Connection and Transmission Use of System Charge...

Connection and Transmission Use of System Charge Methodology:

Initial Proposals Paper

Attachment to the Authority’s letter dated 31 May 2018

i

Table of Contents

1. Introduction 1

Scope and structure of this Initial Proposals document 2

2. The assessment of the existing CUSC methodology 3

The Connection and Use of System Charge Methodology 3

The objectives and principles of transmission charging 6

3. Potential reforms to the connection charge methodology 8

Assessment of connection charge methodology 8

Possible reforms to the connection charge methodology 10

4. Potential reforms to the transmission use of system charging methodology 26

Assessment of transmission and use of system charging methodology 26

Possible reforms to the transmission use of system charge methodology28

Conclusion 59

5. Interactions between the CUSC and the price control review 62

Conclusion 65

6. Timetable for review of the CUSC methodology 66

Appendix A: list organizations that responded to the CUSC Consultation Paper 67

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Glossary

CUSC Connection and Use of System Charges

DSSS Distribution Security of Supply Standard

ENTSO-E European Network of Transmission System Operators (electricity)

GAV Gross Asset Value

kW Kilowatt

kWh Kilowatt hour

LDC Load Dispatch Centre

MAR Maximum Allowable Revenue

MEDC Muscat Electricity Distribution Company

MIS Main Interconnected System

MJEC Majan Electricity Company

MTSD Maximum Transmission System Demand

MW Megawatt

MWh Megawatt hour

MZEC Mazoon Electricity Company

O&M Operation and Maintenance

OETC Oman Electricity Transmission Company

OPWP Oman Power and Water Procurement Company

OR Omani Rial

PPA Power Purchase Agreement

RAEC Rural Areas Electricity Company

TRC Transmission Running Charge

TSS Transmission Security Standard

TUoS Transmission Use of System

WACC Weighted Average Cost of Capital

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1. Introduction

1.1 This document sets out the Authority’s Initial Proposals with respect to the possible

modification of the Transmission Connection and Use of System Charge (CUSC)

methodology.

1.2 The CUSC methodology sets the rules through which the Oman Electricity Transmission

Company (OETC) recoups the costs of financing, building and operating the electricity

transmission system for the Main Interconnected System (MIS) and the Dhofar Power

System.1 These costs are comprised of connection charges (i.e., the capital and

operating costs of a connection to the transmission network) that are paid by

generators and transmission-connected customers and Use of System charges (i.e., the

capital and operating costs of the transmission system) that are paid by licensed

suppliers.

1.3 Based on the CUSC methodology, OETC publishes annually a Statement of

Transmission System Charges that sets out the Transmission Use of System (TUoS) and

connection application fees that will apply for the following year.2 The same charges

apply to both the MIS and the Dhofar systems.

1.4 Transmission charging plays an important role in the efficient operation of the

electricity system and therefore in the overall development of the Omani economy. In

addition to facilitating the recovery of the costs of investment and operation of

transmission infrastructure, charges can also provide signals for investment

requirements in generation and transmission and, to the extent that the charges are

reflected in end-user tariffs, can also encourage more efficient electricity consumption

behaviour.

1.5 In January 2018, the Authority published a Consultation Paper that discussed the

strengths and weaknesses of the existing CUSC methodology based on an assessment

against a set of principles and objectives that electricity transmission charging should

deliver. The Consultation Paper also discussed the interactions between the CUSC

methodology and OETC’s price control review (i.e., whether the CUSC methodology

creates incentives for OETC, generators and/or transmission-connected customers that

improves or reduces the overall efficiency of transmission costs). Finally, the

Consultation Paper proposed a range of areas in which the CUSC methodology could

potentially be reformed in order to better deliver those objectives.

1 In other areas, transmission services are provided by the vertically integrated Rural Areas Electricity

Company (RAEC).

