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

Transcription

1 PC4: REVIEW OF TRANSMISSION 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 TSO 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 transmission opex. ii

5 Figure 2: Summary of PC4 opex 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 Note 2: Business Support Services (BSS) The largest absolute difference between our recommendations and GNI s BPQ request is in Operations Opex where a 13% reduction has been proposed relative to the GNI request. We have also proposed a higher ongoing net efficiency adjustment than GNI proposed in its PC4 BPQ which also reduces the consortium s recommendations compared to GNI s request. 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 transmission opex; all ( 000s) 1 Category 2017/ / / / /22 Total Recommended 75,265 80,067 80,297 73,474 74, ,239 GNI request 81,839 87,853 88,936 82,870 82, ,024 Variance -6,575-7,786-8,639-9,397-8,388-40,785 Variance (%) -8.0% -8.9% -9.7% -11.3% -10.2% -9.6% Source: GNI, Consortium Note: includes innovation and pass-through cost items 1 All figures are in 2015/16 prices unless otherwise stated iii

6 Table 2: PC4 recommended transmission opex; direct only ( 000s) Category 2017/ / / / /22 Total Recommended 53,677 58,453 58,642 51,782 52, ,034 GNI request 59,415 65,787 67,161 61,229 61, ,805 Variance -5,738-7,333-8,519-9,448-8,733-39,771 Variance (%) -9.7% -11.1% -12.7% -15.4% -14.3% -12.6% 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 transmission capex; gross ( 000s) Category 2017/ / / / /22 Total Recommended 53,163 57,404 50,806 41,758 47, ,159 GNI request 56,228 63,895 58,438 51,681 55, ,384 Variance -3,065-6,491-7,631-9,923-8,114-35,225 Variance (%) -5.5% -10.2% -13.1% -19.2% -14.7% -12.3% Source: GNI, Consortium iv

7 Table 4: PC4 recommended transmission capex; net ( 000s) Category 2017/ / / / /22 Total Recommended 46,477 52,980 49,013 40,565 46, ,550 GNI request 49,502 59,430 56,521 50,366 54, ,367 Variance -3,024-6,450-7,508-9,801-8,034-34,817 Variance (%) -6.1% -10.9% -13.3% -19.5% -14.7% -12.9% 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 i.e. net of customer contributions is 15% higher than the PC3 outturn. A summary of the differences between the consortium recommendations and the GNI s request for the key areas of our capex assessment is shown 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 transmission 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. v

8 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 2 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 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. 2 As for example Ofgem has adopted under its RIIO regulatory framework for energy networks in Great Britain. vi

9 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 Operations opex Business support opex IT opex Gaslink opex Pass-through costs Innovation Summary REVIEW OF PC4 OPEX Overview Methodology Unit cost and benchmarking assessment in transmission Group and Shared Service expenditure Operations opex Business support opex IT opex Adjustments to bottom-up analysis Innovation... 49

10 4.10. 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 Non-pipe capex Contributions INCENTIVES Opex incentives Capex incentives Output and delivery incentives... 98

11 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 TSO 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 TSO determination 3, 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. 3 CER (2012) Decision on October 2012 to September 2017 transmission revenues, CER12/058 1

12 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 4, it is important to understand the organisational structure of Ervia; the owner / ultimate controller of GNI and its associated gas network businesses. 4 Our approach to cost assessment is set out below. 2

13 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 1.1.1: 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

14 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 primarily undertaken a bottom-up cost assessment to establish an efficient cost path for GNI s transmission business. 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. The final step in our PC4 opex assessment was then to consider the degree of ongoing efficiency improvement or frontier shift that might be possible from GNI given that 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. 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. 5 GNI (2016): PC4 Distribution Review of Historical Operational Expenditure, p. 95 4

15 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. 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 Operations Business Support Group & Shared IT Source: Consortium 5

16 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 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. 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 sets out our recommendations for opex allowances for PC4; Section 5 contains our review of capex for PC3; Section 6 details our recommendations for PC4 capex; and Section 7 sets out proposals for incentives in PC4. 6

