PC4: REVIEW OF DISTRIBUTION REVENUES COMMISSION FOR ENERGY REGULATION (CER) FINAL REPORT JUNE 2017 TECHNICAL AND ECONOMIC REVIEW

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1 PC4: REVIEW OF DISTRIBUTION REVENUES COMMISSION FOR ENERGY REGULATION (CER) JUNE 2017 TECHNICAL AND ECONOMIC REVIEW FINAL REPORT Prepared by: Cambridge Economic Policy Associates Ltd In association with: Rune Associates & Wavestone

2 IMPORTANT NOTICE This report was prepared by Cambridge Economic Policy Associates (CEPA) in association with Rune Associates and Wavestone for the exclusive use of the client(s) named herein. Information furnished by others, upon which all or portions of this report are based, is believed to be reliable but has not been independently verified, unless expressly indicated. Public information, industry, and statistical data are from sources we deem to be reliable; however, we make no representation as to the accuracy or completeness of such information, unless expressly indicated. The findings enclosed in this report may contain predictions based on current data and historical trends. Any such predictions are subject to inherent risks and uncertainties. The opinions expressed in this report are valid only for the purpose stated herein and as of the date of this report. No obligation is assumed to revise this report to reflect changes, events or conditions, which occur subsequent to the date hereof. CEPA Ltd does not accept or assume any responsibility in respect of the report to any readers of the report (Third Parties), other than the client(s). To the fullest extent permitted by law, CEPA Ltd will accept no liability in respect of the report to any Third Parties. Should any Third Parties choose to rely on the report, then they do so at their own risk. CEPA Ltd reserves all rights in the report.

3 EXECUTIVE SUMMARY Scope of work CEPA is leading a consortium with Rune Associates and Wavestone that is advising the Commission for Energy Regulatory (CER) on economic and technical issues related to the setting of allowed revenues for Gas Networks Ireland s (GNI) Transmission System Operator (TSO) and Distribution System Operator (DSO) businesses during the forthcoming PC4 price control period (October 2017 to September 2022). This paper considers components of the allowed revenues for the DSO gas network in Ireland. It includes both the consortium s assessment of GNI s outturn (historic) capital expenditure (capex) and operating expenditure (opex), and proposed allowances for capex and opex in PC4. The analysis in this paper is informed by submission of a Business Plan Questionnaire (BPQ) response from GNI and a subsequent question and answer process. Context for the PC4 price control GNI states that more than 40 per cent of its network is now more than 20 years old. This presents a maintenance and capital investment challenge during the upcoming control period to ensure the long-term reliability and security of gas supply. Due to the ageing asset base and GNI s projected increase in customer numbers, the required PC4 work programme is potentially larger and more challenging than the programme delivered in PC3. GNI has prepared a resource strategy which it believes will enable the delivery of its PC4 plan/outputs, but the strategy requires recruiting additional staff in critical technical and engineering roles. GNI has also developed a growth and innovation strategy for PC4 to help increase the future utilisation of the gas network and support the role of gas in addressing the wider strategic challenges facing the energy sector in Ireland and to secure supplies of competitive and affordable energy to Irish citizens and businesses. This growth strategy includes targeting a significant increase in new connections during PC4 and new forms of growth, including renewable gas and Compressed Natural Gas (CNG) for transport. One of the other challenges that GNI has stated it faces during PC4 is responding to changing gas flows on the transmission and distribution. Gas supply flows changed significantly in the latter period of PC3, with flows from the Corrib gas field commencing in 2015/16. Corrib will displace Moffat as the dominant gas supply point to Ireland in 2016/17. GNI state the new entry point creates a number of operational challenges for its gas network business. These strategic challenges have been reflected in the company s opex and capex proposals for the PC4 period. i

4 Opex We have undertaken a bottom-up and top-down assessment of GNI s proposed opex for the PC4 control. A summary of GNI s controllable distribution opex over PC3 and the consortium s recommended opex for PC4 relative to GNI s request is shown below. Figure 1: Total controllable opex over PC3 and PC4 Source: GNI/Consortium Our recommendations reflect a step-up relative to the PC3 average opex and the final year of reported outturn data, 2015/16. This reflects funding required by GNI to address the strategic challenges it has set out for the PC4 price control. However, we have also recommended a number of reductions in allowed opex compared to the allowances requested in GNI s PC4 business plan, including adjustments where we consider there is scope for GNI to improve its efficiency during PC4. A summary of the differences between the consortium recommendations and GNI s BPQ request for each of the key areas of our opex assessment is shown below. The illustrated percentages show the implied percentage reduction of the consortium s proposal relative to GNI s request for each individual area of distribution opex. ii

5 Opex ( '000s, 15/16 prices) Figure 2: Summary of PC4 opex recommendation relative to GNI request 480, ,000 8% 460, ,000 5% 6% 38% 440, % 430,000 9% 420,000 GNI request Operations BSS IT Innovation Efficiency Pass-through Consortium Source: Consortium analysis, GNI Note 1: Labels indicate the size of the reduction relative to the original GNI request in that area Note 2: Business Support Services (BSS) The largest absolute difference between our recommendations and GNI s BPQ request is in Operations Opex where an 8% reduction has been proposed relative to the GNI request. The largest proportionate change relative to GNI s BPQ is for efficiency, where we have applied top-down adjustments, consisting of both an ongoing net efficiency adjustment and a catchup efficiency adjustment based on econometric benchmarking for distribution. 1 An overall summary of our PC4 recommendations compared to GNI s request is provided in the tables below. The first table includes all opex (i.e. controllable (direct) expenditure and pass-through items) while the second table includes controllable expenditure only. Table 1: PC4 recommended distribution opex; all ( 000s) 2 Category 2017/ / / / /22 Total Recommended 86,045 86,163 85,593 84,813 83, ,330 GNI request 93,979 94,472 95,104 95,007 94, ,479 Variance -7,934-8,309-9,511-10,194-11,201-47,149 Variance (%) -8.4% -8.8% -10.0% -10.7% -11.8% -10.0% Source: GNI, Consortium Note: includes innovation and pass-through cost items 1 Note the change in efficiency (consortium vs. GNI) is greater than 100% as the consortium s adopted top-down efficiency factor is 1.75% rather than 0.5% as applied by GNI in its BPQ, albeit the consortium 1.75% is applied on a lower starting opex base in light of the conclusions of the bottom-up cost assessment. 2 All figures in this report are in 2015/16 prices unless otherwise stated. iii

6 Table 2: PC4 recommended distribution opex; direct only ( 000s) Category 2017/ / / / /22 Total Recommended 68,788 68,679 68,224 67,503 66, ,938 GNI request 75,218 75,944 77,211 77,695 78, ,556 Variance -6,430-7,265-8,987-10,191-11,745-44,619 Variance (%) -8.5% -9.6% -11.6% -13.1% -15.0% -11.6% Source: GNI, Consortium Note: excludes innovation and pass-through cost items Capex For capex, the consortium has undertaken a review of PC3 capex, including a review of the final year of PC2, 2011/12, as this was not known at the time of the PC3 determination. The consortium has also completed a forward looking assessment of efficient costs for PC4. PC3 and 2011/12 capex close-out We reviewed the expenditure GNI has incurred during PC3 and the final year of PC2. Based on the capex guidelines and incentives set out by CER in its final PC3 determination, we developed proposals for how variations in outturn expenditure compared to PC3 allowances should be treated from an allowed revenue perspective. This has included recommendations to credit GNI where efficiencies had been realised compared to the capex allowances set by the CER at the PC3 review and recommendations for expenditure that has not been incurred by GNI and should be clawed back through an allowed revenue adjustment at the start of the PC4 control. PC4 capex We have undertaken a bottom-up assessment of GNI s proposed capex plans for the PC4 period. This included a review of the expected drivers of capex in PC4 and the technical needs case presented by GNI for proposed capex projects and programmes. Our capex recommendations for PC4, gross and net of customer contributions, are summarised in Table 3 and 4 below. Table 3: PC4 recommended distribution capex; gross ( 000s) Category 2017/ / / / /22 Total Recommended 73,620 68,915 73,012 74,422 73, ,982 GNI request 107, , , , , ,102 Variance -33,674-43,719-45,757-50,327-47, ,120 Variance (%) -31.4% -38.8% -38.5% -40.3% -39.5% -37.9% Source: GNI, Consortium iv

7 Table 4: PC4 recommended distribution capex; net ( 000s) Category 2017/ / / / /22 Total Recommended 66,857 62,497 66,579 68,013 66, ,530 GNI request 96, , , , , ,722 Variance -29,768-38,556-41,058-45,728-43, ,192 Variance (%) -30.8% -38.2% -38.1% -40.2% -39.3% -37.5% Source: GNI, Consortium As both tables show, we have recommended a number of reductions to the capex programme GNI submitted in its BPQ. While this represents a significant decrease relative to the GNI request, the PC4 recommendation for net capex is 2% higher than the PC3 outturn. 3 A summary of the differences between the consortium recommendations and GNI s request for the key areas of our capex assessment is shown in the figure below. Again, the illustrated percentages show the implied percentage reduction of the consortium s proposal relative to GNI s request for each individual area of distribution capex. Figure 3: Summary of PC4 gross capex recommendation relative to GNI request Source: Consortium analysis, GNI Note: Labels indicate the size of the reduction relative to the original GNI request in that area. 3 Gross capex is 4% higher. v

8 The largest absolute proposed reduction to GNI s capex plans is for pipe capex relating to development and growth initiatives, where there is a proposed 44% reduction relative to the GNI request. For other pipe capex, no funding has been allowed for CNG and we have also proposed a decrease in allowed refurbishment spend. A large part of the difference between the consortium s recommendations and GNI s request also relates to a decrease in the outputs assumed to be completed during PC4, albeit with the potential for further funding to be approved by the CER over the course of the price control. Incentives At the request of the CER, we have also considered potential proposals for the incentive framework that would apply during the PC4 price control. This includes incentives related to controllable opex, pass-through opex (e.g. rates, shrinkage), capex and the volumes of new connections the business delivers in PC4. Our key proposals are that CER should: continue with an allowed revenue cap for controllable opex during the forthcoming 5- year price control; adopt some minor amendments to the treatment of pass-through opex items (e.g. expenditure variation sharing factor applied to business rates); and retain a rolling capex incentive mechanism in PC4, supported by guidelines on expected treatment of capex variations vs. PC4 allowances. GNI s PC4 BPQ includes a number of programmes and initiatives which it has stated are a strategic priority for the company and the Irish gas customer. As stated above, these are intended, amongst other objectives, to ensure GNI can: (i) manage an ageing asset base; (ii) promote growth in utilisation of the network; (iii) promote sustainability and innovation; and (iv) continue to deliver a safe and secure network. Given that incremental allowed opex and capex is proposed in PC4 (relative to PC3) to support these initiatives, the gas customer might reasonably expect GNI to deliver on its commitments and be able to demonstrate (by the end of the price control period) that it has made efficient use of the incremental funding allowed by the CER. We have, therefore, also made a number of proposals for how the CER might look to increase the transparency around GNI s delivery of its planned work programmes and strategic initiatives in PC4 compared to its current PC4 BPQ submission. The expectation is not that GNI s allowed revenues would be specifically tied to the delivery of a set of outputs or performance measures 4 in PC4, but instead to: increase transparency (relative to the processes followed in previous price controls) of GNI s record of delivery of the items which have been outlined in its price control 4 As for example Ofgem has adopted under its RIIO regulatory framework for energy networks in Great Britain. vi

9 plans and its use of the allowed incremental expenditure in PC4 to improve network performance; and potentially support the future development of a more outputs/performance based price control/regulatory framework at the PC5 review, should the CER consider this to be appropriate. The main exception to this is that at the request of the CER we have considered options for a financial performance incentive around GNI s delivery of new connections in PC4. The objective of this incentive is to apply a bonus (or penalty) to GNI s allowed revenues should GNI exceed (or fail to achieve) the price control new connection targets which have informed the consortium s opex and capex recommendations. We have set out options and parameters for how this incentive could be implemented at PC4 for further consultation in the next stage of the price review process. vii

10 CONTENTS 1. INTRODUCTION Scope of work GNI objectives, challenges and business context Our approach Understanding how our analysis fits together Report structure CONTEXT TO PC Maintaining utilisation of the gas network Supporting energy policy by building on the innovation funding in PC Responding to changing gas flows Managing an ageing asset base Resourcing for higher volumes of smaller projects REVIEW OF PC3 OPEX Overview Methodology Historical cost trends at a total controllable level Operations opex Business support opex IT opex Gaslink opex Pass-through costs Innovation Summary BENCHMARKING Approach Unit cost benchmarking results Econometric benchmarking results Summary REVIEW OF PC4 OPEX Overview Methodology Group and Shared Service expenditure... 37

11 5.4. Operations opex Business support opex IT opex Adjustments to bottom-up analysis Innovation Pass-through costs REVIEW OF PC3 AND 2011/12 CAPEX Overview Pipe capex IT capex Other non-pipe capex Contributions REVIEW OF PC4 CAPEX Overview Methodology Pipe capex IT capex Other non-pipe capex Contributions INCENTIVES Introduction Opex incentives Capex incentives Output and delivery incentives ANNEX A BENCHMARKING DATA AND ADJUSTMENTS

12 1. INTRODUCTION 1.1. Scope of work CEPA is leading a consortium with Rune Associates and Wavestone that is advising the Commission for Energy Regulatory (CER) on economic and technical issues related to the setting of allowed revenues for Gas Networks Ireland s (GNI) Transmission System Operator (TSO) and Distribution System Operator (DSO) businesses during the forthcoming PC4 price control period (October 2017 to September 2022). This paper considers components of the allowed revenues for the DSO gas network in Ireland. It includes the consortium s assessment of GNI s outturn (historic) capital expenditure (capex) and operating expenditure (opex) and proposed allowances for capex and opex in PC4. We have also been asked by the CER to consider certain regulatory framework design issues, including the design and use of incentives in GNI s price controls. The analysis in this paper is based upon submission of a Business Plan Questionnaire (BPQ) response from GNI and a subsequent question and answer process GNI objectives, challenges and business context To provide context to our analysis, we note the objectives GNI faced for PC3, the key challenges identified by GNI for PC4 and the associated objectives which GNI have stated as driving the focus of its price control business plan PC3 objectives There were seven key commitments identified at the time of the PC3 DSO determination 5, which GNI have stated that they have met: Promoting competitiveness have competitive operating costs and drive efficiencies for the benefits of customers. Maintaining a strong focus on customers provide a high quality service to new and existing customers. Delivering a safe and secure network provide a quality emergency response service and promote safety, in addition to ensuring security of supply. Promoting innovation and sustainability expand the role of natural gas in transportation and to develop the renewable gas sector. Delivery the European Third Energy Package implement European Network Codes for Irish shippers and customers. 5 CER (2012) Decision on October 2012 to September 2017 distribution revenues, CER12/194 1

13 Managing the financial crisis and financing activities efficiently maintain an investment grade credit rating and access debt markets efficiently. Embedding its new organisational structure manage the transition into the Ervia Group model and develop the Asset Management System (AMS) PC4 Key Challenges Looking forward into PC4, GNI have noted three key challenges: Ensuring that gas fulfils its critical role in supporting energy policy help guide transition to a low carbon energy system that provides secure supplies of competitive and affordable energy to Irish citizens and businesses. Managing an ageing asset base a number of assets that make up the gas transmission and distribution are reaching the end of their technical design lives and this requires refurbishment or replacement. Ensuring competitive tariffs for customers and into the future continue to maintain competitiveness of gas with other European countries and alternative fuels. Maximising utilisation of the network is one component of this. These business challenges are expanded on in Section PC4 objectives In PC4, GNI have identified five criteria that they must fulfil: operate to the highest safety standard; ensure reliability and security of supply; ensure competitive tariffs; support Ireland s least cost transformation to a low carbon economy; and respond to changing customer service demands. Our review of historic and future expenditure is made in light of the objectives and business challenges GNI has stated it faces over the PC4 period GNI corporate structure When reviewing the efficient expenditure GNI requires to deliver gas transmission and distribution services, and the setting of allowances in the revenue cap to account for this going forward 6, it is important to understand the organisational structure of Ervia; the owner / ultimate controller of GNI and its associated gas network businesses. 6 Our approach to cost assessment is set out below. 2

14 GNI s business has undergone significant restructuring during PC3, with the gas networks business integrated into the Ervia Group, along with Irish Water (IW). How many key business support functions (e.g. IT, HR and Finance) have in practice been provided during PC3 is very different from what was envisaged at the time of the final PC3 determination, where the adoption of the Independent Transmission Owner (ITO) structure was envisaged. Text Box 1 Independent Transmission Owner (ITO) structure At the time of the PC3 final determination, the gas network operator was part of Bord Gáis Éireann Group (BGÉ) and operated alongside an energy supply business Bord Gáis Energy. Significant change had occurred in the gas networks businesses in the previous price control period PC2. This included the implementation of an asset management transformation programme (Networks Transformation Programme (NTP) and the High Performance Utility Model (HPUM)) and the changes required by the European Third Energy Package (including the unbundling of energy production and supply from transmission networks). The unbundling option chosen by BGÉ was to establish Bord Gáis Networks (BGN) as an ITO. The expectation was that the adoption of an ITO business structure would increase GNI expenditure as it significantly reduced the extent of group shared service activities by creating standalone support activities within the ITO. Source: CEPA GNI now delivers many of its indirect activities through a combination of specific gas distribution and transmission network resources and group services as the business is part of the Ervia Group. This means that there are significant costs allocated to GNI from the Shared Services Centre and the Ervia Group Centre. The organisational structure of the Ervia Group is illustrated in Figure 1.1 below. Figure 1.1: Ervia Organisation Structure Source: GNI GNI and IW are supported by the Shared Services Centre, Major Projects Division and Group Centre. The Ervia Group Centre led the significant restructuring of the Ervia organisation during PC3. The Major Projects division was established in 2014 to manage the development and delivery of the key strategic infrastructure projects on behalf of GNI and IW including the twinning of the Scottish onshore gas transmission system. The Shared Services Centre 3

15 provides transactional services to Ervia business units, including finance, procurement, facilities, Human Resources (HR) and Information Technology (IT). The Shared Service Centre, in particular, was established to help manage shared functions within IW and GNI and has the key objectives to to deliver cost-effective, efficient and high quality transactional support services to the business units (BUs) of Ervia, enabling each unit to focus on core operations activity and strategy delivery Our approach The consortium has taken a bottom-up and top-down approach to establish our view of the efficient cost path for GNI s distribution business Bottom-up assessment For our bottom-up opex assessment, the objective has been to develop a base year or stable run rate of normalised opex that represents the core historic business as usual opex and which can then be revised to reflect additional items of core opex forecast to be incurred in future years during PC4. Normalised costs or historic run rates have been derived from a bottom-up analysis of actual opex costs by functions, adjusted for one-off costs and an understanding of material activities and their drivers over the previous price control period. Informed by GNI s BPQ response we then considered whether there is supporting justification for setting opex allowances above or below the historical run rate / normalised cost level. To determine on required capex in PC4, first we reviewed the capex plans submitted by GNI as part of its BPQ response. This included a review of the expected drivers of capex in PC4 and the technical needs case presented by GNI for proposed capex projects and programmes. Based on our assessment, a series of bottom-up adjustments were made to GNI s capex plans. We also reviewed the expenditure GNI has incurred during PC3 and the final year of PC2. Based on the capex guidelines and incentives set out by CER in its final PC3 determination, we developed proposals for how variations in outturn expenditure relative to the allowances set by the CER time of the PC3 review, should be treated from an allowed revenue perspective. This potentially included recommendations to credit GNI where efficiencies had been realised compared to the capex allowances set at the PC3 review Top-down assessment There have been two components of our top-down cost assessment. First, we benchmarked GNI to comparable utility businesses and how its expenditure compared to an efficiency benchmark for the sector. Second, we considered the degree of ongoing efficiency improvement or frontier shift that might be possible from GNI given that 7 GNI (2016): PC4 Distribution Review of Historical Operational Expenditure, p. 95 4

16 even the most efficient gas network company operating during the PC4 period might be expected to realise productivity gains during the course of the price control. We then combined this analysis to establish potential efficiency targets that might be applied to GNI s business during PC4. Figure 1.2 summarises our approach. While the diagram focuses on opex, our assessment of capex can be considered part of the bottom-up review of GNI s PC4 strategy plan and the projection of baseline allowable costs for the price control period. Figure 1.2: Setting an efficient cost path Assessment of base year allowable costs Projection of changes in base year allowable costs to end of price control period due to volume/mix effects and existing management initiatives Projection of baseline allowable costs for price control period Determination of efficiencies achievable over price control period Projection of an efficient cost path Top-down evaluation of evidence from other operators / industries / time periods Bottom-up detailed review of strategy plans Econometric benchmarking of best practice within the sector Source: Consortium 1.4. Understanding how our analysis fits together Opex For opex, GNI present its costs by functional area (column) and expense category (row). When looking at opex costs and breaking this down in a suitable fashion, there are two issues to overcome: IT is both an expense row and a functional area; and Group & Shared Service costs are apportioned across the functional areas. It is difficult to assess IT in this format, so we have combined the IT functional area costs, together with those IT expenses allocated to other functional areas. IT is, therefore, excluded from our analysis of other functional areas GNI report against. For Group & Shared Services costs, the efficient level of cost has been assessed separately. We have then added back an estimate of this expense within each of the functional areas to aid comparability with other data points. 5

17 These direct opex costs are split into four different categories: Operations Opex which consists of Asset Management, Asset Operations, Commercial, HSQE and Technical Competency functional areas. Business Support Services which consist of Head of Networks, Regulation & Corporate Services, Finance, HR and Facilities functional areas. Group & Shared which includes Group & Shared expense (including allocations from the Group Centre, Shared Service Centre and Major Projects unit). IT which includes IT functional area + IT expenses across other functional areas of the gas networks business. Figure 1.3 below maps our approach to cost assessment to the GNI cost reporting framework that GNI adopted in its BPQ response. Figure 1.3: Mapping our approach to cost assessment to GNI cost reporting framework Asset Asset Management Operations Commercial HSQE People Network Maintenance Insurance Group/ Shared Services IT Establishment Other Technical Competency Head of Networks Reg & Corp Finance HR Facilities IT Source: Consortium We have also made two other adjustments to how the data is presented: 1. We have removed innovation from the individual opex lines when setting an allowance. This had been contained within the 'Commercial' functional area within the GNI business plan submission. 2. In the GNI submission, there was a 0.5% ongoing efficiency assumption applied to total opex. This was contained within the Head of Networks category. We have also stripped this out, such that we can see this adjustment as a separate line item. Pass-through costs are added back to the direct opex total in order to give total opex. Capex Operations Business Support Group & Shared IT Our analysis of capex is split into three categories: Pipe capex - this is the majority of expenditure and deals with pipelines, compressors, AGIs, block valves and minor works. This also includes Grid Control for transmission. 6

