Pricing Methodology for Gas Transmission Services

From 1 October 2019

Summary of stakeholder consultation

First Gas Limited 31 May 2019

2019/20 Pricing Methodology for Gas Transmission Services SUMMARY OF STAKEHOLDER CONSULTATION

Introduction and summary

First Gas prepared a Draft Transmission Pricing Methodology for consultation with stakeholders that was released on 18 April 2019. A workshop was subsequently held with stakeholders on 1 May 2019 and submissions were received from 7 stakeholders (including the Major Gas Users’ Group which represents several major gas consumers) on 17 May 2019. This document summarises the contents of these submissions and outlines the resulting changes to the Transmission Pricing Methodology (TPM). We were pleased with the high quality of submissions received from stakeholders, and the frank and supportive discussions we have had regarding our TPM. Overall the submissions largely supported the approach we have taken to preparing the TPM and also demonstrated a sound understanding of the constraints we face in developing the first year’s pricing under the new Gas Transmission Access Code (GTAC). The key themes in the submissions were:

• An appreciation that the 2019/20 TPM has focused on maintaining price stability as an important part of transitioning to the GTAC; • An understanding that the economic balance of existing Supplementary Agreements needed to be respected in the transition to the GTAC; • That the extent of consistency with some of the Commerce Commission’s pricing principles (such as cost reflective pricing) involved trade-offs with other pricing principles (particularly price stability); • That the draft TPM did not provide guidance on the direction of travel of pricing over the coming years, and was silent on how prices might change should a large user exit (or join) the transmission system; and • That estimating underrun and overrun fee revenue in the first year of the GTAC is difficult, and will have significant impacts on Daily Nominated Capacity (DNC) Fees. Submitters also raised issues relating to the presentation of information and the naming of the delivery zones. No issues were raised relating to how the fees were calculated or the composition of the delivery zones or individual delivery points. As a result of these submissions, we have made the following changes to the TPM:

• Calculated a single price for the Bertrand Rd and Faull Rd individual delivery points; • Changed the estimate of Huntly Power Station volumes for the 2019/20 gas year to 25,000,000 GJ; • Added four letter codes to identify each Delivery Zone; • Reviewed the overrun and underrun percentage estimates for each Delivery Zone, and adjusted assumed overruns and underruns based on the evidence provided; and • Added more information on the calculation of pass-through and recovery costs and moved some information to the appendices. We feel that work on developing cost reflective pricing for the transmission system needs time and, most importantly, consultation with stakeholders. We need to understand stakeholder views on the scope of cost reflective pricing, to what extent pricing should be cost reflective, and how quickly pricing should move towards this goal. We therefore propose that we commence consultation on this issue in early 2020 to progress work on a cost of service model that will test different approaches to allocating costs to the services provided by the gas transmission system. We will then work collaboratively with stakeholders on the potential paths to applying the outputs of this model. Given the scope of this work, we would prefer to take sufficient time on this work to ensure stakeholders are able to participate fully in the process and are not surprised by any price adjustments arising from the work. We anticipate that this work will be completed in line with our proposed Customised Price Path (CPP) application in time for the GY22 TPM.

Separately to the TPM consultation, Shippers raised concerns relating to their ability to adapt to the new regime and requested a more gradual introduction of incentive fees. Their concern focussed on the timing of the IT changes required for GTAC and the additional resources that would be required if they were not able to develop their systems in time. In order to assist Shippers in this matter, we have agreed to a “soft launch” of the GTAC, where incentive fees and excess running mismatch charges are not charged until 2 February 2020. Accordingly, we will adjust pricing so that in the first part of the year Daily Nominated Capacity Fees are collected only for capacity actually used and incentive charges are only collected in the second part of the year. In undertaking the revisions of the Draft TPM, we also identified the following errors in the Draft TPM that have been addressed:

• Excess Running Mismatch charges were added to recoverable costs in the Draft TPM when they should have been deducted from these costs; and • The new Mangorei delivery point on the 400 line for the Junction Rd peaking power station that will commence operation during 2020 was omitted in error and has now been added as an individual delivery point. Following the issue of the TPM Methanex engaged with First Gas on the potential bypass opportunity at the Ngatimaru Road delivery point. We are in discussions with them to avoid this bypass. These discussions will be governed by the criteria for Supplementary Agreements in section 7.1 of the GTAC. We would like to thank all stakeholders for the time taken in submitting on our Draft TPM. We will now complete the update of the TPM and publish this document prior 30 June 2019. We look forward to discussion on our work on cost-reflective pricing in late early 2020.

Glossary

Act: Commerce Act 1986. Allowable Notional Revenue: The revenue First Gas is allowed to earn during the pricing year under the Default Price-Quality Path (DPP) Determination. Connection Point (CP): An aggregation of one or more Delivery Points (DPs) for cost allocation purposes. CPI: Consumer Price Index. Daily Nominated Capacity In respect of a Day and a Shipper, the quantity of Gas that a Shipper (DNC): takes in a Delivery Zone, at a Delivery Point in a Delivery Zone or at an Individual Delivery Point. Delivery Point (DP): A facility (including any associated land and equipment) at which one or more Shippers take (or may take) Gas from the Transmission System. Delivery Zone: Means a group of two or more Delivery Points which, for the purposes of nominations are treated as a single notional delivery point and have a single fee for transmission services. DPP: Gas Transmission Services Default Price-Quality Path Determination 2017, NZCC14, 29 May 2017. GJ: Gigajoule, a unit of energy. GTAC: Gas Transmission Access Code. GTB: Gas Transmission Business, meaning First Gas Limited. GY: Gas Year. ID Determination: Gas Transmission Information Disclosure Determination 2012, consolidating all amendments as of 3 April 2018, published by the Commerce Commission. Input Methodologies: Gas Transmission Services Input Methodologies Determination 2012 consolidating all amendments as of 3 April 2018, published by the Commerce Commission. MPOC: Maui Pipeline Operating Code. NGC: Natural Gas Corporation. Operational Balancing A Gas allocation option available to an Interconnected Party under its Arrangement (OBA): ICA at one or more Receipt Points, or at one or more Individual Delivery Points, whereby at the relevant point: a) Each Shipper’s Receipt Quantity or Daily Delivery Quantity is its Approved NQ; and b) Any difference between the Scheduled Quantity and the metered quantity is the responsibility of the OBA Party. Pass-through costs As defined in clause 3.1.2(1) of the Gas Transmission Services Input Methodologies Determination 2012, pass-through costs include: a) rates on system fixed assets paid or payable by a GTB to a local authority under the Local Government (Rating) Act 2002; and

