Presentation to FTS of Russia

26 April 2012

UK Grid – Issues associated with the Third Energy Package

Anna Saksonov

3

Regulation of GB Gas and Electricity Networks post

Third PackageAnna Saksonov, Senior Legal Adviser

Legal Markets, Ofgem

4

Third Package• Will examine regulation of GB gas and electricity networks

following the implementation of Third Package in Great Britain (GB).

• Third Package – 2 Directives (gas and electricity), 3 Regulations (gas, electricity, establishment of Agency for Cooperation of Energy Regulators (ACER)).

• Transposition deadline into domestic legislation by Member States was 3 March 2011.

• GB transposing legislation came into force on 10 November 2011. Link to the Electricity and Gas (Internal Markets) Regulations 2011:http://www.legislation.gov.uk/uksi/2011/2704/contents/made

5

Key requirements of Third Package• Independence of the national regulatory authority (NRA).

• Unbundling of transmission system operators (TSOs) from generation/ production and supply undertakings.

• New powers and duties of NRA – new cross- border objectives, monitoring duties.

• Enhanced consumer protection measures.

6

Independence of NRA (1)

• Ofgem has been designated as the NRA for GB by the Utilities Act 2000.

• NRA must be functionally independent from any public or private entity and act independently from any market interest.

• Must take autonomous decisions, independently from any political body in relation to its functions as the designated NRA.

• Must not seek or take direct instructions from any Government or other public or private entity when carrying out the regulatory tasks set out in the Directives.

7

Independence of NRA (2)

• Concept of instructions is to be interpreted broadly - “any action calling for compliance and/or trying to improperly influence an NRA decision and thus includes the use of pressure of any kind on NRA’s staff or on the persons responsible for its management.”

• In GB Ofgem is already an independent impartial regulator therefore largely compliant with Directives.

• Independence of Ofgem strengthened - new provision in legislation that members of the Authority may not seek or take any instructions that may compromise independence of Ofgem when carrying out regulatory tasks as the NRA for GB.

8

Unbundling of TSOs• One of central provisions of Third Package is requirement for TSOs

to unbundle from generation/ production and supply interests.

• Requirement for TSOs to be certified pursuant to one of the unbundling models set out in the Third Package.

• We are responsible for administering the certification process for GB TSOs – this is a regulatory task so have to be independent.

9

Certification deadline (1)

• Certification process set out in the Gas Act 1986 and in the Electricity Act 1989.

• Requirement to be certified by 3 March 2012 for current and future holders of gas transporter, gas interconnector, electricity interconnector and electricity transmission licences.

• If TSO licensed but not yet operational, no legal requirement to be certified.

10

Certification deadline (2)

• Authority can extend deadline to 3 March 2013 if

(1) TSO not part of a vertically integrated undertaking and no senior officer is also officer of relevant producer/ supplier, or

(2) for reasons beyond TSO’s and Authority’s control cannot make certification decision by 3 March 2012.

• Future TSOs will also need to be certified (e.g. new interconnectors and offshore transmission owners (OFTOs))

11

TSOs to be certified by Ofgem

• Ofgem is expecting certification applications from 3 onshore electricity TSOs, 4 electricity interconnectors, 1 onshore gas TSO, 4 gas interconnectors and 4 OFTOs.

• Ofgem is working closely with the Commission and with ACER when certifying TSOs.

• Close cooperation with NRAs in other Member States in relation to certification of cross-border infrastructure.

12

GB unbundling models for gas TSOs1. Full ownership unbundling

2. 9(9) derogation – more effective independence of the TSO than ITO model

3. Independent system operator (ISO)

4. Independent transmission operator (ITO)

5. Holder of major infrastructure exemption under Third Package (Article 36 Gas Directive)

6. Holder of major infrastructure exemption under Second Package (Article 22 Gas Directive) or substantially similar to such a person

13

GB unbundling models for electricity TSOs1. Full ownership unbundling

2. 9(9) derogation – more effective independence of the TSO than ITO model

3. ISO

4. Holder of major infrastructure exemption under Third Package (Article 17 Electricity Regulation)

5. Holder of major infrastructure exemption under Second Package (Article 7 Electricity Regulation)

14

Certification process• 4 months to make preliminary certification decision (unless ask

applicant for additional information, restarts clock).

• European Commission 2 months to provide opinion (or 4 months if asks for ACER opinion on compliance with unbundling rules).