2 The Statement of Transmission System Charges for 2018 can be found at: http://www.aer-

oman.org/aer/NetworkCharges.jsp?heading=2

http://www.aer-oman.org/aer/NetworkCharges.jsp?heading=2

http://www.aer-oman.org/aer/NetworkCharges.jsp?heading=2

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1.6 The Consultation Paper was sent to a range of stakeholders in the electricity sector,

including OETC, Oman Power and Water Procurement Company (OPWP), the Discos and

to generators. These stakeholders were invited to submit their views on both the

Authority’s assessment of the existing methodology and the proposed reforms.

1.7 The Authority has scrutinized and analysed the responses received in order to develop

this Initial Proposals document, which considers a number of possible changes to the

CUSC methodology.

Scope and structure of this Initial Proposals document

1.8 The remainder of this Initial Proposals paper is structured as follows:

Section ‎2 provides an overview of the responses related to the criteria that the

Authority used to assess the existing CUSC methodology;

Section ‎3 provides an overview of responses from stakeholders to proposals related

to connection charging and the Authority’s Initial Proposals;

Section ‎4 provides an overview of responses from stakeholders to proposals related

to TUoS charges and the Authority’s Initial Proposals;

Section ‎5 provides an overview of the questions related to the interactions between

the CUSC methodology and OETC’s ongoing price control review; and

Section ‎6 sets out the timetable for responding to these Initial Proposals and the

Authority’s timetable for making any changes to the CUSC methodology.

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2. The assessment of the existing CUSC methodology

2.1 In this section, we provide a brief overview of the CUSC methodology and the objectives

and principles that were developed in the Consultation Paper in order to assess that

methodology. The full methodology is set out in the Connection and Use of System

Charge Methodology Statement (also known as the “Condition 25 Statement”), which is

developed by OETC.3

The Connection and Use of System Charge Methodology

2.2 The Transmission and Dispatch Licence places obligations on OETC with respect to

connection and use of the transmission system. With respect to connection, OETC has

an obligation pursuant to a condition of its licence to offer terms for connection to any

person who applies, where the capital and operating costs of the connection are

recouped from the connecting entity. In terms of use of the transmission system, in

accordance with its licence, OETC is required to accept electricity into the transmission

system from OPWP or a licensed supplier and to deliver such quantities of electricity to

exit points on the transmission system as required by OPWP, or a licensed supplier. The

costs of the transmission system are recouped from licensed suppliers through TUoS

charges.

Connection charge methodology

2.3 Connection charges cover the costs of ‘Connection Assets’ (which are defined as the

assets solely required to connect an individual user to the transmission system and

would not normally be used by another party), any ancillary items (e.g., common

buildings that house the connection assets and other assets) as well as covering the

on-going costs of maintaining the connection.4 The connection charges apply to all

parties connected to the transmission system, which includes electricity generators,

suppliers and transmission-connected customers.

3 See:

www.omangrid.com%2Fen%2FReport%2FConnection%2520and%2520Use%2520of%2520System%2520C

harge%2520Methodology.PDF&usg=AOvVaw1ZPMDMXcw9qnIgZkOz4OMw

4 Connection and Use of System Charge Methodology Statement, Section 2 (Charging Principles).

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2.4 The annual connection charge is composed of two elements: (a) capital charge; and (b)

transmission running charge (TRC). The capital charge component recovers the capital

cost of providing the connection assets. The capital charge is based on the Gross Asset

Value (GAV) of the connection assets (which represents the capital element of the

actual costs of providing the asset, including the costs of purchase, transport,

installation, financing, design and consents) annuitized over the weighted average

asset lifetime. The annuitized value includes a rate of return based on the weighted

average cost of capital (WACC), set through OETC’s price control process. The WACC

that is used in the charge calculation remains unchanged across the lifetime of the

asset The capital charge is based on the following formula (reproduced from the

CUSC5):

Capital charge = (GAV x WACC) / 1 – (1 + WACC)-N

Where:

GAV = gross asset value

WACC = weighted average cost of capital

N = weighted average asset lifetime

2.5 Connecting entities have some flexibility in deciding on the period over which they will

repay the capital costs of their connection. Parties choosing to pay back the costs over

time (rather than up front) can choose to annuitize the capital costs over a period of 5,

10, 15 or 20 years.