b) levies payable: (i) under regulations made under the Commerce Act; (ii) under regulations made under the Gas Act 1992; or (iii) by all members of the Electricity and Gas Complaints Commissioner Scheme by virtue of their membership; or c) a cost associated with the supply of gas transmission services, outside the control of the gas transmission business, not treated as a recoverable cost, and appropriate to be passed through to consumers Price Component The various tariffs, fees and charges that constitute the components of the total price paid, or payable, by a consumer. Pricing Principles: The pricing principles specified in clause 2.5.2 of the Gas Transmission Services Input Methodologies Determination 2012. Pricing Zone: A group of Delivery Points with the same pricing DNC (as set out in section 4.3.2); not the same as a “Transmission Pricing Zone” as defined in the VTC. Pricing Strategy: A decision made by the Directors of the GTB on the GTB’s plans or strategy to amend or develop prices in the future and recorded in writing. Receipt Zone: Means that part of the Transmission System in which Receipt Points are located. Recoverable costs As defined in clause 3.1.3 of the Gas Transmission Services Input Methodologies Determination 2012, recoverable costs include 12 different types of costs that a gas transmission business can directly recoup through its prices. Shipper: A person named as a shipper in a Transmission Services Agreement with First Gas. Specified Shipper The automated nominations made by First Gas for Specified Shippers Nomination: in respect of gas delivered to mass market consumers. Target revenue: The revenue the GTB expects to receive during the pricing year, as described in section 4.1 of this document. TOU: Time of Use TPM: Transmission Pricing Methodology. VTC Vector Transmission Code

Background documents Information about the Gas Transmission Access Code (GTAC) Implementation Project is available on the First Gas website here: https://firstgas.co.nz/about-us/gtac/ All regulatory documents relating to transmission pricing are available on First Gas’ website here: https://firstgas.co.nz/about-us/regulatory/transmission/ All prices are set to comply with the revenue path set in the DPP Determination for gas transmission. Further details are set out in the Ex-ante price-setting compliance statement for the year commencing 1 October 2019, which is also available on the Regulatory page of the First Gas website.

Table of Contents

Introduction and summary ...... 2

Glossary ...... 4

Background documents ...... 5

Table of Contents ...... 6

1 Consultation process with stakeholders ...... 8

1.1 Submissions received ...... 8

2 Maintaining price stability ...... 9

2.1 Our objectives in setting prices ...... 9

2.2 Comments on our objective of price stability ...... 9

2.3 Comments on pass through to end-users ...... 9

3 Treatment of Supplementary Agreements ...... 11

3.1 Supplementary Agreements under the GTAC ...... 11

3.2 Supplementary Agreements included in the TPM ...... 12

3.3 Treatment of existing Supplementary Agreements ...... 14

3.4 Supplementary agreement policy ...... 14

4 Extent of Compliance with Commerce Commission Pricing Principles ...... 16

4.1 Commerce Commission Pricing Principles ...... 16

4.2 Stand-alone and incremental costs ...... 16

4.3 GTAC requirements relating to pricing principles ...... 17

5 Direction of travel for pricing ...... 18

5.1 Information on direction of travel of pricing ...... 18

5.2 Appropriate rate of change ...... 19

5.3 Impact of a significant reduction in load ...... 19

5.4 Proposed way forward ...... 20

6 Estimation of overrun and underrun fees ...... 21

7 Other issues raised ...... 23

7.1 Delivery zone naming and codes ...... 23

7.2 Huntly power station pricing in relation to nearby pricing ...... 24

7.3 Huntly power station volumes ...... 24

7.4 Bertrand Rd and Faull Rd Tariffs...... 24

7.5 Improvements in TPM information ...... 25

7.6 Soft launch of GTAC ...... 25

8 Consequential amendments to the TPM following consultation ...... 27

9 Correction of errors ...... 28

1 Consultation process with stakeholders

First Gas developed the new gas transmission code (the GTAC) in consultation with shippers, gas producers, major gas users and other stakeholders. The Gas Industry Company (GIC) then consulted on the merits of the new arrangements to determine that the GTAC is materially better than existing codes. The GTAC development process took two years and involved numerous workshops and meetings with the sector. We aimed to provide our customers and other stakeholders with a seamless solution to transporting gas from the injection points to the various delivery points across the North Island. Background on the GTAC development process is available on the GIC website.1 During the GTAC consultation period, workshops were held to establish how pricing would work under the GTAC. Draft prices were circulated in 2018 during the consultation period to give stakeholders an indication of possible pricing impacts. It was agreed that final prices would be determined once the GTAC had received final approval from the GIC. This approval was received in February 2019.2 Following on from the consultation relating to the GTAC, a consultation process for the TPM itself was undertaken. This consultation process is outlined in Table 1 below. The notes from the meeting on 1 May 2019 can be found here: https://firstgas.co.nz/wp-content/uploads/Meeting-Minutes-TPM-Stakeholder- Workshop-Memo-Version-2.pdf.

Table 1: TPM consultation process

Timeframe Detail August 2016 to October 2018 The GTAC Framework developed and pricing structure / charges were determined. February 2019 Final Assessment Paper was released from the Gas Industry Company (GIC) approving the GTAC 19 April 2019 to 17 May 2019 Draft Gas Transmission Pricing Methodology and provisional prices released to stakeholders for consultation and feedback. 1 May 2019 Gas Transmission Pricing workshop held to discuss the Draft Transmission Pricing Methodology document. 31 May 2019 First Gas publishes a summary and response to submissions by interested parties on the draft TPM and draft prices. Any agreed changes to TPM or prices will be made accordingly. 30 June 2019 First Gas will notify stakeholders of final TPM and Prices

1.1 Submissions received We received a total of seven submissions from the following organisations:

• Contact Energy • Genesis Energy • Greymouth Gas New Zealand • Methanex • Major Gas Users Group (MGUG) – representing Ballance Agri-nutrients Ltd, Fonterra Co-operative Group, New Zealand Steel Ltd, Oji Fibre Ltd, Refining NZ • Nova Gas • Vector Gas Trading Limited (commercial in confidence) All non-confidential submissions can be found here: https://firstgas.co.nz/about-us/gtac/consultation- documents/.

1 https://www.gasindustry.co.nz/work-programmes/transmission-pipeline-access/developing/ 2 https://www.gasindustry.co.nz/work-programmes/transmission-pipeline-access/developing/gtac-final-assessment-paper/

2 Maintaining price stability

2.1 Our objectives in setting prices In developing a new TPM for the GTAC, we were concerned with the effect of the new transmission products on costs for our customers. The two previous codes, the Maui Pipeline Operating Code (MPOC) and Vector Transmission Code (VTC) had very different pricing mechanisms and transmission products. Our chief concern was therefore to ensure that customers did not pay substantially more or less under the new TPM. Our aims were therefore to:

• Ensure consistency of pricing to shippers to avoid price and revenue shock. We believe that keeping unit prices per zone ($/GJ transported) within 10% of last year’s prices (if they had been expressed as $/GJ of DNC) achieves this objective; and • Ensure geographic consistency so that users further from sources of gas pay more than those located closer to gas sources. The only exception to this was our intention to continue to bring the Kirikiriroa zone prices into line with other zones in the Waikato region, with higher increases than surrounding areas.