18 IT capex - this considers any capital investment for IT (at a total business level i.e. including GNI internal and Group/Shared initiatives). Non-pipe capex - this covers the remainder of capex, including investment in the vehicle fleet, equipment and facilities. We consider net capex, i.e. net of customer contributions Report structure The rest of this report is structured as follows: Section 2 contains context for the PC4 price control decision; Section 3 includes the consortium s review of opex for PC3; Section 4 presents the results of the benchmarking; Section 5 sets out our recommendations for opex allowances for PC4; Section 6 contains our review of capex for PC3; Section 7 details our recommendations for PC4 capex; and Section 8 sets out proposals for incentives in PC4. Annex A contains further information on our top-down benchmarking of the distribution sector. 7

19 2. CONTEXT TO PC4 This section summarises the context for PC4 and explains the main differences in terms of business challenges and need between PC3 and PC4. GNI claim that PC4 will not be a simple continuation of PC3 and that the nature of its business activities and the environment in which it operates will change significantly during the forthcoming price control period. In particular, in GNI s opinion PC4 will be defined by: Maintaining utilisation of the gas network. Longer term independent modelling suggests that gas demand could reduce by 40% - 60% or more by 2050 due to climate change policies, EU directives, and technological developments in areas such as energy storage, increased renewables, greater electrification and energy efficiency dynamics. If GNI is able to increase utilisation of its network without increasing costs, this will help keep tariffs competitive. Supporting energy policy by building on the innovation funding in PC3. GNI has undertaken projects to expand the role of natural gas in transportation and to develop the renewable gas sector in Ireland. To play its role in supporting a low carbon energy policy, GNI state that an ongoing challenge for its business is to adapt its network and leverage its assets and expertise to support and enable an ever increasing penetration of renewables in Ireland s energy system. Responding to changing gas flows. At the end of 2015, the first gas flows from the Corrib entry point were introduced to the gas network. Corrib replaces Moffat as the dominant gas supply point in Ireland. This new entry point has created a number of operational challenges for GNI s networks business related to changing network flows. Plans are also being developed to decommission key network assets as production operations cease at the Inch supply point, which will have a knock-on effect to other parts of the network. Managing an ageing asset base. More than 40 per cent of GNI s network is now more than 20 years old. This presents a maintenance and capital investment challenge during the upcoming control period to ensure the long-term reliability and security of gas supply. Resourcing for a higher volume of smaller scale projects. Due to the ageing asset base and GNI s projected increase in customer numbers, the required PC4 work programme is potentially larger and more challenging than the programme delivered in PC3. GNI has prepared a resource strategy which it believes will enable the delivery of PC4, but the strategy requires recruiting additional staff in critical technical and engineering roles. 8

20 2.1. Maintaining utilisation of the gas network Long term prospects for gas demand In the longer term, energy and climate change policies, EU directives and technological developments in areas such as energy storage, renewable energy generation and energy efficiency, may lead to a significant reduction in demand for fossil fuels. As part of its PC4 submission, GNI cites independent modelling which estimates that these dynamics could reduce demand for gas by 40% - 60% or more by This trend indicates that there is a risk that customers may face increasing tariffs unless GNI is able to maintain demand on the network without additional cost. In order to ensure that the cost of gas to customers remains competitive over the longer term, the challenge to GNI is to maximise utilisation of the gas network by growing demand whilst driving cost efficiencies Promoting growth initiatives during PC4 GNI has argued in its BPQ submission for PC4 that a difficult economic climate, a heightened awareness of energy efficiency and the increasing impact of energy policy contributed to a challenging period for network growth and utilisation during PC3, as average domestic gas consumption fell. Residential demand fell by 3% over PC3 despite a 6% increase in residential customer numbers. Demand for gas from power generation also dropped significantly at the beginning of the period driven by the increasing penetration of renewables together with low coal prices and the economic downturn. This contraction of gas demand from power generation (which reduced by approximately 13% in 2013/14 compared to end of PC2) was offset by growth in the Industrial and Commercial sector (estimated to have increased by 40% by end of PC3). Driven by the extension of the network to Macroom, Nenagh, Wexford and Cootehill, the growth in the Industrial and Commercial sector meant that, relative to the start of PC3, overall demand has remained flat. However, GNI state that recent improvement in macroeconomic conditions may drive greater growth in the network during PC4. GNI has proposed to deliver over 100,000 additional domestic and commercial customers by the end of the price control. In total, GNI projections show that the number of connections will rise by c.14%. In addition to the direct costs associated with a larger customer base, such as meter reading and customer servicing, GNI plans to expand its maintenance and response capability to serve new geographic areas. It also anticipates that increased construction activity from economic growth will lead to an increase in siteworks and response activities (e.g. to react to damage caused to gas installations) requiring increased distribution capex during PC4. However, if GNI is able to achieve these targets without incorporating additional long-term costs it should place downward pressure on network tariffs to the benefit of all gas customers. 8 ESRI and UCC (2014) Implications for Ireland Moving Towards a Low Carbon Energy Roadmap Energy Research Workshop 9

21 GNI has devised a detailed growth strategy which identifies measures it believes can increase market share in the residential and industrial and commercial sectors during PC4. In the residential market, it proposes to target new housing by providing advice to industry participants and working with vendors to promote gas heat pumps and domestic Combined Heat and Power (CHP) units. In the industrial and commercial market, GNI has launched a number of initiatives to increase gas utilisation and deliver savings to customers. One initiative supports institutional customers such as schools, hotels and hospitals which are near but not yet connected to the network. It has also secured a first order for a large data centre site. GNI s PC4 expenditure plans include forecast increases in opex to help support these planned growth initiatives, including marketing and supporting regulatory and commercial schemes Supporting energy policy by building on the innovation funding in PC3 The Irish Government has a stated policy objective to guide the transition to a low carbon energy system that provides secure supplies of competitive and affordable energy to Irish citizens and businesses. Whilst the Government acknowledges that there will continue to be a need for gas to meet Ireland s energy needs, its energy policy is positioned to gradually reduce dependence on fossil fuels and transition to low carbon fuels like natural gas. Natural gas currently provides 27 per cent of Ireland s primary energy requirement and fuels 52 per cent of national electricity generation, providing flexibility to react to and mitigate the challenge posed by the intermittency of renewable energy sources. A key challenge for GNI over this and subsequent price controls will be to adapt to, and support, the transformation of Ireland s energy systems. This was a key focus of the PC4 BPQ submission and GNI has considered its role in facilitating the roll-out of Compressed Natural Gas (CNG) for transport purposes and the development of indigenous renewable gas. Both CNG and renewable gas are also viewed as part of the wider growth initiatives identified by GNI for supporting long term utilisation of the gas network CNG During PC3, GNI undertook a number of projects to expand the role of natural gas in transportation and to develop the renewable gas sector. In 2016, it carried out several CNG trials with industry and commenced the installation of three fast fill CNG refuelling stations. CNG has the potential to deliver benefits in terms of cheaper fuel for transportation, lower air and noise pollution and, with more gas flowing through the network, downward pressure on tariffs for all natural gas users. GNI has identified twenty five strategic locations for CNG refuelling stations around the country and it argues that construction of these stations are necessary for the development of a market for natural gas as a transport fuel and to meeting the requirements of the Alternative Fuels Infrastructure Directive. 10

22 In November 2016, the CER published a funding decision on a trial to examine the impact of introducing compressed natural gas (CNG), delivered through the development of 13 CNG stations throughout Ireland. 9 This follows a request to the Connecting Europe Facility (CEF) by GNI for this trial ( Causeway Study ). GNI received 5.96m from the CEF and could draw down 4.68m from the PC3 innovation fund. The CER approved funding the shortfall of the study ( 12.83m) to permit GNI to recover the total cost of 23.47m Renewable Gas GNI is also working to facilitate the first facility for injecting renewable gas directly into the network and, through the PC3 innovation fund, supported several decarbonisation research projects on gas quality, renewable gas feed stocks and the potential for power-to-gas (converting electricity to hydrogen). In addition, GNI believe that renewable gas can be part of the solution for national waste management through the conversion of waste to gas. Over PC4 GNI has proposed plans to facilitate the development and connection of six renewable gas production and injection facilities around the country as a necessary stimulus to this market. GNI has stated that renewable gas is a versatile and sustainable energy source renewable gas technology is mature and widely used in a number of European countries Responding to changing gas flows One of the challenges that GNI has stated it faces during PC4 is responding to changing gas flows on the transmission and distribution networks. Gas supply flows changed significantly in the latter period of PC3, with flows from the Corrib gas field commencing in 2015/16. 9 CER (2016) Decision on CNG funding request, aper.pdf 10 GNI (2016): PC4 Executive Summary PC4 SD001 11

23 Figure 2.1: Changing gas flows with Corrib Source: GNI Corrib will displace Moffat as the dominant supply point in 2016/17. GNI argue that the new entry point creates a number of operational challenges, including: management of variable calorific values across the network; increased monitoring of gas quality and specification; balancing the configuration of network flows; and a requirement to operate the Southwest Scotland Onshore System (SWSOS) compressor stations on low and intermittent flows. The SWSOS compressor stations, which were originally designed to cater for the full demand of the Ireland, Northern Ireland and Isle of Man networks, may experience additional wear in the future as a result of a start/stop operating profile due to the introduction of Corrib gas and the intermittency of wind generation. Any additional wear would result in an increased maintenance requirement. Plans are also being developed to decommission historically key network assets. It is now expected that the Inch supply point will cease export operations in 2020/21 which will result in the decommissioning of Midleton Compressor Station. This will have a knock-on effect to other parts of the network, as during peak demand periods the Cork area depends on exports from Inch to maintain network pressures. In response, GNI has planned a complex capital project at Ballough AGI, in order to increase pressure in the Dublin Galway Limerick pipeline and defer the requirement for a pipeline reinforcement between Limerick and Cork. 12

24 2.4. Managing an ageing asset base GNI currently forecasts that maintenance costs will increase for PC4 by c.33% compared to PC3, as it administers ongoing maintenance programmes on a growing asset base, as well as delivering maintenance programmes for new asset classes and an aging asset base. In preparation for PC4, GNI has done some initial work to understand the long-term asset renewal and investment profile of the network, which it set out in its BPQ submission. GNI s analysis to date would suggest that the level of replacement expenditure is likely to increase in PC4 and PC5 prior to levelling off towards the end of the 2020s, although there may be options to defer investment whilst reducing risk. Underlying its forecasts is an ageing asset base, of which GNI estimates more than 40% is over 20 years old. The primary components of the network, such as the buried high pressure steel pipework for transmission and polyethylene pipelines in distribution, have long design lives. However, the ancillary components and subcomponents of the pipelines (e.g. Above Ground Installations (AGIs), District Regulator Installations (DRIs) and at meter points) have considerably shorter design lives. Assets which are beyond their design life will require refurbishment or replacement to ensure the continued operation of the network in a safe and secure manner. GNI therefore expect a step-up in work load activity in PC4 and PC5 which has impacted on its opex and capex forecasts, including the company s resourcing strategy as further detailed in section 2.5 below. In addition, GNI argue that a number of asset replacements are required prior to the end of their design lives, particularly on the compressor fleet, due to accelerated degradation caused by harsh environmental conditions and usage profiles (driven by the variability of wind generation) to meet changing demand requirements. Early replacement may be the best option to ensure the continued reliable operation of the network Resourcing for higher volumes of smaller projects In 2013, GNI developed a resource strategy which was to ensure that the company was appropriately resourced to deliver the PC3 work programme to GNI identified gaps in core competencies, particularly for technical and engineering resources, which it claimed were manifesting in a failure of the business to ramp to the required activity levels for PC3 delivery. GNI s assessment of the underlying cause was differences in work type and volume between PC3 and preceding price control periods. In particular, the challenge was to become a high volume but lower project value delivery company, while retaining the ability to deliver large projects such as new town developments. GNI s response was a combination of recruiting additional staff and upskilling, which resulted in significantly increased resourcing costs over the latter years of PC3. GNI argues that the PC4 work programme is potentially larger and more challenging than the programme delivered in PC3. In addition to a growing asset base and forecast maintenance 13

25 programme, GNI is planning for a refurbishment programme which currently includes a number of high volume activities, for example: relocating c.9,000 domestic meters which have been identified to be located in unsafe (and/or non-compliant) positions in customer properties; installation of c.9,000 excess flow valves on 4 bar domestic services to limit the propagation of gas leaks from third party damage or asset failure; replacing c. 4,400 industrial and commercial meters, an increase of 42% on PC3; and replacing c. 124,000 domestic meters, an increase of 10% on PC3. In light of the experience of ramping up resources in PC3, GNI has prepared an updated resource strategy which it believes will facilitate the delivery of the PC4 work programme. The same shortages in technical and engineering roles have been identified, as was the case for PC3. GNI believes that a net increase in headcount of c.70 people over 2016, 2017 and 2018 is required to deliver the programme of work, including 35 technical roles in Asset Operations, Asset Management and HSQE, 25 roles in its apprenticeship and graduate trainee programmes, and the remaining 10 roles in support services. Figure 2.2 below illustrate GNI s forecast total headcount movement over the PC4 price control. 11 Figure 2.2: Forecast movement in GNI headcount Source: GNI 11 Note that this excludes growth in headcount at the Ervia Group level where BUs such as the Shared Service Centre support GNI s activities. 14

26 3. REVIEW OF PC3 OPEX In this section we review distribution opex during the PC3 price control. This includes four years of actual data and one year of forecast data from GNI. This supports our bottom-up assessment of GNI s opex in PC4. Using the reported information on outturn opex during PC3 we have also benchmarked GNI to relevant peer companies. We present the results of the benchmarking analysis in the subsequent section of the report Overview The tables below show how GNI outturn expenditure has compared to the allowances set for the PC3 control. Table 3.1: PC3 outturn distribution opex ( 000s) Category 2012/ / / / /17 Total Operations 32,956 33,070 36,543 35,270 41, ,208 Business Support 16,759 21,214 17,000 18,460 19,924 93,357 IT 5,423 4,852 5,208 6,305 6,502 28,291 Gaslink ,742 Total controllable 55,671 59,762 59,337 60,585 68, ,597 Pass-through 18,990 19,874 20,355 22,669 19, ,535 Innovation ,401 2,731 Total 74,682 79,783 79,934 84,174 89, ,863 Source: GNI Table 3.2: PC3 allowed distribution opex ( 000s) Category 2012/ / / / /17 Total Operations 34,995 34,509 35,040 34,647 34, ,936 Business Support 25,097 22,781 15,613 19,065 19, ,305 IT 5,610 5,826 6,004 2,518 2,132 22,090 Gaslink ,029 Total controllable 65,968 63,429 56,951 56,811 57, ,359 Pass-through 20,616 19,097 20,871 20,732 21, ,918 Innovation Total 86,757 82,838 77,927 77,696 78, ,166 Source: GNI 15

27 Table 3.3: PC3 variance distribution opex ( 000s) Category 2012/ / / / /17 Total Operations -2,039-1,439 1, ,624 5,272 Business Support -8,337-1,567 1, ,948 IT ,787 4,371 6,201 Gaslink Total controllable -10,297-3,667 2,386 3,774 11,041 3,238 Pass-through -1, ,936-1,954-1,383 Innovation ,255 1,842 Total -12,075-3,055 2,008 6,477 10,342 3,697 Note: positive value indicates outturn expenditure above allowance. Source: Consortium 3.2. Methodology Our review of PC3 opex does not involve making a judgement on the efficiency of the incurred expenditure. GNI bear in full any differences from the allowance, either over- or underspends, for opex that is not classified as pass-through under the price control. The outturn expenditure does, however, contribute to our assessment of the efficient costs for the PC4 period, as cost trends are utilised. As a consequence, below we provide high-level commentary of the activities undertaken in each category of opex 12 and the key trends in the phasing of GNI s expenditure during PC Historical cost trends at a total controllable level Figure 3.1 shows that in the first two years of PC3 GNI underspent compared to its allowance, but came back in line with the allowance in 2014/15. GNI is forecasting to spend above its allowance in the last two years of the price control, such that total controllable opex over the whole of PC3 (i.e. 5 year total) is circa 3m above the allowance. This is not an unusual profile for regulated networks, although the profile is more typically associated with capex where, for example, it can take a period of time to mobilise contractors / capex programmes. 12 The way we have disaggregated opex into categories is discussed in Section 1 of this report. 16

28 m (2015/16 price base) Figure 3.1: Opex (excluding pass-through costs), 2012/13 to 2016/17 (2015/16 price base) Actual opex Allowance Source: CEPA calculations based on GNI data Opex is broadly considered to be a recurring cost in nature, which means that the level of costs in one year correlate closely with the costs in the subsequent year (this is not necessarily the case for capex). Therefore, it is important to note that there is increasing opex over PC3, whereas the trend in the allowances had GNI opex decreasing over time (decreases in allowances reflect downwards trend in network maintenance allowances and the opex efficiency glide path applied by the CER in its final PC3 decision) Operations opex GNI reported expenditure of m over the PC3 period against an allowance of m, a breakdown of the outturn by function is shown below. This follows re-allocation of IT expenses from these functional areas to the IT function to enable this to be assessed at the total level i.e. the reported expenditure in Table 3.4 excludes IT expenses. Table 3.4: PC3 outturn distribution operations opex ( 000s) Category 2012/ / / / /17F Total Asset Management 2,140 2,546 3,076 2,579 3,390 13,730 Asset Operations 28,210 27,483 29,302 28,042 31, ,543 Commercial ,045 3,580 6,761 HSQE 2,222 2,126 2,456 1,919 2,116 10,839 Technical Competency ,335 Total 32,956 33,070 36,543 35,270 41, ,208 Source: GNI 2012/ / / / /17 17

29 Asset Management The Asset Management function is responsible for managing the assets of the transmission and distribution businesses. The function identifies, plans, and develops programmes of work on the asset base, in line with approved asset policy, to maintain asset performance and implement appropriate network investment. Staff costs in Asset Management account for almost 70% of the costs in this area. Staff numbers have fluctuated during PC3 as GNI s revised resourcing strategy has been implemented. Although there was a drop in staff numbers in 2014 this rose the following years as transfers within GNI where made. There has been an overall rising trend in asset management costs over PC Asset Operations The Asset Operations function is responsible for the day to day operation of the gas network in a safe and reliable condition. Asset Operations was established in 2012, following the merger of Workflow Management and Service Delivery. Asset Operations delivers across the full lifecycle of distribution projects from work initiation through build, commissioning and maintenance. Its purpose is to interface with customers and successfully deliver all field force based work. This area of spend represents 48% of the total GNI Distribution opex spend for the PC3 period, and is 72% of the Operational Departments expenditure Commercial The Commercial department was established in early 2015 to address the need to increase utilisation on the network. The resources in the department were a mix of transfers from other areas of the business and new hires. A priority of the function is to maximise the potential of the existing gas network while seeking opportunities to expand and diversify into new markets through research and innovation. We note that during PC3 there has been the creation/growth of the Commercial Department to specifically provide the focus on growth of customer numbers and other new and innovative approaches to increase gas demand. The object of this being to maximise the benefit from the installed network asset base HSQE The role of the HSQE function is to ensure that GNI s activities and assets do not harm its staff, contract partners, the public and/or the environment. The function facilitates the development, operation, integration and continuous improvement of its safety, quality and environmental management systems. 18

30 HSQE works closely with all areas of the business on all aspects of occupational and process safety, quality, environmental and risk management. The HSQE expenditure has been relatively flat during PC Technical competency The Technical Competency Development function was established in 2013 to develop and implement systems, processes and programmes necessary to significantly enhance the gas technical competencies within GNI, for both employees and for contract resources working on the gas network. The resources in the department were a mix of transfers from other areas of the business and new hires. GNI has implemented a Technical Competency Framework for all gas technical roles and technical training and upskilling have then been targeted where the competency of any individual was misaligned with the desired level for that specific role. In our opinion the introduction of a structured approach to setting and assessing technical competence of all gas technical roles and addressing any shortfall through training is appropriate Business support opex Under business support opex, we look at five functional areas for GNI. These are: Head of Networks; Regulatory & Corporate (R&C) Services; Network Finance Services ( Finance ); Human Resources (HR); and Facilities. The table below presents outturn costs for these functional areas. 13 Table 3.5: PC3 outturn business support costs ( 000s) Category 2012/ / / / /17F Total Head of Networks 1,786 5,973 3,791 2,459 1,627 15,636 R&C Services 3,646 4,182 2,732 4,176 4,357 19,093 Finance 7,140 6,327 5,323 7,002 8,133 33,925 Human Resources 1,679 1,767 2,118 2,098 2,498 10,159 Facilities 2,509 2,966 3,036 2,724 3,308 14,544 Total 16,759 21,214 17,000 18,460 19,924 93,357 Source: GNI 13 Note that 2016/17 is a forecast. As with operational areas, we have also excluded IT expenditure. 19

31 A key point to note from Table 3.5 is the significant variation in expenditure for a number of the functions (e.g. finance) during PC3. Partly this is driven by changes in activities or increases in workload within individual functions (e.g. increased focus on growth related activities within the Regulation and Corporate Services function). The year-on-year variations are also driven by increased role of the Group & Shared Service Centre in delivering business support functions, with consequential changes in costs allocations across the business Head of Networks Head of Networks refers to the office of the Managing Director of GNI. Each head of the various functions reports directly to the Managing Director. The office is responsible for defining and implementing the overall business strategy for GNI and leads the senior management team in achieving these targets Regulatory and Corporate Services The Regulation & Corporate Services function is responsible for ensuring compliance with, and development of, all aspects of the transportation licences and regulated contracts of GNI. It also has responsibility for customer and marketing strategy, revenue protection, price control co-ordination, commercial metering and shipper services. The function was significantly re-organised over the course of PC Finance The role of the Finance function is to ensure that appropriate structures are in place to support the business, ensure financial control and to manage and mitigate risks through compliance and insurance cover. In addition, the function is responsible for the management of both tariffs and commercial demand forecasting. Finance is organised into specialised areas, namely Financial Reporting and Planning, Internal Audit, Insurance, Commercial Finance and Business Planning Human Resources The HR function supports the business and provides generalist services and Learning and Development (L&D) services. The HR function has changed significantly during the PC3 period with the establishment of Ervia as a multi utility. HR Central Services moved to the Shared Services Centre, HR strategy, compensation and benefits moved to the Group Centre while the GNI HR function reduced significantly in size. 20

