The Australian Pipelines and Gas Association (APGA) represents the owners, operators, designers, constructors and service providers of Australia’s pipeline infrastructure, with a focus on high-pressure gas transmission. APGA’s members build, own and operate the gas transmission infrastructure connecting the disparate gas supply basins and demand centres of Australia, offering a wide range of services to gas producers, retailers and users.
APGA welcomes the opportunity to contribute to the Department of Industry, Science, Energy and Resources (DISER) consultation on the Improving gas pipeline regulation Proposed legal package to give effect to the Decision Regulation Impact Statement Consultation Paper (the Consultation Paper) and the accompanying National Energy Laws Amendment (Gas Pipelines) Bill 2021 (the Draft Legislation).
APGA recognises that the Draft Legislation was to be developed in accordance with the principles embodied within Section 3.2 of the Options to improve gas pipeline regulation Regulation Impact Statement for Decision 2021 (the DRIS). APGA uses this submission to:
APGA identifies five key areas where the Draft Legislation departs from the DRIS principles:
The Draft Legislation includes instances of retrospectively overturning regulatory decisions which were made using sound public-sector decision-making practices, setting a concerning precedent.
These five key areas are addressed in Section 3 below, alongside lower order topics discussed in Section 4, and a list of additional drafting issues in Section 5. Attachment B of the Consultation Paper can be found in Appendix 1.
APGA appreciates the inclusion of elements proposed through prior consultation and engagement with the Department and recognises their inclusion within the Draft Legislation, in particular the provisions associated with greenfield pipelines developed via competitive process. It is anticipated that these inclusions were achievable as they were aligned with the DRIS principles and were not contrary to positions stated in the DRIS. APGA hopes that, on this basis, the issues raised throughout this submission will also be taken up in the final drafting of the legislation.
To discuss any of the details within this submission further, please contact APGA’s National Policy Manager, Jordan McCollum, on +61 422 057 856 or jmccollum@apga.org.au.
Yours Sincerely
STEVE DAVIES
Chief Executive Officer
Australian Pipelines and Gas Association
The process for this most recent period of reform started with the COAG Gas Market Reform process handing down legislation to implement the new commercial arbitration framework in Part 23 of the National Gas Rules in 2018. This was quickly followed by a decision by the Office of Best Practice Regulation requiring a two-year review of the legislation following concerns about the original process. APGA has engaged with this process at every step to ensure the development of well informed, pragmatic, and proportionate legislation.
While this process results from the earlier legislative package in 2018, the commencement of these reforms dates back to the gas market issues of 2013 and 2014 and the ACCC's East Coast Gas Inquiry report delivered in 2016[2]. The ACCC came to the view that pipeline service providers possessed varying degrees of market power and concluded that market power needed to be addressed.
APGA understands and respects the need to protect all customers and consumers. It also understands that gas pipelines, whether or regulated or unregulated, interact with the broader economy. Much has changed in Australia since the early 2010s, particularly in the energy industry which is undergoing a deep and sustained transformation more rapidly and sooner than was foreseeable in 2015/2016.
The ACCC's finding of pipeline service provider market power dates to the time of the East Coast Gas Inquiry. Gas supply and gas infrastructure services now experience much greater competition from alternative energy sources including Australian LNG import terminals. The term of contracts has become much shorter, presenting greater risk to infrastructure investors, and, as traditional gas supply basins decline, there is a new requirement for pipeline expansions and greenfield infrastructure to maintain crucial gas supply to limit price shocks.
Outside of the changed investment environment, pipeline service providers have worked closely with customers in the years since the East Coast Gas Inquiry to deliver improved outcomes to customers. Lack of secure, long term gas supplies, rather than increases in regulatory intervention, is the key issue currently facing pipeline customers.
These macro-changes present pipeline service providers with new risks, making investment more difficult. The prospect of increased regulatory intervention, especially that based on principles and theory best used for monopoly utility infrastructure rather than commercial investments, presents its own additional risks to pipeline service providers.
There are a number of key issues in the Draft Legislation that can conceivably increase risk to pipeline service providers so as to delay efficient investment in brownfield and greenfield assets, to the detriment of the National Gas Objective. In particular:
APGA appreciates that DISER has engaged closely to date, most notably regarding the inclusion of the competitive process provisions within the greenfield incentive. The inclusion of this provision recognises that new gas pipeline assets are genuinely developed through competitive processes, and that the outcomes of such processes should be respected to ensure investment certainty. This view was recently supported by the ACCC in its July 2021 Gas inquiry 2017–2025 Interim report[3].
Through this submission, APGA continues its engagement, recognising and acknowledging the principles upon which the draft legislation was developed. These principles have been set out in Section 3.2 of the DRIS. From these principles, APGA highlights the following as a crucial set of principles upon which the Draft Legislation was developed:
In keeping with the NGO and Vision, the objectives of Energy National Cabinet Reform Committee action are to implement a simpler, more efficient, effective and integrated regulatory framework that supports the efficient operation of the gas market and the long-term interests of gas users and is fit for purpose, targeted and proportionate to the issues it is intended to address.
A regulatory framework which is proportionate to the issues it is intended to address is a key principle upon which the Draft Legislation was developed. Further, the Specific objectives of Energy National Cabinet Reform Committee action as outlined in Box 3.2 of the DRIS form guiding principles around which the Draft Legislation be developed.
In recognising the point at which we are at in the legislation development process, the advice that follows on the draft legislation is contained to elements which APGA notes as being contrary to these principles, hence misaligned with the mandate upon which DISER has developed the Draft Legislation.
This is a complex set of regulatory reforms, testament to which has been the time taken to produce the draft legislation. APGA raise these as potential issues in attempting to draft intended forms into legislation and offer the below commentary in hopes of achieving consistency with the sought-after principles as stated in the DRIS.
Figure 1: DRIS Section 3.2 Box 3.2
APGA’s primary concerns surround five key features of the draft legislation that seek to achieve the key principles of the DRIS:
Draft legislation for these key elements does not appear to effectively adhere to DRIS principles of implementing a more efficient regulatory framework that is fit for purpose, targeted and proportionate to the issues it is intended to address, or to supporting efficient investment in pipelines as per DRIS Box3.2 (c).