• We have to take “utmost account” of European Commission’s opinion and make final certification decision within 2 months of receiving it.

• For Article 9(9) applications European Commission has veto.

• Final decision to be notified to applicant, Secretary of State (SoS), European Commission.

15

Third country clause (1)• If application made on or after 3 March 2013 and applicant is a

person from a third country or a person controlled by a person from a third country, the Authority must

(a)notify the SoS and the European Commission that an application has been made; and

(b) enclose any information which the Authority has and thinks is relevant to the question of whether the security of supplies in the UK or any other EEA state would be put at risk by certification of the applicant.

16

Third country clause (2)• SoS must prepare a report on whether the security of supplies in

the UK or any other EEA state would be put at risk by certification.

• SoS must send the report to the Authority within the 6 weeks of receiving notification of application from the Authority.

• Authority may decide not to certify if on the basis of opinion expressed by the European Commission the Authority thinks that certification would put at risk security of supplies in any EEA state.

• Authority must not certify if a report prepared by SoS statesthat certification would put at risk security of supplies in the UK or in any EEA state .

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Principal objective• Directives contain new cross border objectives for the NRA relating

to promoting an internal market and eliminating restrictions on trade between Member States (see Annex) .

• Principal objective of the Authority, which is to protect the interests of existing and future consumers will be amended to comply with new objectives of the NRA in the Directives.

• Now consumers’ interests include the fulfilment by the Authority (when carrying out regulatory tasks as the NRA) of the objectives set out in Directives.

• Internal market and cross border element will therefore be part of Ofgem’s principal objective.

18

New monitoring duties & information gathering powers

• Authority already had some of the regulatory tasks set out in the Directives (see Annex), therefore GB was already partly compliant.

• Number of new broad monitoring duties introduced- investment plans of TSOs- network security and reliability- transparency, including of wholesale prices- level of market opening and competition- prices for household consumers

• New power to require information for the purposes of monitoring.

• Offence to alter, suppress or destroy documents which we required to produce.

19

Consultation and co-operation• New requirement that we must (wherever we think fit) consult and

co-operate with ACER and with NRAs with a view to:– Integration of national markets

– Promotion/facilitation of co-operation between TSOs

– Optimal management of networks

– Promotion of jointly managed cross-border trade and allocation of cross-border capacity

– Ensuring adequate level of interconnection capacity

– Co-ordination of development of network codes

– Co-ordination of regulation of markets incl. rules on congestion management.

20

Consumer protection neasures

• GB has a large number of obligations in legislation and in licences relating to consumer protection.

• GB was already compliant with some of the requirements of the Directives.

• Some new requirements in licences and in legislation to implement consumer protection measures.

• New obligations on suppliers relating to 3 week switching, energy consumer checklist, provision of final bill within 6 weeks of switching, information that has to be included in consumer contracts.

21

Annex

22

Cross-border objectives (now part of principal objective)

• When carrying out regulatory tasks/ in close consultation with other NRAs take all reasonable measures in pursuit of following objectives:

– Promoting competitive, secure and environmentally sustainable internal market and effective market opening

– Developing competitive / properly functioning regional markets

– Eliminating restrictions on trade between member states …

– Development of secure, reliable and efficient non-discriminatory systems that are consumer oriented …

– Facilitating access to the network for new generation capacity …

– Ensuring system operators and users granted sufficient incentives … to increase efficiency …

– Ensuring consumers benefit through efficient market functioning and promoting competition …

– Protection of vulnerable customers and contributing to compatibility of data exchange procedure for customer switching …

23

Regulatory tasks of the NRA (1)

• Fixing or approving transmission or distribution tariffs or methodologies (transparent criteria) …

• Ensuring TSOs, DSOs and SOs comply with EU obligations …• Co-operating re cross-border issues with ACER and NRAs …• Complying with and implementing legally binding decisions of

ACER/Commission …• Annual report to member state/ACER/Commission re fulfilling duties …• Ensuring no cross-subsidies between transmission, distribution, storage,

LNG and supply … • Monitoring investment plans of TSOs …• Monitoring compliance with and reviewing past network security

performance … and setting/approving quality of service standards …• Monitoring transparency incl. wholesale prices …• Monitoring level and effectiveness of market opening and competition incl.

domestic prices, switching rates, disconnection rates and domestic complaints …

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Regulatory tasks of the NRA (2)• Monitoring restrictive contractual practices …• Respecting contractual freedom re interruptible and long-term contracts if

compatible with EU law …• Monitoring time for transmission and distribution connection / repairs …• Helping ensure consumer protection measures effective and enforced …• Publish annual recommendations on compliance of supply prices with