32 Facilities The Facilities function ensures that a safe and sustainable work environment, compliant with legislation, is provided for all employees across the Ervia Group, including GNI. Facilities services were incorporated into the Shared Services Centre in 2014 where they continue to deliver a full suite of facilities capabilities and property portfolio management to GNI. All aspects of Facilities are managed centrally IT opex For IT opex, we show the total values for the distribution business. This includes the IT function costs and the IT expenses from across the other GNI functions already discussed. Table 3.6: PC3 Outturn IT opex ( 000s) Category 2012/ / / / /17 Total Outturn 5,423 4,852 5,208 6,305 6,502 28,291 Source: GNI As IT capex spend was skewed towards the later years of PC3, the associated IT opex was also backloaded. There was a drop from the first to the second year of PC3 in opex and then a significant increase in the final two years of PC3. GNI stated that despite a growing IT user base and evolving business requirements, they had managed to stay within the allowance through improvements in processes and the establishment of the Shared Services IT function. The number of FTEs started at 53 in the calendar year 2012 and was at 54 in calendar year 2016, remaining at this level on average during PC Gaslink opex Gaslink was historically an independent subsidiary of Bord Gais tasked with the gas system operator role in Ireland to comply with European regulations. During PC3, Gaslink opex has been reported as its own expenditure item under the passthrough cost items of the price control, although over the course of PC3 the company has been merged into GNI. During PC4, expenditure associated with Gaslink activities is included within the Regulation and Corporate Services function of business support costs. Table 3.7: PC3 Outturn Gaslink distribution opex ( 000s) Category 2012/ / / / /17 Total Outturn ,742 Source: GNI 3.8. Pass-through costs Pass-through costs are opex items that receive a different regulatory treatment than core controllable opex under the terms of GNI s price control. The subsections below describe: 21

33 the regulatory treatment of individual pass-through costs during PC3; and the level of reported pass-through costs (excluding Gaslink) during PC Regulatory treatment of pass-through costs For distribution, there were three items which were treated as full pass-through items for PC3. These were Gaslink, CER levies and Revenue Protection. In addition, there was a full pass-through on the price aspect of shrinkage, however, the volume difference between outturn and the target is borne in full by GNI. There is as a consequence, an incentive on GNI to reduce shrinkage against target values. Rates and safety advertising were both subject to a 50% incentive sharing factor e.g. if rates were below the regulatory allowance in the price control, then 50% of this saving would be shared with gas customers and 50% retained by GNI. This has meant that there is financial incentive for GNI to reduce outturn expenditure on these items below ex ante targets Level of pass-through costs The table below shows the outturn values for pass-through cost items (excluding Gaslink) in the PC3 distribution price control. As discussed above, while revenue protection and the CER levy have been a full cost pass-through for GNI s distribution business during PC3, rates, shrinkage and safety advertising have been subject to financial incentive arrangements. Table 3.8: PC3 outturn Pass-through opex ( 000s) Category 2012/ / / / /17 Total CER levy 1,538 1,563 1, ,246 6,616 Revenue Protection ,042 Safety 1,721 2,026 1,770 2,520 2,253 10,289 Shrinkage 3,789 4,227 4,306 6,804 4,455 23,581 Rates 11,671 11,414 12,747 12,091 11,084 59,007 Total 18,990 19,874 20,355 22,669 19, ,535 Source: GNI 3.9. Innovation In the PC3 decision by the CER, an allowance of 8.0m was allowed in total for innovation, in the form of an opex allowance. This allowance covered innovation activities for both the Transmission Business Unit (TBU) and Distribution Business Unit (DBU). The adopted treatment of innovation funding as opex avoided complications of including small capital projects in the Regulatory Asset Base (RAB) and was seen to be more consistent with the focus on innovation funding. A subsequent proposal from BGN regarding the split of 22

34 the allowed 8.0m between transmission and distribution was accepted by the CER, leading to a 90/10 split between the TBU and DBU. Detailed governance arrangements were developed for BGN s innovation fund and used to determine which projects were funded within PC3. This included the formation of an innovation group called the Gas Innovation Group (GIG). This was formed to get a broader view of industry and technical developments, being made up of members of leading research centres in Ireland, key policy advisory groups, government agencies and government departments. GNI have set up evaluation criteria on how to assess projects and shared this in their submission. These are separate for research projects and other funding requests. One of the primary evaluation criteria introduced by GNI is increasing utilisation of the gas network. The innovation funding at PC3 has been allocated to five principle areas: CNG; biogas; research; business/ technical; and programme management services. The split of expenditure across these categories is shown below (across both distribution and transmission). The majority of this funding is expected to be incurred in the final year of the PC3 price control period. This backloading is said to be reflective of the time taken to establish the processes around the innovation fund. Table 3.9: PC3 Outturn Innovation opex for both transmission and distribution ( 000s) Category 2012/ / / / /17 Total CNG ,004 2,615 4,000 Biogas ,789 1,850 Research Business/ Technical Programme management Total ,366 5,607 8,000 Source: GNI GNI note one of the benefits of the innovation fund is that their overall funding is expected to have leveraged additional funding from other sources. In their submission document, GNI note that funding totalling 7.7m has delivered a net benefit of over 14.5m (funding leverage of 187%). A number of projects have received full 100% funding, but the majority have involved co-funding. 23

35 GNI note benefits from this funding has included: development of a new source of demand for gas through the development of CNG in transport thus increasing the customer base for the gas network; potential for reduced tariffs to the gas customer over the long term as a result of increased utilisation of the natural gas network for transport; increased efficiency of the natural gas network through the potential for load management and off peak use of CNG stations; improved focus on the long term sustainability of the natural gas network and certainty of service; addressing the needs of gas customers by fostering a renewable gas industry in Ireland; lowering the carbon footprint of the network through the introduction of renewable gas into the gas network; and informing the policy debate through quality research publications and leveraging the innovation funding to secure other funding Summary In this section of the report we have reviewed outturn opex across the different functions and items of opex included in the PC3 determination. This historical review has informed our recommendations of allowed opex in PC4. Figure 3.2 below illustrates the overall trend in expenditure of controllable opex by individual function. For consistency with the reporting basis for PC4, we have included Gaslink opex in the reported controllable opex totals. Figure 3.2: Overall trends in controllable distribution opex during PC3 Source: GNI. Note: excludes innovation and pass-through opex. 24

36 4. BENCHMARKING This section summarises the work the consortium carried out to benchmark GNI s total controllable distribution opex. This has informed our review of PC4 opex and the expected scope for GNI to improve its relative efficiency during PC Approach Our high-level approach to benchmarking is to use unit rates (at a total controllable opex level) and econometric models that compare GNI s performance against gas distribution networks (GDNs) in Great Britain (GB). We have considered a range of unit cost comparisons using different measures of company scale: customer numbers, units distributed (GWh), network length (km) and a CSV. 14 Through our econometric model development process we identified two models that we combine through a process called triangulation. 15 We had access to historic expenditure and cost driver data for the period 2011/12 to 2015/16 for GNI and GB GDNs for the benchmarking. 16 GNI data has been taken from its BPQ response for PC4 and the data for GB GDNs was taken from annual regulatory reporting packs (RRPs) provided by Ofgem. In line with good practice, we consider that some adjustments to the data are required prior to modelling to ensure that expenditure is on a like-for-like basis across companies. These adjustments take account of different scope of companies (in terms of the types of expenditure incurred), differences in reporting, differences in prices/ currencies, and uncontrollable regional differences affecting company costs. Annex A sets out in detail the assumptions and process which we followed to develop the data set, including cost exclusions and adjustments. There are a range of econometric benchmarking models that could in principle be used to benchmark GNI to GB GDNs. We ran several models and have taken the general-to-specific approach to refining the set of viable cost drivers used in the econometric models. This approach starts from a specification that includes a large range of cost drivers and explanatory variables, and progressively omits variables based on statistical significance and logical criteria. We have also tested more parsimonious models that combine several cost drivers into a single variable (CSV). In refining our models, we have applied a number of statistical diagnostic tests in an attempt to provide an additional level of assurance that the model specifications we have chosen, and the estimation method we have adopted, are appropriate for the data being examined. We adopted the following assessment criteria for developing and refining our models. 14 The CSV is calculated as follows: CSV = Customer numbers 0.25 * Units distributed 0.25 * network length Triangulation is a process of combining different models to come to a single point estimate of costs. 16 We chose not to benchmark GNI and GB GDNs on forecast costs with the uncertainty of future expenditure levels, preferring to rely only on actual outturn expenditure data. 25

37 Figure 4.1: Model selection criteria Statistical robustness Transparency Economic rationale Technical rationale Does the model pass statistical requirements / tests? Transparency of data used and what adjustments have been necessary to allow comparability Do the model specification and results have an economic rationale? Are choices of explanatory variables consistent with engineering view of cost drivers? Statistical tests and data analysis Logic criteria Source: Consortium The statistical robustness criterion covers the following areas: Parameter significance. The parameter estimates should be statistically significant (from zero) to at least to the 10% level of significance. Statistical diagnostic tests of the models: o Normality test. For small sample sizes a normally distributed error term is required in order for tests of statistical significant to be valid. o Ramsey s RESET. This test gives an indication of whether there are any omitted non-linearities in the model which would indicate that the model is incorrectly specified. This test is carried out by running an additional regression using higher order terms of the original modelled residuals. o Pooling test. For pooled OLS 17 models, this test determines whether or not the data is appropriate for pooling together. The two logical criteria capture the engineering and economic rationale behind both the selection of the cost drivers as well as the results. Economic rationale generally considers sign/ magnitude of parameter estimates and the range of estimated efficiencies. The transparency criterion is primarily related to the adjustments and inputs to the unit cost analysis and econometric models, rather than the model results, but also touches on the replicability of the models by others. 17 Ordinary Least Squares. 26

38 (2015/16 prices) (2015/16 prices) 4.2. Unit cost benchmarking results Figure 4.2 to Figure 4.3 present unit cost comparisons using different measures of company scale: customer numbers, units distributed (GWh), network length (km) and a CSV. 18 Figure 4.2 Comparison of unit cost analysis opex per customer, 2015/ Opex per customer GB industry average GNI Source: Consortium Figure 4.3: Comparison of unit cost analysis opex per GWh, opex per km and opex per CSV, 2015/16 6,000 5,000 4,000 3,000 2,000 1,000 - Opex per GWh Opex per km Opex per CSV GB industry average GNI Source: Consortium 18 The CSV is calculated as follows: CSV = Customer numbers 0.25 * Units distributed 0.25 * network length

39 Opex per customer (2015/16 prices) Overall the analysis indicates that GNI has higher unit costs than all other GDNs across all four scale variables. The results indicate that there may be scope for GNI to achieve efficiency gains. However, these are only partial measures in that they use only one output. Therefore, other network characteristics between GNI and the comparators will not be fully accounted for in the benchmarking analysis (e.g., network density). It may be the case that economies of scale allow larger (GB) companies to reduce unit costs, 19 which may partially influence the relatively higher GNI unit costs observed in the analysis. We therefore show an additional chart of / customer plotted against customer numbers below which indicates that, in line with expectations, there is some evidence of economies of scale, illustrated by per customer costs decreasing as a gas distribution network s customer numbers increase. Figure 4.4: Opex per customer plotted against customer numbers (2015/16 prices) Customer numbers (millions) Linear (Opex per customer) Source: Consortium While Figure 4.4 above does indicate that economies of scale exist for customer numbers, if the observations below one million customers (GNI) were removed the economies of scale would be much less pronounced (i.e. a much flatter dotted line). If a linear adjustment for economies of scale were to be made, GNI would still appear to be relatively inefficient on this partial measure i.e., its observations are above the dotted line. However, as we discuss in more detail below, the limited range of comparators with customer numbers ranging from 500,000 to 1.5 million means that we cannot come to a more conclusive view on the economies of scale that exist (there are c.678,000 customers connected to the gas distribution network in Ireland). 19 For example, the smallest GB GDN has approximately 2.7 time the number of customers as GNI. 28

40 4.3. Econometric benchmarking results Base results We identified two preferred econometric models that pass our selection criteria and that we consider to be viable for estimating GNI s historic efficiency. 20 The models, their cost drivers and the key adjustments made in the data set are summarised in the table below. Table 4.1: Econometric models Model specification Model A Model B Estimation method Pooled OLS Pooled OLS Time period Dependent variable Log(Opex) Log(Opex) Parameter estimates Log(CSV) 0.674*** 0.675*** Year (time trend) 0.023** Constant ** ** Diagnostic tests RESET Normality Pooling No. observations R-squared Composite Scale Variable CSV weights Adjustments to data Density Pre-modelling adjustment 21 Regional wage adjustment Other adjustments Inclusions Exclusions 50% network length, 25% units, 25% customer numbers Ireland and individual regions of GB Adjustments for currency, inflation and re-basing to GNI gas year AGI costs included in GNI data Various see Annex A Source: Consortium Note: Stars indicate that coefficients are significant at the following levels of significance: *** 1%, **5%, *10% 20 In an earlier stage of the price review, we also developed a third model that included a variable for density in the model specification. Instead our two selected models adjust for density as pre-modelling adjustment. 21 Based on the methodology applied by Ofgem during RIIO-GD1, discussed further in Annex A. 29

41 Efficiency score All of our preferred specifications are Cobb-Douglas specifications (these models are specified in log-log terms which means that the coefficients are interpreted as cost elasticities). 22 We have also tested a larger number of models (e.g. translog models that allow for varying economies of scale and density) which did not pass our model selection criteria. We do not present the results of these models here. Model A and B are similar, except that Model B includes a time trend. The time trend captures a combination of changes in input price inflation, changes in efficiency (e.g. frontier shift) and changes in quality not explained by other explanatory variables in the econometric model. The positive time trend in Model B indicates that the improvement in technology which would lead to savings had been outweighed by increases in input price inflation or increases in quality that the industry has paid for. The cumulative effect of these factors is an annual 2% increase in costs in the modelling period. The results of the benchmarking are illustrated in Figure 4.5 below, which shows GNI s DBU performance as ( efficiency scores ) against the estimated industry average efficiency line as predicted by the econometric models. Efficiency scores are the percentage difference between the modelled and adjusted GNI submitted costs, with positive values indicating that GNI s submitted (i.e. actual) costs are higher than modelled costs (i.e. relatively inefficient). As Figure 4.5 shows, GNI s reported historic costs are above the predictions of the industry average efficient costs throughout the historic period in both models. Figure 4.5: Efficiency scores generated by Model A and B 12% 10% 8% 6% 4% 2% % -2% -4% Model A Model B Source: Consortium Note positive values indicate relative inefficiency compared to industry average line 22 In other words, a 1.0 coefficient means that a 1% change in the variable will lead to a 1% change in opex. 30

42 Sensitivities We have also conducted a sensitivity analysis on our preferred set of models to determine their robustness to changes in input data. Table 4.2 below summarises each of the sensitivities. Descriptions of additional sensitivities we have run are provided in Annex A. Table 4.2: Summary of key sensitivities run No. Sensitivity Description 1 Excluding wayleaves payments 2 Excluding re-allocated costs for AGIs. Companies need to make payments to landowners for access to their properties. These payments are partially uncontrollable by companies. We conduct this sensitivity to determine the effect of including costs from GNI s transmission business in our benchmarked costs. 3 Two region RWA This sensitivity uses a regional wage adjustment based on two regions, ROI and GB. This was the approach used at PC3. 4 Four region RWA This sensitivity uses a regional wage adjustment based on four regions, ROI, London, South East of England, and the rest of UK. This was the approach taken by Ofgem at RIIO-GD1. 5 Removing 70% of XoServe costs The Northern Ireland Utility Regulator considered that the scope of activities undertaken by XoServe were more extensive than those undertaken by companies in Northern Ireland. Therefore, it removed 70% of XoServe costs from GB DNOs in their benchmarking. We have not evaluated this claim, but test this sensitivity to understand whether XoServe costs play a material role in determining GNI s relative efficiency. 6 Excluding GNI We exclude GNI from the estimation sample for this sensitivity to determine whether it has a material impact on the results. Source: Consortium Figures 4.6 and 4.7 below show GNI s efficiency gap (to the industry average) across each year and sensitivity. We observe that the sensitivity that shows the most material impact on GNI s efficiency gap is sensitivity 6, which excludes GNI from the benchmarking model. As discussed below, this is caused by the change in the regression line that occurs when GNI is excluded from the sample. This suggests that GNI is an important observation for estimating a cost function that is appropriate for smaller companies (i.e., GNI). 31

43 Efficiency score Efficiency score Figure 4.6: Efficiency scores generated by sensitivities for Model A 30% 25% 20% 15% 10% 5% % -5% Source: Consortium Figure 4.7: Efficiency scores generated by sensitivities for Model B 35% 30% 25% 20% 15% 10% 5% % Source: Consortium 32

44 Log(opex), 2015/16 prices Overall the models are sensitive to excluding GNI from the sample, indicated by the large differences in coefficient estimates 23 and GNI efficiency scores when they are excluded from the sample. This could indicate that the models suffer from a relatively limited range of observations and therefore that they may be mis-specified. This finding is not surprising given the relative size of GNI compared to other GB GDNs, and the lack of comparator companies that are in between the size of GNI and GB GDNs. This is shown in the scatter plot below (Figure 4.8), which demonstrates that GNI is an outlier compared to other companies. The scatter plot also shows the regressions lines for Model A under the baseline scenario and sensitivity 6. As we see, excluding GNI from the sample causes the regression line to pivot (i.e., change slope). Figure 4.8: Model A regression line, including and excluding GNI GNI GNI is an outlier compared to GB GDNs and an important observation for estimating a cost function that is appropriate for smaller companies Including GNI Excluding GNI Source: CEPA analysis The implications of this analysis are that while the models perform well under the baseline scenario, if GNI is excluded from the sample, the conclusions reached on its historic relative efficiency can be very different compared to when it is included in the benchmarking sample. However, without more observations at the lower end of the scale it is not possible for us to conclude on whether this result is down to GNI inefficiency or the sector exhibiting greater economies of scale than the available data suggests. 23 Coefficients on the CSV variable increased by circa 0.1 when GNI was excluded. These results are not shown in this report. 33

45 4.4. Summary Our top-down model development process has identified two econometric model specifications that we used to benchmark GNI s direct opex against GB GDNs. Our short-listed models indicate that during the first four years of PC3 GNI reported opex was higher than the estimated industry average efficiency line as predicted by the econometric models. We included GNI s data in our top-down model development process and our sensitivity analysis indicated that the models are a better fit when GNI is included. However, GNI operates a significantly smaller distribution network than any of its GB peers. 24 We have chosen to use an average industry benchmark rather than a more challenging upper quartile or frontier benchmark in part to reflect the limitations we have identified in the modelling and to help mitigate the risk of identifying an efficiency target that is unrealistic. However, there is clearly some regulatory discretion in the choice of the appropriate benchmark applied and there may be reasons why in the context of the current price control in question, the CER might choose to adopt a more challenging efficiency benchmark. GNI was c. 4.75% off the average industry benchmark when averaging the opex predictions from our two preferred econometric benchmarking models. Our econometric modelling result that there is scope for GNI to improve its relative efficiency is also supported by our unit cost (partial factor) efficiency analysis. However, while all of our model specifications allow for economies of scale, and we have tested different specifications to account for the relative size difference, our results may be affected by the limited range of company sizes in our sample. In practice, this means that we cannot definitively conclude whether GNI position in the benchmarking is solely down to inefficiency or whether some of the gap to an efficient frontier is due to insufficient data to allow an accurate assessment of the economies of scale present in the sector. 25 What we consider to be the implications of the historical benchmarking for setting an efficient cost path in PC4, is discussed in the next section of the report. 24 Although when combined with the transmission business, the regulatory asset value of the company is of a comparable size to a number of the GB GDNs. 25 In addition to any other measurement error. 34

46 5. REVIEW OF PC4 OPEX In this section we set out our proposed recommendations for distribution opex for the PC4 price control period Overview The tables below shows how our recommendations compare to the GNI business plan for PC4 on distribution opex. The first table includes pass-through costs and innovation; the second table looks only at controllable opex i.e. operations opex, business support and IT. Table 5.1: PC4 recommended distribution total opex ( 000s) Category 2017/ / / / /22 Total Recommended 86,045 86,163 85,593 84,813 83, ,330 GNI request 93,979 94,472 95,104 95,007 94, ,479 Variance -7,934-8,309-9,511-10,194-11,201-47,149 Variance (%) -8.4% -8.8% -10.0% -10.7% -11.8% -10.0% Source: Consortium Note: includes innovation and pass-through cost items Table 5.2: PC4 recommended distribution controllable opex ( 000s) Category 2017/ / / / /22 Total Recommended 68,788 68,679 68,224 67,503 66, ,938 GNI request 75,218 75,944 77,211 77,695 78, ,556 Variance -6,430-7,265-8,987-10,191-11,745-44,619 Variance (%) -8.5% -9.6% -11.6% -13.1% -15.0% -11.6% Source: Consortium Note: excludes innovation and pass-through cost items 5.2. Methodology As described in the introduction, our recommendations on distribution opex have been derived by combining a bottom-up and top-down cost assessment. The bottom-up assessment has been undertaken at an expenditure category / business function level. This was based on a detailed review of GNI s business plan for PC4 and analysis of how GNI s forecast opex in PC4 compares to the normalised costs / run rates of actual expenditure incurred by individual business functions during PC3. We have then considered whether there is supporting rationale for increasing or decreasing allowed opex in PC4 relative to reported PC3 normalised costs / run rates. This has been 35