A key principle of the DRIS was to implement a more efficient regulatory framework that is proportionate to the issues it is intended to address while supporting efficient investment in pipeline services as per DRIS Box3.2 (c). APGA considers that the absence of Relevant Regulator checks and balances lead to the Draft Legislation failing to adhere to these key principles. The inclusion of appropriate checks and balances is necessary to drive accountability for a fair, transparent and objective regulatory system.
APGA is concerned that currently the draft legislation concentrates too many decisions in one entity to achieve the above objectives and in various cases defines discretions too broadly.
APGA does not question the experience or skill of any particular regulatory body in this regard. APGA does question the desirability of a regime where the entity which is responsible for monitoring compliance with the law and enforcing the law should be the same entity deciding on the scope of economic regulation (the extent to which the law intervenes in the commercial arrangements of an asset) which applies to a pipeline. The proposed arrangement results in a dilution of regulatory accountability, as the Relevant Regulator’s performance can no longer be evaluated solely on the quality of its 'access determination' decisions as is currently the case. Instead, these decisions will be clouded by the Relevant Regulator’s other decisions, including where to apply these powers.
APGA maintains the position that a fairer and more transparent regime, and one more consistent with the separation of functions which preserves the integrity of Australia’s economic regulatory framework, is for a separate entity, such as the NCC, to make form of regulation decisions. The Relevant Regulator can put its case to the NCC (based on the information it has collected through monitoring and enforcement) as can the service provider and users and prospective users. The NCC can then make a decision having given a fair hearing to all interested parties.
APGA notes that the Review of the Gas Access Regime, Productivity Commission Inquiry Report No 31 published 11 June 2004 recommended that different bodies be responsible for policy and administration – a recommendation that the current draft provisions do not adhere to.
Further, APGA has concerns that the Relevant Regulator will now also be the referrer of a pipeline service provider to the Form of Regulation Test, giving the Relevant Regulator the ability to be the sole actor in the regulatory framework. This is because it will refer, make decisions on, test and administer and enforce the outcomes of the Form of Regulation test.
While this is in line with the recommendations of the DRIS, APGA maintains the view that this is an inappropriate outcome and will engage directly with the Energy National Cabinet Reform Committee to raise these concerns. It is far more appropriate that the regulatory framework remove the Relevant Regulator from at least one the steps in the process, either requiring a customer to be the referrer and/or an independent body be the decision maker.
Within the confines of the draft legislation, APGA proposes the following two alternate approaches that adhere to the intent of the DRIS as endorsed by Energy Ministers while maintaining the key DRIS principle of proportionate regulation:
Each of these proposals is detailed in the sections below.
APGA recognises that the form of regulation test is based on the existing light regulation test. Under the draft legislation, the form of regulation test has been elevated to a position of higher importance and impact as the pivotal test between the only two forms of regulation. As such, APGA proposes that an additional level of rigor is required to match the form of regulation test’s elevated level of importance within the regulatory regime.
APGA’s proposal is in the same vein as the AEMC’s 2018 advice on the existing form of regulation test for determination between full or light regulation on the one hand, or Part 23 on the other[4]:
Firstly, and most significantly, an unintended consequence of the introduction of Part 23 of the NGR is that in the case of pipelines that provide third party access, the coverage determination is no longer a test of whether regulation should be applied or not, but instead is a test of which form of regulation should be applied (full or light on the one hand, or Part 23 on the other). However, the wording of the test is unchanged despite the change in outcomes of the test. The questions being asked by the test are designed for assessing whether regulation should apply, but are not the most appropriate for determining which form of regulation is applied.
This may result in the inappropriate form of regulation applying to a particular pipeline. Both over-regulation and under-regulation could result, leading to additional costs that are ultimately borne by consumers. In the case of over-regulation, the cost is the direct and indirect cost of regulation. In the case of under-regulation, the cost is the inefficiencies that arise from the ability of service providers to exercise their market power. These outcomes are inconsistent with the long-term interest of consumers.
To avoid similar concerns as those raised by the AEMC, APGA proposes elevating this test through the following formulation. The below version of the test provides more precise criteria against which the assessment process may proceed and directs attention to the key evidential issue – whether users are currently procuring (or are able to procure) access on appropriate terms. APGA further submits that this formulation directs attention to the key issue the regime is intended to address.
In the case of a scheme pipeline determination:
This test also appears to better reconcile with the form of regulation factors, which focus on market power, bargaining power and fuel substitutes.
The Pipeline Decision Regulation Impact Statement provided as follows (page 147):
The relevant regulator would be required to more actively monitor the behaviour of service providers and to refer pipelines for a form of regulation assessment if it suspects market power is being exercised.
However, this is not reflected in the legislation. Section 92(1) simply provides:
The AER may, on its own initiative or on the application of any person, make a determination that a pipeline is a scheme pipeline.
APGA’s submits that this is a fundamental departure from the Pipeline Decision Regulation Impact Statement which should be addressed. In APGA’s view, there should not be a broad right in section 92(1) to commence the determination process for any reason. There should be some basis for initiating the process. Section 92(1) should be modified to reflect the language of page 147.
As an ancillary matter, APGA notes the legislation imposes no limits on the number of applications which can be made for determinations (noting an application may be made by any person). APGA submits that once a determination has been made one way or another there should be no further applications for 12 months for any particular applicant for any particular pipeline. This will ensure that both the Relevant Regulator and service provider are not administratively overwhelmed by rapid successive applications and is consistent with existing arbitration process limits.
APGA appreciates the Department’s inclusion of the competitive process provisions within the Greenfield Incentive. APGA has long advocated for a Greenfield Incentive which incentivises investment in new pipeline infrastructure by respecting tariff arrangements which have resulted from competitive processes. The ACCC identifies in section 6.2.1 of its 2016 report Inquiry into the east coast gas market that there are a range of ways in which competition to build a new pipeline can be effective in limiting market power. This is reiterated by the ACCC as recently as July 2021 in their Gas inquiry 2017–2025 Interim report.
