…”135

Further, in advocating for a national regime over different state-based

regimes, the Hilmer Committee warned that “different approaches or pricing

principles’ had ‘the potential to impede the development of efficient national

markets for electricity, gas, rail and other key industries.”136 It is reasonable

to infer that efficiency would also be impeded by having substantially

different access frameworks across different industries.

The Federal Government’s recent Exposure Draft clarifies criterion (a) of the

declaration criteria under Part IIIA of the CCA.137 The reframed criterion (a)

is effectively an adoption of the ‘with and without declaration’ test (see

counsel’s opinion).

APA believes the equivalent changes to the NGL pipeline coverage criteria,

to ensure that the criteria remain consistent across the economy and the

NGL coverage criteria retain the benefit of jurisprudence and administrative

developments applying to Part IIIA.

Costs of adopting the ACCC’s Proposed Test

APA believes the ACCC’s Proposed Test is uncertain and not fit for purpose

because it would significantly alter the threshold for coverage and introduce

uncertainty in an area that is currently the subject of significant regulatory

and judicial precedent.

ACCC Proposed Test creates regulatory uncertainty

It is clear that regulatory uncertainty can negatively impact investment. As

noted by the Productivity Commission in its 2015 Research Paper

Examining Barriers to More Efficient Gas Markets, “[a]ny ‘regulatory risk’

135 Harper Review, p 72. 136 Hilmer Review, p 249. 137 The Exposure Draft reframes criterion (a) of the declaration criteria as follows: “that access

(or increased access) to the service, on reasonable terms and conditions, following a declaration of the service would promote a material increase in competition in at least one market (whether or not in Australia), other than the market for the service”.

138 PC2015, p 133. See also PC2015, p 115.

associated with access regulation (such as uncertainty regarding future

access obligations) could also distort investment incentives.”138

In its 2013 Inquiry into the national access regime, the Productivity

Commission was “mindful that changes to the Regime, if implemented, will

impose transitional costs, particularly as new case law is developed, and this

will contribute to regulatory uncertainty”139 and that “uncertainty regarding

future access obligations could compound the inherent risk associated with

making infrastructure investments”.140

The ACCC’s Proposed Test would impose costs through regulatory

uncertainty by:

Replacing a criterion that “has been in place for some 20 years and its

application is well understood, including through its application by the

Tribunal and the courts”141, with new untested criteria that will initially

operate in a vacuum of jurisprudence.

provides the decision maker “with considerable discretion” (Young QC

Opinion), particularly in relation to whether coverage ‘will or is likely to’

contribute to the NGO.142 This level of discretion is inappropriate and

contrary to principles of sound regulation.

Failing to provide the relevant Minister with “any practical guidance on

the circumstances in which coverage is likely to promote the [NGO].”143

Abolishing the ‘rigorous framework’144 for analysis of how access will

promote competition in downstream markets.

139 PC2013, p 30. 140 PC2013, p 101. 141 Young QC Opinion [49]. 142 The Tribunal has acknowledged that the ways in which a contribution can be made to the

NGO are many and varied. See 10.3 above for more details. 143 Young QC Opinion [46]. 144 Young QC Opinion [48].

30253978_7 55

Not having a causal nexus between the element of market power, and

the overall promotion of efficiency objectives and not having regard to

the consequences of market power.

Breaking the nexus with the National Access Regime and forgoing all

the benefits of having a uniform test for access across the economy

(see section 12.2 above for more details about the importance of

maintaining this nexus).

As noted in the HoustonKemp Report:

“Until sufficient jurisprudence is developed, a proposed change to

the coverage criteria of the structural magnitude suggested by the

ACCC would substantially increase the degree of uncertainty

associated with the gas pipeline access regime. As such, it would

give rise to increased legal and administrative costs and eliminate

the significant benefits of the gas pipeline coverage criteria being

framed in the same terms as the wider, Part IIIA regime.”145

The effects of this uncertainty will be amplified in the context of the current

review of the limited merits review framework, as pipeline owners could face

an ambiguous test with no right of merits review.

As discussed below, the costs of adoption of the ACCC’s Proposed Test

would be significant arising from regulatory uncertainty as well as the

efficiency cost of unwarranted overregulation arising from the lowering of the

threshold.

The costs of adoption of the ACCC’s Proposed Test

Regulatory certainty is critical for infrastructure investment. Westpac warned

that “the regulatory regime is the key element for financiers considering the

risk profile of transmission…business. Ultimately, this influences a

financier’s preparedness to provide finance and the terms at which finance is

made available including price. For Westpac, and indeed most other debt

145 HoustonKemp Report, p 13. 146 Westpac, Submission to the COAG Energy Council, Review of the Limited Merits Review

Regime, 3 October 2016. 147 Ibid.

providers, this assessment takes into account (chiefly, although not

exclusively) the predictability and stability of the regulatory regime”.146

With respect to debt servicing, Westpac stated that regulatory risk “may

result in an increased cost of debt for the industry and ultimately this could

flow through to consumers”.147

Similarly, the Commonwealth Bank of Australia’s (CBA) response to the

consultation paper published by the COAG Energy Council with respect to

the limited merits review regime, stated that the Australian energy network

sector’s reputation for “stable and predictable regulatory policy settings” is

“of key importance to the credit assessment of lenders who provide capital to

borrowers in the sector”.148

The ACCC’s proposed test would result in the replacement of the current

well-established and understood test, articulated with over 20 years of

jurisprudence, with one that would have to be interpreted and applied in a

vacuum creating significant uncertainty and unpredictability of regulatory

application which would adversely affect the investment environment.