47 informed by GNI s original BPQ submission and subsequent discussions with the operator over earlier stages of the PC4 price review process. Having completed our bottom-up review, we have then considered a number of sources of top-down evidence of what might be an efficient cost path for GNI s gas distribution business during PC4. This has included: the findings of the top-down distribution benchmarking presented in the previous section; evidence of historic and forecast unit cost trends for GNI s distribution business implied by its business plan; and analysis of potential scope for ongoing (frontier shift) efficiency (net of input price changes above inflation) from GNI s business during PC4. Drawing together the findings from these sources of evidence, we have considered the need and scope for two top-down adjustments to be applied to the bottom-up opex estimates to establish an efficient cost path for GNI s DBU going forward. These are: 1. A catch-up efficiency adjustment if there is considered scope for GNI to improve its relative efficiency during PC4. 2. An ongoing efficiency adjustment if there is considered scope for frontier shift / ongoing efficiency improvement during the PC4 period. We consider our bottom-up estimates to be inclusive of changes in input prices during the price control. For example, we have included an allowance for GNI s projected increase in insurance rates during PC4. GNI also stated that it does not expect its wage rates to increase faster than HICP during the period of PC4 and, as a consequence, no further adjustment has been applied to our opex recommendations for a Real Price Effect (RPE). In considering the need and scope for each top-down adjustment, we have been careful to consider the basis on which the bottom-up opex estimates have been derived. For example, the bottom-up cost assessment has been completed with reference to GNI s forecast expenditure in PC4, which originally included a proposal for an ongoing efficiency factor (0.5%) during the price control. GNI s BPQ submission also included forecast increases in distribution business input prices, in particular, forecast wage levels during PC4. We have, therefore, been careful to ensure that there is not double counting in combining the findings of our bottom-up assessment and the proposed top-down adjustments by: removing GNI s ongoing efficiency adjustment from the expenditure forecasts which informed the bottom-up review; considering whether an ongoing efficiency adjustment may have already been accounted for in findings of the bottom-up assessment; and 36

48 combined top-down adjustments we believe are consistent and achievable in their expectation of GNI s scope to improve its efficiency during PC Group and Shared Service expenditure Our bottom assessment of GNI functional expenditure was undertaken with GNI s forecast for Group & Shared Service expenses excluded from the analysis. The overall trends and justification for allocated Group & Shared Service costs has been assessed separately from other expense items, at a general business level with reference to the expected changes in activities and GNI reliance on the Group & Shared Service Centre during PC4. Informed by the general conclusions of this analysis, we have applied an adjustment to GNI s forecast Group & Shared Service expenses for each of the business functions/categories, which are then added to our bottom-up assessment of other expense items by functional area. This means that our overall recommendations for each business function include Group & Shared Service expenses but are net of the recommended adjustment. The process followed for Group & Shared Service allocations is illustrated in Figure 5.1. Figure 5.1: Treatment of Group & Shared Service expenses in cost assessment Source: Consortium Note excludes IT assessed as a separate category and expense item Ervia s: Group Centre sets the strategic direction for the company and includes functions such as the Chief Executive Office, Commercial and Regulatory, Group Finance and Group Human Resources (HR); and Shared Service Centre provides transactional services to the individual regulated and non-regulated businesses within the Ervia Group, including finance, procurement, facilities, HR and IT. 37

49 In preparing its BPQ response using its new asset-centric reporting model, GNI has individually apportioned costs that have been allocated from the Ervia Group and Shared Service Centre to its individual transmission and distribution networks, and also the business functions (e.g. Asset Operations, Asset Management, Regulation & Corporate Services etc.) that sit across the transmission and distribution businesses. GNI are forecasting a general trend of increasing Group & Shared Service expenses during PC4. This might be expected given the expected growth of GNI as an organisation during PC4 and the planned step-up in work-load / activity during the forthcoming price control period. For example, we would expect an increase in certain finance, procurement and HR initiatives to support the organisational change. GNI have also stated that its forecast Group Centre costs are at a minimum level required to allow Ervia to fulfil its statutory obligations. It has indicated that a reduction in the proposed funding provision for the Shared Services Centre could have an adverse impact on finance and procurement (e.g. tenders completed on time), delays in rollout of HR programmes (e.g. GNI s learning and development courses and EU Cross Agency recruitment processes). While we would expect the Group & Shared Service Centre allocations to increase in support of an increased programme of work over the PC4 period, the expected rate of increase we consider is not as clearly justified as other parts of GNI s PC4 business plan, where we have allowed the forecast increase in expenditure. The justification for changes in Group Centre costs are, in particular, relatively generic rather than linked to specific schemes. There are factors from reviewing GNI s BPQ response which we might also consider should limit the expected rate of increase in allocations which are not obviously referenced by GNI. For example, the expected capital work programme GNI has outlined in its business plan might be expected to rely less on the Ervia Major Projects division than projects which were undertaken during PC3 (e.g. twinning of the SWSOS). 26 As discussed further within this section, there are finance functions which GNI has adopted as a subsidiary in 2015 which might be expected to place some downward pressure on allocations from Ervia group. Therefore overall, we do not consider that GNI has sufficiently justified the forecast rate of increase in total Group & Shared Service expenses during PC4. Consistent with the approach we have taken to business support functions (see below), we have as a consequence developed a revised forecast of Group & Shared Service Centre costs, first by considering what might be an appropriate base level of opex for PC4 and then the allowance for a step-up in cost during PC4 to support increase in workload. We have consider a forecast trend at a total business level rather than individual business function level. 26 GNI has stated elsewhere in its PC4 plan that it is instead resourcing to being a low value high volume delivery company. The capital works projects that the Major Projects unit is expected to support GNI on during PC4 do not appear to be clearly outlined in its PC4 submissions to date. 38

50 We acknowledge that 2016/17 is a forecast and consider there are reasons why the forecast should be going up and down relative to 2015/16, the final year of actual values. We therefore consider a sensible starting base year level of opex for Group & Shared Services may therefore be equivalent to the upper quartile of the 2015/16 and 2016/17 values reported by GNI in its BPQ response. As set out above, there are then good reasons why this base opex should be expected to increase over the forthcoming price control period. We have consequently allowed some step up in later years of PC4 in recognition of these factors. While the step-up is below GNI s request, we have referenced a number of factors (see above) for why the total GNI forecast increase has, in our view, not been fully justified. The BPQ highlighted the interaction between the scale of the planned capital works programme and Group & Shared Service expenses. Given our own proposed capex allowances are below GNI s BPQ request, this is another contributing factor for reducing the total business forecast from GNI s request. We have recommended a 5.5% reduction to the forecast Group & Shared Service expense allocations for the first year of PC4 (for all business categories) with the reduction increasing in 0.5% increments to 7.5% by the last year of the price control. Our recommendations are shown in Figure 5.2 below. Figure 5.2: Group and Shared Service Centre recommendations Source: GNI, Consortium For the regulated gas networks business as a whole (i.e. TBU and DBU), the proposed Group & Shared Service expenses (excluding IT) in PC4 are estimated to be an increase of 1.32m per annum on average over PC4 relative to reported Group & Shared Service allocations for 39

51 2015/16. Our recommended Group & Shared Service allocations allow for a c. 8% increase (in real terms) in this expense item relative to 2015/16 outturn levels. The proposed reduction in Group & Shared Service allocations relative to GNI s BPQ forecasts has been applied because we do not consider GNI has provided sufficient justification in its BPQ for why the allocations from Ervia should increase by nearly 10% (in real terms) by the end of the price control relative to 2015/16 levels. Overall, we would expect Group & Shared Service allocations to increase with the expected growth of the organisation and step-up in work-loads which GNI has projected in PC4. However, there are also a number of factors we would expect to constrain this step-up as we have detailed above. For this reason we have not allowed the forecast step-up in full Operations opex The table below shows our recommendations for the functions that make up operations opex for PC4, compared to GNI s funding request. Table 5.3: PC4 recommendations distribution operations opex ( 000s) Category 2017/ / / / /22 Total Asset Management 3,142 3,135 3,136 3,134 3,133 15,680 Asset Operations 32,967 33,843 34,551 34,970 35, ,889 Commercial 4,117 4,119 4,121 4,123 4,124 20,605 HSQE 2,109 2,100 2,082 2,111 2,090 10,493 Technical Competency ,925 Total 43,116 43,980 44,677 45,126 45, ,593 Source: Consortium Table 5.4: PC4 GNI request distribution operations opex ( 000s) Category 2017/ / / / /22 Total Asset Management 3,630 3,642 3,642 3,643 3,644 18,202 Asset Operations 36,161 36,705 37,182 37,510 37, ,522 Commercial 4,748 4,777 4,697 4,655 4,578 23,456 HSQE 2,109 2,100 2,082 2,111 2,090 10,493 Technical Competency ,925 Total 47,429 48,008 48,390 48,706 49, ,598 Source: GNI 40

52 Table 5.5: PC4 variance distribution operations opex ( 000s) Category 2017/ / / / /22 Total Asset Management ,521 Asset Operations -3,194-2,863-2,630-2,540-2,406-13,633 Commercial ,851 HSQE Technical Competency Total -4,313-4,028-3,713-3,581-3,371-19,005 Note: positive value indicates an increased recommendation compared with the requested amount Source: Consortium Asset Management GNI have set out plans to increase their expenditure in this area well above the average expenditure incurred during PC3. We recognise the positive plans GNI are making in developing their asset management strategy and note they are taking more strategic control of asset maintenance policy. In recognition of these plans we have made a recommendation based on staff costs rising 20% on the PC3 average, this represents a 7% reduction to the levels requested. In addition, we have applied the adjustments to Group and Shared Service costs as set out in section 5.2 above. The figure below shows our recommendations in the context of the trend across PC3 and PC4. Figure 5.3: Asset Management Opex Trend Source: GNI/Consortium 41

53 Asset Operations We have reviewed the workloads for the three key operational areas of Planned Maintenance, Unplanned Maintenance and Services and consider these to be reasonable and the unit rates in the forecast are consistent with PC3 actuals. However, we have reviewed the workloads in terms of a customer number driver and generated our own forecasts for the workloads over the PC4 period. We consider that the categories of spend for Planned Maintenance, Unplanned Maintenance and Services are largely driven by the number of customers on the network, as the number of DRIs, length of mains installed are also broadly driven by customer numbers. We recognise that specific larger customers can distort this broad assumption in localised consideration, however, across the whole network we believe it is a good indicator. The costs and activities for Asset Operations can be split into three key areas; Management and Support Activities; Siteworks; and Maintenance. Management and Support Activities The costs for Management and support are broadly consistent across PC3 and the PC4 forecast and therefore we have not made adjustments to these costs. Siteworks These activities are directly driven by the number of customers on the network and include emergency response, meter maintenance and other work at the customers premised. These workloads have been slightly reduced due to our assumptions on the growth in customer numbers covered in the Capex section of this report. We have used our normalised unit costs developed from our PC3 review of years 2012/13 to 2015/16 to calculate the average unit costs for all work activities. Maintenance These activities are associated with network plant and equipment. In the same way as siteworks, the last 4 years of actuals were used together with a scale factor for the size of the network to calculate workloads and unit rates for our assessment. We have calculated an average unit cost for our roll-forward rates assessment for PC4 as shown in the tables above. We have also calculated weighted average workloads of each category, weightings based upon the customer numbers in each year. Overall we have reduced the recommended allowance for PC4 from that requested by GNI, however our recommendations still show a step-up in costs compared with PC3 levels due to 42

54 the expending network and customers and new activities which GNI has identified which must be carried out. The figure below shows our recommendations in the context of the trend across PC3 and PC4. Figure 5.4: Asset Operations Opex Trend Source: GNI/Consortium Commercial As previously explained the commercial department was established at the start of PC3, with rising costs as the department has grown. A substantial element of the department s costs is allocated to growth promotion activities, with GNI requesting 18.1m over PC4. We recognise the benefit to existing consumers to exploiting the installed network assets, however, we have cut back this forecast to 15.3m, being a 50% increase on the annual expenditure incurred in the last full year of actuals (2015/16). The figure below shows our recommendations in the context of the trend across PC3 and PC4. 43

55 '000s Figure 5.5: Commercial Opex Trend Source: GNI/Consortium HSQE We have recommended no adjustment to this area of expenditure. The figure below shows our recommendations in the context of the trend across PC3 and PC4. Figure 5.6: HSQE Opex Trend 3,000 2,500 2,000 1,500 1, / / / / /17F 2017/ / / / /22 PC3 Actuals PC4 recommended PC4 GNI requested PC3 average Source: GNI/Consortium Technical competency We have recommended no adjustment to this area of expenditure. The figure below shows our recommendations in the context of the trend across PC3 and PC4. 44

56 '000s Figure 5.7: Technical Competency Opex Trend / / / / /17F 2017/ / / / /22 PC3 Actuals PC4 recommended PC4 GNI requested PC3 average Source: GNI/Consortium 5.5. Business support opex Our approach on business support opex has been to use GNI s historic costs and forecast costs to derive a recommended forecast for PC4. We adopt a three step approach. Step 1 we initially develop a normalised cost range for each business support function based on reported PC3 expenditure. Step 2 using the normalised cost range (based on PC3 values), we consider where in the range we think a base opex estimate should sit looking forward to PC4. Step 3 we consider the need for any additional step-up or step-down adjustments for additional activities, or activities no longer required during PC4. The normalised cost ranges seek to remove costs that we would expect not to occur in future e.g. reorganisation costs, or incurred costs in PC3 that are expected to be one-off in nature (e.g. a one-off regulatory or legal project). These can then be revised to reflect additional items of core opex forecast to be incurred in forthcoming years of the price control. We note that in the information reported in GNI s BPQ the detail is insufficient to completely strip away atypical costs in calculating our ranges for normalised cost. As a consequence, in reaching our recommendations for PC4 opex, we have carefully considered in each case whether our normalised / base opex estimate may already allow for some level of additional / atypical items in PC4, mitigating any need for Step 3 adjustments. The tables below shows our recommendations for the functions that make up business support services opex for PC4, compared to GNI s funding request. 45

57 Table 5.6: PC4 Recommendations business support costs ( 000s) Category 2017/ / / / /22 Total Head of Networks 1,978 2,125 2,106 2,087 2,074 10,370 R&C Services 4,363 4,332 4,333 4,329 4,326 21,683 Finance 7,971 7,905 7,917 7,900 7,894 39,587 Human Resources 2,420 2,402 2,401 2,398 2,394 12,015 Facilities 3,314 3,336 3,355 3,352 3,344 16,701 Total 20,047 20,099 20,112 20,067 20, ,356 Source: GNI Table 5.7: PC4 GNI request business support costs ( 000s) Category 2017/ / / / /22 Total Head of Networks 2,022 2,183 2,169 2,154 2,145 10,672 R&C Services 4,617 4,378 4,498 4,499 4,645 22,637 Finance 8,210 8,039 8,527 8,505 8,748 42,029 Human Resources 2,567 2,558 2,558 2,564 2,561 12,808 Facilities 3,437 3,529 3,643 3,627 3,654 17,890 Total 20,852 20,686 21,395 21,350 21, ,036 Source: GNI Table 5.8: PC4 variance business support costs ( 000s) Category 2017/ / / / /22 Total Head of Networks R&C Services Finance ,442 Human Resources Facilities ,189 Total ,283-1,283-1,722-5,680 Note: positive value indicates recommendations above the GNI funding request. Source: Consortium Head of Networks The only adjustments we have applied to this area of expenditure are to Group & Shared Service allocations as set out in section 5.2, otherwise we accept the GNI forecasts. The figure below shows our recommendations in the context of the trend across PC3 and PC4. 46

58 Figure 5.8: Head of Networks Opex Trend Source: GNI/Consortium Regulatory and Corporate Services Allowed Base Opex We established a range for distribution Regulation and Corporate Service normalised cost of c. 1.8m - 2.7m per annum, excluding Group & Shared Services, IT expenses and a number of items identified as one-off in GNI s BPQ (e.g. related to the Shannon LNG legal case dispute and a construction claims arising in relation to individual capex projects). The lower end of the range is more reflective of the earlier years of PC3 and the upper end of the range more reflective of forecast increase in expenditure of the department during 16/17. GNI began to increase growth related expenditure in the Regulatory and Corporate Services function in the latter years of PC3. It has also made a provision for an increase in growth activities in its PC4 opex projections. As detailed in Section 7, our PC4 recommendations for capex have reduced growth activities in PC4 relative to GNI s business plan. However, consistent with our comments on the commercial department (see section 5.3.3) we also recognise the benefits to existing consumers of GNI supporting growth related initiatives. We therefore included provision for growth (market development) related support activities as part of our normalised cost ranges for the Regulatory and Corporate Service function. We adopted the upper quartile of our normalised cost range as base opex for PC4 opex recommendations. This reflects the ongoing growth activities undertaken in PC4 and an expected increased number of connections relative to PC3, meaning there is an expected need to support a greater scope of service in PC4. 47

59 Allowed Step-up / down Opex Items While headcount for Regulation and Corporate services is expected to remain stable over PC4, two additional legal staff are expected to be added in light of the growth related activities and ramp up in activities for the PC4 period. Additional legal staff costs have been estimated by GNI as 63k p.a. on average for distribution and 57k p.a. for transmission. We have included these estimated costs in full as a step up on our base opex assumption. In addition, there will be atypical costs not foreseen at the time of this review that may occur and aiming up from the base cost would, therefore, seem suitable. Litigation and dispute costs, for example, are lumpy and unpredictable by nature. Our normalised costs do not strip out all one-off costs, although as highlighted above, we have subtracted one-off events that could be identified. We have, therefore, included an additional step up of 500k p.a. for each of distribution and transmission for these atypical costs. The level is higher due to the differing nature of services and increased scope for GNI in PC4 For PC3, Gaslink costs were included within their own line under pass-through opex. In practice, the services performed by Gaslink migrated to the Regulation and Corporate Services function within GNI during the price control. For PC4, Gaslink costs will be included within the reported expenditure of the Regulation and Corporate Services function rather than as a separate item. Total forecast PC4 Gaslink costs are 1.7m for distribution and 7.8m for transmission, excluding IT. This equates to a 346k p.a. increase for the DBU, and a 1.563m p.a. increase for the TBU on average over PC4. We have accepted GNI s forecasts in full for Gaslink opex costs and added this as a step-up adjustment to our base level opex. Group adjustments and overall recommendations Finally we have applied the proposed adjustment to GNI s forecast Group & Shared Service allocations to the Regulatory and Corporate Services department described in section 5.3 to derive a recommended opex trend as illustrated in the figure below. 48

60 Figure 5.9: Regulatory and Corporate Services Opex Trend Source: GNI/Consortium Finance Allowed Base Opex We established a range for Finance function normalised cost of c. 4.6m - 5.6m per annum, excluding Group & Shared Service allocations and IT expenses. We have then chosen the mid-point of the normalised cost range as a proposed base opex level which is broadly consistent with the 2015/16 outturn level but below the 2016/17 forecast expenditure (excluding Group & Shared Service allocations). Allowed Step-up / down Opex Items We have then applied a series of step-up / down adjustments to reach proposed opex recommendations. GNI state that they have consulted with experts in the insurance market in order to verify forecast premiums over the PC4 period. Based on current broker advice, GNI projects that insurance rates and premiums in the market will increase by c. 30% to 35% in real terms during PC4, and have built this assumption into the PC4 opex forecasts. We have applied a step-up adjustment of 700k p.a. in distribution and 225k p.a. in transmission over PC4 to our base opex to account for the expected increase in insurance expenses. This results in a PC4 run-rate for insurance above GNI s 17/18 forecast level but below the BPQ request for the latter years of PC4. Our recommendations will therefore challenge GNI to constrain the increase in the expense item below its business plan In part we believe this is justified by the lower level of allowed capex in our PC4 recommendations, compared to GNI s original BPQ forecasts. 49

61 We have applied a downward adjustment to the finance function people costs to reflect lower projected people costs in GNI s BPQ during PC4. This adjustment is 350k p.a. for distribution and 150k p.a. for transmission over PC4 resulting in forecast people costs broadly equivalent to GNI s BPQ proposals for the PC4 period. The final adjustment proposed relates to the reorganisation of the business and the transfer of assets/ liabilities in August GNI face additional costs from acting as a subsidiary that were previously undertaken at the Ervia Group level or within the Bord Gais Group. This includes credit rating agency fees, legal advice, costs related to the Euro Medium Term Note (EMTN) programme, statutory audit fees and administrative pension fees. We have made an annual adjustment to distribution only of 725k to account for this new activity. The activity is already considered to be accounted for in our normalised cost ranges for the TBU where we assumed a range of m Other infrastructure support expenses which covers GNI s forecast for this expense item during PC4. Group adjustments and overall recommendations We have applied the adjustment set out in section 5.3 to GNI s forecast Group & Shared Service allocations for the Finance function. Added to our recommendations for other Finance expense items we arrive at recommended opex trend set out in Figure 5.10 below. Figure 5.10: Finance Opex Trend Source: GNI/Consortium HR Allowed Base Opex GNI states that it expects HR headcount to remain flat in PC4. The function s planed objectives for PC4 include (but are not limited to) the continued development of GNI employees, developed stakeholder engagement, select and implement a best in class HR information system and the development of an employee engagement programme. 50

62 We established a range for distribution HR normalised cost of c. 1.1m - 1.5m per annum, excluding Group & Shared Service allocations and IT expenses. We have then used the midpoint of the normalised cost range as the adopted base level of opex for the HR function in PC4. Relative to actual and forecast 15/16 and 16/17 expenditure, we consider this covers a base level of activity required for PC4. Allowed Step-up / down Opex Items We have then included a step up adjustment for additional initiatives that GNI have highlighted that the HR function will undertake in PC4. This includes their Learning and Development programme and the potential for additional resources being required to conduct further recruitment activities. We note that this activity has been started within PC3, so may be included to some degree in our normalised cost range. However, we have still made an additional annual adjustment of 150k for distribution and 15k for transmission in our recommendations. Group adjustments and overall recommendations Again, the adjustment set out in section 5.3 is applied to forecast Group & Shared Service allocations to derive HR opex recommendations illustrated in Figure Figure 5.11: HR Opex Trend Source: GNI/Consortium Facilities Allowed Base Opex We established a range for Facilities function normalised cost of c. 1.9m - 2.4m per annum, excluding Group & Shared Service allocations. 51