17 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. 7

18 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. 6 ESRI and UCC (2014) Implications for Ireland Moving Towards a Low Carbon Energy Roadmap Energy Research Workshop 8

19 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. 7 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 7 For example, the Irish Government White Paper published in 2015, Ireland s transition to a low carbon energy future. 9

20 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. 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. 8 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 CER (2016) Decision on CNG funding request, aper.pdf 9 GNI (2016): PC4 Executive Summary PC4 SD001 10

21 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. 11

22 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 12

23 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. 10 Figure 2.2: Forecast movement in GNI headcount Source: GNI 10 Note that this excludes growth in headcount at the Ervia Group level where BUs such as the Shared Service Centre support GNI s activities. 13

24 3. REVIEW OF PC3 OPEX In this section we review transmission opex during the PC3 price control. This includes four years of actual data and one year of forecast data from GNI Overview The table shows how outturn expenditure compares to the allowance for the PC3 control, note that 2016/17 is still a GNI forecast. Table 3.1: PC3 outturn transmission opex ( 000s) Category 2012/ / / /16 F2016/17 Total Operations 21,129 25,599 26,189 27,971 35, ,229 Business Support 13,649 15,071 13,416 15,698 16,487 74,321 IT 5,427 4,748 5,209 6,241 6,643 28,268 Gaslink 2,129 2,395 3,118 1,469 2,302 11,413 Total controllable 42,335 47,813 47,933 51,379 60, ,231 Pass-through 12,485 12,999 13,721 12,651 17,410 69,265 Innovation ,197 3,901 5,864 Total 54,903 61,717 61,430 65,227 82, ,360 Source: GNI Table 3.2: PC3 allowed transmission opex ( 000s) Category 2012/ / / /16 F2016/17 Total Operations 23,687 25,408 26,388 26,906 29, ,573 Business Support 12,148 12,722 12,974 16,139 15,680 69,663 IT 5,735 5,883 6,283 2,649 2,645 23,195 Gaslink 2,462 2,363 2,343 2,324 2,324 11,817 Total controllable 44,032 46,376 47,988 48,019 49, ,248 Pass-through 13,024 13,327 13,425 14,490 15,657 69,924 Innovation 1,481 1,498 1,494 1,472 1,832 7,776 Total 58,537 61,201 62,907 63,980 67, ,947 Source: GNI Table 3.3: PC3 variance transmission opex ( 000s) Category 2012/ / / /16 F2016/17 Total Operations -2, ,065 6,156 4,656 Business Support 1,501 2, ,658 IT ,135-1,073 3,592 3,998 5,073 Gaslink

25 Category 2012/ / / /16 F2016/17 Total Total controllable -1,698 1, ,361 10,938 13,983 Pass-through ,840 1, Innovation -1, , ,069-1,912 Total -3, ,477 1,246 14,761 11,412 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 11 and the key trends in the phasing of GNI s expenditure during PC 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. Table 3.4: PC3 outturn transmission operations opex ( 000s) Category 2012/ / / /16 F2016/17 Total Asset Management 2,940 3,586 3,981 3,671 4,046 18,224 Asset Operations 17,346 20,441 20,665 22,449 29, ,159 Commercial HSQE 726 1,212 1,250 1,552 1,683 6,423 Technical Competency ,436 Total 21,129 25,599 26,189 27,971 35, ,229 Source: GNI 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 11 The way we have disaggregated opex into categories is discussed in Section 1 of this report. 15

26 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 80% of the costs in this area. Staff numbers have fluctuated during PC3 as GNI s 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. We have considered the maintenance expenditure within Asset Operations in five groups of activities: Irregular Expenditure Pipelines AGI Compressor Miscellaneous Although the level of operational expenditure is driven by maintenance activities and irregular items such as 7 or 10 year inspections and the associated remediation activities, the level of operational expenditure has been on a rising trend during PC3. We consider that the categories of spend for Maintenance are largely driven by the; length of installed pipeline, number of DRIs, and number of Compressors 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, the object of this being to maximise the benefit from the installed network asset base. We have split out the Innovation expenditure from this area of expenditure. 16