Costs of overregulation

The costs of regulation are discussed in Part D of this submission. Adopting

the ACCC’s Proposed Test will set a lower threshold thereby likely imposing

the costs of regulation on more pipelines and with the real risk of

overregulation.

However, it is well recognised that the risk between under and over

regulation is asymmetric. While regulators should strive to minimize both

types of regulatory error, the costs of over regulation tend to be higher from

an efficiency perspective than the costs of under regulation.149

This will negatively impact pipeline investment to the detriment of the long

term efficiency of the east coast gas market and, ultimately, consumers.

148 Commonwealth Bank of Australia, Submission to the COAG Energy Council, Review of the Limited Merits Review Regime, 30 September 2016.


30253978_7 56

Further, the costs will be even greater given that the ACCC’s Proposed Test

has no apparent offsetting efficiency benefits.

Benefits do not clearly outweigh the costs

The primary benefits claimed to be available from greater regulation of

pipelines brought by the ACCC’s Proposed Test are that:

the current test is failing to regulate pipelines where it should,

particularly given the ACCC’s assertions of widespread monopoly

pricing; and

regulation of more pipelines will materially reduce prices in southern

markets.

APA does not believe that the ACCC has made a compelling case in relation

to either of these claimed benefits:

as discussed in Part B, the evidence of monopoly pricing is

underwhelming when rigorously tested;

as discussed in Part C, the benefit of lower southern prices which is

claimed from greater regulation is based on a simplified model which

may, but for questionable assumptions, actually lead to an increase in

prices for southern states; and

as discussed in Part E, the claimed inadequacies of the current test are

not accurate.

In contrast, the downsides of these changes are greater:

it is not disputed that regulation imposes costs and impacts on

incentives to invest and innovate even when properly imposed under the

current regime (as discussed in Part D);

the ACCC’s Proposed Test creates a new untested regime applicable

only to gas transmission pipelines and out of step with Part IIIA and

access regulation for other Australian infrastructure;

it risks over-regulation (discussed in Part D and section 12.3 of Part E)

and with it,

the higher costs and impacts of having underinvestment in infrastructure

versus the speculative benefits of shaving a few cents from transport

tariffs.

30253978_7 57


13 Where to from here?

Improving efficiency

For the reasons set out in Parts B and C, APA does not consider that the

ACCC has shown that pipeline operators are monopoly pricing and does not,

therefore, consider that there is a need to change the coverage criteria to

address this purported economic concern.

APA considers the appropriate test remains the coverage criteria and those

criteria should be kept consistent with the changes proposed to declaration

criteria following the recent Productivity Commission and Harper Reviews.

That does not mean that the operation of the East Coast gas markets cannot

be improved.

At the request of the COAG Energy Council, the AEMC initiated its East

Coast Wholesale Gas Market and Pipelines Review in February 2015. The

AEMC’s Stage 2 Final Report provides for a comprehensive and far reaching

reform program out to 2020 with recommendations for market-based

mechanisms that will change and develop the various modes by which

market participants access pipeline capacity. It specifically addresses a

number of the ACCC’s recommendations from the ECGI Report.

The key AEMC reforms that are relevant to questions of access are:

development of an auction process for contracted but unutilised

capacity (which APA considers should be limited to fully contracted

pipelines), which will provide a mechanism for shippers to access

unutilised day-ahead capacity at a market-set price (with an effective

zero reserve price);

development of a capacity trading platform for anonymous exchange

based trading which would assist shippers to access pipeline capacity in

the secondary market on a day ahead or longer period;

standardisation of key capacity contract terms and conditions to assist

in trade of capacity products; and

improved transparency of both pipeline capacity and gas commodity

prices, which will reduce the perceived information asymmetries and

emphasise opportunities for trade of gas and capacity.

These reforms build on work already undertaken by the pipeline operators

themselves to support pipeline capacity markets (discussed in the next

section).

The AEMC also recommends:

reforms to increase the liquidity of existing gas markets which

should improve the operation of those markets, and therefore the

opportunities for arbitrage between markets, and should reduce

gas prices through competition; and

biennial reviews by the AEMC on the growth of liquidity in trading in

wholesale gas and pipeline capacity.