2.2 Comments on our objective of price stability Stakeholders were largely supportive of this objective and were generally in agreement that this objective had been met. MGUG stated that they supported this view:

We support the view that pricing arrangements of this first TPM under GTAC should look to minimise any price shock (MGUG, p2). Nova also supported this objective as a pragmatic way of creating a first TPM under the GTAC:

As a basis for prices in the first year of operation of the GTAC, the pricing basis appears fair and reasonable. In the absence of First Gas completely reviewing its overall allocation of costs against the pricing principles it is required to adhere to, it is appropriate for First Gas to minimise price shocks across the regions, while reflecting pipeline distances, zonal boundaries and volumes where appropriate. (Nova, p1) Similarly, Genesis was supportive:

We are generally comfortable with the draft TPM and appreciate consultation with stakeholders on pricing under the GTAC was foreshadowed during the GTAC’s development process. We also acknowledge First Gas’ efforts to minimise price shock for any pricing under the new GTAC. (Genesis, p1) These supportive comments were generally linked to discussion of the need to demonstrate compliance with Commerce Commission pricing principles and show direction of travel of pricing in future years. We will discuss these comments in sections 3 and 4 respectively of this document.

2.3 Comments on pass through to end-users In our TPM, we noted the following statement relating to price stability:

We note that the price stability achieved through this TPM does not necessarily avoid significant changes in the transmission prices that are passed on from shippers to end-users of gas. Final end-user pricing is determined by shippers, who will need to consider how changes in transmission prices across their customer base will be reflected in their charges to customers. (Draft TPM, p27)

Contact raised the following issue with this statement:

This may be correct for the mass market sector of customers, but not likely to represent the position for industrial consumers of gas. However, it is acknowledged that where there is price shock, or alternative fuel options, or prices making operations uneconomic, such parties can apply for a Supplementary Agreement with special pricing. (Contact, p1) We acknowledge that changes in gas transmission prices may be more visible to large users than smaller users,due to the potential for greater transparency in contracting arrangements. However, we are uncertain how we can impact this situation. We agree with Contact’s statements regarding supplementary agreements and look forward to further discussions on these issues with stakeholders as appropriate.

3 Treatment of Supplementary Agreements

Concerns were raised by several parties regarding the treatment of existing Supplementary Agreements in the TPM.

3.1 Supplementary Agreements under the GTAC The GTAC allows for First Gas to enter into Supplementary Agreements in the following circumstances:

7.1 Any Shipper may at any time request First Gas to enter into a Supplementary Agreement (with such request to address each of the following criteria). First Gas will promptly evaluate that request against any of the following criteria:

a) the amount of transmission capacity requested, including whether providing it would affect Available Operational Capacity to the extent of impeding or forestalling opportunities more beneficial to First Gas and other users of the Transmission System;

b) whether the Shipper (or End-user) can demonstrate that it has a practical opportunity to bypass the Transmission System or use an alternative fuel that is cheaper than Gas;

c) whether the Shipper (or End-user) can demonstrate that paying First Gas’ standard transmission fees would be uneconomic; and

d) whether the Shipper (or End-user) is the sole user of the relevant Delivery Point or other transmission assets and those assets would cease to be useful were the End-user to cease using Gas. The GTAC also mandates that First Gas must publish the agreements and information about why the Supplementary Agreement was entered into and maintain a Supplementary Agreement policy:

7.2 When evaluating any request to enter into a Supplementary Agreement against the criteria referred to in section 7.1, First Gas will use the information available to it at that time. If First Gas enters into a Supplementary Agreement (but not otherwise), it will publish on OATIS a summary of both the information provided by the Shipper under section 7.1 and the analysis undertaken by First Gas pursuant to this section 7.2 when evaluating the Supplementary Agreement request. Any decision whether to enter to a Supplementary Agreement, and the evaluation of any such request, is solely a matter for First Gas. First Gas shall maintain a publicly available Supplementary Agreement policy document. The GTAC further states that First Gas does not have to enter into a Supplementary Agreement with any shipper.

7.3 No Shipper has the right to require First Gas to enter into a Supplementary Agreement. We also have a number of existing Supplementary Agreements that were entered into under the VTC. Some of these expire after the commencement of the GTAC and some of these are confidential. First Gas has undertaken to honour these Supplementary Agreements as this ensures that current users who have invested in equipment to use gas continue to do so on the same economic basis. This benefits other users of the transmission system by ensuring diversity of load. Furthermore, we have some annual Supplementary Agreements that are linked to transmission pricing agreements. Transmission pricing agreements give stability of pricing and reservation of capacity for users who have supported investment in transmission system capacity. First Gas needs to recover the costs of these investments and end-users need certainty over pricing to recover their investment in the use of gas. Again, we consider such agreements are beneficial to other system users as they ensure diversity of load and ensure system development. The Supplementary Agreements associated with these transmission pricing agreements are renewed annually, so as to not tie the end user to a particular shipper over an extended timeframe.

3.2 Supplementary Agreements included in the TPM During the workshop with stakeholders on 1 May 2019, there were concerns raised relating to transparency on the Supplementary Agreements included in the TPM. A summary table was produced for the meeting notes and is reproduced in Table 2 with some additional information requested through various email conversations following publication of the meeting notes. This shows a total of twelve supplementary agreements within the TPM. The revenue associated with these agreements is $24,667,4703. The following Supplementary Agreements have been included in our pricing as they have an expiry date after 1 October 2019:

• Supplementary Agreement (Te Rapa Cogeneration Plant) • Supplementary Agreement (CHH Penrose) • Four confidential supplementary agreements The revenue from these agreements is $9,657,497. The following agreements are annual agreements linked to transmission pricing agreements that have been included in our TPM:

• Supplementary Agreement (Auckland District Health Board) • Supplementary Agreement (Marsden Point) • Interruptible User Contract (New Zealand Refining Company)

The revenue from these agreements is $10,141,249. Finally, we intend to renew the following annual agreements as we consider the reason for these agreements still exist:

• Supplementary Agreement (Whakatane Mill) • Supplementary Agreement (Kauri & Maungaturoto Dairy Factories) • Supplementary Agreement (Southern Paprika) The revenue from these agreements is $4,868,724. The revenue from agreements to be renewed based on a continuing reason for renewal (by-pass threat or alternative fuel) therefore represents only 15% of supplementary agreement revenue in our TPM. Prior to renewing these agreements First Gas will publish the summary report required under section 7.2 of the GTAC. In previous TPMs, information has not been given on the supplementary agreements included in the TPM calculations. Ex-post reporting on Supplementary Agreement revenue per contract is provided in Appendix 3 of the Annual DPP Compliance Statement here: https://firstgas.co.nz/wp-content/uploads/First-Gas- transmission-DPP-compliance-statement-2018.pdf. The request for this information is appreciated and this information will enhance the utility of the TPM for stakeholders. Stakeholders also requested at the workshop on 1 May that the listing of delivery zones show which zone a delivery point under a supplementary agreement would fall into. Again, we consider this a useful improvement to the TPM document.