Article 3 of Directives 2009/72/EC and 2009/73/EC …• Ensuring customer access to consumption data …• Monitoring implementation of rules on roles and responsibilities of TSOs,

DSOs, suppliers and customers …• Monitoring investment in generation …• Monitoring technical co-operation between EU and third country TSOs …• Monitoring implementation of safeguards as per Article 42 Directive

2009/72/EC and Article 46 Directive 2009/73/EC …• Contributing to compatibility of data exchange processes for most

important market processes …

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Regulatory tasks of the NRA (3)

• Monitoring access to storage, linepack and other ancillary services … may including reviewing tariffs …

• Monitoring correct application of criteria that determine whether storage facility falls under Article 33(3) or (4) of Directive 2009/73/EC …

In carrying out these duties we must, whilst preserving our independence, consult with TSOs and co-operate with NRAs.

RAV Regulation – framework and issues

Bob Davey

27

Overview of GB regulated utilities• Utilities are asset intensive businesses and in network only businesses (no

supply activity) asset related costs (ie depreciation and return) are typically the vast majority of revenues

• The Regulatory Asset Value (RAV) is therefore at the heart of the regulatory system

• If there is confidence in:– Stability of the RAV– Durability of the RAV– Transparency of the RAV

• It will allow– Funds to be easily raised– At relatively low rates of return – For long duration

• To the benefit of lower charges for consumers

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Investor perceptions• RAV is a cornerstone of investment

– Allowed return can vary– Depreciation rates can vary– Value must remain intact

• Need to build confidence over time in stability and predictability of RAV• Net Present Value of future cashflows must => RAV

• Consultation feedback: “long term investment with opportunity for acceptable returns based on predictable and stable cashflows”

• Typical values• Gearing (Debt/RAV) - 60-65%• Cost of debt funding - 5% (2% real)• Cost of equity - 7% real• Asset Life - 45 years

29

Key requirements

• For RAV to be effective:– Need transparent rules– Regulatory body to act consistently and transparently in

decision making– Clear methodology/ definitions to add values– Deal with stranded asset risks

Opening RAV + RAV

additions - Depreciation -Cash

proceeds of sale

= Closing RAV

30

RAV Opening value• In Ofgem we use a financial capital maintenance approach• In a financial capital maintenance approach the value of investors

investment is maintained in real terms as opposed to the operating capability of the network. We do this by index linking the RAV to a widely acceptable measure of general inflation.

• The main alternative is an operational capital maintenance approach - MEAV (modern equivalent asset value)

• The approach has implications for assessing the initial value• For our utilities the initial value was set following privatisation to reflect the

investment made by investors• The initial values were in general significantly lower than the MEAV

valuations

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Depreciation & Disposals

Depreciation• We believe the appropriate approach is to use economic asset lives• Generally quite long for infrastructure assets – 45 years • Longer periods spread recovery of investment over period that reflects the

period in which asset will be in use • We have used accelerated rates of 20 years in the past• The period used does not affect value of cash flows but does affect the

timing of return of investment and cash flowsDisposals• Generally low for disposal of pipes or wires but can be more substantial, for

example, for land• We deduct proceeds of any disposals from RAV • All benefits attributable to consumers who have been funding the assets• Can introduce some incentives on management to sell surplus land by

allowing company to retain a portion of sales proceeds.

32

RAV additions• At each Price Control we agree a funded level of additions• Licensees are remunerated during the price control period for this assumed

level (ie they receive deprecation funding and return on investment as if the investment had been made).

• In our annual reports we update forecast with actual additions so that the markets have a latest view of our provisional RAV (subject to efficiency review)

• Actual additions are therefore based on actual spend• Traditionally at the next Price Control we will review the efficiency of the

expenditure and disallow any inefficient spend• We then confirm an opening RAV number with actual additions for the next

period (subject to amending final year forecast spend)

33

Adding costs to the RAV• At the price control review the RAV is projected forward using allowed costs• When operators report their actual costs these are reviewed and the

allowed actual costs, subject to a sharing factor, are used to update RAV• The sharing factor enables operators to keep a portion of any efficient

underspend but only allows a portion of efficient overspend to enter RAV

34

Recent developments

• Under our RIIO framework we have moved to the use of totex in determining RAV additions

• Totex is total allowable capex and opex (excluding items dealt with as pass through costs)

• A fixed percentage of totex is treated as additions to RAV with the remainder funded in the year incurred

• We also now have a sharing factor for over and under spend of totex so that these are shared with consumers. E.g. an overspend of £10m and sharing factor of 50% would see £5m being treated as totex with the remainder being funded by shareholders.