Given these forthcoming market changes, APA considers it unfortunate that

the first issue to be considered is a change to introduce significantly

increased pipeline access regulation (out of step with the current and

proposed clarifying reforms to the national access regime for all other

sectors of the economy) rather than considering whether the detailed

reforms already in progress will address concerns and inefficiencies in gas

markets. A key factor in improving liquidity is available capacity; a regulatory

approach that stifles the market-based investment and innovation that would

deliver this capacity appears a poor alternative to a vibrant market.

The ACCC’s Proposed Test is poorly targeted and betrays a mindset of

reverting to regulation as a first response to any perceived issue. APA

considers the best way to improve the efficient operation of the

transportation of gas on the East Coast is through industry led change

guided by regulatory processes and clear policy objectives.

In APA’s view, there is no need to introduce the ACCC’s Proposed Test –

the problem is not established and the costs would be significant.

Instead, the outcomes of the current reform process should be assessed

and the AEMC could be tasked with considering gas pricing outcomes (in

30253978_7 58

light of the greater transparency) as part of its biennial reviews, the first of

which is in 2018.

Industry has led change

In considering APA’s comments above, APA points out that the pipeline

industry has shown a willingness to work cooperatively to facilitate reforms

and in fact had been taking many of the steps now being recommended by

the AEMC.

APA and other pipeline operators have already developed capacity trading

platforms. After consultation with participants, APA launched its capacity

trading service in March 2014 comprising a trading website which is an

information portal enabling shippers to access detailed information about

available capacity, nominations, utilisation, trading opportunities (bids and

offers) and contact details for trading parties for APA pipelines. It also

launched a capacity trading service in the APA standard Gas Transportation

Agreement (GTA) and an offer to include that service in existing GTAs. The

capacity platform offered by APA facilitates capacity trading to occur on

APA’s major East Coast contract carriage pipelines.

Similarly, APA had already introduced standardised services and terms into

its GTAs to enable greater trading between shippers.

Sufficient time must be given to market-based processes to allow them to

work. For example, the development of liquidity in the gas markets should

drive liquidity in capacity markets and vice versa, providing the impetus for

these markets to further develop and mature.

The pipeline industry has responded to unprecedented changes and the

above shows that it continues to respond. It should be given an opportunity

to continue to provide market led solutions rather than rushing to impose

price regulation which runs the real risk of stifling investment and innovation

to the detriment of the market as a whole.

30253978_7 59


14 Glossary

ACCC means the Australian Competition & Consumer Commission.

ACCC Scenarios means the four scenarios found on pp 130-131 of the

ECGI.

ACCC’s Proposed Test means the new test of coverage criteria of

pipelines proposed by the ACCC.

AEMC means the Australian Energy Market Commission.

AER means the Australian Energy Regulator.

AGP means Amadeus Gas Pipeline.

B means billion.

CBA means the Commonwealth Bank of Australia.

CBD means central business district.

CCA means the Competition and Consumer Act 2010 (Cth).

CEG means Competition Economists Group.

CEG Pricing Report means CEG’s report titled “Transport Costs and

Domestic Gas Prices”.

CEG Returns Report means CEG’s report titled “Returns on Investment for

Gas Pipelines”.

CGP means the Carpentaria Gas Pipeline.

CSG means coal seam gas.

COAG means Council of Australian Governments.

DORC means depreciated optimised replacement cost.

DTS means the Victorian Declared Transmission System.

East Coast Grid means APA’s integrated grid of pipeline assets on the east

coast.

ECGI Report means the ACCC’s report on the East Coast Gas Inquiry.

EGP means the Eastern Gas Pipeline.

Exposure Draft means the amendments to the declaration criteria in Part

IIIA of the CCA that have been proposed by the Federal Government found

in Cl 44CA(1)(a) Competition and Consumer Amendment (Competition

Policy Review) Bill 2016.

GBJV means the Gippsland Basin Joint Venture.

GFC means the Global Financial Crisis.

GGP means the Goldfields Gas Pipeline.

Glencore means Application by Glencore Coal Pty Ltd [2016] ACompT 6.

GTA means Gas Transportation Agreement.

Harper Review means the Competition Policy Review: Final Report

released in March 2015.

Hilmer Review means the National Competition Policy Review released by

the Hilmer Committee in 1993.

HoustonKemp Report means HoustonKemp’s report titled “Economic

foundations of the gas pipeline coverage review”.

IOC means APA’s Integrated Operations Centre.

IRR means internal rate of return.

IT means Information Technology.

LNG means liquefied natural gas.

30253978_7 60

M means million.

MAPS means the Moomba to Adelaide Pipeline System.

MSP means the Moomba to Sydney Pipeline.

NCC means the National Competition Council.

NEGI means the North East Gas Interconnector.

NEL means the National Electricity Law.

NEO means the National Electricity Objective in the NEL.

NGL means the National Gas Law.

NGO means the National Gas Objective in the NEL.

NPV means net present value.

PC2013 means the National Access Regime: Inquiry Report released by the

Productivity Commission in 2013.