63 GNI have stated that they expect increases in facilities opex during PC4 because there will be a rent renewal and a series of other facilities contracts will be up for renewal. This could impact on establishment costs and charges that are received from Group / Shared Services. GNI also expect square metres managed by facilities to increase slightly in PC4, but generally the function appears to be expected to operate close to business as usual, noting the points raised above related to rent renewal and facilities contracts. As such, we have used the midpoint of the normalised cost range to establish a base level of expenditure for PC4. Allowed Step-up / down Opex Items We have then included further step-up adjustments for changes in establishment costs and the expected rent increases in PC4, i.e. buildings and equipment maintenance, power and equipment, and rental expenditure. The increase in establishment costs are based on the renegotiation of framework agreements in light of improved economic conditions in Ireland and other factors out of GNI s control. We have allowed an annual upwards adjustment of 50k for each of the distribution and transmission businesses. There is a larger increase for rental costs. This includes notional rents at Donmoy House and at Finglas for the Network Services Centre, in addition to office space due to rent renewal over PC4. The annual adjustment is 275k each for distribution and transmission. Group adjustments and overall recommendations Again, the adjustment set out in section 5.3 is applied to forecast Group & Shared Service allocations to derive Facilities opex recommendations illustrated in Figure Figure 5.12: Facilities Opex Trend Source: GNI/Consortium 52

64 5.6. IT opex GNI stated that the PC3 capex projects would deliver 6.4m of opex benefits realisation and we note the links between capex and opex in investment decisions. GNI is requesting an increase of 35% in IT opex in PC4 relative to PC3 IT opex actual spend. The increase is significant and the annual increases are on average higher than industry benchmarks. While specific circumstances within GNI may explain the need for the increase in opex, GNI have only provided a high level explanation of the drivers of the forecast trend in expenditure, highlighting an increased user base and corresponding growing business demand for Mobile, Voice, and Data services. While these reasons may explain the increase in required IT opex, they have not been individually quantified and, therefore, are difficult to validate. In addition, opex benefits to be realised as a result of PC4 ICT capex projects have not been quantified in GNI s BPQ submission and it is unclear what assumptions have been made or whether these opex benefits have been factored into the submission. Without this information it is difficult to justify the increase. We have as consequence built up recommendations for GNI IT opex using a benchmarking methodology that compares GNI to utility peer groups and IT expenditure by the GB GDNs. Based on a benchmark of GNI's IT opex spend as a percentage of total expenditure, our analysis indicates that GNI on average is forecasting to spend 9% more on IT opex during PC4 than their peers. The corresponding figure for PC3 was also 9%. This benchmark excludes both SCADA/OT and market-facing systems costs from the benchmarking analysis. A similar benchmark, but removing market-facing systems only from the analysis, leads to a slight reduction in GNI s relative efficiency measured against the peer group. Given the critical nature of the services GNI provide on their infrastructure, it may be unreasonable to require them to adjust their IT opex spend in line with peer average instantly. Instead we recommend GNI be encouraged to reduce the variance between their requested IT opex spend and industry averages in a linear fashion over the 5-year period. However, given uncertainties around the benchmarking analysis and specific factors potentially impacting on GNI IT spend during PC4, we have applied the most conservative benchmark (i.e. excluding SCADA/OT and market-facing systems costs) to inform our recommendations. By decreasing the forecasted IT opex over time, GNI's year-on-year IT opex would be brought closer in line with its peers at the end of PC4. This gradual approach would result in an overall c.5.9% reduction in GNI's requested total PC4 IT opex spend. This adjustment would correspond to a PC4 IT opex allowance (TBU and DBU combined) of 71.9M. Our recommendations on distribution IT opex relative to PC3 trends and GNI s PC4 request are illustrated in the figure below. 53

65 Figure 5.13: IT Opex Trend Source: GNI/Consortium 5.7. Adjustments to bottom-up analysis As described in section 5.2, there are two adjustments made to our bottom-up assessment of opex. Both of the adjustments lead to a reduction in opex. The first relates to a catch-up efficiency adjustment. The second is a net ongoing efficiency adjustment. Our adjustments lead to a net 1.75% annual reduction factor relative to our bottom up assessment. This adjustment factor is compounded each year over the five year life of the PC4 control, with the annual compounded adjustment applied to our bottom-up opex assessment to set final distribution opex recommendations for each year of the price control Catch-up efficiency The findings of our historical benchmarking in Section 4 would suggest there is scope for GNI to improve the relative efficiency of its gas networks business during PC4. 28 Compared to an industry average efficiency benchmark, our econometric modelling suggested for the period that GNI was c. 4.75% off the average industry benchmark if averaging the opex predictions for our two preferred models and the full time period of the benchmarking analysis. Arguably GNI should also have the ambition to be a better than average performer which is one reason why other regulators have considered or adopted the upper quartile performer as the industry efficiency benchmark, rather than the industry average. 28 As part of the price review process GNI has submitted benchmarking analysis using forecast information. We have not taken this into account in our findings or completed our own benchmarking using forecast expenditure information, as we believe there is too much uncertainty of future outturn expenditure and changes in cost drivers across both GNI and the GB GDNs to draw any meaningful conclusions from the analysis. As a consequence we rely solely on the findings of the historical benchmarking. 54

66 We, however, recognise that there are a number of reasons to be cautious in drawing too strong conclusions from the benchmarking of GNI s relative efficiency given the differences in regime, currency base, age of network etc., between GNI in Ireland and the GDNs in GB. For this reason, we have used the industry average benchmark, although as discussed in Section 4, this is a point a of regulatory judgement and discretion and there may be reasons why in the context of the current price control in question, the CER might choose to adopt a more challenging efficiency benchmark (e.g. upper quartile). Taking the evidence in the round using the average industry efficiency benchmark, we suggest there is scope for the CER to include a catch-up efficiency target of 2.5% to 5% during PC4. Given the justification GNI has provided in its BPQ for the expected step-up in work-load and opex during PC4, we would suggest that this range of the catch-up target is applied to the final year of PC4, requiring GNI to meet a glide-path to this efficiency factor over the five-year period of the price control. In annualised terms, this would imply a compounding catch-up efficiency target of c % during PC4. We have applied a 0.75% annual but compounding catch-up efficiency assumption in our opex recommendations on the basis this is the mid-point of the range. We have not applied this to IT opex given that the bottom-up recommendations are already based on challenging GNI to perform to an industry average benchmark Ongoing efficiency assumption In analysing net ongoing efficiency we concluded that our analysis could support a range of efficiency factors between 0.5% and 3.0% per annum. GNI s proposed ongoing efficiency factor of 0.5% p.a. is at the lower bound of our suggested range and regulators have previously tended to select a conservative value from the range of plausible estimates. The CER could, therefore, be justified in accepting GNI s proposed factor. Alternatively, a more challenging efficiency factor in excess of 1% p.a. could be justified in light of strong productivity growth observed in the electricity, gas and water supply sector. We propose a 1.0% annual ongoing efficiency assumption, consistent with the precedent of the ongoing efficiency challenge that that CER adopted for GNI at the PC3 review. This would seem to strike a balance of taking a relatively conservative view from within our derived range, whilst still challenging GNI to improve its ongoing efficiency during PC4. We note that one of the comments which GNI has raised during the price review is if there are factors that are considered to constrain the input price (i.e. RPE) pressures that the company may face during PC4 (e.g. existing wage structures or contractual arrangements that fix the input prices of the gas business) then it would also be less realistic for GNI to be expected to achieve dynamic efficiency gains over PC4. While fixed contractual arrangements (e.g. long term partnership agreements with outsourced contractors) or existing company employment arrangements may have some limit on the ability of an operator to improve its dynamic efficiency, we note that productivity 55

67 improvements can also be realised through the quantity component of productivity measures. For example, even with relatively sticky wage structures, GNI should still be able in principle to realise productivity improvements through adopting new working practices (e.g. asset management systems), new technologies or limiting replacement of staff as opportunities for new working practices are identified. GNI may therefore be able to limit the volume of work-load during PC4 as a consequence of new productivity initiatives. Furthermore, we note it may be appropriate for the CER to take the view that the Irish gas consumer should not necessarily be prevented from receiving the benefits of productivity improvements within the sector as a result of the contracting decisions adopted by an individual regulated company in managing its business risks Impact on controllable opex Figure 5.14 below shows the impact of the proposed overall 1.75% net adjustment per annum applied to the bottom-up recommendations for controllable distribution opex. The downward sloping path in recommended opex reflects the compounding effect of the annual reduction factor. Figure 5.14: Total controllable opex net of reduction factor Source: GNI/Consortium The recommendations for the first year of PC4 includes a 2% increase on 2016/17 forecast controllable opex. There are further step-ups in our bottom-up analysis, however these are offset by our applied top-down adjustments. This presents a challenge for GNI to contain future increases in opex to the allowed step-up in the last year of PC3 / first year of PC4. 56

68 5.8. Innovation GNI have requested 25.0m of innovation funding during PC4 for the TBU and DBU. This was initially in addition to funding already included in the CER decision on the Causeway Study ( 12.83m) 29 which will fund the roll-out of a number of CNG stations during PC4. During the engagement process with GNI, this was revised to 25.0m inclusive of this Causeway Study funding. The request is split 90/10 TBU and DBU respectively. This request included a request for funding for biogas purification, power-to-gas, low carbon heating solutions and carbon capture and storage projects, as well as research and programme management funding. In developing a proposal for innovation opex in PC4, we have considered regulatory precedent of percentage of allowed innovation funding within allowed revenues, and the submission on innovation in GNI s BPQ Top down analysis We have reviewed regulatory precedent on allowed innovation funding. This includes previous CER decisions and Ofgem decisions in GB. A summary of these proposals are contained below. Table 5.9: Allowed innovation funding in other price controls Price control Innovation funding Total allowed revenues Percentage of innovation within allowed revenues CER DSO m 4,077.5m (exc smart meters), 4,577.5m (inc smart meters) 2.5% (exc smart) 2.2% (inc smart) CER TSO & TAO m ( 1.0m promotion of research, 2.21m research, development and demonstration) 771.7m (TSO only), 1,973.7m (TSO and TAO) 0.4% (TSO only) 0.2% (TSO and TAO) Ofgem RIIO GD NIA is expressed as % of allowed revenues NIC includes up to 160m for gas T&D 24,822m (GD1 only) 32,305 (GD1 + T1 (NGGD + SPTL)) NIA 0.5% (SGN, WWU) 0.6% (NGGD, NGN) NIC 0.6% (GD1 only) 0.5% (GD1 + T1) CER PC m 996m (D), 999m (T), 1,995m (T&D) 0.4% (T&D) Source: Regulatory determinations and Consortium analysis 29 CER (2016) Compressed Natural Gas Funding Request, Decision Paper, CER16/

69 A number of key points can be drawn from the top-down comparisons of innovation funding presented in the table above. There is a significant range of values between price controls across this group, including within the CER price controls. This reflects the different circumstances across sectors and priorities of the regulator. As an example, there is a significant difference between the innovation funding allowed for the electricity DSO and the electricity TSO & TAO decisions by the CER in PR4. The 100m DSO innovation funding was noted as providing clear long-term benefits to customers but involving significant cost in the short-term. In contrast the level of innovation funding for the TSO & TAO control was explained through the absence of a guarantee that technology trials will necessarily deliver a consumer benefit. There is, however, the potential for ESBN to request additional innovation funding in PR4 on a case-by-case basis, if there is robust supporting evidence of the need for project investment. The business case should set out the problem attempted to be solved, how the project will be governed, the project approval and evaluation milestones, how success is defined, the role of the TSO and an overall cost-benefit or multi-criteria analysis for the proposed project. Depending on the method chosen, total innovation funding available for the GB GDNs is around 1% of allowed revenues, as per the RIIO GD1 decision. A difference is that half of this funding is subject to competition, where only the best innovation projects proposed receive funding. As such, this reduces concerns over the funds not delivering consumer benefits in light of this competitive pressure Bottom up assessment We considered the funding proposals put forward by GNI utilising a set of assessment criteria, including whether the funding is likely to deliver consumer benefits, links to government policy and whether the funding request is consistent with the goals of the innovation fund. While the nature of the innovation fund means that there will be a less developed benefits case from investment than in the core control, we would still want to ensure that the money invested by the Irish gas consumer is worthwhile and there is a strategy in place for how the investment would lead to benefits. With the capex recommendations not including the requested funding for renewable gas infrastructure or CNG infrastructure, this creates additional uncertainty of the need for the proposed innovation funding in addition to the Causeway Study. In our view there was not a sufficiently established benefits case to accept GNI's proposals and as such the bottom up assessment indicated that GNI should seek to develop one or two favoured projects. Our approach has not attempted to directly select projects for funding, as permitting GNI to choose the projects that best meet the objectives of the innovation fund in our view continues to be appropriate. 58

70 Overall assessment As part of the Causeway funding decision, the CER noted that there would need to be exceptional circumstances to justify an increase in the innovation fund above the 12.83m allowed over PC4 for the Causeway Study. We note the costs involved in setting up the governance of the innovation fund and GNI s involvement in this process during PC3. Given the investment that has been made in establishing innovation activities, it does seem sensible to provide GNI with some funding provision to maintain these activities in PC4. Our proposal, therefore, is that there should be an additional 0.5m in total (i.e. 100k per annum) of innovation funding provided by the CER for programme management in addition to the 12.83m allowance already set out in the Causeway Study decision. This funding would be used to maintain the innovation framework developed at PC3 and support funding for GNI to obtain grants and other sources of funding for supporting innovation initiatives during PC4 e.g. energy research funding at EU level. In addition, one of the features of the PC3 innovation fund has been the ability of GNI to leverage research funding with other organisations. We would recommend including a further 1.0m in total for research (i.e. 200k per annum). For the PR4 (electricity TAO/TSO) decision, the CER noted that they would be open to reviewing future requests on a case-by-case basis. In light of the uncertainty around growth capex linked to innovation activities (e.g. support for renewable gas and CNG), this could also be an appropriate approach to take for strategic innovation projects in PC4 as well. The alternative would be make further provision for 1-2 strategic innovation projects in the exante controls for PC4, although inconsistent with the statement made by the CER as part of the decision related to the Causeway study. We propose an innovation funding allowance of 17.5m over PC4. Using GNI s forecast transmission and distribution allowed revenues in PC4 30 this would imply innovation funding in PC4 of c. 0.83% of allowed revenue. This would include provision for project management, research and a small number of strategic projects in addition to the existing allowance for the CNG Causeway study. Table 5.10: PC4 Recommendations Innovation opex for distribution and transmission ( 000s) Category 2017/ / / / /22 Total GNI request 5,000 5,000 5,000 5,000 5,000 25,000 Recommended 3,500 3,500 3,500 3,500 3,500 17,500 Variance -1,500-1,500-1,500-1,500-1,500-7,500 Source: GNI/Consortium Note GNI request is revised submission to include Causeway study ,041m and 1,095m for PC4 in total, which will be higher than allowed revenues if the proposals on opex and capex in this report are adopted by the CER. 31 We have made a simplifying assumption of GNI s expected funding profile for the 25m. 59

71 In setting final opex allowances for the TBU and DBU respectively, we have retained the GNI split of 90% weighting for transmission and 10% for distribution Pass-through costs As discussed above, pass-through costs no longer include Gaslink, which is included in business support service costs. Therefore, the five pass-through items for the distribution price control in PC4 are CER levy, Revenue Protection, Safety Advertising, Shrinkage and Rates. Below we consider the potential level of these costs during PC4. The proposed regulatory treatment of these pass-through items is considered in Section 8, along with other incentives operating under GNI s price control regime Shrinkage In general, we have accepted GNI s proposals for the majority of pass-through cost line items on distribution. The area where we have modified GNI s proposals on pass-through costs is shrinkage, where we have proposed a reduction in the Unaccounted for Gas (UAG) targets adopted by the CER for the PC4 period. We note that historically GNI has been able to outperform against the UAG estimates that had proposed in their BPQ submissions at previous price control reviews. With the exception of the introduction of Corrib gas, the arguments proposed for increases in UAG factors for PC4 broadly match previous submissions GNI has made at past price reviews (e.g. PC2 and PC3). For PC3, the CER assumed that there would be improvements over time. Outturn UAG factors within PC3 have been above the allowances in each year, though GNI are now approaching the target for the final year of PC3 as illustrated in the table below. Table 5.11: UAG factor over PC3 2012/ / / / /17 Allowed 1.00% 0.94% 0.88% 0.81% 0.75% Outturn 1.17% 1.00% 1.76% 0.86% TBC Source: GNI, Consortium GNI are proposing a UAG factor starting at 1.3% at the beginning of PC4, reducing to 0.9% in the final year of PC4. We agree with setting a challenge to improve over time, though disagree with the starting point proposed by GNI. GNI themselves note that the 2014/15 value represented an outlier, for which an investigation was undertaken and improvements made. Our proposed UAG factors are based on a starting point of the 2016/17 target and then applying a small ongoing annual improvement in performance of 0.05% p.a. We have not adjusted throughput estimates down from GNI forecasts, which we note likely provides some headroom to offset more challenging UAG targets. 60

72 Table 5.12: Proposed UAG factor target for PC4 2017/ / / / /21 Recommended 0.75% 0.70% 0.65% 0.60% 0.55% Source: Consortium The UAG factor is multiplied by system throughput to arrive at a UAG shrinkage factor, which is itself split into commodity and capacity elements. Transportation charges are then used to derive an overall monetary target Overall pass-through recommendations The table below summarises our pass-through proposals. Table 5.13: PC4 Recommendations Pass-through opex ( 000s) Category 2017/ / / / /22 Total CER levy 1,246 1,246 1,246 1,246 1,246 6,230 Revenue Protection ,079 Safety Advertising 2,157 2,431 2,392 2,421 2,179 11,579 Shrinkage 2,667 2,619 2,540 2,449 2,352 12,627 Rates 10,225 10,225 10,225 10,225 10,225 51,127 Total 16,907 17,134 17,019 16,959 16,624 84,642 Source: GNI For PC3, the CER have monitored these line items on an annual basis and have updated the forecast estimates accordingly for tariff setting purposes. We suggest the process continues during the PC4 control. 61

73 6. REVIEW OF PC3 AND 2011/12 CAPEX In this section we review PC3 capex, including the final year of PC2. The inclusion of the final year of PC2, 2011/12, stems from the fact that the outturn values were not known at the time of the PC3 determination and there are incentives around treatment of capex variations Overview The tables below show how distribution capex outturn compared to the allowances for PC3. As noted above, this includes the final year of PC2 for capex. Table 6.1: PC3 and 2011/12 outturn distribution capex ( 000s) Category 2011/ / / / / /17 Total Pipe capex 45,828 43,684 40,779 52,668 59,008 81, ,257 IT capex 2,590 2,122 1,932 3,640 3,872 4,225 18,380 Other non-pipe , ,675 1,673 5,662 Total (gross) 48,463 46,307 43,803 56,984 64,555 87, ,299 Contributions -3,149-2,913-2,647-4,121-4,955-4,540-22,326 Total (net) 45,313 43,394 41,156 52,862 59,600 82, ,974 Source: GNI Table 6.2: PC3 and 2011/12 (revised) allowance distribution capex ( 000s) Category 2011/ / / / / /17 Total Pipe capex 52,525 46,413 50,870 59,805 47,010 71, ,733 IT capex 3,638 4,190 3,424 3,168 2,298 2,336 19,053 Other non-pipe 2,468 1, ,135 Total (gross) 58,631 51,811 55,136 63,656 49,793 73, ,922 Contributions -2,538-2,657-1,793-2,346-4,538-3,320-17,192 Total (net) 56,092 49,154 53,342 61,310 45,255 70, ,730 Source: Consortium/ GNI Table 6.3: PC3 and 2011/12 variance distribution capex ( 000s) Category 2011/ / / / / /17 Total Pipe capex -6,696-2,730-10,091-7,137 11,998 10,180-4,476 IT capex -1,048-2,068-1, ,574 1, Other non-pipe -2, ,190 1, Total (gross) -10,168-5,504-11,333-6,672 14,762 13,292-5,622 Contributions , ,220-5,134 Total (net) -10,779-5,760-12,186-8,448 14,344 12,072-10,756 Source: Consortium/ GNI 62

74 PC3 incentive framework Under PC3 regulatory arrangements, GNI is rewarded for making savings against its capex allowances. Tariffs were set at the start of PC3, on the basis of an opening RAB value, together with a stream of project capex figures (set out in the PC3 decision) for capital works projects and programmes approved by the CER. In general terms, where GNI is able to achieve a saving compared to its project investment allowance, then it would be allowed to earn the rate of return plus a depreciation payment on the expenditure saved. It would retain this benefit for five years, at which point the notional RAB and depreciation payments are recalculated on the basis of the actual investments. The capex incentive is thus a rolling incentive mechanism. CER supplemented this regime with specific guidance in the PC3 determination on how it expected to approach assessing under and over spends of capex. This included cases where GNI may have achieved efficiency savings, but also cases where specific projects were not carried out or deferred, or GNI exceeded the allowance for the project / programme PC3 clawback As a result of the incentive framework put in place for the PC3 price control, unlike with PC3 opex, there is a potential revenue impact from capex over- or under-spends which require an assessment of the reasons for why capex outturn has differed from the allowance. This review includes the final year of PC2 capex, which was not known at the time of the PC3 determination, as the same capex guidelines and incentives applied in PC2 as well. Our assessment mechanism for the capex incentive is based on a two-step approach; Step 1: establish work quantities and unit costs Firstly, we have drawn upon the information presented by GNI to establish the following: The quantity of work anticipated when the PC3 allowances were set; If more work (or an equal amount) is delivered than the allowance anticipated; o The quantity of work delivered up to the quantity anticipated by the allowance o The additional quantity of work justified which is above the allowance quantity If less work is delivered than anticipated by the allowance; o The quantity of work delivered o The quantity of work deferred (not exceeding the allowance amount, less the quantity delivered) 63

75 Step 2: establish appropriate adjustments to the financial allowance There are a number of categories for assessing PC3 capex. These are defined in the table below, with the following table showing the regulatory treatment. Table 6.4: Calculation steps Term Ref Calculation steps Inputs Allowed volume Allowed unit cost Actual volume Actual unit cost A B C D Volume deferred E Cannot exceed A-C-F Volume disallowed F Calculations (Unit rate calculations made for each year to account for different Yearly Rates) Core calculations for volumes up to allowed volume (A) (Volume assessed on total period) Allowed efficient G min (A,C) x B Workload expenditure H min (A,C) x D Efficient savings I G H (if G>H) Unfinanced overspend J H G (if G<H) Efficient deferrals K E x B Extra calculations for volumes exceeding allowed volume (A) (Volume assessed on total period) Additional volume L C A F Allowed efficient M L x B Workload expenditure N L x D Efficient savings O M N (if M>N) Unfinanced overspend P N M (if M<N) Outputs Allowance Q A x B Revised Allowance R G + M + K Efficient Expenditure S G + M Financed overspend T M Unfinanced overspend U J + P Efficient Deferral V K Efficient Savings W I + O The treatment of these categories is shown below. 64