27 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. HSQE works closely with all areas of the business on all aspects of occupational and process safety, quality, environmental and risk management 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 Note that 2016/17 is a forecast. As with operational areas, we have also excluded IT expenditure. 17

28 Table 3.5: PC3 outturn business support costs ( 000s) Category 2012/ / / /16 F2016/17 Total Head of Networks 1,733 2,248 1,480 2,029 2,123 9,613 R&C Services 2,380 2,848 2,039 3,090 3,022 13,379 Finance 5,956 6,278 5,552 6,346 6,498 30,629 Human Resources 1,201 1,386 1,724 1,677 1,823 7,810 Facilities 2,379 2,312 2,621 2,557 3,021 12,890 Total 13,649 15,071 13,416 15,698 16,487 74,321 Source: GNI 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. 18

29 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 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 transmission 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/ / / /16 F2016/17 Total Outturn 5,427 4,748 5,209 6,241 6,643 28,268 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. 19

30 Table 3.7: PC3 Outturn Gaslink transmission opex ( 000s) Category 2012/ / / /16 F2016/17 Total Outturn 2,129 2,395 3,118 1,469 2,302 11,413 Source: GNI 3.7. 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: 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 transmission, there were three items which were treated as full pass-through items for PC3. These were Gaslink, CER levies and CO2. Rates were both subject to a 50% incentive sharing factor i.e. 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 rates below targets Level of pass-through costs The table below shows outturn values for PC3 for the three pass-through cost items (excluding Gaslink) in the PC3 transmission price control. As discussed above, while CO2 and the CER levy have been a full cost pass-through for GNI s transmission business during PC3, rates have been subject to financial incentive arrangements. Table 3.8: PC3 outturn Pass-through opex ( 000s) Category 2012/ / / /16 F2016/17 Total CO CER levy 1,538 1,563 1, ,246 6,616 Rates 10,855 11,291 12,195 11,647 15,952 61,941 Total 12,485 12,999 13,721 12,651 17,410 69,265 Source: GNI 3.8. 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). 20

31 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 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/ / / /16 F2016/17 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 21

32 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. 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. 22

33 Figure 3.2: Overall trends in controllable transmission opex during PC3 Source: GNI. Note: excludes innovation and pass-through opex. 23

34 4. REVIEW OF PC4 OPEX In this section we set out our proposed recommendations for transmission opex for the PC4 price control period. This is based on a bottom-up assessment Overview The table below shows how our recommendations compared to the GNI business plan for PC4 on transmission 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 4.1: PC4 recommended transmission total opex ( 000s) Category 2017/ / / / /22 Total Recommended 75,265 80,067 80,297 73,474 74, ,239 GNI request 81,839 87,853 88,936 82,870 82, ,024 Variance -6,575-7,786-8,639-9,397-8,388-40,785 Variance (%) -8.0% -8.9% -9.7% -11.3% -10.2% -9.6% Source: Consortium Note: includes innovation and pass-through cost items Table 4.2: PC4 recommended transmission controllable opex ( 000s) Category 2017/ / / / /22 Total Recommended 53,677 58,453 58,642 51,782 52, ,034 GNI request 59,415 65,787 67,161 61,229 61, ,805 Variance -5,738-7,333-8,519-9,448-8,733-39,771 Variance (%) -9.7% -11.1% -12.7% -15.4% -14.3% -12.6% Source: Consortium Note: excludes innovation and pass-through cost items 4.2. Methodology For transmission, we do not have the same quality of data to undertake top-down benchmarking of GNI s TBU as with the DBU. As a consequence, we rely primarily on the findings of the bottom-up cost assessment to set PC4 opex allowances, although trends in the real unit operating expenditure of GNI s transmission have been reviewed together with a transmission benchmarking report that was submitted by GNI as part its BPQ. 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. 24