3 This figure has been updated following discussions with some supplementary agreement holders. This is the final value for consideration in the TPM.

Agreement name Delivery Point ‘Expiry date’ Date signed Linked to a Reason for Capacity Transmission fee basis Revenue as defined in TPA? agreement VTC SA Supplementary Te Rapa 30 June 2023 13 May 2015 Physical bypass mdq 23,200 GJ; Fixed fee ($/day); variable Agreement (Te Rapa Cogeneration mhq 1,092 GJ fee ($/GJ); (daily) overrun Cogeneration Plant) Plant fee ($/GJ)

Supplementary Greater 30 Sep 2021 25 Sep 2015 Physical bypass mdq: 1,600 GJ; Fixed fee ($/GJ.mdq); $9,657,497 Agreement (CHH Auckland mhq: mdq/20 (daily) overrun fee ($/GJ) Penrose)

Confidential Supplementary Agreements (4)

Supplementary Greater 30 Sep 2019 3 Sep 2018 Yes Encourage new mdq: 1,451 GJ; Fixed fee ($/day); variable Agreement (Auckland Auckland use of gas mhq: mdq/16 fee ($/GJ); (daily) overrun District Health Board) fee ($/GJ)

Supplementary Marsden 1 30 Sep 2019 28 Jan 2019 Yes Investment mdq: seasonal profile, Fixed fee ($/GJ.mdq); Agreement (Marsden certainty for First 13,600 to 15,600 GJ; variable fee ($/GJ); (daily) $10,141,249 Point) Gas mhq: mdq/24 overrun fee ($/GJ)

Interruptible User Marsden 1 30 Sep 2019 21 Dec 2018 Yes To access mdq: approved NQ; Fixed fee ($/GJ.mdq); Contract (New Zealand capacity above mhq: approved NQ/24 (daily) overrun fee ($/GJ) Refining Company) firm limit

Supplementary Whakatane 30 Sep 2019 28 Sep 2018 Alternative fuel mdq: 3,400 GJ; Fixed fee ($/day); variable Agreement (Whakatane mhq: 176 GJ fee ($/GJ); (daily) overrun Mill) fee ($/GJ)

Supplementary Kauri, 30 Sep 2019 11 Dec 2018 Alternative fuel mdq: seasonal profile, Fixed fee ($/GJ.mdq); Agreement (Kauri & Maungaturoto 2,500 to 5,000 GJ; variable fee ($/GJ); (daily) $4,868,724 Maungaturoto Dairy mhq: mdq/20 with overrun fee ($/GJ) Factories) max. 130 GJ per DP

Supplementary Warkworth 30 Sep 2019 27 Aug 2018 Alternative fuel mdq: 1,500 GJ; Fixed fee ($/GJ.mdq); Agreement (Southern mhq: 73 GJ variable fee ($/GJ); (daily) Paprika) overrun fee ($/GJ)

Total Supplementary Agreement Revenue $24,467,470

3.3 Treatment of existing Supplementary Agreements Some stakeholders have raised concerns with our treatment of existing supplementary agreements. Given that some agreements are point to point and delivery points such as Frankley Rd no longer exist under the GTAC, it has been proposed that existing supplementary agreements have zero value as they are frustrated. In its submission, Greymouth states:

Therefore we query:

- Why the dollar value of a Kupe to Frankley Road Existing Supplementary Agreement wouldn’t be $0 given the switch from point-to-point to zonal receipt point pricing implies that the location of Kupe is irrelevant; (Greymouth, p2). While we understand the issue with this concept, we also have to consider the perspective of the holder of the existing Supplementary Agreement. Under such an agreement, they have a right to lower cost transmission services (relative to prices charged under the MPOC/VTC), which was based on a valid reason for a Supplementary Agreement at the time of entering into that agreement. The holder of that agreement has made business decisions based on the cost of transmission in that agreement and it was reasonable for them to expect that cost of transmission in the agreement would continue until the end of the agreement. We agree that it is tricky to ensure that we are respecting these contracts with the new GTAC transmission products in place. We have therefore sought to modify pricing as follows to allow the existing agreements to work with the new transmission products:

• Add in the variable cost of shipping on the Maui system to the VTC agreements to reflect the additional service being provided under the agreement; or • Take a revenue-based approach to ensure that for specific large customers we are equalising revenue generation between the previous set of contracts (VTC + MPOC + SA) and the new set of contracts (GTAC + SA) However, we consider that these agreements cease at the end of the term of the agreement and end users would need to make a case under section 7.1 of the GTAC for the agreements to be renewed.

3.4 Supplementary agreements policy First Gas is in the process of developing its Supplementary Agreements Policy for the GTAC. A draft is being released for consultation on 31 May 2019 with a workshop to discuss the document on 19 June 2019. Submissions on the document will close on 30 June 2019. MGUG stated the following regarding this document:

One area of concern we have with the current process is that the Supplementary Agreement policy workstream is set down to occur after completion of TPM. Given the contribution supplementary agreements make to target revenue (~25%) we think the finalisation of TPM should also have the benefit of consideration of the SA workstream. We note Clause 7 of GTAC sets out the terms and conditions of the Code that FG may vary, including Clause 7.4 (a) (iv), the transmission fees payable, but does not prescribe the basis for calculating fees. The TPM paper indicates it is FG’s intention to consult on the SA policy in parallel with TPM (page 22) but the timetable still has the SA policy set down for June. FG should consider how it can align more closely these two workstreams. (MGUG, p2) We understand that it may appear that these workstreams cannot occur in isolation. However, this document deals with the decision by First Gas to enter into a Supplementary Agreement rather than the pricing in the agreements themselves, and therefore can be done independently. We felt that this relieved pressure on industry to consult on multiple documents at once. Notwithstanding, we will not conclude discussions on any new Supplementary Agreements prior to consultation on the Supplementary Agreement Policy.

A guide for the scope of the Supplementary Agreements Policy is the existing Supplementary Agreement Policy under the VTC available here: https://www.oatis.co.nz/Ngc.Oatis.UI.Web.Internet/Common/Publications.aspx. For the reasons, given section 3.3 and 3.4 relating to the treatment of existing Supplementary Agreements and renewal of some existing annual supplementary agreements we are happy with the decision not to run these two workstreams in parallel.

4 Extent of Compliance with Commerce Commission Pricing Principles

4.1 Commerce Commission Pricing Principles The Commerce Commission Pricing Principles are as set out below.

(1) Prices are to signal the economic costs of service provision, by

(a) being subsidy free, that is, equal to or greater than incremental costs and less than or equal to standalone costs, except where subsidies arise from compliance with legislation and/or other regulation; (b) having regard, to the extent practicable, to the level of available service capacity; and (c) signalling, to the extent practicable, the effect of additional usage on future investment costs.

(2) Where prices based on ‘efficient’ incremental costs would under-recover allowed revenues, the shortfall is made up by prices being set in a manner that has regard to consumers’ demand responsiveness, to the extent practicable.