Returns allowed – the balancing act

Ben Shafran

36

The regulatory balancing act

Protect the interests of consumers

Facilitate investment

in the networks

How do we do it?• Allowed return on

the Regulatory Asset Value

• Financeability assessment

• Return on Regulatory Equity (RoRE) analysis

37

Approach to the allowed return• We set an allowed return on the Regulatory Asset Value (RAV) based on an

estimate of the Weighted Average Cost of Capital (WACC)• We set a real vanilla WACC – i.e. we exclude the impact of inflation• Our approach to the WACC consists of:

– Pre-tax cost of debt – updated annually based on a 10-year trailing average index

– Post-tax cost of equity – estimate based on the Capital Asset Pricing Model (CAPM) and sense-checked against other measures

– Notional gearing - an assumption based on credit rating agencies’ target gearing ratios for network companies with BBB-A credit rating, and sense-checked against observed gearing levels of the companies we regulate

• Under RIIO, the allowed return may be set at different levels for sector and/or companies that face materially different cash flow risks

38

• At the start of each price control period the cost of debt will be set based on a long-term historical average

• It will then be adjusted annually to account for movements in the index

Cost of debt indexation

• Following consultation we decided on an index of bonds with 10+ years remaining maturity and credit ratings in the range BBB-A

• The network companies have typically been able to raise debt at a lower cost than the prevailing market rate

39

Cost of equity - CAPM• CAPM parameters have been affected by the crisis: negative real risk-free rate

in the UK, high equity risk premium• We ignore short-term volatility and focus on long-term trends: risk-free rate has

been declining for 15 years, but overall returns on equity have been stable in the long-term

• Equity beta for regulated companies very low (around 0.5-0.6) but we typically make a more conservative estimate close to 1

-1.0

-0.5

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5(%) Estimate of the real risk-free rate using index-linked gilt yields

10-yr ILG 20-yr ILG 10-yr fixed average

RIIO-T1/GD1range: 1.7-2.0%

40

Cost of equity – sense checks• To ensure that we set the cost of equity at an appropriate level, we sense-

check the CAPM range against alternative measures:– Regulatory precedents, in order to ensure consistency over time– Market data, such as premiums to RAV when network companies are sold– We also consider estimates from the Dividend Growth Model (DGM) and the

Residual Income Model (RIM), although both have limitations

41

Financeability• The Authority has a ‘financing duty’ to ensure that price control settlements

allow network companies to finance their activities at economic cost• We measure financeability with reference to various ratios that assess the

ability of a company to meet its obligations to its debt and equity providers• On the debt side, the notional company should achieve ratios that are

consistent with the target levels set by the three major rating agencies for regulated network companies to attain a rating in the range BBB-A

• On the equity side, we target low and stable ratios for:– Regulated Equity/EBITDA– Regulated Equity/Regulated Earnings

A BBB A Baa A BBBNet debt / RAV (%) 50 - 65 >65 45 - 60 60 - 75 <70 >70FFO interest cover (x) 4.0 - 5.0 <4.0 3.5 - 5.0 2.5 - 3.5 >3.5 2.5 - 3.5PMICR1 (x) >1.7 <1.7 2.0 - 4.0 1.4 - 2.0FFO / Net debt (%) 12 - 20 8 - 12 >12 8 - 12RCF / Capex (x) 1.5 - 2.5 2 1.0 - 1.5 2

2 According to Moody's, utilities undergoing a large capex programme who do not benefit from accelerated depreciation are expected to score this metric at a Ba level, i.e in the range 0.5 - 1.0.

Standard & Poor'sMoody'sFitch

1 Moody's calls this metric 'Adjusted interest cover ratio (I CR)' but the definition it uses is consistent with the definition of PMI CR used by Fitch.