PC2015 means the Examining Barriers to More Efficient Gas Markets:

Research Paper released by the Productivity Commission in 2015.

RBP means the Roma Brisbane Pipeline.

ROR means rates of return.

SWQP means the South West Queensland Pipeline.

VNI means the Victorian Northern Interconnect.

VTS means the Victorian Transmission System.

WACC means weighted average cost of capital.

Young QC Opinion means N J Young QC and C M Dermody’s opinion titled

“APA Group: coverage criteria in the National Gas Law – Opinion”.

30253978_7 61


ATTACHMENT A – Responses to questions in consultation paper

APA’s responses to the questions set out in the consultation paper are set out in the below table.

No Question Response

1 Do you agree with the ACCC’s finding that the

majority of existing transmission pipelines on the

east coast have market power and are using this

power to engage in monopoly pricing?

Why/why not?

Please provide evidence to support your

argument.

APA does not agree.

See detailed analysis in Part B of this submission and the CEG Returns Report.

2 Is the ACCC’s characterisation of why monopoly

pricing is a problem accurate?

Why/why not?

The ACCC’s characterises the problem of monopoly pricing in two ways.

First, it presents a circumstance where it suggests that reducing transmission tariffs by 10% - 50% would have a

“one for one” reduction in gas prices in southern states. However, as the CEG Pricing Report shows, with flows of

gas from southern states to Queensland (as is currently occurring and expected to occur given $450M of pipeline

investment to allow this), the ACCC’s model would lead to a price increase for southern customers. The ACCC

relies on an assumption of GBJV having a high degree of market power (or being part of a cartel) to enable it to

concurrently charge southern customers higher prices and Queensland customers lower prices. As the CEG Pricing

Report discusses, this would not be profit maximising for GBJV and it does not appear to be restricting output to

undertake this strategy as its sales are at record levels. The ACCC analysis is simplistic and cannot be relied upon.

See Part C of this submission and the CEG Pricing Report.

Secondly, the ACCC suggests that the current coverage criteria are not designed to address monopoly pricing or

non-vertically integrated industries. This is not correct as discussed in sections 10.5 and 10.6.

See Part E of this submission.

3 Are there any additional effects of monopoly

pricing on gas market participants that the ACCC

did not identify?

APA does not consider that the ACCC has established that there is monopoly pricing.

4 What do you believe is the objective of the

existing coverage test?

The objective for economic regulation of gas pipelines should be the enhancement of economic efficiency.

Regulation should only occur where it maximises net benefits for the community as a whole. That is, where the total

economic benefits of regulation exceed the costs.

In the context of economic regulation of gas pipelines, that efficiency objective is embodied in the NGO. The focus of

the coverage criteria and, in particular, criterion (a) on a material promotion of competition in dependent markets, is

30253978_7 62


consistent with the framework embodied in the CCA and National Access Regime, that competition is the vehicle

through which efficiency objectives are achieved. The link between efficiency and competition is explored in section

10. The ACCC’s Proposed Test is a departure from the established principles of the CCA and NGL.

5 To what extent does the current interpretation of

the existing coverage test fulfil the objective?

APA considers that existing coverage test does meet the objectives – it is consistent with the NGO and the objects of

Part IIIA. It focusses on the right question as discussed below.

The issues raised by the ECGI Report relate to criterion (a). In the Young QC Opinion, they summarise the current

judicial interpretation of criterion (a) as an inquiry involving:

whether there is an ability and incentive to exercise market power (by charging monopoly prices); and

any use of that market power in a way that is likely to adversely affect competition in a dependent market – such

that access (or increased access) would promote a material increase in competition in that dependent market.

Therefore, the capacity and incentive to exercise market power and the consequent impacts on competition in

dependent markets are the critical considerations in the application of criterion (a) and consistent with the objectives

discussed above.

In contrast, the ACCC’s Proposed Test seeks to impose a reworded market power test (even though such issues are

dealt with under criterion (a)) and an untested “efficiency” test that is uncertain in its application and not grounded in

either the NGO or economic principles which led to the current test.

6 Is the existing coverage test an effective

constraint on pipeline operators’ behaviour? Why

or Why not?

APA executives provided an example under oath to the ACCC during the inquiry of a recent acquisition where the

threat of regulation did materially reduce APA’s bid price for an asset. (APA is happy to discuss this matter with Dr

Vertigan in confidence).

Despite this, the ACCC stated that there was no evidence in the material provided by pipeline operators that the

threat of regulation was posing a constraint on the behaviour of unregulated pipelines. It went on to say that the

prices paid for some pipelines carried out over the last 5 years also suggest purchasers are assuming little reduction

in returns from future regulation.150 The ACCC cites no evidence for this other than the “70%” above regulated

returns for the SWQP (discussed above).