(3) Provided that prices satisfy (1) above, prices are responsive to the requirements and circumstances of consumers in order to-

(a) discourage uneconomic bypass; and (b) allow negotiation to better reflect the economic value of services and enable consumers to make price/quality trade-offs or non-standard arrangements for services.

(4) Development of prices is transparent, promotes price stability and certainty for consumers, and changes to prices have regard to the effect on consumers. The Information Disclosure Determination 2012 requires First Gas to:

2.4.3(2) Demonstrate the extent to which the pricing methodology is consistent with the Pricing Principles and explain the reasons for any inconsistency between the pricing methodology and the Pricing Principles; These requirements recognise the tension in the pricing principles between pure cost-reflectiveness and the need to discourage economic bypass and bring other loads into the system. For this reason, the Commerce Commission asks for the extent of compliance, rather than strict compliance with the pricing principles.

4.2 Stand-alone and incremental costs Previously Vector demonstrated the standalone and incremental costs of the network in their TPM, based on work undertaken in 2012 by PriceWaterhouseCoopers (PWC). This work implied transmission pricing caps between $4.20/GJ for large industrial coal users and $39.05/GJ for domestic LPG users. A summary of the PWC study is provided in our GY2018 Transmission Pricing Methodology on page 36. This document can be found here: https://firstgas.co.nz/wp-content/uploads/First-Gas-GTB-pricing-methodology-PY2019.pdf . Given the very high stand-alone costs and inherently low incremental cost of service, we did not seek to demonstrate compliance with this range. Moreover, since we have continued pricing from the VTC we see no reason to question compliance with this principle. However, Greymouth has stated in their submission that this is not sufficient: In particular, in the final GTPM, FG should provide analysis showing that each Delivery Point (including Huntly power station) complies with the incremental / standalone cost component of the Pricing Principles. (Greymouth, p1)

MGUG, in their submission also raised this issue and states that this approach is sufficient for the current year but should be corrected in future years:

FG has opted to follow this historical analysis, in part because it contributes to reducing the risk of significant price change. While we accept that position for the purposes of this TPM, this shouldn’t be accepted as the norm. We would recommend FG regularly undertakes this analysis, and probably as part of the next TPM. It would also enhance transparency around the approach taken to setting pricing. MGUG considers it important that this FG articulates a vision about where it wants to be with regard to pricing methodology in subsequent years. (MGUG, p3). Methanex also agrees with this position:

To what extent is individual pricing subsidy-free?

The draft TPM provides no information. Methanex recognises that the pricing trade-off required to prevent price shocks during the code changeover will have constrained First Gas’ ability to satisfy this principle but First Gas needs to provide sufficient information in the TPM to demonstrate to customers how it will better achieve this principle over time. (Methanex, p2) We agree that further work on understanding the stand-alone costs and incremental costs of the network is appropriate. While we can understand capital and operating costs about our network, we need further input from stakeholders for this work to be successful. We need to understand:

• Which alternative fuels need to be considered to fully understand stand-alone costs? • How do transmission price increases affect the economics of the use of gas? • What is the right balance to strike between incremental and stand-alone cost and should this be a fixed level across the network or individualised dependent on individual users? We therefore propose to engage with stakeholders in early 2020 prior to scoping this study.

4.3 GTAC requirements relating to pricing principles The GTAC provides for compliance with the Commerce Commission pricing principles in section 11.15.

11.5 First Gas will determine standard transmission fees annually using its then current Gas Transmission Pricing Methodology (GTPM), including in compliance with the then current price-quality path set by the Commerce Commission and, as far as practicable, the Commission’s “Pricing Principles”. Greymouth, in its submission states:

To comply with s11.15 of the GTAC, FG will have to demonstrate compliance with the Pricing Principles. (Greymouth, p1) As discussed in section 4.2, there is inherently a wide range between standalone and incremental cost when dealing with transmission assets. Since our revenue has followed on from previous pricing, we have not sought to demonstrate compliance with the standalone cost and incremental cost range and remain confident that pricing is likely to lie within this range meeting the principle in part (1) of the pricing principles. Where our pricing is non-standard, it meets part (3) of this test. There may remain some issues with compliance in our existing Supplementary Agreements. However, as stated in section 3, we need to honour these arrangements to ensure there are no price shocks to existing customers. Our view is that this is the practical limit of compliance with the Commerce Commission Pricing Principles. Hence, our TPM meets the test in section 11.5 of the GTAC.

5 Direction of travel for pricing

Our TPM has focused on achieving price stability for GY20. We have not sought to build a longer-term strategy for pricing, as our focus has been on maintaining price stability in the first year of the GTAC. We have sought to continue price paths to equalise pricing in geographically contiguous areas, such as Hamilton. However, we have not sought to further move prices on from this point. Recent TPMs have had similar scope as the focus was on ensuring a smooth transition to the GTAC transmission products. We acknowledge that a longer-term view is desirable for industry. We see that longer-term view being built together with industry, to ensure that we co-create a pricing environment that meets current and potential future needs of the industry, as well as ensuring increased utilisation of the pipeline.

5.1 Information on direction of travel of pricing Stakeholders raised a number of issues in relation to the lack of information on direction of travel. We acknowledge that this information is not contained in the TPM. Some views from submitters on these points were:

We also believe the TPM document should be forward looking, with discussion on where the TSO aspires to be beyond this initial TPM period, how it would expect pricing methodology to facilitate development of the market for gas, and the proposed steps. We would encourage greater transparency by documenting the cost and revenue allocations by zone when calculating prices. (MGUG, p2)

We would also appreciate FG’s view and statement on whether its proposed pricing for zones is on a transition pathway from the previous separate MPOC and VTC pricing methodologies to a single gas transmission network. The purpose of this is to highlight where FG has views whether certain zones (such as Hamilton) are currently not cost reflective and what the likely adjustment process might look like. (MGUG, p2)

As raised at the recent workshop, it was not clear from the TPM if First Gas intended to retain prices close to this initial structure or undertake a full review of its long-term pricing objectives. Nova understands that First Gas has agreed that such a review is appropriate. (Nova, p1)

There is no information in regard to how prices will evolve over time, or First Gas’ strategy in that regard, such as forecast price trajectories to better satisfy the subsidy-free principle, with segmented asset value/cost data provided to customers as support. (Methanex, p2) While we need to work with stakeholders to determine the finer details of the direction of travel for pricing, we feel that there are some points that can be answered upfront:

• We feel that work on stand-alone costs and incremental costs for the network will provide a robust basis for discussion and build understanding of how costs are allocated across the network and what subsidy-free pricing might look like; • We also feel that work needs to be undertaken on the implications of truly subsidy-free pricing, as this may be at odds with encouraging growth in load on the network and therefore encouraging price stability through diversity of load; • Based on the work on the cost and revenue allocation, we can determine a harmonised pricing model for the network that balances the objectives of subsidy-free pricing and growing and diversifying load; and • In the short term, we remain committed to maintaining the direction of travel for Hamilton (Kirikiriroa Delivery Zone) to meet pricing in adjacent pricing zones and have increased the costs in Hamilton accordingly. This pricing developed under the VTC due to potential bypass of volumes through the Maui system. We are not aware of any other zone pricing anomalies in the system. However, we feel that this work is best done in close consultation with industry as we only have some of the answers. Our customers have better visibility of the needs of their customers, their price sensitivity and how their loads are evolving over time. Moreover, they have better knowledge of potential new customers. We

therefore propose a process to consult on the outcomes of the work proposed in section 4.2 of this document to develop a view on a desirable pricing model. This consultation will occur in early 2020.