In their 2018 report Review into the scope of economic regulation applied to covered pipelines final Report, the AEMC identified that the application of Part 23 regulation to pipelines with
…the practical effect of introducing Part 23 of the NGR has been to apply near-universal regulation regardless of whether a market failure has been identified on a case-by-case basis. Specifically, the market failure of service providers using market power is assumed. The coverage determination process has in effect been bypassed. The possible impact of this is unnecessary regulation of those pipelines where there is no or only limited or transient market power, with associated direct and indirect costs
This has been recognised by the DRIS. The AEMC goes on to state that:
…applying economic regulation under Part 23 to those pipelines that have been granted a 15-year no-coverage determination under the greenfields pipeline incentive framework may risk regulatory over-reach, and may distort investment incentives for new pipelines.
As discussed with DISER, APGA agree with the AEMC’s advice and submit that this advice extends to the Draft Legislation. APGA submits that the inclusion of effective competitive process provisions within the greenfield incentive is necessary to mitigate this risk of distorting investment incentives for new pipelines.
In noting that this is the first time that competitive process provisions have been included in the Greenfield Incentive, APGA seeks to work constructively with the Department to ensure that it achieves the principles which it is seeking to adhere to. APGA anticipates that the competitive process provisions were included in order to adhere to the principle of supporting efficient investment in pipelines. As such, it is APGA’s expectation that the competitive process provisions within the greenfield incentive are genuinely intended to capture all instances where competitive tensions result in a workably competitive commercial gas contract outcome.
It is critical for debt and equity investors in a new pipeline to have some degree of confidence in its revenue stream as a condition to investing. A significant element of that confidence will come from knowing that assumed tariffs are in place for a minimum term. Foundation shipper tariffs are likely to provide a significant part of that confidence.
The difficulty for a service provider investing in new pipeline infrastructure is obvious – they have the regulatory risk that arbitration will lead to future tariffs lower than what they had forecast when making the investment decision. This price uncertainty increases investor risk and reduces the appetite for investment in direct opposition to the principle of supporting efficient investment in pipeline services as per DRIS Box3.2 (c).
A regime that does not address these issues will inevitably stifle investment as compared to a regime which does address these issues. The proposed greenfields incentive provisions seek to address the issue by providing some pricing certainty. However, the test of competitive process used within the Draft Legislation however is unduly narrow and may not respect accepted circumstances of competitive tension.
Proposed rule 26 provides:
For the purposes of this Division, a pipeline will be taken to have been developed following a competitive process if the AER is reasonably satisfied from the information provided to it by the applicant that there was a genuine competition to develop the pipeline between 2 or more prospective service providers that are not related bodies corporate of each other, and that do not include a related body corporate of the applicant, for the greenfields incentive determination.
Further, when regard is had to rule 27(2) it appears the regime contemplates only a formal tender process. That rule requires an application to include:
These provisions ignore scenarios where:
(a) a greenfields pipeline project competes against alternative fuels;
(b) a greenfields pipeline project negotiates with foundation shippers of equal, or possibly greater, bargaining power;
(c) there is more informal competition between prospective projects in the sense there is no formal tender but greenfields pipeline projects still negotiate with shippers.
For example, a prospective shipper might approach one service provider first for all types of reasons, including because they have been happy with previous projects. There is no formal bid process, but the service provider knows it must come up with appropriate pricing otherwise the shipper may either approach other service providers or instigate a more formal tender process.
By casting the competitive process test in too narrow terms the legislation ignores other genuine sources of competition. This may stifle investment contrary to the National Gas Objective. APGA has difficulty understanding why it would be objectionable to use a broader test as the applicant still has to satisfy the regulator the requisite level of competition existed. That is the Relevant Regulator will be acting as the gatekeeper to vet that there was an appropriate level of competition.
Examples of competitive processes are set out in greater detail below:
As noted above the draft legislation currently approaches the definition of competitive process using a formulation that would perfectly capture instances where either a customer or government department undertook a formal tender process for a specific pipeline route. It is uncontroversial to state that a commercial gas contract arising as a result of such a process would be the result of a workably competitive process, and the draft legislation rightly respects the outcomes of such a process.
However as noted above, the competitive tensions of energy transport extend wider than only this one type of competition. These forms of competition, despite resulting in outcomes of a workably competitive process, would not be captured by the current drafting of the competitive process provisions within the greenfield incentive.
The three examples set out below are by no means exhaustive of all forms of competitive processes influencing tariff pricing for greenfield pipeline investments.
Competition between multiple gas transport pathways from source to market is seen regularly around the Australian gas market. These can involve any number of combinations of single or multiple supply options and single or multiple demand centres.
The ACCC notes that competition to build a new pipeline can be effective in limiting market power in its 2016 Inquiry into the east coast gas market. An example was provided of competition to develop a new pipeline to enable gas from Queensland to be transported into the southern states, in which APA Group and EPIC Energy competed across two very different pipeline routes through an untendered process. There was also a third competing route offered by the Hunter Gas Pipeline being pursued at this time[5].
The ACCC also notes that this form of competition has been seen more recently between multiple Gas Import Terminals and existing pipeline infrastructure[6].
Wholesale gas customers located across the country have a growing list of competing energy options. Beyond the traditional options of electricity network connection and trucked in diesel, utility scale solar and renewable gases now compete side by side with the wholesale gas market and the pipelines that connect them.
The ACCC recently noted that competition, or the threat of competition, affected pipeline operator pricing, with some tariffs being set to maintain a competitive position, and to take into account competing energy sources4. Every customer large enough to enter into a foundation contract for gas transport has sufficient capacity to weigh up the option of utilising another source of energy other than gas delivered by pipeline. This has been seen historically with countless mine sites opting to truck diesel in at no small cost, and more recently in the development solar plus battery installations rather than choosing diesel, gas or electricity connections.