2.6 In addition, connecting entities have the opportunity to make an up-front capital

contribution through the Capital Charge Payment Option. Any up-front capital

contribution is deducted from the GAV in the calculation of the annual capital charge.

In the situation where the connecting entity pays the capital costs up-front in full, the

annual capital charge will be zero.

2.7 The TRC component of the annual connection charge recovers the costs of operation

and maintenance of the connection assets. Some entities are responsible for the

operation and maintenance (O&M) of their connection asset (so-called ‘user

maintained assets’). As such, no TRC is charged to these entities.

2.8 For all other entities, the TRC is calculated through an annual ‘TRC factor’, which is

based on the inflation-adjusted connection asset operating expenditure allowance

(which is set in OETC’s price control review) as a proportion of the total connection

asset GAV (excluding user maintained connection assets). The TRC factor is calculated

through the following formula:

5 Connection and Use of System Charge Methodology (p.19)

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TRC Factor = Connection Asset Operating Expenditure Allowance (inflation

adjusted) / (Connection Asset GAV – User Maintained Connection Asset GAV)

2.9 The TRC factor will therefore vary from year-to-year depending on the evolution of

operating costs and connection capex. The TRC for a particular entity is then calculated

by multiplying the TRC factor by that entity’s GAV. The TRC is calculated through the

following formula:

TRC for customer A = TRC factor x (customer A’s Connection Asset GAV –

customer A’s user maintained Connection Asset GAV)

Transmission use of system charge methodology

2.10 Transmission Use of System Charges are designed to recover OETC’s Maximum

Allowed Revenue (“MAR”). This is set by the Authority at periodic price control reviews

and covers the investment, operation and maintenance costs of the transmission

network and those costs associated with balancing and dispatch. The same charges

apply in both MIS and Dhofar.

2.11 The MAR is recovered from licensed suppliers (and transmission-connected customers,

who are required to have a supply agreement with the appropriate licensed supplier)

through TUoS charges that reflect their share of Maximum Transmission System

Demand (MTSD). That is, “the maximum average electricity demand in an hour as

metered or otherwise measured at exit points on the Transmission System in relevant

year t”6 meaning that the transmission charge for each supplier is determined entirely

by the consumption of that supplier’s customers during the peak hour of the year.

2.12 For each year, OETC estimate the MAR for the coming year (based on forecasts of

MTSD and total units transmitted). OETC then deducts from MAR any other regulated

income earned in order to reach the residual amount to be recovered through TUoS

charges. The residual amount is then divided by forecast MTSD to derive a TUoS charge

expressed in Omani Rials (OR) per MW. This TUoS tariff is published by OETC in

December of each year, for the following calendar year, as part of the Transmission Use

of System and Connection Charging Statement.

2.13 As MTSD cannot be known in advance OETC invoices licensed suppliers based on an

expectation of their contribution to maximum transmission system demand. That is, if it

is expected that a licensed supplier will account for 20% of maximum transmission

system demand, it will be required to pay 20% of the MAR (minus other regulated

income).

6 Connection and Use of System Charge Methodology Statement, Section 3.

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2.14 OETC revisits these calculations at the end of the year (once maximum system demand

is known) to reflect each supplier’s actual/outturn contribution to the system and will

make any required adjustments to the amounts paid by suppliers.

The objectives and principles of transmission charging

2.15 The Consultation Paper set out a number of objectives that are potentially impacted by

the approach to connection and use of system charges. These included, objectives

related to energy (e.g., security of supply, sustainability and affordability) and the

economy (e.g., through the impact on the perception of Oman as a place to do

business).

2.16 Based on these objectives, the Authority identified a number of key principles that were

used to assess the existing CUSC methodology and guide potential reforms. These

were:

Efficiency: does the CUSC methodology encourage efficient behaviours in terms of

investment and operation of the transmission network and in terms of the type and

location of generation and demand that is connected to the network?