The ACCC notes one shipper informed the ACCC that it had obtained advice that one major unregulated arterial

pipeline that had raised its prices by 90% was unlikely to satisfy the coverage criteria. APA can’t comment on that

advice. However, in the four scenarios which the ACCC says the coverage criteria would not be satisfied when they

should, both the Young QC Opinion and HoustonKemp say to the contrary that the coverage criteria are sufficiently

robust to apply in these scenarios.

Finally, APA notes that most shippers are very large and sophisticated businesses with a long term view and

investment in the industry - they are well capable of bringing a coverage application.


30253978_7 63


Therefore, APA maintains that the threat of coverage under the current test is a material consideration in the way it

operates its business.

7 Do you agree with the ACCC that the existing

coverage criteria, and in particular criterion (a),

establishes a hurdle for regulation that is unlikely

to be met by the majority of transmission

pipelines on the east coast? /

It is speculative to discuss whether most of the unregulated East Coast pipelines would satisfy a coverage

application if brought. However, as noted above, Neil Young QC and HoustonKemp disagree that the coverage

criteria could not be satisfied in the four scenarios raised by the ACCC as showing where they are deficient. Further,

if the ACCC’s finding that it is both warranted to reduce transmission prices by half and such reduction would lead to

a $1/GJ reduction in gas prices, that would be very relevant evidence to showing the criteria would be satisfied.

APA believes the existing coverage criteria do not pose an inappropriate hurdle for regulation. The Productivity

Commission in its review of the National Gas Regime and Part IIIA have consistently acknowledged the costs of

regulation. The coverage criteria are carefully framed, and now operate after 20 years of jurisprudence, to the right

balance in determining whether regulation is justified and outweighs the costs.

8 Can the current coverage criteria address the

market failure identified by the ACCC – monopoly

pricing that gives rise to economic inefficiencies

with little or no effect on the level of competition

in dependent markets? Why/why not?

Yes.

First, see the HoustonKemp Report (p 5) which disagrees with the ACCC’s core proposition that competition and efficiency are not sufficiently synonymous for the purpose of establishing pipeline coverage criteria that would be likely to contribute to the achievement of the NGO:

“It is a fundamental underlying principle of economics that competition and efficiency are inextricably linked. The incentives that encourage firms to compete with one another are the same as those that encourage firms to operate and price efficiently. All else equal, a decision on whether or not to regulate the price of an input product cannot promote one in the absence of promoting the other.”

Second, see the Young QC Opinion and HoustonKemp Report which disagree that the four scenarios raised by the

ACCC show circumstances where the coverage criteria fail to a respond to an efficiency benefit arising where there

is no promotion of competition in a dependent market.

See section 10.

9 Could the coverage criteria be satisfied in the

case of a non-vertically integrated pipeline?

Why/why not?

Yes. Both the Hilmer Committee and the Productivity Commission have made statements to this effect. Sydney

Airport and Port of Newcastle were declared even though they are not vertically integrated.

Furthermore, eight gas revocation applications have been unsuccessful. This means that the coverage criteria were

found to continue to be satisfied in each of those cases.

See section 10.6 and the Young QC Opinion.

10 What is the relationship between the gas pipeline

capacity trading reforms and the gas access

regime?

It is unfortunate that one of the first issues to be considered out of the ECGI Report are changes designed to impose

onerous regulation on pipelines without first considering how changes to market structures, such as those included in

the AEMC report, will develop liquidity in the gas market and enhance options for securing gas and pipeline capacity.

30253978_7 64


The key AEMC reforms that are relevant to questions of access are:

Development of an auction process for contracted but unutilised capacity (which APA considers should be

limited to fully contracted pipelines), which will provide a mechanism for shippers to access unutilised day-ahead

capacity at a market-set price (with an effective zero reserve price);

Development of a capacity trading platform for anonymous exchange based trading which would assist shippers

to access pipeline capacity in the secondary market on a day ahead or longer period;

Standardisation of key capacity contract terms and conditions to assist in trade of capacity products; and

Improved transparency of both pipeline capacity and gas commodity prices, which will reduce the perceived

information asymmetries and emphasise opportunities for trade of gas and capacity.

These reforms build on work already undertaken by the pipeline operators themselves to support pipeline capacity

markets. Sufficient time must be given to market-based processes to allow them to work. For example, the

development of liquidity in the gas markets should drive liquidity in capacity markets and vice versa, providing the

impetus for these markets to further develop and mature.

Further, AEMC reforms to increase the liquidity of existing gas markets should improve the operation of those

markets, and therefore the opportunities for arbitrage between markets, and should reduce gas prices through

competition.

These market-based options should be preferred to regulatory approaches. Indeed, improving gas market liquidity

(and encouraging new gas production) in Southern Australia appears more likely to achieve real price reductions for

customers. A key factor in improving liquidity is available capacity; a regulatory approach that stifles the market-

based investment and innovation that would deliver this capacity appears a poor alternative to a vibrant market.

11 What are the implications of any changes to the

LMR regime in the context of this examination?