42

Return on Regulatory Equity (RoRE)• RoRE is a common measure that shows the impact of all variations in outturn

and ranks their relative importance• We are using RoRE to estimate a likely performance range of the price control

settlement, essentially indicating the likely level of risk for the companies• RoRE helps us identify whether the overall settlement achieves an appropriate

balance between risk and return

0%

2%

4%

6%

8%

10%

12%

SPTL SHETL NGET_TO

RoRE

Return On Regulatory Equity - Plausible Range for Electricity Transmissionunplanned outages

tax trigger deadband

under delivery

Broader environmental objectives

SF6, +ive mean value

connections

stakeholders, +ive mean value

customers - broad measure

planned outages, +ive mean value

late delivery

Cost upside

RORE per WACC + non zero incentives

Cost downside

late delivery

planned outages

customers - broad measure

stakeholders

connections

SF6

Broader environmental objectives

under delivery, -ive mean value

tax trigger deadband

unplanned outages

TPCR4/GDPCR 60%/62.5% gearing

TPCR4/GDPCR 7.0%/7.25% CoE

Benchmarking

Adam Cooper

44

Benchmarking

• Benchmarking is an important part of UK economic regulation• Comparisons within sectors – water, electricity and gas

distribution• Less easy for GB transmission – three electricity operators of

different scale, one gas operator.• Can also use the past as a benchmark, but transmission networks

are changing in size.• Opex/Business support• Unit costs• Age based modelling

45

Benchmarking

• Two types of benchmarking undertaken for RIIO– Totex benchmarking– Disaggregated benchmarking

46

Totex Benchmarking

• Comparing total expenditure of transmission companies against identified cost drivers.

• Using total expenditure avoids problems with capex and opex definitions

• Use international comparators• Ofgem kicked off a project in September 2010• Wrote to international regulators seeking common data• Legal and practical issues meant that we could only use US data

from FERC.• Collected data on 28 electricity companies and 26 gas companies

to compare with GB TOs

47

Totex Benchmarking

• Identified cost drivers – for electricity these included:– Length of network– Energy transmitted– Age of assets.

• Used econometric analysis to rank the transmission companies• Difficulty over comparability of data (eg pole km, circuit km,

controlling for voltages, depreciation rates)• Decided to place less weight on the results compared to other cost

analysis tools.• We will be publishing an initial report in Summer 2012.

48

Disaggregated Benchmarking• We are able to benchmark specific costs in order to determine

efficiency• Particularly useful for asset replacement, but also for new

connections and for business support costs.• For asset replacement, companies provide costs of specific

projects (eg replace a 275kV transformer or 10km of overhead line).

• We can compare this to:– Historic costs and allowances– Other GB TOs– International TOs

• We use specialist engineering consultants to determine whether project costs are efficient, and will set allowances at the level of efficient costs.

49

Disaggregated Benchmarking• Business support costs (HR, IT, Property) can be compared to

other non-transmission companies• We collect cost information with standard definitions across

transmission and electricity and gas distribution companies• We have also bought information from a specialist benchmarking

consultancy firm (Hackett) regarding the business support costs in other network businesses (eg mobile telephones, railways)

50

Benchmarking – the future

• We hope to work with other energy regulators to share information and develop robust benchmarking studies for transmission

• We are also looking for TOs to provide evidence that they use benchmarking or market testing to determine that their costs are efficient.

The role of Ofgem in assessing investment

Adam Cooper

52

Introduction

• Background to RIIO• Overall methodology for assessing transmission costs• Investment drivers• Non-load related expenditure• Load-related expenditure• Input prices

53

The industry is facing unprecedented change

De-carbonisation

Security of Supply

Ageing Assets

Affordability

ELECTRICITY NETWORKS

GAS NETWORKS

• Renewables / new generation• Smart Grids• Electricity storage• Electric vehicles• Different network patterns• Electrification of heat• Energy efficiency• Local generation• Demand Side Management• Carbon Capture and Storage• Biomethane• HVDC• Skills shortages

54

RIIO framework seeks to address these challenges

Constraint set up front to ensure:

Revenue

Deliver outputs efficiently over time with:Incentives

Technical and commercial innovation encouraged through:

Innovation

Outputs set out in clear ‘compact’, reflecting expectations of current and future consumersOutputs

=

+

+

Timely and efficient delivery

Network companies are

financeable

Transparency and

predictability

Balance between costs faced by current and future consumers

8 yr control Rewards/penalties for delivery Upfront efficiency rate

Core price control incentives

Option to give third parties a greater role in delivery

Innovation stimulus package

55

Overall methodology for assessing transmission costs

• Toolkit approach to assessing transmission network owners’ (TOs) forecast expenditure– International totex benchmarking: primarily focusing on US and

European data– Trend and unit cost analysis, disaggregated benchmarking

(relevant for opex, capex unit costs)– Age and condition-based modelling (non-load capex)– Output-based analysis– Expert review (all areas of costs)– Project by project review – large load-related and non-related

schemes– Detailed network modelling undertaken by the companies

themselves

56

Distribution and transmission investment drivers

• Large number of drivers of investment in transmission and distribution assets

• Peak investment occurred during the 1950s to 1970s for both distribution and transmission – these assets are now reaching the end of their asset lives. Condition based monitoring smoothes the peak but still large increases.