Furthermore, the future of gas in the Australian energy system, and subsequently the role of gas pipelines, is subject to a level of uncertainty. The energy industry is seeing increasing levels of decentralisation and decarbonisation driven by changing customer preferences, market dynamics, and technological and policy developments. As the Energy Security Board has recognised:
it is difficult to overstate the scale and pace of change across Australia’s electricity sector as, both large and small scale, renewable generation enters the system rapidly and in volume.[7]
Energy decentralisation and decarbonisation will change the forms of energy used by future energy customers, as well as where energy is produced and transported to and from. Increasing electrification of gas loads is likely. For example, in three of the five future scenarios being considered by the Australian Energy Market Operator, residential gas heating loads are forecast to be entirely (or almost entirely) electrified by 2050[8].The gas industry is also seeing a greater drive to the use of renewable sources of gas such as green hydrogen and biomethane which will not necessarily be produced in the same locations as current gas fields and further broaden the range of energy supply options for customers.
These factors have the dual effect of increasing the competitive tension gas pipeline operators face while also increasing investment risk. In turn, this increases the cost of investing in and operating gas pipeline assets.
In industries large enough to consider gas pipeline connection, competition between types of energy is alive and well. This means that any gas pipeline transport contract formed in an environment in which the customer could have chosen one of a number of different energy solutions has been formed through an inherently competitive process. The competitive process provisions within the greenfield incentive in the current draft legislation would not respect these informal competitive outcomes.
Spanning both the gas pipeline industry and the energy industry as a whole, organisations seeking to invest in new pipeline infrastructure in a region are aware of not only their own activities, but the activities of other organisations seeking to invest in competing infrastructure in the region.
This has been seen in the Queensland CSG fields even across the past years, where multiple pipeline companies compete to sign up foundation shippers for new pipeline infrastructure between marginal CSG production and existing pipeline infrastructure. In the same area, regional industries seek energy supply opportunities often approaching pipeline companies to consider developing new pipelines to existing infrastructure against continued diesel use or the development of their own solar fields. In the negotiating rooms of companies which know there are competing investors vying for the same small pool of opportunities, this threat of the other company getting to strike the deal before they do drives fierce competition.
From the ACCC Gas inquiry 2017–2025 Interim report July 2021:
While this is generally the case, we have observed instances of some pipeline operators appearing to consider the threat of competition, including potential future competition, when setting prices. Pipeline operators may adjust their pricing approach in anticipation of other supply and transport options becoming available in the near future, including through LNG import terminals.
Considering the fast landscape across which different LNG import terminals are being considered, this can only amount to regional actor competition.
Any region where more than one energy infrastructure or supply company is vying for a finite market leads to competitive tension, and the contracts that are signed are formed in a workably competitive fashion. The competitive process provisions within the greenfield incentive in the current draft legislation would not respect these informal competitive outcomes.
APGA proposes a more high-level definition of competitive process but noting the Relevant Regulator will make the determination whether a process was competitive, and the service provider will have to satisfy the Relevant Regulator of this fact.
For example:
For the purposes of this Division, a pipeline will be taken to have been developed following a competitive process if the Relevant Regulator is reasonably satisfied from the information provided to it by the applicant that the pipeline was developed through formal or informal processes that were sufficient to ensure the prices, terms and conditions offered for pipeline services reasonably reflected those which would arise in a workably competitive market.
Without limitation such formal or informal processes may include:
(a) a formal tender process;
(b) competitive tension between alternative pipeline projects;
(c) competitive tension between a proposed pipeline and projects using alternative fuels
(d) negotiations between foundation shippers and a pipeline project proponent who are of approximately equal bargaining power or where the foundation shippers have greater bargaining power.
APGA also recommends that shipper satisfaction with foundation contracts be taken as evidence that the greenfield pipeline has delivered prices, terms and conditions consistent with those which would arise in a workably competitive market.
APGA agrees with the intent of the Small Shipper provisions but is concerned that the current Small Shipper definition in the draft legislation may not effectively deliver a targeted approach to achieving the intended outcome. APGA appreciates the Department acknowledging that these provisions may require some tightening to avoid unintended consequences. APGA believes that both it and the Department share the same concern that large gas market participants or large corporate entities could utilise Small Shipper provisions if the only definition of Small Shipper is 5TJ as in current draft legislation.
In this respect APGA notes the concern that a large corporate entity may not have the same gas industry experience as a gas retailer, gas trader, gas producer or entity with a long history of direct gas purchases. However, in APGA’s view these concerns are addressed by the original introduction of Part 23 (providing for information disclosure and a negotiation and commercial arbitration regime) and further addressed by the additional transparency and detailed reporting provisions of the new regime.
AGPA does not see how a large corporate entity has a monetary disadvantage that requires it to be protected from arbitration costs. For example, why should a large corporate entity not have an adverse costs order made against it in an arbitration if it has attempted to deceive the service provider or the arbitrator or engaged in vexatious conduct? Why does a large corporate entity need the help of a user association to negotiate its contracts (when it can perfectly well appoint its own professional advisers).
AGPA is also concerned to ensure that the competition law aspects of this proposal have been fully worked through. If the user association has members who may acquire pipeline services in competition with the small shipper, how can they lawfully provide assistance to a small shipper in negotiations?
The September 2021 Consultation Paper provides as follows:
Of the options identified by stakeholders, the size of a shipper’s business could provide an indication of the shipper’s financial capability to credibly threaten arbitration, but determining what an appropriate revenue, profit, asset value or employee size threshold is and how it should be applied (e.g. taking into account the parent company’s size or the individual entity) is complex. There are also no examples of this type of threshold being employed elsewhere in the NGL/NGR or in the NEL/National Electricity Rules (NER) to distinguish between small, medium or large shippers or users. Rather, to the extent a distinction has been made between different entity sizes in these instruments, it has tended to be based on a consumption or capacity threshold.