76 Table 6.5: Regulatory treatment of outputs Term Ref Treatment Outputs Allowance Q Original allowance for which revenues were set Revised Allowance R Updated allowance in light of newer volumes Efficient Expenditure S Included in RAB Financed overspend T Actual expenditure is added to RAB at start of next control No explicit WACC or depreciation penalty Unfinanced overspend U Actual expenditure is added to RAB at start of next control GNI face carry cost of overspend until next price control Efficient Deferral V Retain depreciation and return on PC3 No value (actual cost) added to the opening PC3 RAB Efficient Savings W GNI retain benefits of saving for five year period Source: Consortium Actual capex added to RAB for next price control We make an assessment of the work efficiently delivered and efficiently deferred to establish the appropriate adjustment to the financial allowance, by reference to the corresponding rate or amounts at the time of setting the PC3 allowance, to produce a Revised Allowance (R). This assessment leads to one of two variance scenarios between the expenditure incurred and the adjusted allowance; an underspend or an overspend as shown below. Figure 6.1: Capex variance scenarios Source: Consortium Expenditure less than the Revised Allowance In the lower scenario, the variance is allocated between Efficient Savings (W) and Efficient Deferrals (V). 65

77 Expenditure greater than the Revised Allowance In the higher scenario, there is no ability for the allocation of either Efficient Savings (W) or Efficient Deferral (V). Determination of workloads In the case of simple quantities of work, for example numbers of meters, services or length of mains installed the determination of workload quantities is straight-forward and the flexing of the allowance is applied in the same way as outlined above. In other areas of expenditure, the quantity of work is less easily determined. In these cases, we have used judgement and have asked for more information from GNI to establish these quantities where possible. Where it has not been possible to establish the quantities anticipated at the time of setting the allowance, we have assumed the quantity of work delivered is directly proportionate to the expenditure level reported by GNI. In these cases, we have also considered all the information presented to establish if: a case has been made that the work carried out was more difficult; or of greater quantity than was anticipated at the time the allowance was set; or due to efficient practices the amount of work delivered represents a greater proportion than would otherwise have been assumed. If a case has been made, we have adjusted the allowance to recognise the increased work delivered ratio. Our judgements have been based upon the evidence provided by GNI for the amount/difficulty of the work undertaken compared to that set out in the allowance. Where we are unable, in any sense, to assess the work anticipated or the work carried out we have been unable to recommend any efficient savings or deferrals. In conducting our initial review of PC3 transmission pipe capex, in principle we believe there are two scenarios where incurred expenditure by GNI could fall under the category of Unfinanced overspend (U): 1. where GNI has incurred capex for completed work but our review has not identified any need for the work to be completed; and 2. where GNI delivered a volume of work at a higher unit cost than was assumed at the time of the PC3 determination, but in our view there is no justification for why the operator exceeded the allowed unit rate. All of the expenditure that has been recommended as Unfinanced overspend, has fallen under the second of these two scenarios. In line with the capex guidelines the CER developed at PC2, and adopted again for PC3, our expectation is that for expenditure that falls within the second scenario for Unfinanced 66

78 overspend, the CER would not remunerate GNI for financing these higher capex costs in PC3, but the actual capex incurred would be included in the starting RAB for PC4. Differences in classification of expenditure between GNI and CEPA/RUNE As detailed in the next section of the report, there are a number of examples where our review of PC3 pipeline capex has proposed an alternative classification of expenditure than those presented in GNI s BPQ submission. For example, there are cases where our review has identified potential Efficient Savings when GNI may have not made a claim under that category for incentive calculation purposes. There are also examples where we have taken a different view to GNI on the justification for overspends relative to allowances. The cases where our review has identified Efficient Savings but GNI has not claimed any saving, are a result of the structured assessment mechanism (set out above) that we have applied to evaluate GNI s actual capex relative to allowances. We consider our approach to be a more structured and robust approach of classifying each of the expenditure variation categories that fall under the CER s capex guidelines, while still based on the historical capex report that GNI has submitted as part of its BPQ submission for PC4. PC3 review references Throughout the detailed assessment references are made to commentary and assumptions made by GL GL Noble Denton who were part of the CEPA led consortium that undertook the detailed review of forecast distribution capex plans in PC3. Where possible, our review of outturn distribution capex makes reference to the comments / assumptions included in the CEPA/GL PC3 capex working paper which supported the CER s final capex allowances. Gross and net capex We have netted off actual contributions from gross capex. Our assessment considers gross capex as this indicates the total cost, and then looks at contributions separately. Summary of our assessment The table below shows our assessment of PC3 capex using this methodology. The subsections which follow outline our proposals in further detail. 67

79 Table 6.6: Assessed PC3 and 2011/12 Capex Overall Recommendations ( 000s) Actual Efficient Spend Financed Assessment Overspend Unfinanced Efficient Saving Deferred Work Pipe capex 323, ,938 40,488 14,832 26,071 13,874 IT capex 18,380 18,380 Other non-pipe 5,662 5,662 Total (gross) 347, ,980 40,488 14,832 26,071 13,874 Contributions -22,326-22,326 Total (net) 324, ,655 40,488 14,832 26,071 13,874 Source: GNI/Consortium 6.2. Pipe capex GNI reported net expenditure of m against a reported flexed allowance of m, the original allowance was m, a breakdown of these figures into the main categories is shown in Tables 6.7, 6.8 and 6.9. Table 6.7: PC3 and 2011/12 outturn distribution pipe capex ( 000s) Category 2011/ / / / / /17 Total Connections 15,272 13,986 15,025 15,373 15,634 31, ,205 New Towns 2,092 6,839 2,419 8,226 13,618 12,381 45,575 Repex Mains 7,022 4,442 4,003 6,617 3,456 6,026 31,566 Repex Meters 18,944 13,616 13,473 13,805 14,587 13,915 88,341 Repex Services 2,481 3,374 3,341 6,507 7,581 7,246 30,530 Repex Other 17 1,426 2,517 2,140 4,110 6,080 16,290 CNG ,729 3,750 Total (gross) 45,828 43,684 40,779 52,668 59,008 81, ,257 Contributions (growth) Contributions (refurb) -2,431-2,151-1,901-3,415-4,085-3,735-17, ,607 Total (net) 42,679 40,771 38,132 48,547 54,052 76, ,931 Source: GNI 68

80 Table 6.8: PC3 and 2011/12 flexed allowance distribution pipe capex ( 000s) Category 2011/ / / / / /17 Total Connections 13,263 14,219 15,782 17,453 18,752 34, ,159 New Towns 7,808 5,496 11,349 11,349-7,000 43,002 Repex Mains 9,399 4,728 2,430 3,965 4,061 5,440 30,023 Repex Meters 17,772 13,702 11,887 14,326 15,010 14,794 87,491 Repex Services 4,130 4,765 4,410 3,638 2,103 2,102 21,148 Repex Other 153 3,503 5,012 9,074 7,084 7,084 31,910 CNG Total (gross) 52,525 46,413 50,870 59,805 47,010 71, ,733 Contributions (growth) Contributions (refurb) -2,197-2,442-1,578-2,131-4,323-3,105-15, ,416 Total (net) 49,986 43,757 49,077 57,459 42,472 67, ,541 Source: GNI Table 6.9: PC3 and 2011/12 original allowance distribution pipe capex ( 000s) Category 2011/ / / / / /17 Total Connections 17,218 20,191 21,441 22,714 24,204 25, ,291 New Towns 8,870 5,495 11,349 11,349-7,000 44,062 Repex Mains 7,861 6,894 4,288 4,063 5,774 5,779 34,660 Repex Meters 24,693 17,934 15,354 12,814 10,258 10,841 91,895 Repex Services 2,222 4,384 4,384 3,413 1,502 1,502 17,407 Repex Other 1,533 4,418 5,837 9,704 7,713 7,713 36,919 CNG Total (gross) 62,398 59,316 62,653 64,057 49,452 58, ,233 Contributions (growth) Contributions (refurb) -2,665-2,312-2,455-2,601-2,771-2,922-15, ,416 Total (net) 59,390 56,790 59,983 61,242 46,466 55, ,091 Source: GNI Our distribution pipe capex review is based on the methodology set out above and summarised in Table 6.4 and 6.5. To undertake this assessment, we have considered information provided by GNI both in its original BPQ submission and subsequently through a question and answer process. For each of the pipe capex projects or work areas, we assessed GNI s actual expenditure and classified this as shown in the following table: 69

81 Table 6.10: Assessed PC3 and 2011/12 Capex Pipe capex recommendations ( 000s) Actual Efficient Spend Financed Assessment Overspend Unfinanced Efficient Saving Deferred Work Connections 107,205 96,135 6,883 4,187 11,158 - New Towns 45,575 40,129 1,720 3,726 2,873 - Repex Mains 31,566 25,360 6, ,922 Repex Meters 88,341 77,249 5,369 5,722 5,905 6,709 Repex Services 30,530 15,474 13,859 1,197 1,500 - Repex Other 16,290 13,590 2,700-4,560 4,243 CNG 3,750-3, Total 323, ,938 40,488 14,832 26,071 13,874 Source: GNI/Consortium In the following sections we consider each of the category areas in turn: Connections The following chart shows the connections numbers, by sector, achieved during PC3 and in the final year of PC2, compared with the allowance. Figure 6.2: PC3 and 2011/12 New Connection numbers 16,000 14,000 12,000 10,000 8,000 6,000 4,000 2, / / / / / /17 New Housing Connections I&C Connections Mature Housing Connections Allowance Total Source: GNI/Consortium New connection to the gas network comprises three prime components; Mains Pipe Service Pipe 70

82 Meter As the chart shows the volume of new connections in the last year of PC2 and early years of PC3 were slightly higher than those provided for in the PC3 allowances, albeit the number of services laid during this period was lower than the allowance, due to a higher numbers of connections per service relative to the allowance. In the period 2011/12 to 2015/16 the total number of connections made were 36,551 compared with an allowed 34,301. In the final year of PC3 GNI are forecasting a further 14,228 connections will be made. We have challenged GNI to evidence this large anticipated volume of new connections in 2016/17. The table below shows the breakdown of volume of connections work carried out and forecast in PC3 compared to the allowance granted. Overall it is forecast that GNI will underspend the original allowance by 24.1m. Table 6.11: New Connections workloads and costs Allowance Actual Work /Unit Cost k Work /Unit Cost k New Housing Mains (km) ,261 11, ,751 10,561 Mature Housing Mains (km) 5 180, ,989 2,980 I&C Mains (km) ,014 34, ,838 13,168 New Housing Services 10, ,224 12, ,628 Mature Housing Services 21,832 1,884 41,134 19,924 1,977 39,384 I&C Services 5,132 2,637 13,531 3,815 2,905 11,084 New Housing Meters 13, ,061 15, ,478 Mature Housing Meters 24, ,496 30, ,172 I&C Meters 5,235 2,605 13,638 4,643 2,962 13,749 Total 131, ,205 Source: GNI/Consortium We have reviewed the expenditure in the separate areas as set out in the table below. Considerable savings were achieved in New Housing Mains, I&C Mains and New Housing Services compared to the rates allowed for PC3. However, this is offset by increased costs for Mature Housing Services, I&C Services and I&C Meters. We will take these variances into account when recommending rates for PC4. It is difficult to assess the specific meter costs in PC3 as the costs for all connection types are aggregated making unit costs comparisons difficult. Therefore, the efficient costs for average I&C meters depends on the workload blend of meter sizes. This category of work operates as part of the flexed allowance scheme therefore there is no deferred expenditure associated with these activities. The table below summaries our proposals for this category of pipe capex: 71

83 Table 6.12: Assessed PC3 and 2011/12 Capex New Connections ( 000s) Actual Efficient Spend Financed Assessment Overspend Unfinanced Efficient Saving Deferred Work New Housing Mains 10,561 8,677 1, ,066 - Mature Housing Mains 2, , I&C Mains 13,168 13, ,170 - New Housing Services 6,628 5,490 1,138-2,002 - Mature Housing Services 39,384 37,782-1, I&C Services 11,084 10, New Housing Meters 3,478 2, Mature Housing Meters 6,172 4,896 1, I&C Meters 13,749 12,086-1, Total 107,205 96,135 6,883 4,187 11,158 - Source: GNI/Consortium New Towns The table below provides a summary of the allowed and actual capex workloads, unit costs and expenditure for this category of spend over the review period. Table 6.13: New Towns workloads and costs Mains (km) Allowance Actual Work /Unit Cost k Work /Unit Cost k New Town (Nenagh) ,146 8, ,656 10,556 New Town (Wexford) ,999 13, ,967 17,975 New Town (Macroom) ,309 3, ,144 3,437 New Town (Tuam) ,735 3, ,536 3,432 New Town (Listowel & Foynes) ,630 7, ,351 5,800 New Town (Cootehill) ,331 5, ,988 4,761 New Town (Other) Total 43,002 45,575 Source: GNI/Consortium The new towns projects were delivered in order to provide gas connections to the nominated towns across Ireland. The towns were selected by GNI following a business case analysis of each town based on the expected expenditure versus the value to the network in terms of new connections. These analyses were subsequently submitted to the CER in order to attain approval to proceed with the projects. 72

84 We have reviewed each of the new town projects, one challenge to this process is that the mains work quantities that are associated with the expenditure allowance were not initially available and hence it was not possible to flex the allowance in proportion to the outturn workload quantity. GNI has subsequently been able to provide this information for the two projects where the actual expenditure was greater than the allowance. From our review of the information provided we have concluded that for both Nenagh and Wexford some of the overspend was related to matters outside of GNI s control and should be treated as Financed Overspend and the remainder as Unfinanced Overspend. We have also recommended Efficiency Savings on Macroom, Tuam, Listowel & Foynes and Cootehill. In the case of Other New Towns - 387k was referenced as cost recovery. To facilitate future reviews, we recommend that CER requires GNI to specify in detail the mains workload for all future projects. This may require a provisional project approval by CER, based on the NPV assessment, followed by confirmation of the allowance in terms of cost and mains quantities (pressure, pipe size/length, unit costs) when the detailed design has been completed and this information is available. The table below summaries our proposals for this category of pipe capex: Table 6.14: Assessed PC3 and 2011/12 Capex New Towns ( 000s) Actual Efficient Spend Financed Assessment Overspend Unfinanced Efficient Saving Deferred Work New Town (Nenagh) 10,556 8, New Town (Wexford) 17,975 13,918 1,229 2, New Town (Macroom) 3,437 3, New Town (Tuam) 3,432 3, New Town (Listowel & Foynes) 5,800 5, ,200 - New Town (Cootehill) 4,761 4, ,100 - New Town (Other) Total 45,575 40,129 1,720 3,726 2,873 - Source: GNI/Consortium Repex Mains The table below provides a summary of the allowed and actual capex workloads, unit costs and expenditure for this category of spend over the review period. 73

85 Table 6.15: Repex Mains workloads and costs Mains (km) Allowance Actual Work /Unit Cost k Work /Unit Cost k Mains Relocations ,642 2, ,642 5,045 Reinforcement (General) ,971 21, ,971 14,683 Reinforcement (Limerick 4Bar) 70 - Reinforcement (Limerick Optimisation) Reinforcement (Upgrade Dublin City Distribution Pressures) 1,635 2,975 1, Reinforcement (Waterford) ,250 1,300 Replacement Mains 4,250 4,779 Strategic Mains 3,486 2,040 Total 34,661 31,566 Source: GNI/Consortium This category mains reinforcement as well as the relocation and replacement of mains. There were significant under or over spends on most projects, the Limerick (4Bar) work was not carried out as it was linked to the Limerick Optimisation project. We have reviewed in detail each of the work areas and concluded that the overspends on mains relocations, Limerick optimisation, Waterford and replacement mains should be treated as Financed Overspend. We also concur with GNI that work associated with a reinforcement requirement at Naas AGI has justifiably been deferred into PC4 and that some work on the Dublin City Pressure Upgrade has been deferred pending a survey to identify issues with services to be identified and prioritised. We recommend that the expenditure associated with the deferred work is treated as Efficiently Deferred. The table below summaries our proposals for this category of pipe capex: Table 6.16: Assessed PC3 and 2011/12 Capex Repex Mains ( 000s) Actual Efficient Spend Financed Assessment Overspend Unfinanced Efficient Saving Deferred Work Mains Relocations 5,045 2,008 3, Reinforcement Mains (General) Reinforcement Mains (Limerick 4Bar) Reinforcement Mains (Limerick Optimisation) 14,683 14, , ,975 1,635 1,

86 Reinforcement Mains (Upgrade Dublin City Distribution Pressures) Reinforcement Mains (Waterford) ,060 1,300-1, Replacement Mains 4,779 4, Strategic Mains 2,040 2, Total 31,566 25,360 6, ,922 Source: GNI/Consortium Repex Meters The table below provides a summary of the allowed and actual capex workloads, unit costs and expenditure for this category of spend over the review period. Table 6.17: Repex Meters workloads and costs Allowance Actual Work /Unit Cost k Work /Unit Cost k Conversion Meters 71, ,736 65, ,334 Domestic Exchange Meters 34, ,305 54, ,082 I&C Exchange Meters 1, ,263 1,222 1,543 Meter Battery Replacement 12, , Meter Regulator Replacement 3, ,004 5, ,113 Planned Domestic Credit Replacement Meters Planned Domestic Prepayment Replacement Meters 168, , , ,297 2, , Planned I&C Replacement Meters 4,361 5,157 22,488 3,328 5,009 16,673 Smart Meters 1,440 1,298 1,869 1,440 1,114 1,604 Upgrade Gas Supply & Meter 14, ,561 8, ,362 Total 94,667 88,341 Source: GNI/Consortium This category covers all aspects of meter replacement, including meter battery replacement. There were significant under or over spends on most projects, in part due to differences between the allowed and actual workloads and unit costs. We have reviewed in detail each of the work areas, where possible a comparison was made of the unit rate estimated in the PC3 submission with the outturn unit costs for PC3 and proposed unit cost for PC4, where possible costs were also compared with UK norms. 75

87 In the case of two work areas (domestic exchange meters and meter regulator replacement) where expenditure was in excess of the allowance, actual workloads were significantly greater than allowed while unit costs were significantly less than allowed. We have concluded that whilst the overspends due to additional volumes of work completed should be treated as Financed Overspend, lower actual unit costs in some other work areas also mean Efficient Savings have been realised. Our full category assessment for this capex area is summarised in the table below: Table 6.18: Assessed PC3 and 2011/12 Capex Repex Meters( 000s) Actual Efficient Spend Financed Assessment Overspend Unfinanced Efficient Saving Deferred Work Conversion Meters 18,334 18, ,470 - Domestic Exchange Meters 10,082 6,385 3,697-2,885 - I&C Exchange Meters 1, Meter Battery Replacement Meter Regulator Replacement Planned Domestic Credit Replacement Meters Planned Domestic Prepayment Replacement Meters Planned I&C Replacement Meters 3,113 1,600 1, ,297 28,108-4, ,673 16, ,709 Smart Meters 1,604 1, Upgrade Gas Supply & Meter 3,362 2, Total 88,341 77,249 5,369 5,722 5,905 6,709 Source: GNI/Consortium Repex Services The table below provides a summary of the allowed and actual capex workloads, unit costs and expenditure for this category of spend over the review period. 76

88 Table 6.19: Repex Services workloads and costs Allowance Actual Work /Unit Cost k Work /Unit Cost k Brass Valves 1, Meterbox Replacement 16, ,787 80, ,896 Re-lay Service After Escape 2,754 1,600 4,406 4,912 1,265 6,216 Removal of Gun Barrel Services 2,219 1,152 2,555 2,959 1,152 3,408 Remove 4Bar in Buildings 3,211 1,262 Replace PE Service in Building Line 4,264 1,380 5,885 6,700 1,380 9,247 Total 19,732 30,530 Source: GNI/Consortium This category includes various service and service related items. There were significant under or over spends on most projects, in part due to differences between the allowed and actual workloads and unit costs. In the case of meter box replacement where actual workload was some five times great than the allowance, we have concluded that the additional expenditure associated with the increased workload at the allowed unit rate be treated as Financed Overspend and the remainder associated with actual unit costs above the allowed level as Unfinanced Overspend. For replacement of PE services in the building line and removal of gun barrel services we have concluded that the overspend should be treated as Financed Overspend. Re-lay service after escape, where again the workload was much greater than the allowance, showed a lower actual unit cost and so we have recommended Efficient Savings as well as Financed Overspend. For replacement of brass valves and removal of 4 Bar in buildings, where the scope of work was not clear at the time the allowance was granted and where it has evolved in response to further information and risk assessment, we think GNI has adopted a reasonable approach have assessed the actual expenditure as Efficient Spend. The table below summaries our proposals for this category of pipe capex: 77

89 Table 6.20: Assessed PC3 and 2011/12 Capex Repex Services ( 000s) Actual Efficient Spend Financed Assessment Overspend Unfinanced Efficient Saving Deferred Work Brass Valves Meterbox Replacement 9,896 1,787 6,912 1, Re-lay Service After Escape 6,216 3,484 2,731-1,500 - Removal of Gun Barrel Services 3,408 2, Remove 4Bar in Buildings 1,262 1, Replace PE Service in Building Line 9,247 5,885 3, Total 30,530 15,474 13,859 1,197 1,500 - Source: GNI/Consortium Repex Other The table below provides a summary of the allowed and actual capex expenditure for this category of spend over the review period. Table 6.21: Repex Other workloads and costs Allowance Actual Work /Unit Cost k Work /Unit Cost k ATEX Upgrades 11,242 4,210 C&I Upgrades 2,564 2,001 Emergency Upgrades - 2,700 Installation Upgrades 15,191 6,537 Update GIS Records 2, Total 31,910 16,290 Source: GNI/Consortium This category covers a number of upgrades associated with AGIs. In all cases, apart from emergency upgrades, actual expenditure is less than the allowance and in the cases of ATEX and installation upgrades, substantially less. We have reviewed in detail each of the work areas and concluded that GNI has achieved justifiable savings in all of cases where expenditure exceeds allowance, which should be treated as Efficient Savings. Emergency upgrades cover a number of programmes that were initiated during PC3 as a result of either learning from incidents or issues identified which required a priority response. The main issues identified were; 78