35 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 informed by GNI s original BPQ submission and subsequent discussions with the operator over earlier stages of the PC4 price review process. While we do not use top-down benchmarking to inform opex allowances in PC4, we have still considered what might be an efficient cost path for GNI s gas transmission business during PC4. This has included a review of: evidence of historic and forecast unit cost trends for GNI s transmission business implied by its business plan (as discussed above); and potential scope for ongoing (frontier shift) efficiency from GNI s transmission business during PC4. 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). We have been careful to ensure that there is not double counting in combining the findings of our bottom-up assessment and any 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 combined top-down adjustments we believe are consistent and achievable in their expectation of GNI s scope to improve its efficiency during PC Unit cost and benchmarking assessment in transmission Real unit operating expenditure (RUOE) of GNI s transmission business increased during PC3 and is forecast to continue rising over the course of PC4. There has been a gradual increase in RUOE over PC3 and an expectation of this trend continuing in the early years of PC4, peaking around 2019, and falling the later years of PC4. The two figures below show how direct operating costs have changed in relation to the number of kilometres of the network and per MWh transported. Both methods show a step up relative to 2015/16 unit costs. 25

36 Figure 4.1: Change in direct operating costs per Km relative to 2015/16 base % / / / / / /22 Actual Forecast Source: Consortium analysis Unit costs are forecast to increase by around a third at their peak relative to 2015/16 levels on a per kilometre basis. The trend is similar when considering the per MWh basis. Figure 4.2: Change in direct operating costs per MWh relative to 2015/16 base % / / / /22 Actual Forecast Source: Consortium analysis The figure below shows percentage contribution of each functional area to the increase in RUOE from 2015/16. This shows that the main drivers of the forecasted increase in RUOE are Asset Operations, Commercial and Regulation & Corporate Services, though all categories except Head of Networks are forecasted to increase. 26

37 Figure 4.3: Contribution to increases in RUOE from 2015/16 120% 100% 80% 60% 40% 20% 0% -20% 2016/ / / / / /22 Asset Management Asset Operations Commercial Facilities Finance Head of Networks HR HSQE IT Regulation & Corporate Services Technical Competency Source: Consortium analysis The increase is primarily driven by the three functions: Asset Operations, Commercial and Regulation & Corporate Services. The benefit of top-down analysis is that it abstracts away from detailed allocations/ cost categorisations, recognising that companies may be able to trade-off between different types of expenditure in delivering network outputs. However, given this unit cost analysis is relatively simplistic it is not able to capture all the drivers of expenditure. For example, there may be other factors other than network scale (e.g. increasing quality of service) that could justify the observed increases in expenditure. This type of analysis has not considered any of GNI s justifications for additional expenditure in their business plan. Therefore, we do not propose to use this analysis to set cost allowances directly but instead as a cross-check to the separate bottom-up analysis when considering PC4 allowances. We have also considered evidence provided by GNI on comparative transmission opex benchmarking, authored by Juran Europe 13. This report noted that performance by GNI was variable across different areas of the transmission business and there is difficulty in comparing companies in an accurate fashion i.e. controlling for their unique characteristics. 13 Juran Europe Ltd (2016) An Independent Analysis of Gas Networks Ireland Gas Transmission Operational Performance 27

38 4.4. 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 4.4. Figure 4.4: 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. In preparing its BPQ 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. 28

39 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 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). 14 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, 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. 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. 14 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. 29

40 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 4.5 below. Figure 4.5: Group and Shared Service Centre recommendations Source: GNI, Consortium 30

41 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 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 4.3: PC4 recommendations transmission operations opex ( 000s) Category 2017/ / / / /22 Total Asset Management 3,978 3,963 3,963 3,962 3,961 19,828 Asset Operations 22,009 27,223 27,995 21,447 22, ,511 Commercial ,290 HSQE 1,722 1,717 1,706 1,726 1,723 8,593 Technical Competency ,809 Total 28,692 33,926 34,695 28,166 29, ,031 Source: GNI Table 4.4: PC4 GNI request transmission operations opex ( 000s) Category 2017/ / / / /22 Total Asset Management 4,150 4,176 4,191 4,192 4,194 20,903 Asset Operations 26,315 31,963 32,940 26,481 26, ,234 Commercial ,290 HSQE 1,722 1,717 1,706 1,726 1,723 8,593 Technical Competency ,809 Total 33,171 38,880 39,867 33,430 33, ,829 Source: GNI 31