APGA does not agree with the first sentence, which it feels is overstating the difficulty of identifying when a business is large. For example, it would be very simple to use a test that a small shipper excludes any listed entity with a market capitalisation of over $500 million (at the time it applies for access) and any subsidiary of such a small shipper. Market capitalisations are published on the ASX website. APGA also finds it difficult to see how the case can be made that, in the context of all the other protections and requirements now being incorporated in the NGL and NGR, a $500 million entity cannot protect itself.
Further there is no reason a test based around an entity with assets, revenues or employees above or below a certain level cannot be readily used. A prospective user will know the value of its assets in its accounts. Its revenues, and its number of employees. It can substantiate to the service provider and the Relevant Regulator whether it is or is not a small shipper.
Finally, APGA sees no reason that government entities should be classified as small shippers given that they will have all the financial resources of government to assist them.
The second sentence from the Consultation Paper noted above is not correct. The AER’s Network Service provider registration exemption guideline – March 2018 defines large energy users by reference to large corporate entities, which is in turn a test based on the size of the corporate entity. In the case of such entities, embedded network charges are left to commercial negotiation.
While APGA agrees a volume test of 5 TJs could be used as the primary measure, an entity wishing to deemed a small shipper must apply to the Relevant Regulator for the designation and the following categories of persons should be excluded from the definition of small shipper:
Given the above APGA submits that the definition of a small shipper should exclude any entity on the following basis or on the basis of any other matters the Relevant Regulator considers relevant:
Use of the above framing of any other matters the Relevant Regulator considers relevant is founded in precedent within the NGR47A (13), in which this phrasing is used to give the AER discretion within the application of this rule. APGA is confident that, given such discretion, the Relevant Regulator would not allow the misuse of Small Shipper provisions by either subjectively or objectively large shippers.
APGA notes that the reach of the Draft Legislation applies the same provisions intended to control the potential exercise of market power in the pipeline sector to the gas storage facility sector. Doing so does not take into account the fact that the gas pipeline transport market and the gas storage market are very different markets. Rather than being in response to demonstrable imbalances of market power, application of the draft legislation to gas storage facilities is occurring without adequate consideration of whether such an approach is appropriate.
APGA proposes that the application of Draft Legislation provisions to gas storage facilities sits outside the principle of applying regulation in instances where monopoly powers result in demonstrable adverse outcome to customers. As such, APGA proposes that the Draft Legislation should remove provisions expanding its powers to cover gas storage facilities.
The Consultation Paper is seeking views on the regulatory treatment of pipeline expansions that do not form part of a fully regulated scheme pipeline. Energy Ministers intend on including transitional provisions in the final legislative package that mean such pipeline expansions will form part of the scheme pipeline from the commencement date of the new package. This includes pipeline expansions that have been the subject of a decision by a regulator to not cover a particular expansion.
In effect, policy makers are choosing to overturn previous regulatory decisions through policy, rather than regulatory means. This approach is concerning for a number of reasons:
This is a concerning precedent given Energy Ministers are proposing reforms to the form of regulation decision processes in question.
Alongside expansion on APGA primary concerns, DISER asked for further detail on a number of queries raised through the DISER – APGA Workshop held 21 September 2021. Further detail on each of these points can be found within this section.
APGA appreciates that NGR 113ZI and NGR 113V(2)(d)(v) were simply relocated clauses of existing legislation. APGA propose further development of these rules in line with the DRIS principles of supporting efficient investment in pipeline services and continued safe, reliable and efficient operation and use of pipelines.
Rule 113ZI defines when the provision of pipeline services is unsafe in the following terms:
unsafe – the provision of a pipeline service is unsafe if it is not reasonably possible for the service provider to provide it consistently with:
(a) the safe operation of the relevant pipeline; or
(b) prudent pipeline practices in the gas industry.
While the notion is no doubt inherent in complying with prudent pipelines practices, APGA submits this section would be clearer if there was also a reference to applicable laws. This would be more consistent with section 113ZK which refers to all applicable statutory and regulatory requirements. APGA would anticipate such a clarification is not controversial.
Secondly the section should refer as a further limb to “the requirements of any leases, easements and other access rights” held by the pipeline. A pipeline must comply with its access rights as they fundamentally support the ability of the pipeline to exist and operate.
APGA acknowledges rule 113ZI is based on an existing rule (113). However, APGA’s above clarifications seem consistent with establishing a workable regime which reflects operating and developing pipelines safely and efficiently. Such a refinement would also be in line with other policy refinements undertaken through Draft Legislation development.
Rule 113V contains, in APGA’s submission, two issues which should be addressed.
APGA acknowledges the provision is based on existing rule 570 which also contains these issues. However, APGA submits addressing the issues identified will improve the efficiency and workability of the regime. Further the changes will ensure consistency between rule 113V and new rule 37.
Rule 113V relevantly provides as follows:
(2) Without limiting subrule (1), an access determination may:
(a) require the service provider for a pipeline to provide access to a pipeline service; and
(b) specify the price and other terms and conditions on which the user or prospective user must be given access to the pipeline service; and
(c) require the service provider to permit another facility to be connected to the scheme pipeline; and
(d) subject to subrules (5) and (6), require the service provider to carry out, either alone or in combination:
(i) an expansion of the capacity of a pipeline;
(ii) a conversion of a pipeline to a bi-directional pipeline;
(iii) the development of a new receipt or delivery point;
(iv) an expansion of an existing receipt or delivery point; or
(v) an interconnection with another pipeline or other facility; and
(e) specify conditions to be satisfied before access to a pipeline service commences.
(3) An access determination may require access to be provided for a service term different to that sought by the user or prospective user but must otherwise be made in relation to the pipeline service or services sought by the user or prospective user.
(4) An access determination does not have to require the service provider to provide access to the pipeline service or services sought by the user or prospective user or any pipeline service.
(5) An access determination must not require the service provider to provide a pipeline service or carry out any of the activities referred to in subrule (2)(d) unless the provision of the pipeline service or activity is:
(a) technically feasible; and
(b) consistent with the safe and reliable operation of the pipeline.