90 replacement of 305 kerotest valves, replacement of 5,648 Donkin 225 regulators, recovery/remediation of c 140 DRI isolation valves, and various leak management related activities. We are satisfied that these activities are required and that GNI have progressed them appropriately, so we recommend that this expenditure, for which there was no allowance, is treated as Financed Overspend. The table below summaries our proposals for this category of pipe capex: Table 6.22: Assessed PC3 and 2011/12 Capex Repex Other( 000s) Actual Efficient Spend Financed Assessment Overspend Unfinanced Efficient Saving Deferred Work ATEX Upgrades 4,210 4, ,633 - C&I Upgrades 2,001 2, Emergency Upgrades 2,700-2, Installation Upgrades 6,537 6, ,184 4,243 Update GIS Records Total 16,290 13,590 2,700-4,560 4,243 Source: GNI/Consortium CNG The table below provides a summary of the allowed and actual capex expenditure for this category of spend over the review period. Table 6.23: CNG workloads and costs Allowance Actual Work /Unit Cost k Work /Unit Cost k CNG - 3,750 Source: GNI/Consortium GNI have developed proposals for a number of CNG stations during PC3 and progressed these initially under an Innovation allowance. The forecast expenditure of 3.75m is additional to that Innovation allowance based on our understanding of the GNI submission. 32 Subsequent to the submission of this proposal this funding request for 3.75m has been included by GNI within a broader CNG proposal, known as the Causeway Study, for which CER have agreed a funding approach. The table below confirms our proposals: 32 The treatment of this CNG expenditure within the revenue controls is to be confirmed at the final determination given that CNG has been funded in PC3 through the opex innovation allowance. 79

91 Table 6.24: Assessed PC3 and 2011/12 Capex CNG ( 000s) Actual Efficient Spend Financed Assessment Overspend Unfinanced Efficient Saving Deferred Work CNG 3,750-3, Source: GNI/Consortium 6.3. IT capex One of the key drivers of IT expenditure was the deferral of IT capital programme initiatives e.g. Oracle Release 12 upgrade, WAM systems upgrade and Digital Strategy implementation. Overall GNI has forecast IT capex to exactly match the allowance, with forecast spend in the final year of PC3 matching the gap between total allowed and total outturn to date. GNI underspent on capex significantly in the first three years of the regulatory period, with backloading in the final two years. In our view, the delays to the project appear reasonable and GNI remained within the capex allowance for the period. The table below shows outturn IT capex for PC3. Table 6.25: PC3 and 2011/12 outturn IT capex ( 000s) Category 2011/ / / / / /17 Total Outturn 2,590 2,122 1,932 3,640 3,872 4,225 18,380 Source: GNI 6.4. Other non-pipe capex Other non-pipe capex covers investment in GNI s property and facilities services, together with their fleet of vehicles and associated equipment. Allowances were granted in transmission and distribution for the upkeep of buildings and fleet. GNI anticipate spending in-line with this allowance over PC3. Table 6.26: PC3 and 2011/12 outturn other non-pipe capex ( 000s) Category 2011/ / / / / /17 Total Outturn , ,675 1,673 5,662 Source: GNI 6.5. Contributions Contributions are in two different areas; growth and refurb. GNI received a higher volume of contributions to net off gross capex than included in setting PC3 allowances for both categories. 80

92 Table 6.27: PC3 and 2011/12 outturn contributions (growth) ( 000s) Category 2011/ / / / / /17 Total Outturn -2,431-2,151-1,901-3,415-4,085-3,735-17,719 Allowance -2,197-2,442-1,578-2,131-4,323-3,105-15,776 Variance , ,943 Source: GNI Table 6.28: PC3 and 2011/12 outturn contributions (refurb) ( 000s) Category 2011/ / / / / /17 Total Outturn ,607 Allowance ,416 Variance ,191 Source: GNI 81

93 7. REVIEW OF PC4 CAPEX In this section we set out our proposed recommendations for distribution capex for the PC4 price control period Overview The tables below show how our recommendations compare to the GNI business plan for PC4 on distribution capex. This is broken down into pipe capex, IT capex and non-pipe capex to arrive at a gross capex total. Contributions are then netted off this figure. Table 7.1: PC4 recommended distribution capex ( 000s) Category 2017/ / / / /22 Total Pipe capex 68,080 63,551 67,279 68,088 67, ,052 IT capex 4,260 3,836 4,636 4,841 4,714 22,287 Other non-pipe 1,280 1,528 1,096 1,493 1,245 6,642 Total (gross) 73,620 68,915 73,012 74,422 73, ,982 Contributions -6,763-6,418-6,432-6,409-6,429-32,452 Total (net) 66,857 62,497 66,579 68,013 66, ,530 Source: GNI Table 7.2: PC4 GNI request distribution capex ( 000s) Category 2017/ / / / /22 Total Pipe capex 101, , , , , ,427 IT capex 4,383 4,065 5,063 5,454 5,485 24,448 Other non-pipe 1,447 1,702 1,172 1,580 1,325 7,227 Total (gross) 107, , , , , ,102 Contributions -10,670-11,581-11,132-11,009-10,989-55,380 Total (net) 96, , , , , ,722 Source: GNI Table 7.3: PC4 variance distribution capex ( 000s) Category 2017/ / / / /22 Total Pipe capex -33,384-43,316-45,254-49,628-46, ,374 IT capex ,161 Other non-pipe Total (gross) -33,674-43,719-45,757-50,327-47, ,120 Contributions 3,906 5,163 4,699 4,600 4,560 22,928 Total (net) -29,768-38,556-41,058-45,728-43, ,192 Source: GNI 82

94 7.2. Methodology Our assessment has been made by looking at the three broad capex categories noted above. We have looked to break the allowances down further and link these to projects or a broader overall programme in setting allowances. Having this clarity of outputs with associated funding should support a future review of capex efficiency at the PC5 determination Pipe capex The tables below provide a summary of capex recommendations for pipe capex over the review period, the GNI requested amount and the variance between this and our recommendations. GNI has requested distribution pipe capex expenditure of m for the PC4 period. Following our review, we have recommended a total of a total m. Table 7.4: PC4 recommended distribution pipe capex ( 000s) Category 2017/ / / / /22 Total Connections 24,767 24,868 24,994 24,966 24, ,555 New Towns 9, ,129 Repex Mains 5,798 6,639 7,077 5,566 5,399 30,479 Repex Meters 15,419 15,763 19,342 20,304 20,304 91,132 Repex Services 10,631 12,328 11,527 11,189 10,021 55,697 Repex Other 2,332 2,957 4,339 6,062 6,370 22,061 CNG Total (gross) 68,080 63,551 67,279 68,088 67, ,052 Contributions (growth) -5,959-5,613-5,628-5,604-5,625-28,429 Contributions (refurb) ,023 Total (net) 61,317 57,133 60,847 61,679 60, ,601 Source: GNI Table 7.5: PC4 GNI request distribution pipe capex ( 000s) Category 2017/ / / / /22 Total Connections 45,120 48,455 45,864 45,456 45, ,090 New Towns 11,002 1, ,202 Repex Mains 6,832 14,031 14,835 12,597 12,427 60,722 Repex Meters 15,383 15,778 21,680 23,268 23,268 99,377 Repex Services 12,946 17,807 21,043 23,169 18,149 93,112 Repex Other 2,682 3,346 5,362 6,976 7,307 25,674 CNG 7,500 6,250 3,750 6,250 7,500 31,250 83

95 Category 2017/ / / / /22 Total Total (gross) 101, , , , , ,427 Contributions (growth) -9,865-10,776-10,327-10,204-10,185-51,357 Contributions (refurb) ,023 Total (net) 90,795 95, , , , ,047 Source: GNI Table 7.6: PC4 variance distribution pipe capex ( 000s) Category 2017/ / / / /22 Total Connections -20,353-23,587-20,871-20,490-20, ,536 New Towns -1, ,073 Repex Mains -1,034-7,392-7,757-7,031-7,029-30,243 Repex Meters ,338-2,963-2,963-8,245 Repex Services -2,314-5,479-9,515-11,979-8,128-37,415 Repex Other , ,613 CNG -7,500-6,250-3,750-6,250-7,500-31,250 Total (gross) -33,384-43,316-45,254-49,628-46, ,374 Contributions (growth) 3,906 5,163 4,699 4,600 4,560 22,928 Contributions (refurb) Total (net) -29,478-38,153-40,555-45,028-42, ,446 Source: GNI In the following sections we consider each of the category areas of pipe capex in turn Connections As part of their PC4 submission GNI submitted challenging forecasts for the number of new connections of the three connection types: Domestic New Housing Domestic Mature Housing I&C Connections Our initial thoughts were that these targets were unrealistic. CER considering the issue requested that we estimate the Business as Usual (BAU) numbers for rolling forward throughout PC4. We have based our assessment of the BAU numbers upon the volumes of connections made in the first four years of PC3, together with the most recent information supplied by GNI for the first five months of 2016/17. 84

96 GNI were concerned that the 2015/16 volumes were not representation of the higher volumes already seen in the period Oct 2016-Feb 2017 and undertook to provide more details of this data. Our conclusions are shown in the following three charts. Figure 7.1: PC4 New Connection Numbers New Housing 20,000 15,000 10,000 5, / / / / /22 GNI Request Recommended Source: GNI/Consortium Figure 7.2: PC4 New Connection Numbers Mature Housing 10,000 8,000 6,000 4,000 2, / / / / /22 GNI Request Recommended Source: GNI/Consortium Figure 7.3: PC4 New Connection Numbers Industrial & Commercial 2,000 1,500 1, / / / / /22 GNI Request Recommended Source: GNI/Consortium The table below provides a summary of the requested and recommended capex workloads, unit costs and expenditure for this category of spend over the review period. 85

97 Table 7.7: PC4 recommended distribution pipe capex; New Connections Request Recommend Work /Unit Cost k Work /Unit Cost k New Housing Mains (km) ,679 34, ,000 23,470 Mature Housing Mains (km) ,262 28, ,000 12,677 I&C Mains (km) ,952 22, ,171 10,332 New Housing Services 41, ,503 32, ,729 Mature Housing Services 34,340 1,983 68,102 15,835 1,983 31,406 I&C Services 5,397 2,961 15,981 2,770 2,914 8,072 New Housing Meters 50, ,902 40, ,988 Mature Housing Meters 39, ,408 22, ,587 I&C Meters 6,776 2,970 20,127 3,475 2,962 10,293 Total 230, ,555 Source: GNI/Consortium We have reviewed both the volume of work proposed by GNI and the rates they have forecast. For the total package of work associated with new connections GNI have forecast a total gross expenditure of 230.1m over PC4. Using our own assessment of the rates for each element or work, we have reduced the total anticipated expenditure for this volume of work to 219.7m, a reduction of 5%. We have used GNI s own performance in PC3 as our primary guide to the assessment of appropriate rates for PC4. The table above shows the reduced level of work, which together with our rate assessment, gives a recommended total expenditure for PC4 of m. The chart below shows the requested and recommended capex in this category of spend for each year of the PC4 period. Figure 7.4: PC4 Capex - distribution pipe capex profile; New Connections ( 000s) 60,000 50,000 40,000 30,000 20,000 10, / / / / /22 Requested Recommended Source: GNI/Consortium 86

98 New Towns The table below provides a summary of the requested and recommended capex workloads, unit costs and expenditure for this category of spend over the review period. Table 7.8: PC4 recommended distribution pipe capex; New Towns Request Recommend Mains (km) Work /Unit Cost k Work /Unit Cost k New Town (Listowel & Foynes) ,351 12, ,000 10,129 Source: GNI/Consortium Our review and assessment of the PC4 Listowell and Foynes New Town Mains Mains forecast makes no adjustment to GNI's Planned Workload and is based on determination of an efficient unit cost only. GNI has based their requested expenditure on overall actual average PC3 unit cost of 349/m, however, this is is significantly influenced by the proportion of large 315mm mains laid in the PC3 period and we recommend a blended unit rate of 290/m as an appropriate basis for the PC4 allowance. The chart below shows the requested and recommended capex in this category of spend for each year of the PC4 period. Figure 7.5: PC4 Capex - distribution pipe capex profile; New Connections ( 000s) 12,000 10,000 8,000 6,000 4,000 2, / / / / /22 Requested Recommended Source: GNI/Consortium Repex Mains The table below provides a summary of the requested and recommended capex workloads, unit costs and expenditure for this category of spend over the review period. 87

99 Table 7.9: PC4 recommended distribution pipe capex; Repex Mains Mains (km) Request Recommend Work /Unit Cost k Work /Unit Cost k Mains Relocations ,177 5, ,088 5,358 Reinforcement Mains (General) ,000 17, ,000 16,771 Reinforcement Mains (Upgrade Dublin City Distribution Pressures) Reinforcement Mains (Waterford) 4, ,000 1, , , Proximity Mains 10,365 6,049 Supply Security Mains ,796 22,566 - Total 60,722 30,479 Source: GNI/Consortium We have reviewed each of the work areas in detail and in the case of mains relocations and reinforcement mains have recommended reductions to the requested unit rates, whereas we concur with the requested rate for Waterford. The Dublin City upgrade proposes a range of activities associated with the network uprating project, we recognise that significant challenges are to be expected in progressing such a project, even on a substantially PE network. Given the scale and complexity of the undertaking and the potential cost and scope challenges, together with the range of benefit opportunities, we anticipate that GNI would adopt a structured programme management approach with clearly defined work packages, timescales, milestones and accountabilities and have taken this into account in our recommendation. For proximity mains, we have taken a view on the level of different activities proposed, which include, moving mains, protecting mains and GIS updating to recommend the allowance. In the case of supply security mains, GNI is proposing a programme of reinforcements to improve the security of supply in their 11 largest networks, this is based on EU Regulation 994/2010 related to the failure of a single element of infrastructure. We do not consider that the proposed programme is an appropriate interpretation of these Regulations and as GNI has not provided a business case to demonstrate the benefits of such an investment, we recommend that no allowance is provided. The chart below shows the requested and recommended capex in this category of spend for each year of the PC4 period. 88

100 Figure 7.6: PC4 Capex - distribution pipe capex profile; Repex Mains ( 000s) 20,000 15,000 10,000 5, / / / / /22 Requested Recommended Source: GNI/Consortium Repex Meters The table below provides a summary of the requested and recommended capex workloads, unit costs and expenditure for this category of spend over the review period. Table 7.10: PC4 recommended distribution pipe capex; Repex Meters Request Recommend Work /Unit Cost k Work /Unit Cost k Conversion Meters 41, ,558 41, ,555 Meter Battery Replacement 143, , , ,749 Meter Regulator Replacement 9, ,313 9, ,313 Planned Domestic Credit Replacement Meters 180,384 Planned Domestic Prepayment Replacement Meters Planned I&C Replacement Meters , , ,700 22, ,440 22, ,438 5,576 5,225 29,137 5,576 5,005 27,909 Upgrade Gas Supply & Meter 6, ,469 6, ,468 Total 99,377 91,132 Source: GNI/Consortium We have reviewed in detail the requested workloads and unit costs in each of work areas and, with one exception, have only proposed minor changes to GNI s proposals. In the case of Planned Domestic Credit Replacement Meters and based on the volume performance in PC3, we have recommended whet we think is a more realistic workload target. The chart below shows the requested and recommended capex in this category of spend for each year of the PC4 period. 89

101 Figure 7.7: PC4 Capex - distribution pipe capex profile; Repex Meters ( 000s) 25,000 20,000 15,000 10,000 5, / / / / /22 Requested Recommended Source: GNI/Consortium Repex Services The table below provides a summary of the requested and recommended capex workloads, unit costs and expenditure for this category of spend over the review period. Table 7.11: PC4 recommended distribution pipe capex; Repex Services Request Recommend Work /Unit Cost k Work /Unit Cost k Brass Valves 10, ,986 6, ,000 Excess Flow Valves 9, ,100 9, ,850 Meterbox Adaptors 5,800 1,160 6,728 6, ,600 Meterbox Replacement Multiple Occupancy Buildings 89, ,922 87, ,401-23,512 5,500 Other Relay Service 9,271 1,834 17,000 7,000 1,834 12,836 Re-lay Service After Escape Removal of Gun Barrel Services Remove 4Bar in Buildings Replace PE Service in Building Line Replace 1" Donkin Valves Replace/Refurbish Test PRI 4,990 1,267 6,323 4,990 1,267 6,322 1,000 1,100 1,100 1,000 1,100 1,100-1,935 1,935 6,000 1,722 10,332 5,400 1,380 7, , , Total 93,112 55,697 Source: GNI/Consortium 90

102 We have reviewed in detail the requested workloads and unit costs, where available, in each of the work areas and recommended some significant reductions. One rationale for reducing workloads is the potential interaction between replacement activities. For example, we would anticipate that brass valves on non-pe services or those with gun barrel at the house end of the service would be addressed by relays on other programmes. In the case of excess flow valves, we have recommended a reduced unit rate as we are aware of alternative installation techniques and assume that the significant majority of such installations will in future be performed via insertion from the meter box. We do not accept the rationale behind GNI s proposal to replace, refurbish and test PRIs, the anticipated programmes are not defined and we recommend that GNI's requirements are met from the Operational Upgrade programme and, therefore, we recommend that no allowance is provided for this activity. The chart below shows the requested and recommended capex in this category of spend for each year of the PC4 period. Figure 7.8: PC4 Capex - distribution pipe capex profile; Repex Services ( 000s) 25,000 20,000 15,000 10,000 5, / / / / /22 Requested Recommended Source: GNI/Consortium Repex Other The table below provides a summary of the requested and recommended capex workloads, unit costs and expenditure for this category of spend over the review period. 91

103 Table 7.12: PC4 recommended distribution pipe capex; Repex Other Request Recommend Work /Unit Cost k Work /Unit Cost k ATEX Upgrades 2, C&I Upgrades 5,247 5,247 Installation Upgrades 14,677 12,814 Scada Refurbishment 2,750 2,750 Update GIS Records Total 25,674 22,061 Source: GNI/Consortium We have reviewed in detail the proposed expenditure for each of the work areas and in three of the cases our recommendations align with GNI s request. For ATEX upgrades we have concluded that an unspecified programme cannot be justified at the level proposed, particulary given the extent of under spend on the core ATEX compliance programme in PC3. We recommend that an allowance of 750k be provided to support resolution of any prioritised issues that cannot be resolved on other associated programmes. For installation upgrades, which consists of a number of different activities, we accept the proposed costs apart from those associated with upgrades of AGL installations and removal of deep pits, where we have recommended reductions in scope and cost. Figure 7.9: PC4 Capex - distribution pipe capex profile; Repex Other ( 000s) 8,000 6,000 4,000 2, / / / / /22 Requested Recommended Source: GNI/Consortium 7.4. IT capex GNI has requested 48.75M of IT capex for both GNI and Ervia Centrally Delivered IT capital initiatives, an increase of 12.03% on PC3 IT capex spend. The benefits and project scope of these initiatives have only been qualitatively outlined which GNI has explained is due to the capex projects not yet going through 'Gate 3' investment approval, which is when quantitative analysis of initiatives occur. The qualitative explanations seem valid but it is difficult to justify the requested IT capex spend without a description of the quantified benefits to be realised. 92

104 The IT capex within a price control period can vary significantly by company and by price control period depending on the individual circumstances of each business, e.g. the company asset profile. For example, GNI's GB gas network peers experienced a large decrease in their benchmarking indicator of IT capex/total Expenditure from PC3 to PC4. Based on the benchmark of GNI's IT capex spend as a percentage of total expenditure over the combined 10-year period of PC3 and PC4 (forecast), GNI spends 16% more on average of IT capex in comparison to its peers. Similarly the industry average is 14% lower than GNI's forecast IT capex spend. Following the same logic as with the IT opex forecast, we adopt a gradual reduction that results in an overall 9% reduction in GNI's requested total PC4 IT capex spend. The table below shows how our recommendation differs to the GNI request for PC4 IT capex for the distribution business. Table 7.13: PC4 recommended IT capex ( 000s) Category 2017/ / / / /22 Total Recommended 4,260 3,836 4,636 4,841 4,714 22,287 GNI request 4,383 4,065 5,063 5,454 5,485 24,448 Variance ,161 Source: GNI 7.5. Other non-pipe capex GNI s submission has demonstrated that their PC4 non-pipe capex proposal (excluding IT) is generally underpinned by a number of specific (scoped) buildings projects and/or drivers of fleet investment that are linked to wider changes taking place within the gas networks business (e.g. apprentice schemes). It is also to be expected that office buildings will over time require refurbishment and modernisation. Therefore, GNI s BPQ submission at least makes a reasonable business case of the need for why planned non-pipe investment (excluding IT) should take place. However, it is still very difficult to reach any conclusions on whether the business has already taken the difficult choices on behalf of the Irish gas consumers to control the scale and scope of planned investment (e.g. specification of the proposed upgrade of the major GWR building investment) in preparing its capex plans. For this reason, we believe the CER should look to challenge GNI to deliver the major projects it has proposed for PC4 within a lower budget envelope. The proposed challenge is supplemented by the efficiency incentives that exist for GNI under the existing revenue cap / rolling capex incentives. For facilities investment, we have proposed a 25% reduction in the assumed cost for upgrade projects with GWR and Donmoy House, plus Grid Control relocation to challenge GNI to find efficiencies in the design and procurement of its buildings, together with a lack of justification for why costs in this area should have increased significantly since PC3. 93

105 For a number of areas, including other facilities capex projects, vehicles/ fleet investment and fleet equipment, we do not have sufficient confidence to allow the proposed expenditure in full. We have applied a 10% reduction to the GNI BPQ request. In addition, it is important to consider how these investments might interact with other areas of the overall revenue allowances for PC4. As an example, an investment in the fleet could indicate that GNI are looking to do a greater proportion of work in-house rather than rely on contractors as much. As such, we would expect to see that there would be countervailing cost decreases in other areas, for example, with reduced opex in light of the use of fewer contractors. However, we have not seen any evidence of this in GNI s BPQ submission. GNI provided very limited information on its proposed Shared & Group Equipment capital expenditure, including justification for why the proposed allocation of 0.7m is an appropriate figure relative to how capex is recovered through other parts of the group business. Given the limited justification provided, we have proposed a 25% reduction for this item relative to GNI s request. Table 7.14: PC4 recommended other non-pipe capex ( 000s) Category 2017/ / / / /22 Total Recommended 1,280 1,528 1,096 1,493 1,245 6,642 GNI request 1,447 1,702 1,172 1,580 1,325 7,227 Variance Source: GNI 7.6. Contributions In the table below, we set out our proposals for contributions for PC4. We forecast there to be a lower level of contributions than that set out by GNI. This is based on our assumptions of a reduced workload for growth capex. Table 7.15: PC4 recommended contributions (growth) ( 000s) Category 2017/ / / / /22 Total Recommended -5,959-5,613-5,628-5,604-5,625-28,429 GNI request -9,865-10,776-10,327-10,204-10,185-51,357 Variance 3,906 5,163 4,699 4,600 4,560 22,928 Source: GNI 94