5.2 Appropriate rate of change Stakeholders were also concerned that the rate of change in pricing to a new pricing model was not defined.

While that review cannot be completed within the time frame necessary for this year’s TPM, Nova Energy suggests that consumers should be given assurance at this time that DNC prices will not be increased by more than 5%, in real terms, for any Zone from one year to the next should prices be transitioned to a new regional allocation. (Nova, p1).

Section 6.1 of the draft TPM refers to the objective of keeping price changes within 10% of last year’s prices but does not set out what limit (if any) would be applied in setting price changes, up or down, in future years. (Methanex, p2). We agree that this has not been provided. We would anticipate that the rate of change of pricing needs to be understood in the context of the quantum of price change required to move to a new pricing model and the load affected. While 10% may be appropriate for a charge of $0.5/GJ, it may not be appropriate of for a charge closer to $3/GJ. Moreover, it will depend on the price sensitivity of the loads being affected and the decisions being made by the customers (e.g. capital expenditure on new equipment) within the timeframe of the change period. We therefore propose to incorporate the rate of change into the discussion on pricing we intend to have over the next two years..

5.3 Impact of a significant reduction in load Further comments related to the absence of information about the effect of the loss of a major load to the system.

One area where MGUG has concerns relates to how the TPM would respond to a loss of significant demand from the transmission system, particularly in the context of zone pricing. As an example, in 2015 Contact shut Otahuhu power station at relatively short notice. Vector (as TSO) responded by adjusting transmission charges, so as to reallocate any shortfalls to remaining users. As a result, MGUG members on the Vector system incurred very significant increases in cost, in a very short space of time. Furthermore, it was not made clear how the reallocation of those costs occurred. This example raises the question how TPM would operate in the event of something similar occurring again. (MGUG, p3)

Secondly, we recommend First Gas considers what it would do if forecast volumes in future years prove to be inaccurate e.g. if a large user were to decrease or increase gas use compared with what had been forecast, how would how transmission prices be reallocated between zones? It is important to have regard for such considerations now seeing the draft TPM, once finalised, will have a precedent setting effect on future pricing. (Genesis, p1)

If throughput reduces because supply reduces, transmission costs can be expected to increase. There needs to be a process, and a policy, on out-year prices on a rolling basis. (Greymouth, p1) The revenue effect of the loss of a major load varies depending on the location of the load on the system: the loss of a load on the ex-Maui system will have much less revenue impact than the loss of the same size load in Northland. We see two basic choices in this situation:

• Retain revenue collection for the zone affected by increasing prices in that zone; or • Spread the loss over the entire system. If First Gas was required to collect the same revenue from a smaller volume of load in the same zone, this could disproportionately raise prices in that zone and potentially create issues of geographic parity with adjacent regions. For this reason, we would prefer to remove the revenue from the zone and spread the increase over the entire system.

5.4 Proposed way forward We feel that work on developing cost reflective pricing for the transmission system needs time and, most importantly, consultation with stakeholders. We need to understand stakeholder views on the scope of cost reflective pricing, to what extent pricing should be cost reflective and how quickly pricing should move towards this goal. Given the current workload in the industry, we are reluctant to push consultation too quickly as we feel that the quality of consultation (and therefore the resulting work) will suffer. We are also mindful that we intend to apply for a Customised Price Path (CPP) in mid- to late-2021, which will apply from the start of our next regulatory control period on 1 October 2022. We see merit in aligning these two workstreams to ensure that any new, harmonised TPM takes effect from the date of our new price-quality path. We therefore propose that we commence consultation on this issue in early 2020 and develop the work over 2020 and 2021. The GY21 TPM would continue pricing based on revenue stability per zone as per the current TPM. The proposed workplan is set out in the table below.

Table 3: TPM pricing strategy consultation process

Timeframe Detail Early 2020 First Gas internal analysis on network costs for standalone cost versus incremental cost model February 2020 Consultation with stakeholders scoping final cost of service model analysis March to June 2020 Develop GY21 TPM based on current methodology Late 2020 Complete cost of service model development End 2020 Consultation on cost of service model and appropriate rates of change for pricing to inform draft pricing strategy End 2020 Development and approval of pricing strategy Early 2021 Development of GY22 TPM May 2021 Consultation on GY22 TPM June 2021 Refinement of GY22 TPM based on outputs of consultation 30 June 2021 First Gas will notify stakeholders of final TPM and Prices

6 Estimation of overrun and underrun fees

Stakeholders also raised concerns over the scale of estimated overrun/underrun fees collected for individual zones. It is important to note that the estimated overrun/underrun percentages in our model are not able to be based on experience as this year will be the first year under the GTAC. At our workshop stakeholders showed understanding on this topic. Our methodology for calculating DNC Fees depends on the scale of overrun/underrun in a zone or point as the starting point for the DNC fee is as follows:

DNC Fee = DNC Target Revenue / (Throughput Quantity + Overrun Quantity x F + Underrun Quantity x (F-2)) Following on from this calculation we adjust for geographic parity. Contact raises the following issues with the implied accuracy of nominations in the model.

It would be unlikely that a shipper would be able to nominate to a 1% accuracy (low) yet this is how First Gas have categorised Auckland. Even in low/medium at 2% accuracy is highly unlikely yet Kapiti/Wellington with a high mass market, large volume load has been assigned this category.

Where Contact chooses to rely on auto-nominations for its mass market customers it is then exposed to the average overrun/underrun charges for all TOU customers as the applicable fee. This would seem logical if the TOU customers demand was easy to predict. While telemetry provides accurate metered data the next day, the imbalance has already occurred and the overrun/underrun already incurred. If that load is also unpredictable it causes continuous imbalance in nominations and therefore fees.