(6) An access determination must not, unless the service provider agrees, require the service provider to:
(a) extend the geographical range of a pipeline; or
(b) carry out any of the activities referred to in subrule (2)(d) unless the user or prospective user funds the activity in its entirety; or
(c) fund (in whole or in part) any of the activities referred to in subrule (2)(d)
The issues in the section revolve around 113V(2)(c). 113V(2)(c) should be subject to (5) and (6) in the same way as 113V(2)(d) is otherwise the obligation to connect a new facility is not subject to safety requirements and the requirement on the user to fund construction.
Secondly an order to connect a facility to the pipeline should only be made if the owner/operator of the facility is party to the arbitration. Otherwise, the service provider may be put in a position where it is required to establish a connection but where no terms for the connection have been agreed and it has no contractual or statutory right to require the connection. Alternatively, it should be made clear that in such circumstances the obligation to comply with the award is conditional upon the terms of the connection being agreed with the facility owner.
To APGA these proposals seem unobjectionable. They are consistent with the regime, which is to require connections and investment where technically feasible and safe (see rule 37(a)). It reflects new rule 37(b) which requires a person wishing to establish a new connection to fund it. It avoids an obligation being placed on a service provider which it cannot fulfil (and presumably it cannot be the intent of the regulatory regime to put a service provider in such a position).
APGA Members noted through the recent DISER – APGA workshop that there may be points of conflict between elements of the draft legislation and FIRB requirements. APGA appreciates that the Department will engage directly with Members on this topic and anticipates that the Department will seek to accommodate necessary changes to ensure the Draft Legislation does not have adverse consequences through interaction with FIRB requirements.
Following the DISER – APGA Workshop held 21 September 2021, APGA identified a number of additional concerns about the draft legislation. Some larger concerns are addressed independently below, while other additional concerns are also listed in this section.
|
Section No. |
Issue |
Submission |
|
NGL 28(4) |
Definition User Association
|
APGA notes an association needs to only have 2 members to qualify as a user association (and only one needs to be a user/end user). This seems a relatively low bar. APGA suggests the definition incorporate some notion that a user association is a recognised association representing users or, alternatively and perhaps preferably, that user associations be prescribed in the regulations. |
|
NGL 185(2) |
Costs Orders Small Shippers |
Section 185(2) prevents cost orders being made against small shippers even in the case of conduct which involves attempting to deceive, acting vexatiously or failing to comply with the law. APGA queries if this is appropriate – if a party has caused costs by acting deceptively why should they not contribute to costs? A person, whether large or small, should not act deceptively. APGA notes the position in the policy papers that shippers should not have costs awarded against them, but APGA assumes this is where shippers have conducted themselves in accordance with accepted standards of honesty and legal compliance. |
|
NGL 168 |
Reasons for termination of arbitration |
While in the same terms as previous section 186 (scheme pipelines), the section is narrower than section 216O (non-scheme pipelines). Section 216O contained additional powers to terminate an arbitration if the arbitrator considered there was “some other good reason why the arbitration should not proceed” or if the user is not engaging in the arbitration in good faith. APGA submits these reasons should be included in section 168. |
|
NGL 165 |
Expansions |
This may be broader than its previous iteration (section 191). Section 191 applied to any expansion due to installation or construction of a new facility. New section 165 applies to any expansion (but is still headed “Rules may allow determination that varies applicable access arrangement for installation of a new facility”). APGA submits it should be clarified whether or not section 165 extends beyond circumstances where a new facility is installed. |
|
NGR 16(4) |
Adverse Inferences |
Rule 16(4)(a) enables the AER if the service provider does not provide relevant information within a period specified by the AER to “draw such adverse inferences from the failure to comply as the circumstances justify.” The ability to draw adverse inferences is already dealt with in section 59 of the NGL which is headed “Assumptions where there is non-compliance with regulatory information instrument”. It provides: “Without limiting sections 56 and 57 and despite anything to the contrary in this Law or the Rules, the AER— (a) may make the AER economic regulatory decision or the rate of return instrument on the basis of the information the AER has at the time it makes that decision or instrument; and (b) in making that decision or instrument, may make reasonable assumptions (including assumptions adverse to the interests of the scheme pipeline service provider) in respect of the matters the information required under the regulatory information instrument would have addressed had that information been provided as required.” APGA submits the wording in rule 16(4) should be consistent with the wording in section 59. It will create ambiguity to have two provisions dealing with adverse inferences which are framed in inconsistent ways. Further the wording of the rules should follow the wording of the superior instrument. Finally, APGA submits the NGL wording is more appropriate, incorporating a reasonableness requirement around the inference which may be made. |
|
NGR 16/21 |
Provision of information for scheme determinations. |
Where a scheme determination is proposed rule 16 requires a service provider to provide the AER various information including the location of all pipelines within 100 kilometres (for a transmission pipeline) and other sources of energy available to customers (in the case of a distribution pipeline). The APGA notes this is not information confidential or proprietary to the service provider so it is not clear why the service provider should be required to provide it. More importantly the service provider may not know all of this information – i.e. it may not know all the different types of energy used by potential customers and, to the extent it does know, it is obtaining this knowledge from the same sources as available to the AER. APGA considers a service provider should only be required to provide this information to the extent the service provider is aware of it. This reflects the reality of the situation. Section 21 raises the same issue. |
|
NGR 27 |
Competitive process |
In respect of pipelines being developed through a competitive process, the service provider must notify the AER of proposed prices and terms and conditions and of how long they will apply. While a service provider may intend to lock in terms and conditions for the long term, changes in law (for example the introduction of Parts 24 and 25 or the Standard Market Timetable) may require changes to existing terms. APGA recommends NGR 27 acknowledge trigger events may require changes in terms over time. For example, there could be a (c)(v) which refers to trigger events (such as changes in law) which will lead to an adjustment in non-price terms. |