Non-discrimination: does the CUSC methodology avoid undue discrimination (i.e.,

differences in the costs charged to different customers that cannot be objectively

justified)?

Cost reflectivity: does the CUSC methodology target the costs of investment and

operating the transmission network at the entities responsible for those costs?

Fairness: are the costs to current and future customers of using and connecting to

the transmission network reasonable?

Simplicity: is the CUSC methodology simple to administer and understand?

Transparency: are market participants able to predict future changes in connection

and transmission charges? Is it clear to participants how they can reduce their

costs?

Future-proofed: is the CUSC methodology appropriate given the changes that are

expected within the electricity sector over the short to medium-term (i.e., creation of

a spot market for electricity and greater penetration of renewable energy)?

2.17 In the Consultation Paper, the Authority asked stakeholders if they agreed with the

principles which the Authority had mentioned in the Consultation Paper.

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Stakeholder views

2.18 In total, there were 15 responses to the Consultation Paper, from a variety of

stakeholders. This included OETC, OPWP, distribution companies and a number of

electricity generators. A list of all of the entities that responded to the consultation can

be found at Appendix A.

2.19 All of the responses indicated support for the principles set out in the Consultation

Paper. While it considered the principles a good basis for assessing the CUSC

methodology, OPWP felt that more emphasis could be put on ensuring that the

methodology provides incentives for OETC to undertake its activities in an efficient

manner (although OPWP did acknowledge that this issue was addressed in the

Consultation Paper in the section related to the interactions between the CUSC

methodology and the price control review).

2.20 Noting the responses to the Consultation Paper, the Authority continues to regard the

principles and objectives described above as appropriate for evaluating the CUSC

methodology. The Authority uses these principles and objectives in its evaluation of the

methodology throughout the rest of this Initial Proposals document.

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3. Potential reforms to the connection charge methodology

3.1 In this section, we provide an overview of the assessment of the transmission

connection charging methodology presented in the Consultation paper and consider

whether any reforms would be appropriate.

Assessment of connection charge methodology

3.2 The Consultation Paper discussed the features of the existing transmission connection

charging methodology against the assessment criteria summarized in the previous

section. A summary of that discussion is presented in Table 1. A more comprehensive

discussion can be found in the Consultation Paper.

Table 1: summary of the assessment of the existing transmission connection charge

methodology presented in the Authority’s Consultation Paper

Criteria Assessment

Cost-reflectivity

/ Efficiency

Shallow charging methodology (i.e., connecting entities pay

the cost of their connection but not the costs of any network

reinforcement that is required) means that, in the presence

of network constraints, connectors do not face the full cost

of their decision to connect.

This issue could be compounded in future given the

expected increase in renewable generation, especially if

renewable generation capacity is located far from centres of

demand.

The cost of the connection assets are passed through to the

connecting entity in full (i.e., irrespective of the costs of the

connection). It could be argued that this does not place a

strong incentive on OETC to deliver the connection at least

cost).

Non-

discrimination

The CUSC methodology offers generators and transmission-

connected customers non-discriminatory terms for

connection to the network in that they are charged directly

for the cost of their connection asset.

However, the methodology for allocating connection

operating costs (based on the value of a customer’s own

connection assets) could potentially discriminate between

customers if actual connection O&M is not proportional to

the value of the asset.

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Criteria Assessment

Fairness

Annuitizing the capital costs of connections across the

lifetime of the asset can help to achieve a fair

intergenerational distribution of costs (i.e., both current and

future customers that benefit from the connection asset are

required to pay a share of the costs).

On the other hand, though more an efficiency rather than a

fairness issue, the requirement for OETC to meet connection

costs up-front, whilst recovering such costs over the lifetime

of the asset, could potentially impact on OETC’s cash-flows

and financeability.