Contact would like to see some further analysis on the basis of these accuracies before the final prices are set. We believe that the current setting may lead to higher underrun/overrun charges and therefore over recovery of revenue. (Contact, p2) It its confidential submission, Vector raised the issue that the following zones have the same implied level of accuracy as Methanex and Huntly:

• Tāmakimakaurau (Auckland) • Tauranga • Central Plateau • Whanganui-a-tara / Kapiti (Kapiti-Wellington) They also state that the following zones appear to have very low levels of overrun/underrun:

• Central Plateau • Aotea (South Taranaki-Whanganui) • Kahungunu (Hawkes Bay). It is very useful to have these perspectives on the assignment of these percentages. While we agree that it is difficult for individual users to nominate to a high degree of accuracy, the accuracy over a zone may be different. Where there are multiple users in a zone, the diversity effect of this large number of users should average out issues with an individual load. We therefore think that zones, such as Tāmakimakaurau, will have a low forecast inaccuracy due to the high numbers of non-specified shipper connection points in the zone. We also need to consider the impact of the specified shipper (mass market nominations) regime, as this will remove a large part of the highly variable/unforecastable load out of the underrun/overrun pool. This effect can be seen in Table 4 which shows the forecast amount of revenue from mass market load and other load in the TPM model. Hence for zones like Whanganui-a-tara / Kapiti, we agree that there is very little of the load subject to overruns/underruns and potentially this zone could have less benefit of diversity. We therefore think there may be merit in increasing the overrun/underrun percentage in this zone, and therefore could move this zone from ‘Low-Medium’ to ‘Medium’.

For the Central Plateau and Aotea zones, we also consider that the overrun/underrun percentages could be higher based on the data presented by Vector. We will move these zones from ‘Low’ to ‘Low-Medium’ and ‘Medium-High’ to ‘High’ respectively. We also note the comments from Nova who suggested that it was more prudent to have a low estimate of overrun/underrun fees: Nova suggests there is a case perhaps for making a marginally conservative (low) estimate of expected penalty charges, which would result in slightly higher DNC charges in the short term, rather than the converse. (Nova, p1) We are conscious of the interplay between the estimations of overrun/underrun percentage and the DNC revenue. We are therefore reluctant to raise estimated overrun/underruns from the ranges stated in the TPM. We consider it prudent to maintain a lower forecast of accuracies to ensure recovery of revenue. A complete review of all overrun/underrun category assignments was undertaken, and the results are shown in Table 4.

Table 4: Forecast incentive fee revenue from specified shippers and other shippers

Overrun/ Underrun Reason for Change Delivery Zone or Individual Delivery Point Category Initial Final Te Tai Tokerau (Northland) M M Tāmakimakaurau (Auckland) L L Waikato ki te Raki (Waikato North) MH MH Kirikiriroa (Hamilton) H H Te Rohe Pōtae-Taupiri (King Country-Taupiri) H H Waikato ki te Tonga (Waikato South) MH LM Change to conform with other zones. Tauranga L L Increase in category to reflect information L LM Central Plateau from Vector Whakatane MH MH Te Tai Rawhiti (Eastland) M M Reduction in category to reflect large LM L Taranaki ki Uta (Inland Taranaki) TOU loads in zone Taranaki ki Tai (Coastal Taranaki) MH MH Increase in category to reflect information MH H Aotea (South Taranaki-Whanganui) form Vector Tararua (Manawatu-Horowhenua) MH MH Kahungunu (Hawkes Bay) LM LM Increase in category to reflect information LM M Whanganui- a- tara / Kapiti (Kapiti-Wellington) from Vector. Bertrand Road (Waitara Valley) L L Faull Road L L Huntly Power Station L L Ngatimaru Rd (Delivery) L L Mangorei Delivery Point - L New TOU load.

7 Other issues raised

7.1 Delivery zone naming and codes An issue raised in the workshop was the need for codes for the delivery zones to make these easier to remember. We had initially thought three letter codes were requested, but it appears that stakeholders would prefer four letter codes. Nova, in its submission suggested some codes that could be used. We have also had feedback from the GIC on the potential codes and the need to ensure that these are different from the gas gate codes. In creating the names for zones, we were conscious of the opportunity to name the network in Te Reo. We would therefore prefer to maintain the Te Reo names as the primary reference for the delivery zones where possible. However, we understand that this needs to be balanced with creating codes that are recognisable. We also note the GIC’s concerns over confusion with existing gas gate codes. We have accepted the proposed codes from Nova which are shown in Table 5.

Table 5: Proposed four letter codes for delivery points and zones

Delivery Zone/Individual Delivery Point Translation (if applicable) Proposed Name Code Te Tai Tokerau Northland NTHL Tāmakimakaurau Auckland AUCK Waikato ki te Raki Waikato North WKTN Kirikiriroa Hamilton HMTN Te Rohe Pōtae-Taupiri King Country-Taupiri KING Waikato ki te Tonga Waikato South WKTS Tauranga TNGA Central Plateau TAPO Whakatane WHAK Te Tai Rawhiti Eastland EAST Taranaki ki Uta Inland Taranaki TKIE Taranaki ki Tai Coastal Taranaki TKIW Aotea South Taranaki-Whanganui ATEA Tararua Manawatu-Horowhenua TRUA Kahungunu Hawke’s Bay HWKB Whanganui-a-tara/Kapiti Kapiti-Wellington WGTN Bertrand Rd (Waitara Valley) BERD Faull Road FAUD Huntly Power Station HUPS Ngatimaru Rd (Delivery) NGRD Mangorei MAND

We have also had queries on the naming conventions for other points in the network. We would like to reassure stakeholders that the codes and names for each receipt point and delivery point will not change. The only names created in this exercise were the names for delivery zones and points under standard pricing.

7.2 Huntly power station pricing in relation to nearby pricing Some stakeholders queried the differential between the Huntly Power Station pricing in relation to other nearby pricing.

Fee for Huntly – Slide 32 of the presentation made at the workshop has Huntly DNC at $0.57/GJ, which seems at odds with zone pricing for others in that zone. (MGUG, p1)

Genesis ships to Huntly power station which has a draft DNC fee of $0.57/GJ. Huntly power station is geographically located in the Te Rohe Pōtae-Taupiri Delivery Zone which has a draft DNC fee of $1.90/GJ. First Gas is proposing that all Shippers (and consumers) in Huntly town and its zone pay 233% more than Genesis at Huntly power station. (Greymouth, p1) We note that this pricing needs to be viewed in the context of the power station’s connection to the Maui pipeline and therefore, the fee being set in relation to revenue generated under the MPOC. It is important to note that the value of assets used to transport gas to Huntly is lower per GJ than on other parts of the network that use assets off the Maui pipeline which is a contributing factor to the lower cost. This due to the large volume of gas being transported through the Maui pipeline assets in relation to other pipelines. In the interests of the principle of no price shocks, the MPOC pricing has continued to ensure we are maintaining the same amount of revenue collection from Huntly.

7.3 Huntly power station volumes Genesis also raised an issue with the forecast for consumption at Huntly Power Station.

First, the gas usage volume that has been assumed for Genesis’ Huntly Power Station is too low at 22 petajoules (PJ). In our view, 25 PJ is more accurate and consistent with the past three-year average; also noting our intention to transition away from coal-fired generation in the next decade. Further, while electricity demand growth is occurring, material new renewable generation is not expected to be commissioned in the next 12 to 24 months. This means that thermal generation will be required to fill the gap in the short to medium term at least. (Genesis, p1) While we understand that our consultant did request data from Genesis at the time of preparing their analysis, it appears there was some miscommunication on the point. We equally questioned the volume and are therefore happy to have the volume confirmed at 25 PJ. Given that Genesis has stated it wishes to reduce coal usage at Huntly and its backing of Huntly gas consumption with equity volumes in the Kupe field, we are comfortable to increase this estimate.