The introduction of the ACCC’s Proposed Test:

replaces a test that has been in place for 20 years and is well understood with a body of jurisprudence

supporting its application;

is an uncertain test – for example, in respect of whether coverage will or is likely to contribute to the National

Gas Objective, the South Australia House of Assembly stated:

“The national electricity objective and national gas objective explicitly target economically efficient outcomes

that are in the long term interests of consumers, but the nature of decisions in the energy sector are such

that there may be several possible economically efficient decisions, with different implications for the long

term interests of consumers” (Hansard, 26 September 2013, 7171)

provides the Minister “with considerable discretion” (Young QC Opinion);

fails to provide the NCC or the Minister with any practical guidance on how it should be applied; and

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breaks the nexus with the National Access Regime and forgoes the benefits of having a uniform access test

across the economy.

The impact of the above, combined with a potential removal of limited merits review for coverage decisions, would be

enormously concerning. There would be no ability to have the application of the test considered in a specialist

Tribunal with the expertise and experience in access matters and the guidance that such decisions would provide.

12 Absent this examination and any decision by

Energy Ministers, once implemented, the

amendments to the declaration criteria will see

the coverage criteria differ from the CCA.

Should the coverage criteria continue to be

consistent with the declaration criteria or is an

industry-specific test warranted?

Why/why not?

The coverage criteria should be consistent with the declaration criteria.

See section 12.2 and section 4 of the HoustonKemp Report which refers to the costs associated with divergence

between the coverage and declaration tests.

There is no basis to treat gas transmission differently from railways, airports and ports. There are important

differences between gas transmission and electricity transmission and telecommunications such that the reasons for

having a bespoke regime in those industries are not warranted for the gas sector. See section 2.1.

13 What impact, if any, is the amendment to section

46 of the CCA likely to have on pipeline operators

who operate in a manner consistent with that

identified by the ACCC as engaging in monopoly

pricing?

It appears likely that section 46 will be amended to incorporate the “effects test”. APA’s view is the introduction of

the “effects test” broadens the scope of section 46 to the extent that it could apply to legitimate behaviour, including

unilateral pricing decisions. Therefore it could apply to monopoly pricing or, for that matter, to discounting.

The introduction of the effects test will impose further discipline on businesses’ pricing decisions (including APA) to

consider whether there is any adverse impact on competition in any market and ensure that the business is not

exposed to proceedings for breach of law.

APA does not agree with the finding by the ACCC of widespread monopoly pricing but if it did exist and it was having

the impact of inefficiently increasing gas prices as claimed by the ACCC, then section 46 could potentially apply

thereby exposing APA to a breach of the CCA.

14 Is a new regulatory test required under the NGL?

Why/why not?

No

See Part F.

15 What percentage of the price of delivered gas do

transportation costs (transmission and

distribution) represent?

In the ECGI Report, the ACCC stated transmission charges constitute only 10-15% of the delivered price of gas for

retail customers.151

In the 2015 Gas Price Trends Review report by Oakley Greenwood for the Department of Industry stated that in

2015, the national average retail gas price was 2.64 c/MJ, of which 42% was the distribution component, 27% was

the retailer component, 23% was the wholesale gas component and only 8% was the transmission component.152

151 ECGI Report, pp 34-35. 152 Oakley Greenwood, Gas Price Trends Review (February 2016), p 154.

30253978_7 66


16 What impact would a change to the coverage test

have on pipeline investment, including capital-

raising, debt servicing and innovation?

The ACCC’s Proposed Test will create enormous uncertainty. As noted in the HoustonKemp Report:

“Until sufficient jurisprudence is developed, a proposed change to the coverage criteria of the structural

magnitude suggested by the ACCC would substantially increase the degree of uncertainty associated with

the gas pipeline access regime. As such, it would give rise to increased legal and administrative costs and

eliminate the significant benefits of the gas pipeline coverage criteria being framed in the same terms as the

wider, Part IIIA regime.”153

See Part D for the impact of regulation on investment and innovation and detailed case studies in relation to each.

Uncertainty means a lack of predictability in regulatory outcomes. Regulatory certainty or lack thereof is a relevant

factor in raising capital and debt as evidenced by the comments of the following financiers in the Review of the

Limited Merits Review:

In the Commonwealth Bank of Australia’s (“CBA”) response to the consultation paper published by the COAG

Energy Council with respect to the limited merits review regime, CBA stated that the Australian energy network

sector’s reputation for “stable and predictable regulatory policy settings” is “of key importance to the credit

assessment of lenders who provide capital to borrowers in the sector”.154

Similarly, in Westpac’s response to the same consultation paper, Westpac warned that “the regulatory regime is

the key element for financiers considering the risk profile of transmission…business. Ultimately, this influences

a financier’s preparedness to provide finance and the terms at which finance is made available including price.

For Westpac, and indeed most other debt providers, this assessment takes into account (chiefly, although not

exclusively) the predictability and stability of the regulatory regime”,155

With respect to debt servicing, Westpac stated that regulatory risk “may result in an increased cost of debt for

the industry and ultimately this could flow through to consumers”.156

17 What impact would a change to the coverage test

have on investment, including equity and debt-

raising, in upstream and downstream

industries/companies?