Simplicity

The use of shallow connection charges that just recover the

cost of the connection (but not the wider costs associated

with any system expansion or reinforcement) from the

connecting entity is relatively straightforward, which means

that it is simple to administer and understandable by

market participants.

Transparency

Both the connection charging methodology and the annual

statement of transmission system charges (which sets out

the application fees for connections) are published by OETC.

During their application, connecting entities are provided by

OETC with an indicative estimate of the capital costs of

connection. However, since the connecting entity does not

know the cost of connecting before it agrees the connection

offer the arrangement is not perfectly transparent.

Future proofed

Under the current shallow connection charging regime a

future increase in the volume of remotely located grid-

connected capacity (for example some renewables or even

conventional thermal capacity in new demand centres)

could significantly increase the costs of grid reinforcements.

These would need to be recovered through transmission

charges and would not be attributed to the party causing

such costs. Potentially this could lead to a less cost efficient

system.

Source: Connection and Use of System Charge Methodology: Consultation Paper

3.3 In the Consultation Paper, the Authority asked stakeholders whether they agreed with

the Authority’s assessment of the existing connection charging methodology.

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Stakeholder views

3.4 In general, there was a high level of support for the Authority’s assessment of the

transmission charging methodology. For example, Muscat Electricity Distribution

Company (MEDC) felt that while the current methodology is fit for purpose, it was

prudent to consider whether amendments are required given the anticipated changes

in renewable penetration (e.g. to move towards greater cost-reflectivity in connection

charging).

3.5 OPWP highlighted that, while the assessment presented in the Consultation Paper was

a good conceptual consideration of the current methodology, it would be important to

understand the materiality of the issues presented in order to properly judge the case

for reform.

Possible reforms to the connection charge methodology

3.6 The following sections discuss the range of potential reforms to the transmission

connection charging methodology that were proposed in the Consultation Paper. These

are:

Deep connection charges: this entails charging connecting entities for the costs

of any reinforcement to the transmission network that are required as a result of

the decision to connect (in addition to the costs of the connection itself). In

principle, deep connection charges should help to ensure that connecting

entities take account of the broader costs associated with their decision to

connect and, specifically, should provide an incentive to entities to avoid

connecting at more constrained parts of the network.

Reforming the methodology for charging for connection operating and

maintenance: as discussed in Table 1, the current method of charging

connection operating costs may discriminate between connections if the actual

connection O&M costs are not proportional to the value of the asset. As such,

the Authority indicated it would explore whether an alternative charging

methodology could result in a more equitable distribution of operating costs

across connections.

Up-front charging of connection capex: connecting entities are currently

permitted to repay connection capex over time (up to 20 years). Requiring that

these costs are paid up-front has a positive impact on OETC’s cash flows and

financeability, though it would have the opposite effect on parties connecting to

the network.

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3.7 For each reform, we present the range of views presented by stakeholders as well as

the Authority’s assessment and Initial Proposals. Reform options are assessed against

the set of criteria set out above. Where appropriate, the Authority has also considered a

broader set of criteria such as the impact of options on the competitiveness of the

Omani economy and public finances.

3.8 In assessing these reform options, the Authority is mindful of the fact that the Omani

market is a dynamic one, characterised by rapid, and to some extent, geographically

concentrated economic growth. This creates a potential for there to be a significant

change in the pattern of generation and demand over the next few years.

3.9 Furthermore, the Authority notes that the Omani electricity sector operates within an

economic environment characterized by a mixed economy, with private sector

investment increasing, but with significant restraints, (e.g., in relation to the availability

of land and the freedom to carry out generation or demand related activities in

different geographical locations). The Authority notes that this can limit the ability of

customers and investors to respond to price signals provided by transmission

connection and use of system charges.

Deep connection charges

3.10 As was discussed above, the current approach of shallow connection charges means

that, in the presence of network constraints, connecting entities do not necessarily face

the full cost of connecting to the transmission network. In a situation where a new

connection results in the requirement for wider network reinforcement, this cost will be

recovered from suppliers through the Transmission Use of System (TUoS) charges

rather than from the connecting entity.