|
NGR 27 |
Competitive process – information |
Rule 27(2) requires the service provider to provide various information in respect of a competitive tender process including “how many prospective service providers competed to develop the pipeline and what criteria were used to select the pipeline that is the subject of the application” (27(2)(b)). While this reflects the wording of existing rule 21(2), the context is different. Under rule 21 the party setting up the tender process applies to the AER and so has the relevant details. In contrast under rule 27 the application is made by the service provider (NGL section 100). The service provider may not know the information referred to in 27(2)(b) and/or the information may be confidential. They are not going to know the exact criteria actually applied to make the decision (as compared to the published criteria). As with rules 16 and 21, APGA considers these obligations should only apply to the extent the service provider knows the information. |
|
NRG 38 |
Interconnection – Allocation of Responsibility for Construction and Ownership |
Rule 38 assumes that either the service provider constructs/operates the interconnection or the applicant. This is a simplification of what happens in practice which is that each party will have equipment at/around the connection point (and the connection itself is just a notional point). That is each party is likely to build part of the connection facilities and how operation is divided up will also be a matter of commercial negotiation between the parties. The Rules should reflect this common scenario. |
|
NGR 39 |
Interconnection Policy Elements |
Rule 39 sets out the elements of an interconnection policy but does not actually state that a connection agreement is required. In modern infrastructure developments, connection agreements are always required when a new facility is connected (and operate separately from the haulage agreement). They set out parties’ obligations in respect of construction and ownership, maintenance procedures, the circumstances in which valves can be closed (and so supply or take curtailed), procedures for exchange of information and may deal with legal concepts such as liability, assignment, dispute resolution and confidentiality. APGA recommends section 39 should make clear that one of the service provider’s requirements may include a contract governing the connection (and potentially that the policy should set out the essential terms of such contract). |
|
NGR 46(1A) |
Lodgement Times |
Rule 46 provides 20 business days to lodge a reference service proposal (from becoming a scheme pipeline) and 3 months to prepare an access arrangement from the time the AER makes a reference service proposal decision. The AER may extend the 3-month period by another 2 months. This is quite a short timeframe given that generally service providers start working on their access arrangements 12 months prior to lodgement. APGA appreciates the above timeframes are the existing timeframes in the rules but the process of becoming a covered pipeline is much more extensive than the process of becoming a scheme pipeline – i.e. the service provider would have much more notice that the requirement is coming and in particular would have the time between the initial NCC recommendation and the Ministerial decision. APGA also notes that regulatory expectations around the pivotal role customer engagement should play in access arrangement determinations continue to evolve. Best practice examples of customer engagement recognised by the AER, Energy Consumers Australia and Energy Networks Australia in recent years include service providers such as AGIG and Jemena which have spent considerable amounts of time – in some cases, over 18 months – engaging with customers. This has included preparing full ‘draft plans’ for public consultation 6 months prior to the formal submission of their regulatory proposals. Particularly in the context of an asset which has not previously been subject to economic regulation, APGA questions whether these provisions give adequate time for effective and meaningful customer engagement. APGA recommends a period of 9 months to lodge an access arrangement. Regarding the 20 business days to lodge a reference service proposal, APGA submits that this timeframe may not allow for appropriate consultation with shippers. APGA propose that the 20 business days to lodge a reference service proposal be extended to 2 months to ensure sufficient time to engage with shippers and provide the most true and accurate response. |
|
NGR 68(c)(2) |
Updating Information |
Section 68(c)(2) provides: If a service provider becomes aware that information required to be provided or published by it under this Part does not comply with the access information standard or any other provision of this Part, or is no longer accurate, the service provider must provide or publish information that does comply, or is accurate, as soon as practicable after the service provider becomes aware of the non-compliance or inaccuracy. During an access arrangement review process a service provider will provide various information which will become out of date in due course as circumstances change (or events which have been forecast actually evolve). Literally interpreted section 68(c)(2) imposes an ongoing obligation to update information even if the access arrangement review process is completed and the information is no longer relevant. APGA recommends the temporal operation of section 68(c)(2) should be made clearer. |
|
NGR 101A |
Obligation to publish |
The obligation to publish information under this rule is continuous. That is, information must generally be published within 20 days and immediately notified to the AER. This continuous obligation will create a continuous overhead for service providers and result in a continuous flow of emails for the AER. To reduce the administrative burden on service providers and the AER, APGA recommends that the obligation to publish information and notify the AER should be on a monthly basis. |
|
NRG 102 |
Exemptions - Test |
Rule 102 provides: The AER must, on the application of the service provider for a non-scheme pipeline, grant an exemption under this Subdivision in respect of the service provider's pipeline if: (a) the exemption sought is one of the exemption categories in subrule (4); and (b) the service provider has demonstrated to the reasonable satisfaction of the AER that the pipeline satisfies the exemption criteria applicable to the exemption category; and (c) the AER is otherwise satisfied that in all the circumstances the exemption should be granted. Paragraph (c) is very broad and largely leave the matter to the discretion of the AER. It is questionable if this catch all needs to be included. For example, if a pipeline is not a third party access pipeline why does the “in all the circumstances” test need to be taken into account at all? We appreciate rule 102 reflects the wording of existing rule 585. However, the exemption categories are now narrower. Given this APGA considers (c) should be removed or if not removed at least some guidance as to what it means provided. |
|
NRG 102A |
Exemptions – conditions |
Rule 102A(1) provides: “An exemption may be granted subject to any conditions determined by the AER.” We consider it would be preferable to provide some guidance as to what the exemption conditions may be. Again, as the exemption categories are now quite narrow it is not clear what the exemption conditions should be. |
|
NRG 102E(1) |
Exemption Revocation |