APA does not have upstream or downstream interests so cannot provide first hand views on this issue.

18 In relation to the market power test proposed by

the ACCC:

The problems that the ACCC ascribes to the current test are:

it is not designed to address monopoly pricing – this is not correct. See section 10.5.

153 HoustonKemp Report, p 13. 154 Commonwealth Bank of Australia, Submission to the COAG Energy Council, Review of the Limited Merits Review Regime, 30 September 2016. 155 Westpac, Submission to the COAG Energy Council, Review of the Limited Merits Review Regime, 3 October 2016. 156 Ibid.

30253978_7 67


Is it likely to address the problem identified?

Why/why not?

it is not appropriate for regulating natural monopolies which are not vertically integrated. This is not correct. See section 10.6.

the test which focusses on regulating where it enhances competition in dependent markets does not capture efficiency gains in those markets which are unrelated to competition and the ACCC provides four scenarios which are said to demonstrate this issue.

On this last point:

See HoustonKemp Report – efficiency and competition are “inextricably” linked. The ACCC’s core proposition is not consistent with economic principles.

Young QC Opinion and HoustonKemp Report which disagree that the four scenarios raised by the ACCC show circumstances where the coverage criteria fail to a respond to an efficiency benefit arising where there is no promotion of competition in a dependent market.

In relation to the market power test proposed by

the ACCC:

Is it likely to better facilitate the achievement

of the NGO? Why/why not?

No.

The ACCC’s Proposed Test replaces a regime which APA considers still fit for purpose with one that is untested and

is out of step with access regulation for other Australian infrastructure and competition law.

The test would create significant uncertainty which would impact investment and potentially the asymmetric costs

(when compared to the benefits) of overregulation, including underinvestment and stifling of innovation. This is not in

the long term interests of gas consumers.

See Part D.


the ACCC:

Would the test increase the number of

pipelines regulated? Why/why not?

This would appear to be the ACCC’s intention in proposing its alternative test.

The question is whether regulation is appropriate given the well acknowledged costs of regulation and whether the

ACCC’s Proposed Test strikes a better balance than the current test. APA considers it does not.


the ACCC:

Would the test likely see the prices charged

by pipeline operators move towards the

efficient cost of supply? Why/why not?

Are the outcomes associated with pipeline

prices moving towards the efficient cost of

supply appropriate? Why/why not?

The question assumes that current pipeline tariffs are not efficient.

APA notes that just because some pipeline tariffs may provide returns above those calculated under today’s

historically low regulated returns does not mean they are inefficient. In many cases, they reflect risks not borne by

regulated pipelines. See section 4.

It also is not clear to APA that any reduction in transport tariffs will actually be passed on to consumers. Refer to

section 2.3 which notes the ACCC’s analysis of the impact of any reduction in pipeline tariffs on the delivered price of

gas is overly simplistic.


the ACCC:

See Part C regarding claimed benefits.

30253978_7 68


Should the proposed test be implemented,

what impact, including costs, benefits and

risks, would you expect this to have on

market participants?

Are there any unintended consequences of

the test?

See section 12 regarding costs and risks.


the ACCC:

If implemented, should the proposed test

also apply to 15 year no-coverage

determinations?

APA believes there should be consistency between the coverage test and the test for no coverage. If the ACCC’s

Proposed Test is adopted, then there may be merit in having a different threshold for the no coverage test with the

objective of having greater protection for new investment given the impact of the ACCC’s test on investment and

risks of overregulation.

19 Is there a regulatory test that would be more

appropriate than that proposed by the ACCC? If

so, please provide details of what form this test

could take.

APA considers the current coverage criteria should be amended to reflect the Government’s Exposure Draft

amendments to the National Access Regime, so as to maintain consistency. This would ensure that the criteria

remain consistent across the economy and the NGL coverage criteria retain the benefit of jurisprudence and

administrative developments applying to Part IIIA.

See section 12.2.

See section 4 of the HoustonKemp Report.

30253978_7 69


ATTACHMENT B – ACCC comments relating to APA

Context relevant to ACCC’s selected evidence.

One major arterial pipeline is earning

70 per cent more in revenue than the

pipeline operator estimated it would

be earning if it was regulated.

This is directed to the SWQP.

The ACCC has made this calculation based

on one sentence in Appendix 3 of a 60 page

Board presentation. The particular page

was addressing regulatory risk and was

highlighting that the long term contracts

mitigated against the future risk of regulation

as represented by the “back of the envelope”

assessment included.

Importantly, given the context, the

assessment was made was using the

regulated rate of return applying in 2015

(~6%), not that which was applying in 2008

and 2009 during the GFC (~10.5%) and

used an 80 year depreciation profile rather

than one linked to the remaining life of the

gas fields (which is significantly shorter). It

also used rough expenditure estimates with

only notional allocation of corporate costs.