3.11 This means that, in the presence of material system constraints, entities are not facing

efficient economic incentives to guide their location decisions (and may, therefore,

locate in an area that is sub-optimal from the perspective of transmission costs). A

system of deep connection charges would ensure that connecting entities face a

charge that equals the cost that they are imposing on the transmission network (i.e.

connection costs plus any required network reinforcement). This should, therefore,

provide the signals for entities to connect to the less congested parts of the

transmission network.

Stakeholder views

3.12 In the Consultation Paper, the Authority asked stakeholders whether the current

shallow connection charging methodology had resulted in sub-optimal location

decisions by generators and transmission-connected customers.

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3.13 In its response, OETC described two instances where the location of generation

capacity (i.e. Sur and Ibri power plants) was sub-optimal from the perspective of

minimizing transmission costs. In these cases, OETC noted that the power from both of

these plants needed to be transported to the Muscat area, which required substantial

investment in transmission capacity (in excess of RO 150 million). However, OETC also

pointed to a number of factors that suggest that the incentive provided by deep

connection charges would have limited impact on the market outcome. These were:

Lack of material network constraints: OETC are required to maintain and invest

in the network in order to adhere to the Transmission Security Standard (TSS),

which they argue means that there are no sustained and material transmission

constraints.7 This being the case, there would be no benefit to introducing deep

connection charges (i.e., the lack of transmission constraints means that OETC

should, in most cases, be indifferent to the location of new connections from the

perspective of required network reinforcement).

Availability of land: OETC argued that there is a very limited number of sites

available for new generation plant and that, in general, transmission connected

customers locate in ‘free zones’ or ‘special economic zones’ (which confer

benefits in terms of tax and ‘lighter touch’ regulation). That being the case, OETC

argue that it is unlikely that connecting entities would respond to the signal

provided by deep connection charges;

The importance of other factors: OETC described that there were a range of

other factors that were important in determining the location of generation plant.

For example, easy access to fuel is one of the most critical factors for fossil-

burning generation while being located in an area with the right climatic

conditions is important for renewable generation. This means that the decision

on location needs to balance a broad range of considerations (and not simply

the costs of transmission); and

Transmission costs already considered in site location: OETC noted that

transmission costs are already a factor that is considered by OPWP when

deciding on the location for new capacity. OETC describe how they provide OPWP

with analysis of the transmission costs associated with different proposed sites,

and that this is one of the factors that OPWP considers in making its decision.

7 The Transmission Security Standard is designed to ensure that transmission investment is done

in a way that will deliver the power that is required in Oman. OETC’s primary objective – which is

given effect through the TSS – is to ensure that the demand for power can be met.

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3.14 While some respondents saw some in-principle advantages of a system of deep

connection charges (e.g., MEDC felt that generators should be encouraged to locate

closer to centres of load), there was a high level of consensus around the points raised

by OETC about the lack of choice for generators in relation to locational flexibility.

3.15 OPWP pointed to the new generation procurement process that has been developed for

‘Power 2022’, which will in principle allow generators to choose between different

locations. However, OPWP felt that, in practice, the lack of available sites for new

generation would continue to be a real constraint on this choice.

Assessment

3.16 The Authority notes that moving to a deep charging methodology would potentially

result in greater cost-reflectivity in connection charges. This could result in more

efficient locational decisions by generators and transmission-connected customers,

which could help to reduce the costs of the transmission system.

3.17 Moving to a system of deep connection charges could result in larger variations

between the connection charges that are faced by different entities. For example, an

entity that connected in a constrained part of the transmission network would face a

substantially higher connection charge than an entity that connected at an

unconstrained part of the network. The Authority considers that such differences would

reflect costs placed on the system and would not therefore be discriminatory.