• Large amounts of new generation being connected at both distribution and transmission. The move to more renewable generation being connected both onshore and offshore is a large driver of both local reinforcement and reinforcement across major boundaries

• The SQSS security standards are an important investment driver. This is based around N-2 for the core of the transmission network. The P2/6 standard for distribution is based around N-1.

• Both operational (SCADA and telemetry on the network) and non-operational (back-office functions are a key driver of investment.) Significant SO investment being proposed as balancing becomes more complicated.

• National security and resilience expenditure is also an important driver of investment.

57

Non-load related expenditure• Number of key tools that we make use of in assessing non-load related

expenditure– Age based modelling: we have a common model which has been

shared with the TOs.– Monte Carlo modelling– Condition and criticality information– Unit costs– Scheme based review

• Age based modelling is a useful tool for assessing the overall volumes of replacement work forecast by the companies and for looking at longer-term volumes. However, we expect the companies forecast to be robustly justified using condition evidence.

• We have been working with the distribution and transmission companies to define common scopes of work to allow unit cost comparisons across companies and against independent information. KEMA provided unit cost information to us for the TPCR rollover. KEMA and Poyry are doing similar work for RIIO-T1

58

Load-related expenditure• For high-volume low cost work such as connections we typically rely on unit

costs analysis. We will form an appropriate view of baseline costs through benchmarking and then apply of volume driver for differences in workload. Essentially the adjustment is the change in volumes times a unit cost allowance

• For higher value projects there are typically 3 elements to our review– we review the “need case” or economic justification of the projects and

potentially some of the sub-components and the readiness of the company to take forward the planned work.

– we review the extent to which the project (or sub-component) has materially different characteristics, e.g. in terms of utilisation risk, cost risk or deliverability risk, compared to other similar projects in the past.

– we assess the appropriate costs of the project taking into account the factors listed above and put in place appropriate output measures. As part of this we carry out unit cost benchmarking within the projects (e.g. procurement of transformers) both between the companies and wider industry (using consultants).

59

Input price inflation• In setting an ex-ante allowance for input price inflation we use a range of

evidence and challenge the companies’ assumptions which they submit to us. Eg. ONS: average weekly earnings, producer price indices, Bloomberg: commodity prices both historic and forward curves.

• The techniques for forecasting input price inflation that we have used previously and will look to use in future price controls include:– analysis of historical trends of relevant price indices relative to the RPI– historical correlation of price indices with RPI combined with forecasts

of RPI to produce RPE forecasts (our consultants, CEPA, used this approach in their analysis for us at the fifth electricity distribution price control review (DPCR5))

– examining analysts' forecasts of input price growth where available (eg the HM Treasury publication 'Forecasts for the UK Economy')

– any other well-justified evidence provided by the network companies

60

Setting companies’ allowances• Baseline: annual capex and opex allowances set at the beginning of the

price control period.• Volume drivers: allowances vary with the level of work undertaken, with a

unit rate set at the beginning of the period. Used when the timing and amount of work is outside the company’s control (eg new generation connections to the grid).

• Within-period determinations: large projects where no allowance is set at the beginning of the period. A ‘trigger’ event leads to companies submitting forecast project costs, which are agreed or adjusted by Ofgem

These mechanisms protect consumers by matching allowances to volumes of work, and protect companies from uncertainty over costs and volumes of work.

Quality and Reliability Indicators

Adam Cooper

62

Quality and Reliability Indicators• Quality of supply determined by the Security and Quality of Supply

Standards (SQSS). These standards are owned by National Grid, and updated in consultation with the industry. Ofgem provides input.

• Ofgem sets a number of outputs for Transmission Owners as part of the RIIO price control. These include:– Energy not Supplied (ENS)– Average Circuit Unreliability (ACU)– Asset health and criticality measures

• Intention is for companies to work with stakeholders to determine reliability levels.