7.4 Bertrand Rd and Faull Rd Tariffs Methanex also raised an issue with having separate pricing for their Bertrand Road and Faull road delivery points.

The two Individual Delivery Points at Bertrand Road (Waitara Valley) and Faull Road are at the same physical location with respect to the First Gas Pipeline, that is, at the Bertrand Road Offtake Station. Consequently, there is no logical reason for Bertrand Road and Faull Road Delivery Points not to have the same tariff. (Methanex, p3).

Consequently, Methanex proposes a pragmatic solution: (i) Sum the revenues and gas volumes for Bertrand Road and Faull Road as set out in draft TPM. (ii) Divide the combined revenue by the combined volume to determine the DNC Fee to apply at both Delivery Points. (p4). We feel that this is a pragmatic suggestion and are happy to combine the two prices. However, we note that the eventual single pricing may differ slightly in the final TPM from that calculated by Methanex due to other changes in the TPM as a result of this consultation.

7.5 Improvements in TPM information We received comments from MGUG relating to improvements in the presentation of information on the allocation of delivery points to delivery zones.

Allocation of Delivery Points to Delivery Zones – Table 5 could be made more transparent by including all parties in the delivery points, including those holding supplementary agreements. (MGUG, p3) We agree that this would be an improvement. We plan to amend the table accordingly to include information about which zones delivery points subject to Supplementary Agreements would lie in, if they were on standard pricing. Methanex requested further information on the break-down of pass-through and recoverable costs and the allocation of these costs across the network to be included in the TPM.

Methanex believes that First Gas has more information available that it has not included in the draft TPM. One obvious example of this being that the breakdown of Forecast Allowable Revenue in the slide pack provided at the recent stakeholder workshop contained additional information breaking down the elements of pass-through and recoverable costs not included in the draft TPM.

The same concern regarding insufficient detail on the allocation of Forecast net Allowable Revenue applies to the methods of allocating Pass-through and Recoverable Costs, and how this may need to change over time to ensure it is, as far as practicable, subsidy free. Section 4.5 is limited to a brief description of how the total cost of the particular component is determined; it contains no information on how it is apportioned to individual prices, such as:

• How is the $5.8m forecast of pass-through and recoverable costs apportioned in individual prices? Is it proportional to the volume of gas supplied, proportional to prior revenues, or allocated using some other methodology? • How is the Mokau Compressor fuel gas cost allocated? Is it allocated to those customers who directly benefit from use of the Mokau Compressor, or by some other means? (Methanex, p3) We did not include detail on how the pass-through and recoverable costs were calculated as this has not been included in previous TPMs. It is available in Schedule 3 of our Annual Information Disclosures here: https://firstgas.co.nz/wp-content/uploads/Final-GTB-information-disclosure-2018.pdf. We will provide more detail on the forecast costs in the TPM. On the apportionment of pass-through and recoverable costs to individual prices, these costs are added to the forecast net allowable revenue to create the forecast allowable revenue. This treatment is undertaken as set out in the Commerce Commission’s Input Methodologies. There is therefore no specific treatment of the pass-through and recoverable costs, and they are apportioned across all volumes in line with other revenue.

7.6 Soft launch of GTAC Separately to the TPM consultation, Shippers raised concerns relating to their ability to adapt to the new regime. Shippers were concerned that they would not be able to develop their internal IT systems in time for the launch of the GTAC. Moreover, that additional resources would be required to manage exposure to incentive fees if they were not able to develop their systems in time.

We agree that this is a material concern. Incentive fees are intended to ensure that we get accurate information in order to operate the system (in the case of overrun/underrun and peaking charges) and that parties balance their injections and deliveries of gas (in the case of excess running mismatch (ERM) charges). We do not see these fees as a primary means of gathering revenue. In order to assist Shippers in this matter we have agreed to a “soft launch” of the GTAC where incentive fees and ERM charges are not charged until 2 February 2020. During this period, we will adjust fee settings as follows:

• The overrun/underrun factor ‘F’ will be set to 1; • The peaking factor ‘M’ will be set to 1; and • The ERM fees will be set to $0 /GJ. The overrun/underrun and peaking fee settings will ensure that shippers pay for all units of capacity used on a day, but there is no additional incentive fee if there are any deviations from the nomination. In terms of balancing, while we will not charge ERM fees, we will pass through balancing gas purchased or sold, which will ensure that balancing of the pipeline is maintained. In order to maintain revenue generation, we will need to adjust the TPM for this first period of the year as follows:

• The ERM revenue estimate will be reduced to account for zero revenue up until 2 February 2020; and • The overrun/underrun factor ‘F’ will be set to 1 to reflect that we will collect fees for all DNC booked but no incentive fees will be charged. We think it is important to make this adjustment to ensure that our allowable revenue is collected in GY 2020. While incentive fee revenue is only 3% of our revenue from standard prices, if we under collected revenue in GY2020, we would wash this up in GY 2022. We would like to avoid factors that contribute to instability of pricing.

8 Consequential amendments to the TPM following consultation

As a result of these submissions we have made the changes in Table 6 to the TPM.

Table 6: Consequential changes to the TPM following consultation Area Change

Estimates of underrun and Reviewed the overrun and underrun percentage estimates for each delivery zone. overrun percentages

Delivery zone and individual Added four letter codes for the identification of delivery zones as per the names in delivery point naming Table 5.

Huntly Power Station volumes Increased the forecast of Huntly Power Station volumes to 25,000,000 GJ.

Bertrand Road and Faull Road Single, homogenised price across the Bertrand Rd and Faull Rd individual delivery Pricing points.

Delivery zone table Add in delivery points subject to supplementary agreements to Table 5 of the TPM to show which zone they would be in if they were subject to standard pricing.

Calculation of pass-through More detail on the calculation of the pass-through and recover costs in an additional and recovery costs appendix to the TPM.

Pricing Strategy Insert information on the proposed consultation process to develop the pricing strategy as outlined in section 5.4 of this document.

9 Correction of errors

In undertaking the revisions of the Draft TPM we also identified errors in the Draft TPM that have been addressed. These are outlined in Table 7 below along with a subsequent amendment brought to our attention following consultation.

Table 7: Corrections to the in Draft TPM Area Change

Treatment of Excess Running Excess Running Mismatch charges were added to recoverable costs in the Draft TPM Mismatch (ERM) charges when they should have been deducted from these costs.

Mangorei delivery point The new Mangorei delivery point on the 400 line for the Junction Rd peaking power station that will commence operation during 2020 was added as an individual delivery point.

Ngatimaru Rd Delivery Following the issue of the TPM Methanex engaged with First Gas on the potential potential bypass bypass opportunity at the Ngatimaru Road delivery point. We are in discussions with them to avoid this bypass.