The key point, however, is that it is not

legitimate to compare revenue calculations

using today’s rate of return with contractual

rates stuck at a different time and that were

commensurate with what would have been

the prevailing regulatory rates of return

imposed at the time.

In any case, the tariffs of the SWQP were a

result of a competitive tender process, which

reflected the risks of the project at the time,

and it is not correct to use a regulated rate of

return benchmark against such a competitive

project to find that that the agreed tariffs

reflect monopoly pricing.

Three major pipelines are charging

prices for non-firm services from

185% to 350% of the firm

transportation charge.

APA does not accept the ACCC’s

benchmarks for excessive pricing – the

ACCC provides no economic or empirical

support for them.

Even using the ACCC’s benchmarks, the

ACCC ‘found’ very few instances on which to

base their argument of increased regulation.

Two of the examples are a product of history

and APA does not include these rates in

contracts struck today.

The third example has been incorrectly

calculated by the ACCC using the wrong

comparator tariff.

As chart 6.1 shows, the expected

return on equity on these projects

ranges from 6 per cent to 159 per

cent.

APA provides a detailed analysis of the

projects identified which relate to it in section

4. APA makes the following high level points

in relation to these projects and the ACCC’s

assertions:

The ACCC uses the wrong comparator

and therefore the RORs are overstated;

Expected project returns must be higher

than the business’s cost of capital,

otherwise the project would be value

destroying. The ACCC’s ‘finding’ that

returns are higher than its view of the

cost of capital is therefore

unremarkable;

The project returns quoted by the ACCC

are the high uptake values set out in the

relevant Board Papers. The ACCC does

30253978_7 70

not quote the low uptake values. For

example, the RBP bi-directionality

project had a range of 5.3% to 159%.

Following from the previous point, the

project returns set out in the Board

papers were in many cases based on

expected or possible uptake of capacity

– in reality uptake has been different

(lower) than the high case. This is true

for the RBP bi-directional project.

These are incremental projects where

the substantial sunk costs of the

pipelines are not taken into account in

the incremental investment.

The projects with the highest reported

returns are all related to making the

pipeline in question bidirectional. These

are unique projects that deliver large

increases in capacity at relatively low

cost. Importantly, they can occur only

once in pipeline’s history, and therefore

are not indicative of the returns that are

achieved the vast majority of on

incremental expansions.

“The proposed [western haul] tariff [of

$0.55 per GJ] has been canvassed

with potential shippers. This tariff is

higher than the effective tariff for a

‘new build’ bypass pipeline and higher

than the current [RBP] backhaul

tariff”.

The ACCC ignores that the by-pass tariff is

only relevant if shippers are prepared to

make a long term (that is more than 10

years) investment commitment. The fact is

that no shipper has or is prepared to make

such a commitment for this capacity instead

preferring to contract on a short term basis

so that they maintain flexibility.

The results of this modelling revealed

that two of the pipelines have already

recovered the cost of construction

One of the pipelines that the ACCC refers to

is the CGP.

from users while the other has

recovered a substantial proportion of

these costs (~85 per cent) and is

expected to recover the remainder in

the next five years.

APA strongly disagrees with the ACCC’s

rudimentary assessment.

It does not appear to have been reached

using established regulatory principles,

precedent or indeed compliance with the

Rules.

There are three core problems with the

ACCC’s approach (as explained more fully in

the CEG Report):

Competitive industries charge based on

new entrant costs. At no stage did the

ACCC look at whether pipeline

operators were charging above new

entrant costs when reaching its

conclusion on monopoly pricing.

As was the case with its use of IRRs,

applying the ACCC’s methodology to

determine if a pipeline has recovered its

initial capital costs is likely to result in a

finding of full capital recovery and

therefore ‘monopoly power’ in the most

competitive of markets (e.g. residential

and commercial real estate).

If the ACCC actually imposed pricing on

the basis of marginal cost for pipelines

that have “fully recovered” past capital

expenditure then this would inevitably

result in the present value of new

pipeline investments being negative –

with a consequent damage to new

investment incentives.

Finally, it is worth noting that the ACCC

defines monopoly pricing as charging above

that which should be charged in a workably

30253978_7 71

competitive market. In relation to the CGP,

APA notes that past tariffs have been set via

competitive processes at initial pipeline

construction and in competition to the

CopperString Project, i.e. a competitive tariff.

The most recent competitive process (that

for the NEGI) set the current tariff that is

offered to all potential shippers on the

pipeline.

The bi-directional charges levied by

two pipelines were higher than the

cost of the forward haul service but in

both cases the contracts were

relatively short term in nature and in

one case the GTA provides for the

price to fall if the shipper exercises an

option to extend the contract term.

The ACCC provides its own explanation for

the prices in these contracts. APA agrees

with the ACCC’s conclusions here.

Examination of the current test for the regulation of gas ... · 30253978_7 4 DRAFT [NO.]: [Date]...

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