63

Energy not Supplied• Set by companies and agreed with Ofgem for each year of the price control• Companies set a target for ENS (MWh), with revenue rewards if they beat

this target and penalties if they fail. Penalty capped at 3% of revenue.• Companies can also decide on the strength of the incentive (ie how much

reward or penalty). Penalty should be based around Value of Lost Load (VOLL) – academic studies estimate this at £4000-£32000 per MWh.

• All TOs have suggested £16000 per MWh.• Some exceptions to ENS (mainly force majeure or very extreme weather).• One TO has also proposed a mechanism to provide compensation directly

to customers in the event of energy not supplied.

64

Average Circuit Unreliability (ACU)• ACU sets a target for the average amount of time that a TOs circuits are

not available.• This includes unplanned outages (eg storms, equipment failure) and

planned outages (eg maintenance, asset replacement, connection of new infrastructure)

• Incentive for TOs to work with each other and the System Operator to agree planned outage times and minimise constraint costs.

65

Asset health and criticality• Robust asset information and network outputs are key assets in relation to

network businesses– For the day-to-day running of the networks– Making appropriate interventions– Developing business plans (internally and for the regulator)– Give clarity to customers in terms of what will be delivered– Setting the regulatory contract– Monitoring and reviewing company performance

• Important to remember that the main reason for encouraging/incentivising better information is for companies to manage themselves more effectively and therefore deliver better value for money

66

RIIO Process• Network demographics requiring increases in expenditure• In their business plans, Companies ...• commit to achieving forecast level of network risk;• identify most efficient intervention options; and • forecast likely costs

• Ofgem assesses quality of plans and efficiency• Annual allowances set ex ante• Other lagging indicators – energy not supplied, average

circuit unreliability• Ongoing monitoring - sharing factor applied to

under/overspends• End of period review (2020/21) – unjustified under-delivery

penalised and output gap rolled forward, justified over-delivery rewarded

67

Risk/Criticality MatrixHealth Index Description

HI1 New or as newHI2 Good or serviceable conditionHI3 Deterioration requires assessment and monitoring

HI4 Material deterioration, intervention requires consideration

HI5 End of serviceable life, intervention required

Criticality Index

Description

CI1 Very HighCI2 HighCI3 MediumCI4 Low

CI1 CI2 CI3 CI4HI5 RI1 RI2 RI3 RI3HI4 RI2 RI3 RI4 RI4HI3 RI4 RI4 RI4 RI5HI2 RI5 RI5 RI5 RI5HI1 RI5 RI5 RI5 RI5

Risk Index drives intervention decisions and replacement priorities

68

Asset health and criticality measuresCurrent

Forecast degradation Forecast price

control package

0

10

20

30

40

50

60

RI 1 RI 2 RI 3 RI 4 RI 5

No.

of a

sset

s

Year 0 risk index

RI 1

RI 2

RI 3

RI 4

RI 5

0

5

10

15

20

25

30

35

RI 1 RI 2 RI 3 RI 4 RI 5

No.

of a

sset

s

Year 8 no investment

RI 1

RI 2

RI 3

RI 4

RI 5

0

10

20

30

40

50

60

RI 1 RI 2 RI 3 RI 4 RI 5

No.

of a

sset

s

Year 8 with investment

RI 1

RI 2

RI 3

RI 4

RI 5

Price control funds the delta between these profiles

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Forward looking • Companies take greater responsibility for appropriate asset

management decisions and intervention and the safety and reliability of their networks.

• Companies can demonstrate that delivery is at efficient cost over the longer-term (whole-life costing, value for money)

• Companies have appropriate information and decision support tools in place to make asset management decisions. They can justify them to regulators and customers.

• Aspirational goal to have a measure of risk that can be used across different types of assets (e.g. overhead line, transformers).– in the meantime looking for companies to be able to articulate

the key trade-offs they are having to make.

Tariff menu and Charging

Adam Cooper

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Tariff Menu• Tariff menu known as IQI (Information Quality Initiative) under

RIIO.

• Companies have an incentive to provide accurate forecasts based on efficient costs

• Companies with lower forecasts gain extra revenue

• Companies with higher forecasts have a penalty

• Forecast also affects the sharing factor – a higher forecast means a lower sharing factor.

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Tariff Menu

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When we say ‘the National Grid’…….

Transmission Licence:• Single licence relating to the

NETS.

• Covers both SO activities and TO activities.

• Currently three onshore TOs.