106 Table 7.16: PC4 recommended contributions (refurb) ( 000s) Category 2017/ / / / /22 Total GNI request ,023 Recommended ,023 Variance Source: GNI 95

107 8. INCENTIVES 8.1. Introduction In this section we discuss potential proposals for incentives in the forthcoming price control period. This covers: opex; capex: outputs o direct opex o pass-through opex o innovation o PC4 treatment of general capex o reporting framework o PC4 incentives for connections 8.2. Opex incentives Direct opex Direct opex is assessed on a total opex basis, rather than split into categories. The treatment of direct opex in PC3 and proposed for PC4 is that GNI will continue to keep any difference between the allowed opex and outturn opex for the price control. There is no review of the efficiency of outturn opex like there is for capex. We continue to believe that a revenue cap on controllable opex provides strong regulatory incentives for GNI to make efficiency savings and control opex within the PC4 allowance. However, one point we would emphasis is that the allowance for opex should be set at a total direct level, as opposed to individual function level. While our bottom-up assessment has provided recommendations for opex at a functional level, it is for GNI to decide how it chooses to incur opex over the course of the price control. It is for this reason our recommendations on opex should be viewed in the round as well as at an individual function level Pass-through opex Pass-through items do not have the same incentive structure as for direct opex. Under the pass-through cost category there are line items that are complete pass-through i.e. GNI can recover all outturn expenditure. The intention behind this is that the costs are out of the control of GNI and so placing an incentive on GNI would only lead to windfall gains or losses. 96

108 There are other items where there is seen to be a degree of control by GNI. As such, differences between outturn and allowed costs are shared with the customer, often through a 50-50% sharing factor. We have noted the PC3 treatment of different line items and GNI s proposals for how these should be treated for PC4. Table 8.1: Overview of treatment of pass-through costs Category PC3 treatment PC4 treatment GNI proposals Distribution CER levy Complete pass-through Complete pass-through Revenue Protection Complete pass-through Complete pass-through Safety 50-50% sharing factor Complete pass-through - Incentive seen as being contrary to the public interest Shrinkage Complete pass-through (price) Volume diff borne by GNI in full As per PC3 Rates % sharing factor Maintain 50% sharing factor in Ireland with respect to liabilities associated with the Value of Assets in Ireland Transmission Move to 100% pass-through for ARV rates liabilities in Ireland and Scotland, as reduced ability to control Gaslink Complete pass-through Contained in controllable opex Regulatory levies Complete pass-through Complete pass-through CO2, Other Complete pass-through Complete pass-through Rates % sharing factor As noted for distribution Source: GNI, Consortium CER levy, Revenue protection and Shrinkage We propose to apply the same treatment as PC3 for these line items, consistent with GNI s recommendations. Safety advertising We agree with the proposed change in treatment of safety advertising and removing the incentive on this line item, as there is the possibility that this could run contrary to the public 33 Distribution has previously been allocated 61% of costs, Transmission 39% of costs for rates. 34 GNI propose that rates will be allocated 50% to Distribution, 50% to Transmission going forward. 97

109 interest. As such, we recommend that this would be full pass-through for PC4, with an annual review that the expenditure remained appropriate. Rates Irish Rates GNI are subject to commercial property rates. The liability is estimated as the product of the Value of the Asset (with a Global Valuation every five years) and the Annual Rate on Valuation (ARV) from each local authority. GNI reference that they have some limited control over the Value of the Asset e.g. participation in determination and right to appeal, but none over local ARVs due to the dissolution/ merger of councils and no right to appeal. As such GNI have proposed a 50-50% sharing factor on the Value of the Asset, but a full pass-through on the ARV. Scottish Rates The liability in the form of Non Domestic Rates (NDR) is similar to the approach in Ireland, with a Rateable Value of the Asset multiplied by the Poundage (similar to ARV). GNI note that there is limited right to appeal the proposed value with a National Pricing Matrix being used, while the Poundage is set by the UK government with no right to appeal. GNI propose a 100% pass-through in Scotland on both the value and the applicable rate. Recommendation GNI cannot fully control the outcome of the Global Valuation in Ireland. For example, it cannot control the discount rate used in this valuation. In addition, there is uncertainty over this and it is difficult to derive robust estimates of costs in each valuation. We agree that it is beneficial for GNI to strive to achieve beneficial outcomes for the Irish gas consumer and in light of the potential role that can be played by GNI as part of the valuation process, we propose to maintain an incentive on this aspect of rates. However we propose reducing the incentive strength to 25% i.e. GNI retain 25% of outperformance or underperformance, rather than the existing 50% incentive factor. We agree with GNI that for rates there should be a full pass-through, due to GNI being unable to control this value. For Scotland, we agree with GNI that a 100% pass-through incentive should apply to both the value and applicable rate in light of GNI s inability to influence the outcome Innovation The innovation fund is treated as an opex line item i.e. not included within the RAB. GNI are allowed to recover outturn opex up to the allowed level of the innovation fund. If outturn opex is under the allowed level, this amount is not allowed to be recovered i.e. GNI can 98

110 recover only the minimum of outturn or allowed innovation funding. This amount is not known at the end of the price control, so there will need to be an adjustment early within the PC4 price control for assessing PC3 innovation expenditure Capex incentives As was referenced at the PC3 review, strong capex incentives are important for capital intensive businesses such as GNI. We therefore propose that the CER should seek to retain a rolling capex incentive mechanism in PC4. However, having completed the capex close-out assessment for PC3, we have reviewed whether the current incentive framework remains fully appropriate for PC4, including areas where the existing guidance / framework might be improved and how to best facilitate the capex expenditure review that will take place at PC5 review Incentives for general capex in PC4 and beyond Informed by the learning from the PC3 close-out, in undertaking this review we have considered four key questions: 1. Should the assessment of capex variations be made on an annual or total price control period basis? 2. Are the incentive categories that been adopted in the PC3 close-out assessment the correct ones for the PC5 review? 3. What should be the regulatory treatment of the different categories of expenditure e.g. efficiency saving vs. unfinanced overspend? 4. How to facilitate as predictable and transparent process for the capex close-out assessment as possible? 1. Should the assessment be made on an annual basis? In applying the PC3 assessment, we have considered the total volume of work delivered across the period against the criteria of under or over delivery. Assessing the volume of work on an annual basis creates difficulties in that there will be high levels of over-delivery and under-delivery identified, due to differences in phasing or workload. The PC3 determination included individual yearly unit rates in many cases, which we have applied in our assessment for the PC4 close-out review. An alternative approach is to set-out for PC4 a common unit rate across all years of the control and undertake the assessment based up on the total period workloads and a common unit rate for all years. Assessment on a total period basis avoids issues of creating perverse consequences and in our view is a simpler and more transparent approach, which is why we recommend this approach continues for the upcoming price control. We have adopted the proposal in deriving our capex allowances for PC4 as set out in Section 7. 99

111 2. Are the incentive categories the correct ones? It is clear that there should be incentives linked to efficient savings and instances of overspends relative to price control allowances. However, incentives around efficient deferral of projects are more contentious due to the issue of potential additional funding i.e. the company receives depreciation and return on deferred expenditure, which then possibly is fully funded again in a future price control determination. The intention of the incentive is to have GNI not undertake projects that had been recommended in the price control determination, due to there no longer existing a clear business case for this investment. By permitting GNI to retain the return on this capital for a period of time, there is a financial benefit from this behaviour. The incentive, as a consequence, helps to align the interests of GNI and customers, given GNI can financially benefit from deferring projects as well as projects which go ahead. However, with the risk of incurred expenditure being disallowed (if subsequently no investment need case can be provided) and general licence conditions related to efficient operations of a gas network business, there may be incentives for GNI to behave in this way already (i.e. defer projects where there is not a clear investment case). In addition, the category of efficient deferral under the existing capex guidelines in principle creates an incentive for GNI to propose projects at the time of the price review that have less clear business cases. GNI can propose projects and then obtain a financial return on these even if there is not a clear business case in the first place. Notwithstanding these issues, our view is that the category of efficient deferral should be retained in the PC4 capex guidelines, to ensure that money is not wasted on unnecessary projects, as it is very difficult to review the business rationale for all transmission and distribution investment projects over the five year cycle. However, we would expect a high burden of proof from GNI of why it considers deferred projects / programmes should be deemed efficiently deferred, to avoid risks of double funding. We suggest that the final capex guidelines also make clear that claimed efficient deferrals at the PC5 review should be tied to GNI initiatives leading to the deferral of tangible work, rather than instances of simply deferred expenditure. 3. Regulatory treatment of over and under spends for delivered work We would propose that there is symmetric treatment of efficiency savings and unfinanced overspend in terms of the timing of retention of any variations against PC4 allowances. Both relate to the unit costs the work is conducted at. Having a symmetric approach means there are not different effects applied where costs are moved to one area, leading to a higher unit cost, from another, where there would be a lower unit cost. 100

112 As consequence, we suggest that for unfinanced overspend category variances, GNI be required to finance the overspend for 5-years, to be symmetric with the 5-year rolling incentive that applies to efficiency saving variations. The CER could consider extending the symmetry of the incentive further, if GNI were required to bear both the depreciation and return element of the unfinanced overspend variation, consistent with the treatment that currently applies to efficiency savings. However, this would significantly increase the power of the incentive that applies to unfinanced overspend variations during PC4 compared to the PC3 period. 4. How do we ensure future reviews are predictable and transparent? In light of incentives for capex being linked to projects, it is important that there is a clear understanding of the outputs that GNI has been funded to deliver. The UK Competition Commission (CC) Northern Ireland Electricity (NIE) Transmission and Distribution RP5 determination 35 for example included an annex that set out the projects that were to be delivered in the price control and the financial amounts linked to this expenditure. We have developed our capex recommendations to follow a similar approach. For each category of PC4 capex, we have set out the unit rates and associated workloads that have been used to set the allowances. We propose that as part of the final PC4 determination, a workbook is developed which provides a clear summary of the projects, work programmes and assumptions (e.g. unit rates) that have been used to set the determination and would then form a key input to the PC4 close-out at the PC5 review. Summary The table below summarises our overall proposals on the capex incentives / guidelines that might be adopted by the CER for PC4. Table 8.2: Proposals on capex incentives and guidelines Element Form of incentive Comments Rolling capex incentive Categories of variance As per Table 6.5 Assessment period Retention period of incentives Power of incentive Process Source: Consortium Total period basis 5-years 5-years of depreciation and return for efficiency savings 5-years of return for unfinanced overspend 5-years of return for efficient deferral Agreed unit rates and workload / programme assumptions

113 8.4. Output and delivery incentives Output and work-programme delivery framework As set out in previous sections of the report, GNI s BPQ includes a number of work programmes and initiatives which it has stated are a strategic priority for the company and the Irish gas customer. These are intended, amongst other objectives, to ensure GNI can: manage an ageing asset base; promote growth in utilisation of the network; promote sustainability and innovation; and continue to deliver a safe and secure network. Given that incremental allowed opex and capex is proposed in PC4 (relative to PC3) to support these initiatives, the Irish gas customer might reasonably expect GNI to demonstrate it has delivered on these commitments and by the end of the price control period show that it has made efficient use of the incremental funding allowed by the CER. We do not consider it is feasible or desirable for the CER to implement an outputs based price control framework for PC4, such as the RIIO regulatory framework that Ofgem has developed and implemented for energy networks in GB. RIIO is a performance based regulatory model for setting network companies price controls, which explicitly links networks allowed revenues to incentives and delivery of outputs. However, we do recommend that the CER should seek increased transparency around GNI s delivery of its PC4 BPQ plans and the network operator s use of the incremental expenditure that has been allowed to improve network performance and support new initiatives in PC4. This should not be a straight-jacket which prevents GNI taking sound management action/decisions as the price control proceeds and priorities may need to change, but a clearer definition (relative to previous price controls) of the planned initiatives and programmes the final PC4 determination is based upon. This can then be used to provide greater transparency around the PC4 capex close-out assessment and the forward looking opex and capex assessment the CER undertakes at the PC5 review. In addition, we recommend steps are taken to increase the engagement with stakeholders such that they are more informed about the decisions taken by GNI and the cost/benefit trade-offs. In order to engage with stakeholders it is importance a transition is started to move to expressing the items which are delivered by GNI more in terms of the benefits the stakeholder will see from their delivery in regulatory jargon these are called Outputs. We have already set out a proposal that, as part of the final PC4 determination, a workbook is developed which provides a clear summary of the projects, work programmes and assumptions (e.g. unit rates) that have been used to set the determination and would then form a key input to the PC4 close-out at the PC5 review. We would also propose that GNI be required to provide a report as a key part of its submission for the PC5 review that details its record of performance and delivery against the programmes and initiatives that constituted its PC4 business plan. 102

114 This should include a detailed analysis of how outturn volumes of work and delivered programmes specifically compare to the business plan GNI submitted for the PC4 review and how GNI considers it has met its proposed commitments during PC4 and improved the performance of its network. This should enhance rather than replace the opex and capex lookback assessment historically provided by the operator as part of its BPQ submission. This report might be expected to achieve the following: evidence of tangible KPIs GNI has itself used to measure its performance in PC4 and the outputs / things GNI considers it has delivered in the context of its strategic objectives/commitments and work programmes as proposed in the PC4 BPQ; evidence GNI has consulted with a range of relevant stakeholder groups to confirm the types of KPIs and outputs it has delivered reflect stakeholders expectations of GNI as the gas network operator in Ireland; where there have been material changes to the business priorities and the work programmes and strategic initiatives delivered in PC4, an explanation of those material changes and how they developed over PC4; and close-out assessment of whether GNI considers the broad strategic objectives / output commitments it has proposed in the PC4 BPQ continue to be appropriate for the PC5 price control period. Subject to an assessment of the regulatory framework by the CER at the time of its PC5 review, this report might in principle be used as the basis to develop a more comprehensive outputs monitoring and regulatory framework for PC5. To provide sufficient opportunity for GNI, CER and other stakeholders to consult and comment on the features of such framework, we would therefore also recommend GNI provide an interim report to CER at the end of the third year of the price control (2019/20) setting out interim progress against the reporting objectives above. To summarise, the proposals set out in this subsection are intended to: increase transparency (relative to the processes followed in previous price controls) of GNI s record of delivery of the items which have been outlined in its price control plans and its use of the allowed incremental expenditure in PC4 to improve network performance; and potentially support the future development of a more outputs/performance based price control/regulatory framework at the PC5 review should the CER consider this to be appropriate. No change is proposed to GNI s existing incentive framework for opex and capex during PC4, except for the specific proposals set out earlier in this report. This means that except for any new incentives which the CER might introduce for the PC4 controls (e.g. new connections targets (see below) and customer satisfaction KPIs) or the 103

115 targeted performance incentive mechanisms that apply in GNI s existing price controls (e.g. shrinkage), GNI s allowed revenues are not expected to be tied to the operator s delivery of a specified set of outputs or performance measures Growth related incentives In addition to general capex and opex incentives, the CER have also asked the consortium to consider an incentive around new connections in PC4. As discussed in Section 7, on the direction of the CER we have proposed connection numbers for PC4 based on information submitted by GNI of what currently could be considered a Business As Usual (BAU) (although still challenging relative to PC3) run-rate for new connections during PC4. As part of our PC4 opex recommendations, we have included a provision to support new growth related initiatives, in both the Commercial and Regulation & Corporate functions. There is, therefore, a prospect that GNI may be able to exceed the connection volumes that have been outlined in the previous section of the report. However, this expenditure has been allowed partly on the expectation that GNI will deliver a return for customers on their investment by delivering (or even exceeding) the assumed BAU connections run-rate, thereby improving future expectations of network utilisation relative to the current price controls. In addition, the revenue cap, should our proposed opex recommendations be accepted, will be set with the expectation GNI will deliver its BAU runrate, and so includes incremental churn 36 opex for those new connections. The objective of this new incentive would be to apply a financial bonus (or penalty) to GNI if it exceeded (or failed) to meet the price control connection targets. This would operate alongside the normal flex process in place for price control capex allowances for new connections 37 (see Section 7) with the objective to both: encourage GNI to seek new growth opportunities (on the underlying premise new connections are positive for network utilisation and customers); and permit allowed incremental opex for new connections in the price controls to vary if the actual delivered number of new connections are lower or higher than what is assumed in setting the final PC4 review determination. The incentive would, as a consequence, partly operate as a connections volume driver (i.e. uncertainty mechanism) for the PC4 price control, as well as opportunity for GNI to outperform its allowed cost of equity by delivering on its growth plans. The proposed approach is as follows: 36 e.g. move meter, exchange meter, meter fault, gas escape. 37 Whereby should GNI exceed (or fall below) the connection numbers originally used to the set the RAB for the price control, GNI will be rewarded (not rewarded) for the capex and financing costs of the connections which exceed or fall below the original price control targets. 104

116 Scope the incentive would apply to both domestic housing and I&C connection targets. There would be a separate domestic connections target and I&C connections target to avoid GNI focusing on only one type of new connection. Incentive target rather than annual targets, any bonus or penalty would be paid on total delivered connection numbers in PC4 vs. the BAU recommendations in the PC4 determination. The bonus/penalty would be paid in the first year of PC5. Incentive structure the bonus (penalty) payment would increase on a linear basis increasing (decreasing) from zero to a maximum bonus (penalty) for meeting (not meeting) the connection targets using a fixed marginal incentive rate. The CER would set a symmetric marginal incentive (reward/penalty) rate for each connection that falls below or exceeds the PC4 BAU target. So for example, if the marginal incentive rate was 100 per domestic housing connection, then if actual connections were to fall below the PC4 target by 100, the penalty applied under the scheme would be 10,000. For both the domestic and I&C connection targets, we propose there would be a cap and floor on the total monetary reward/penalty under the scheme. So for example, if actual connection numbers fall below a floor level, the penalty applied would be capped. Similarly if actual connection numbers exceed the cap, the reward paid out would be capped. This is to ensure that GNI and customers are not exposed to too greater financial risk. We propose that: Incentive cap GNI s original PC4 forecast connection numbers for both domestic (new and existing) housing and I&C connections would be used to set the maximum incentive reward pay-out 38 ; and Incentive floor the floor for connection numbers below the PC4 determination targets would, where possible (see below) be set symmetrically to the proposed cap which is based on GNI s BPQ projections. 39 Table 8.3 below illustrates how each of these building blocks could be combined. Note that for the I&C component of the scheme, the cap and floor on the incentive is in this example not perfectly symmetrical, as a symmetric floor level of connections would have implied a negative number of new I&C connections relative to the BAU run-rate. 38 Rounded to the nearest thousand. 39 So for example, if the cap was set at 10,000 new connections above the PC4 BAU targets, the floor would be set at 10,000 new connections below the PC4 BAU targets. 105

117 Table 8.3: Illustrative connection incentive scheme Incentive input / parameter Domestic connections I&C connections PC4 BAU target [A] = no. of new connections 63,145 3,475 GNI BPQ forecast [B] = no. of new connections 89,887 6,776 Cap [C] = no. of new connections 1 90,000 7,000 Floor [D] = no. of new connections 2 27,290 - Incentive rate [E] = Euros ( ) Maximum reward [F] = ([E] x ([C] [A]))/10^6 3.5m 0.6m Maximum penalty [G] = ([E] x -([A] [D]))/10^6-3.5m -0.6m Note 1: GNI BPQ forecast rounded to nearest thousand Note 2: Equal to: [A] minus ([C] minus [A]) for new housing; capped at zero for I&C connections For the example incentive scheme set out above, we have used a working definition of a new connection as being the supply of a meter to a customer premise. This definition of a new connection is used to establish the BAU connection targets in Table 8.3. However, we understand that within the meter fits GNI forecast in its original BPQ, there are a number of multi-unit apartments (district heating) schemes where GNI expect a single gas service and a single gas meter to be installed to connect a much larger number of new domestic apartments. These schemes will as a consequence deliver a much larger number of new connection units (and so higher volumes onto the network) than the single meter fit that is accounted for in the domestic connection forecasts above. As a consequence, further work may be needed to establish the most appropriate measure for the incentive connection targets to account for these apartment schemes, given the regulatory objective of the incentive scheme is to promote greater network utilisation. However, if the targets were stated in terms of new connection units (where, for example, a multi-unit apartment would be defined as say 90 new connections rather than a single new connection (as assumed in the meter fit definition adopted in Table 8.3)) then the baseline BAU domestic connections target would need to be scaled up to reflect the expected number of new apartments for a given number of multi-unit apartment schemes. We suggest that the financial value of the incentive is set with reference to the allowed incremental churn opex that is included in the PC4 opex allowances associated with each new connection and the capex and opex (e.g. in the Commercial and Regulation & Corporate departments within GNI) associated with the growth initiatives. So for example, the monetary value of both the cap and floor might be set so that: new connections above or below the agreed connection target level would lead to an increase or decrease in GNI s allowed revenue, in part consistent with the expected incremental opex associated with each new connection; and 106

118 should GNI exceed or fail to meet the price control connections targets set, GNI could also expect to earn/lose a margin on the allowed capex and opex in PC4 40 to support the growth initiatives. The proposed incentive rates for new housing and I&C connection in Table 8.3 have been set with reference to: the average incremental opex per new connection implied from our asset operations opex modelling of incremental connections (c. 22 per connection); and the maximum penalty/reward under the incentive scheme, expressed as a percentage of the expected capex programme for new connections in PC4 at different outturn levels of new connections. 41 Figure 8.1 below illustrates the structure of the incentive assuming the building blocks above for new domestic connections. Figure 8.1: Illustration of incentive applied to new domestic PC4 connection target Source: Consortium 40 e.g. in the Commercial and Regulatory & Corporate functions. 41 The maximum reward using the parameters in Table 8.3 would be ~ 3.3% of allowed new connections capex in our PC4 recommendations. The reward/penalty would also broadly be around 0.5% of distribution revenues (15/16 prices). 107