42 Table 4.5: PC4 variance transmission operations opex ( 000s) Category 2017/ / / / /22 Total Asset Management ,075 Asset Operations -4,307-4,741-4,945-5,034-3,697-22,723 Commercial HSQE Technical Competency Total -4,479-4,953-5,172-5,264-3,930-23,798 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 steps GNI are making in developing their asset management strategy and reflecting this in their 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 5% reduction to the levels requested. In addition, we have applied the adjustments to Group and Shared Service costs as set out in section 4.3. The chart below shows our recommendations in the context of the trend across PC3 and PC4. 32

43 '000s Figure 4.6: Asset Management Opex Trend 4,500 4,000 3,500 3,000 2,500 2,000 1,500 1, PC3 Actuals PC4 GNI requested PC4 recommended PC3 average Source: GNI/Consortium Asset Operations We have considered the maintenance expenditure within Asset Operations in five groups of activities: Irregular Expenditure Pipelines AGI Compressor Miscellaneous In each area of expenditure, we have used a different methodology or driver to establish our recommendations for the PC4 period. Irregular Expenditure Examples of irregular activities include sub-sea and onshore pipeline on line inspection, as well as compressor overhauls, where the amounts incurred during PC3 are not a satisfactory indicator of the expenditure for PC4. We have therefore applied a general reduction of 3% to reflect our assessment that overall maintenance costs have been forecast at a higher level than experienced during PC3. 33

44 Pipelines This area covers regular maintenance activities associated with onshore pipelines and we have used a driver of length of pipelines in operation. Using this driver, we have derived a weighted average expenditure for these items over the 4 years of PC3 for which actual expenditure is available. Using the driver, we have rolled forward this average to each year of PC4. AGI This area covers regular maintenance activities associated with AGIs and we have used a driver of the number of AGIs in operation. Using this driver, we have derived a weighted average expenditure for these items over the 4 years of PC3 for which actual expenditure is available. Using the driver, we have rolled forward this average to each year of PC4. Compressor This area covers regular maintenance activities associated with compressor stations and we have used the average expenditure for these items over the 4 years of PC3 for which actual expenditure is available. We have rolled forward this average to each year of PC4. Miscellaneous This area covers Bio-gas and CNG and is relatively new and small in comparison to other items of maintenance expenditure. For this review we recommend the forecasts made by GNI. The chart below shows our recommendations in the context of the trend across PC3 and PC4. 34

45 '000s Figure 4.7: Asset Operations Opex Trend 35,000 30,000 25,000 20,000 15,000 10,000 5,000 0 PC3 Actuals PC4 GNI requested PC4 recommended PC3 average Source: GNI/Consortium Source: Consortium Commercial As previously explained the commercial department was established in early 2015 to address the need to increase utilisation on the network. The requested expenditure of 3.29m is focussed on supporting the growth strategy and we have not recommended any adjustment to this area. The chart below shows our recommendations in the context of the trend across PC3 and PC4. 35

46 '000s Figure 4.8: Commercial Opex Trend PC3 Actuals PC4 GNI requested PC4 recommended PC3 average Source: GNI/Consortium HSQE We have recommended no adjustment to this area of expenditure. The chart below shows our recommendations in the context of the trend across PC3 and PC4. 36

47 '000s Figure 4.9: HSQE Opex Trend 2,000 1,800 1,600 1,400 1,200 1, PC3 Actuals PC4 GNI requested PC4 recommended PC3 average Source: GNI/Consortium Technical competency We have recommended no adjustment to this area of expenditure. The chart below shows our recommendations in the context of the trend across PC3 and PC4. 37