3.18 However, a system of deep connection charges would require OETC to make an

assessment of the impact of a connection on the requirement for system

reinforcement in order to make the connection offer. The Authority considers that this

would increase the administrative burden on OETC and would reduce the transparency

of the system of connection charges. This could make it more challenging for

connecting parties to predict and understand the costs of connection to the

transmission network. The Authority notes that the uncertainty of connection costs

under a deep system of charges could be exacerbated by planning issues, which can

on occasions result in relatively last-minute changes in substation and route locations.

The Authority considers that this could cause substantial additional costs and

complexity for connecting entities under a deep connection charging regime.

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3.19 The Authority notes that, in some circumstances, a system of deep connection charges

could be said to be a fairer system, because costs are recovered from those entities

responsible for causing costs, rather than from all customers. However, deep charges

could result in substantially higher charges on certain entities and may be less

appropriate in an environment where the pattern of supply and demand reflects other

economic drivers and limitations, such as land availability and planning constraints.

Indeed, the Authority also notes that, to the extent that deep connection charges

increase the costs of connecting to the transmission network (which would be expected

to be the case in the presence of material system constraints), this could reduce the

attractiveness of Oman as a place to do business. That is, internationally mobile

electricity-intensive businesses may choose to locate in another country in which the

connection costs are not so high. As such, deep connection charges could have a

negative impact on economic growth.

3.20 Moving to deep connection charges may also have an impact on the timescale over

which costs are recovered by OETC (and potentially therefore the requirement for

Government subsidy). Currently, the costs of network reinforcement are added to

OETC’s Regulated Asset Base (RAB) and these costs are recouped through TUoS

charges over the lifetime of the network asset (35 years). Under a system of deep

charges, these reinforcement costs are charged to the connecting entity, which can pay

the costs back either up-front or annuitized over 5, 10, 15 or 20-years. As such, deep

charges will mean that OETC will recoup these reinforcement costs over a faster

timescale, which could have a positive impact on OETC’s cash flows and financeability.

3.21 In the Authority’s view, there are some clear pros and cons associated with deep

connection charges. The key advantage of a system of deep charges relates to the

efficiencies that could be achieved through encouraging entities to connect to less

constrained parts of the network. However, realizing these benefits requires a number

of conditions to hold. These are:

Material constraints on the transmission system: in the absence of material

transmission constraints there would be no network expansion or reinforcement

required as a result of the connection, which means that the connecting entity

would simply face the cost of the connection. In this case there would be no

benefit to the introduction of deep connection charges;

Entities have a choice about where to connect: realizing the benefits of deep

charging also relies on entities being able to respond to the price signal. That is,

an entity needs to have the flexibility to be able to choose a location in a less

congested part of the network in order to effectively manage its connection

costs; and

That the current process for selecting sites for generation does not consider

transmission costs: if the transmission system costs associated with different

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potential sites are already factored into the process through which OPWP

determine the sites for new generation it is unlikely that the application of deep

charges will, in practice, impact on site selection.

3.22 As discussed in the Consultation Paper, OETC’s annual Capability Statement sets out

its assessment of system performance, which details the parts of the network that are

under stress.8 The Capability Statement suggests that there is a lack of capacity at

certain points on the transmission system to accommodate demand at summer peak.

This will limit the ability to make new transmission connections in these areas unless

action is taken to reinforce the transmission network (and/or transfer demand from

heavily loaded to more lightly loaded grid stations). However, the Capability Statement

also sets out the actions that OETC is planning in order to bring the network in

compliance with the TSS.

3.23 The Authority notes that the effectiveness of deep connection charges to influence the

behaviour of generators will also depend on how those generators are remunerated for

the power they produce. Generators currently recover their connection costs through

Power Purchase Agreements (PPAs) with OPWP. Under this set-up a generator would be

able to pass-through the full cost of a deep connection charge within the PPA price.

What this means is that generators would not suffer any financial penalty from facing a

substantial connection charge. However, the Authority notes that this could change

with the inception of the spot market. Under the new market arrangements, a

generator that faced a substantial connection charge may be less likely to be within the

merit order in the spot market (all else equal). Under these circumstances, deep

connection charges could provide a financial incentive for generators to choose a lower

cost location. We will return to the issue of the spot market in Section ‎4.