Rule 102E(1) provides: “If the AER proposes to vary or revoke an exemption other than on the application of the service provider for the pipeline concerned, it must notify the service provider for the pipeline and invite the service provider to make submissions about the proposed variation or revocation within 20 business days of the notice.” APGA submits the Relevant Regulator’s notice should set out why it is considering to vary or revoke the exemption so that the service provider has all details relevant to responding to the notice. We appreciate rule 102E(1) reflects the wording of rule 590 but again the efficiency of the regime will be improved if the lack of clarity of some aspects of the rules is addressed. |
|
NGR 105F |
Legal professional privilege |
Rule 105F reproduces old rule 562 from Part 23 but subrule 562(9) is missing. We assume this is an error as rule 105F(7) refers to the (missing) 105F(9). 562(9) provides disclosure cannot be compelled of documents subject to legal professional privilege. As legal professional privilege is a fundamental common law right APGA assumes it is intended to continue to be recognised in rule 105F. |
|
NGR 113A(1) |
Drafting Issue |
APGA notes various words appear to be missing from this rule – i.e. there seems to be a drafting or typographical error. |
|
NGR 113B |
Matters carved out of access disputes |
Rule 113B provides: For section 152(4) of the NGL, the following matters are excluded from arbitration: (a) a dispute about a pipeline service provided under an existing access contract; and (b) a request to vary the terms and conditions of access applicable to a pipeline service provided under an existing access contract for any part of the current service term for that pipeline service; and (c) an access request that would require the extension of a pipeline; and APGA submits that a (d) should be added to exclude disputes about operation of a mechanism in an existing access contract dealing with provision of a new service. For example, if a contract had a mechanism dealing with converting to reverse flow or swapping a firm service into a storage service that should not be subject to arbitration but should be determined in accordance with the terms of the contract. |
|
NGR 113B |
Drafting Issue |
Rule 113B ends with an “and” suggesting a provision is missing. Rule 594 refers to rule 113B(2)(d) but there is no existing (d) (or 2(d)). |
|
NGR 1136G |
Reference to mediation |
113G(6) provides the AER must refer an access dispute to a pool mediator within 15 business days after receipt of the access dispute notice. However, in the event a service provider initiates an access dispute this is not enough time because the small shipper has 5 business days to refer to mediation, then there is 5 business days to give notice of this election, then 5 business days for the parties to seek to agree a mediator. I.e. the 15 business days is up before 113G(6) is activated. |
|
NGR 113H and I |
Mediation – attendance of lawyers |
It should be made clear a party may have its lawyers in attendance at a mediation. Practically service providers will not sign off on contractual terms unless they have been signed off as appropriate by their legal advisers. This is an essential part of good governance. |
|
NGR 113ZB |
Variation of Access Arrangement |
Section 113ZB (which reflects existing rule 119) allows a dispute resolution body to vary an access arrangement. It is unclear what happens to the variation at the next access arrangement review by the AER – for example can the AER effectively undo the variation? We note this is an issue with rule 119. APGA submits the AER should be bound by the determination unless the service provider agrees otherwise. Any other approach introduces uncertainty for the service provider as it does not know whether, in fact, the determination is binding in the longer term. |
|
NGR 113ZC(d) |
Confidential Information |
This exempts from publication any information caught by Chapter 10 Part 2 of the NGL. This reference seems wrong since Chapter 10 Part 2 deals with when the AER and AEMC may disclose confidential information. Presumably the obligation to disclose information under rule 113ZC(d) should be subject to any confidentiality orders made by the adjudication body. In any event it is difficult to understand why all information provided by the parties in the course of a dispute needs to be published (rather than just the outcomes of the dispute). |
|
NGR Schedule 6 rule 9 |
Transitional provision – Financial information, historical demand information and cost allocation methodology |
The proposed transitional provision has the effect of requiring service providers to commence reporting against requirements specified in an instrument (being the relevant regulator’s guideline) with respect to the reporting period in which that instrument is first published. To the extent that the guideline requires service providers to collect and report new types of information, it is unreasonable to require service providers to collect such information prior to them having knowledge of the need to collect it. APGA submits that this issue could be addressed by providing for an additional year of reporting under the current framework within the transitional provisions. |
|
NGR |
Actual prices paid information |
The proposed transitional provision provides that service providers are not required to publish the required information until 2 months after the commencement day. Clause 101E introduces new publishing obligations for every individual services. Many of these new obligations will require changes to business processes and systems, resulting in additional costs for service providers. For these reasons, we suggest that the transitional provision allow a period of 6 months after commencement for service providers to publish the required information. This would also more closely align with other Rule101 timelines such as the AER guideline development. |
|
Conflict of interest |
Conflicts of Interest |
Rule 577 of Part 23 dealt with conflicts of interest of arbitrators (which is an important provision for ensuring the integrity of the arbitration process). This provision appears to have been removed from the Rules. APGA submits this provision should be reinstated – it is appropriate the Rules have a mechanism to deal with conflicts of interest. |
The Consultation Paper identifies that there are elements of the draft legislation which were not included in the consultation ahead of DRIS development and publication. These were flagged in Attachment B, our responses to which can be found in Appendix 1.
[1] Review of the Gas Access Regime, Inquiry Report No 31, Productivity Commission 2004
[2] Inquiry into the east coast gas market, ACCC 2016
https://www.accc.gov.au/system/files/1074_Gas%20enquiry%20report_FA_21April.pdf
[3] Gas inquiry 2017–2025 Interim report July 2021, ACCC 2021
https://www.accc.gov.au/system/files/Gas%20Inquiry%20-%20July%202021%20interim%20report_0.pdf
[4] FINAL REPORT Review into the scope of economic regulation applied to covered pipelines, AEMC 2018
https://www.aemc.gov.au/sites/default/files/2018-07/Final%20Report.PDF
[5] Hunter Gas Pipeline
https://www.huntergaspipeline.com.au/
[6] Gas inquiry 2017–2025 Interim report July 2021, ACCC 2021
https://www.accc.gov.au/system/files/Gas%20Inquiry%20-%20July%202021%20interim%20report_0.pdf
[7] Energy Security Board, Post-2025 Market Design, Final advice to Energy Ministers Part A, July 2021, p. 7
[8] 2021 Electricity Statement of Opportunities, Australian Energy Market Operator 2021
https://aemo.com.au/-/media/files/electricity/nem/planning_and_forecasting/nem_esoo/2021/2021-nem-esoo.pdf?la=en&hash=D53ED10E2E0D452C79F97812BDD926ED