48 '000s Figure 4.10: Technical Competency Opex Trend PC3 Actuals PC4 GNI requested PC4 recommended PC3 average Source: GNI/Consortium 4.6. 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. 38

49 The table below shows our recommendations for the functions that make up business support services opex for PC4, compared to GNI s funding request. Table 4.6: PC4 Recommendations business support costs ( 000s) Category 2017/ / / / /22 Total Head of Networks 2,614 2,759 2,757 2,747 2,751 13,628 R&C Services 4,552 4,522 4,522 4,519 4,516 22,631 Finance 6,176 6,113 6,125 6,109 6,102 30,624 Human Resources 1,750 1,732 1,732 1,728 1,725 8,667 Facilities 3,097 3,117 3,136 3,133 3,125 15,609 Total 18,189 18,244 18,272 18,237 18,218 91,159 Source: GNI Table 4.7: PC4 GNI request business support costs ( 000s) Category 2017/ / / / /22 Total Head of Networks 2,656 2,815 2,816 2,810 2,819 13,916 R&C Services 4,733 4,967 4,806 5,174 4,991 24,671 Finance 6,375 6,244 6,519 6,481 6,555 32,175 Human Resources 1,834 1,823 1,826 1,830 1,829 9,141 Facilities 3,159 3,279 3,383 3,354 3,308 16,483 Total 18,757 19,128 19,350 19,649 19,501 96,385 Source: GNI Table 4.8: PC4 variance business support costs ( 000s) Category 2017/ / / / /22 Total Head of Networks R&C Services ,040 Finance ,550 Human Resources Facilities Total ,079-1,412-1,283-5,226 Note: positive value indicates outturn expenditure recommendations above GNI s request. Source: Consortium Head of Networks The only adjustments we have applied to this area of expenditure are to Group and Shared Service costs as set out in Section 4.3, otherwise we accept the GNI forecasts. 39

50 Figure 4.11: Head of Networks Opex Trend Source: GNI/ Consortium Regulatory and Corporate Services Allowed Base Opex We established a range for transmission Regulation and Corporate Service normalised cost of c. 1.2m - 1.8m 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 6, 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 4.4.3) 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. 40

51 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 1,563k 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 4.3 to derive a recommended opex trend as illustrated in the figure below. 41

52 Figure 4.12: Regulatory and Corporate Services Opex Trend Source: GNI/Consortium Finance Allowed Base Opex We established a range for the transmission Finance function normalised cost of c. 4.1m - 5.0m 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 42

53 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. 15 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 4.3 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 4.9 below. Figure 4.13: Finance Opex Trend Source: GNI/Consortium 15 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. 43

54 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. We established a range for transmission HR normalised cost of c. 0.7m - 0.9m 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. Group adjustments and overall recommendations Again, the adjustment set out in section 4.3 is applied to forecast Group & Shared Service allocations to derive HR opex recommendations illustrated in Figure Figure 4.14: HR Opex Trend Source: GNI/Consortium 44

55 Facilities Allowed Base Opex We established a range for the transmission Facilities function normalised cost of c. 1.8m - 2.2m per annum, excluding Group & Shared Service allocations. 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 4.3 is applied to forecast Group & Shared Service allocations to derive Facilities opex recommendations illustrated in Figure

56 Figure 4.15: Facilities Opex Trend Source: GNI/Consortium 4.7. 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. 46

57 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 update 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 transmission IT opex relative to PC3 trends and GNI s PC4 request are illustrated in the figure below. Figure 4.16: IT Opex Trend Source: GNI/Consortium 4.8. Adjustments to bottom-up analysis As set out in Section 4.2, in addition to the bottom-up cost assessment, we have also considered the scope for ongoing (frontier shift) efficiency from GNI s transmission business during PC4. Our proposed ongoing efficiency adjustment (see further discussion below) leads to a 1.00% annual reduction factor relative to our bottom up opex 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 transmission opex recommendations for each year of the price control. 47