• Currently four Offshore TOs.

Technical:• E&W: Transmission is 275 kV

and over

• Scotland: Transmission is 132 kV and above

• Offshore: adopted 132 kV and above

• The ‘high voltage’ electricity transmission system (NETS) in GB is owned by monopoly companies (Transmission Operators aka TOs)

• The TO activity function involves the provision of transmission network services to the single System Operator (SO). This role is performed by NGET

• The provision of network services is linked to providing transmission capability at different locations.

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There are three ‘transmission charges’ …Connection charges

• Charges for the provision and maintenance of assets that facilitate connection to the transmission system

• Assets solely required to connect a generator

• Costs and charges are specific to a individual user

Access charges

• Charges for the provision and maintenance of assets that facilitate access to the transmission system

• Assets that can be potentially shared

• Charges vary by location• Charges are recovered from

all users (both G and D).

Balancing charges

• Charges relate to the costs of the real time operation of the network

• Used to mitigate constraints

• Costs are smeared across all users through a socialised charge

In combination, these charges seek to:• recover the costs incurred• generate an appropriate return on efficient activities. • ensure overall cost of electricity is minimised (generation and transmission)

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Current GB approach to allocating transmission costs (2011/12)

Generation: ~£400m

Demand: ~£1200m

£100m

Demand: £350m

Generation: £350m

Non locational

15% Locational85% Non locational

Uniform energy price in wholesale market;(transmission losses recovered by non-locational volume scaling in energy trading)

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Generator use of system charging structure

Assets local to generators: potentially shareable infrastructure assets that would not be required without the generation connection.

Wider assets: potentially shareable infrastructure assets in the deeper transmission system (known as the ‘Main Interconnected Transmission System’ (MITS), that facilitate bulk transfer of power.

Generation TNUoS tariff is comprised of three separate components:i. A ‘local’ component reflecting the costs of the local network, this is comprised of

a local substation and local circuit charge.ii. A ‘wider’ component reflecting the costs of the wider networkiii. A ‘residual’ charge which recovers the costs of non-locational elements of the

wider transmission system.

The effective tariff paid by a generator is the sum of i, ii and iii.

The annual charge is based on: effective tariff * capacity (TEC).

Generator charges differentiate between local and wider transmission infrastructure:

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Demand TNUoS Charging structure There is no local asset distinction in Demand, it comprises of:

i. A ‘wider’ component reflecting the costs of the wider network. There are 14 demand zones, corresponding to the 14 Grid Supply Point groups.

ii. A demand ‘residual’ charge

Unlike generators, demand users do not have an explicitly stated capacity (TEC). To provide an equivalent proxy capacity for demand, charges are based on metered demand.

Two types of demand user:

Half Hourly (HH) demand users (large industrial)

• Charge is levied on a capacity basis and calculated by: Zonal tariff (£/kW) x users’ average demand (kW) over the period of system peak (the ‘triad’).

• Triad describes the three hh settlement periods of highest transmission system demand (kW) within a Financial Year.

Non-HH demand users (smaller commercial)

• A zonal p/kWh demand charge is calculated based on annual energy (kWh) consumed during the period 16:00 to 19:00hrs over the relevant financial year.

The liability for DTNUoS can be avoided if there is no consumption during the relevant ‘peak’ demand periods.

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2011/12 TNUoS TariffsGeneration TNUoS

 Zone No. Zone Name

Zonal Tariff (£/kW)

1 North Scotland 21.492 Peterhead 19.77

3 Western Highland & Skye 22.934 Central Highlands 18.185 Argyll 14.056 Stirlingshire 14.24

15 South Wales & Gloucester 0.6916 Central London -6.8517 South East 0.6718 Oxon & South Coast -1.8819 Wessex -3.6720 Peninsula -7.04

Demand TNUoS Zone No. Zone Name

Zonal Tariff (£/kW)

Energy consumption tariff (p/kWh)

1 Northern Scotland 6.54 0.89

2 Southern Scotland 11.73 1.67

3 Northern 15.68 2.17

4 North West 19.45 2.745 Yorkshire 19.58 2.70

11 South East 26.74 3.7412 London 27.94 3.78

13 Southern 27.57 3.91

14 South Western 28.41 3.89

• Most of the demand is in the south of GB, and most generation is on the north.

G tariffs are relatively higher in the north and relatively lower in the south. D tariffs are relatively higher in the south of England and in Wales and lower

in the north of England and in Scotland.

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