58 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 impose some limit on the ability of an operator to improve its dynamic efficiency, we note that productivity 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 4.17 below shows the impact of the proposed overall 1.00% 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. 48

59 Figure 4.17: Total controllable opex net of reduction factor Source: GNI/Consortium The first year of PC4 involves a slight decrease on 2016/17 forecast controllable opex. There are further step-ups in our bottom-up analysis, especially in the second and third years of PC4. However these are offset by our applied top-down adjustments and a lower base cost to start the period than for 2016/17. 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 PC 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) 16 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. 16 CER (2016) Compressed Natural Gas Funding Request, Decision Paper, CER16/

60 Top down analysis We have reviewed regulatory precedent on allowed innovation funding. This includes previous CER decisions in Ireland and Ofgem decisions in GB. A summary of these decisions are contained in the table below. Table 4.9: 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 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. 50

61 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 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). 51

62 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 17 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 4.10: 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, Source: GNI/Consortium Note GNI request is revised submission to include Causeway study 18 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 three pass-through items for the transmission price control in PC4 are CO2, CER levy and rates. Below we consider the potential level of these costs during PC4. Transmission is relatively limited in terms of the number of line items relative to distribution. Regulatory levies and CO2 items are subject to full pass-through, while the item subject to incentives is rates (proposals for how this incentive might operate in PC4 are set out Section 7). The table below summarises our pass-through proposals. We have accepted GNI s BPQ forecast pass-through opex in full. 17 1,041m 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. 18 We have made a simplifying assumption of GNI s expected funding profile for the 25m. 52

63 Table 4.11: PC4 Recommendations Pass-through opex ( 000s) Category 2017/ / / / /22 Total CO ,327 CER levy 1,246 1,246 1,246 1,246 1,246 6,230 Rates 16,980 16,980 16,980 16,980 16,980 84,898 Total 18,437 18,464 18,506 18,542 18,507 92,455 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. 53

64 5. REVIEW OF PC3 AND 2011/12 CAPEX In the 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 transmission capex outturn compared to the allowances for PC3. As noted above, this includes the final year of PC2 for capex. Table 5.1: PC3 and 2011/12 outturn transmission capex ( 000s) Category 2011/ / / / / /17 Total Pipe capex 19,762 29,065 36,448 27,609 55,010 86, ,695 IT capex 3,604 3,320 2,425 5,382 5,050 5,224 25,005 Other non-pipe ,374 1,130 5,083 Total (gross) 24,120 33,201 39,340 33,532 61,434 93, ,782 Contributions ,066-1,851-4,173-7,535-24,277-39,420 Total (net) 23,601 32,136 37,490 29,360 53,899 68, ,362 Source: GNI Table 5.2: PC3 and 2011/12 (revised) allowance transmission capex ( 000s) Category 2011/ / / / / /17 Total Pipe capex 31,308 38,186 35,557 29,849 36,746 48, ,292 IT capex 3,998 4,190 3,424 7,627 2,795 2,248 24,281 Other non-pipe 1, ,575 Total (gross) 36,531 43,254 39,567 38,183 40,214 51, ,148 Contributions ,066-1,851-4,173-7,535-24,277-39,420 Total (net) 36,012 42,188 37,717 34,010 32,679 27, ,728 Source: Consortium/ GNI Table 5.3: PC3 and 2011/12 variance transmission capex ( 000s) Category 2011/ / / / / /17 Total Pipe capex -11,546-9, ,240 18,264 38,155 34,403 IT capex ,245 2,255 2, Other non-pipe Total (gross) -12,411-10, ,651 21,220 41,756 35,634 Contributions Total (net) -12,411-10, ,651 21,220 41,756 35,634 Source: Consortium/ GNI 54

65 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 Unlike with PC3 opex, as there is a potential revenue impact from capex over- or underspends due to the incentive framework, we need to make an assessment of the reasons for why capex outturn has differed from the allowance. This review also includes the final year of PC2 capex, which was not known at the time of the PC3 determination. 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) 55

66 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 5.4: 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. 56

67 Table 5.5: 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 5.1: 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). 57