3.24 The Authority notes that deep connection charges are used in some other jurisdictions.

The approach to connection charging in a range of European counties is shown in Table

2 (which also shows whether the approach to TUoS charging includes a locational

element).

Table 2: approach to connections and TUoS charging in European countries

Country

Do TUoS

charges

vary by

location?

Shallow or

deep

charges?

Notes

Austria No Shallow -

Belgium No Shallow -

Bosnia & Herzegovina No Shallow -

8 OETC (2017), Five Year Annual Transmission Capability Statement (2017-21)

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Country

Do TUoS

charges

vary by

location?

Shallow or

deep

charges?

Notes

Bulgaria No Shallow -

Croatia No Deep

Generation pays

reinforcement costs. Load

pays a reduced rate.

Cyprus No Shallow -

Czech Republic No Shallow -

Denmark No Shallow -

Estonia No Deep -

Finland No Shallow -

France No Shallow -

Germany No Shallow -

Great Britain Yes Shallow -

Greece No Shallow -

Hungary No Deep Discounts for renewable

generators

Iceland No Shallow/

deep -

Ireland Yes Shallow -

Italy No Shallow -

Latvia No Deep -

Lithuania No Deep Discounts for renewable

generators

Luxembourg No Shallow -

Macedonia No Shallow -

Montenegro No Shallow -

Netherlands No Shallow -

Northern Ireland Yes Shallow -

Norway Yes Shallow -

Poland No Shallow -

Portugal No Shallow -

Romania Yes Shallow/

deep

Generation pays

reinforcement costs. Load

pays shallow charges

Serbia No Deep -

Slovakia No Shallow -

Slovenia No Shallow -

Spain No Shallow -

Sweden Yes Deep -

Switzerland No Shallow -

Source: ENTSO-E9

9 ENTSO-E (2017), Overview of Transmission Tariffs in Europe: Synthesis 2017

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3.25 The data in Table 2 shows that while deep charges are used by some countries (only

nine of the 35 countries listed, two of which use a combination of shallow and deep),

most use shallow charges. Of the countries with deep charges, only two (Romania and

Sweden) also use a locational element in their TUoS charges. As such, it appears that

countries tend to use either deep charges or locationally-varying TUoS charges to

provide signals to connectors, but typically not both.

3.26 The Authority also notes that in some cases discounts are provided on deep charges

for particular types of connectors. For example, Romania and Croatia both offer

discounts to transmission-connected customers (which should help to prevent the

impact of deep charges on economic competitiveness) while Lithuania and Hungary

provide discounts for connecting renewable generation.

Initial Proposal

3.27 The Authority has carefully considered the responses from stakeholders on this issue. A

summary of the Authority’s assessment of this reform against the assessment criteria

is shown in Table 3.

Table 3: Authority’s assessment of deep connection charges against assessment

criteria

Criteria Deep connection charges

Cost-reflectivity / Efficiency √

Non-discrimination -

Fairness √

Simplicity X

Transparency X

Future proofed √

Notes: √ positive assessment against criteria; X negative assessment against criteria; -

no substantive impact

3.28 The Authority notes that there are some clear in-principle benefits of a system of deep

connection charges. However, the apparent lack of material transmission constraints

suggests that creating a system of charges aimed at encouraging entities to locate on

less-congested parts of the network is not required. In addition, the lack of choice

around the location for new generation suggests that entities would be unable to

respond to such an incentive. Furthermore, we also note that the impact on

transmission costs is something that is already considered when OPWP proposes the

location of new generation. This suggests that even if a deep connection charges

methodology was adopted, it would be unlikely to change the outcome in terms of

where new generators are located. As such, the Authority is not minded to consider this

option further at this time.

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3.29 However, the Authority intends to keep under review whether it may be appropriate to

adopt a deep connection charging regime at some point in the future. As a contribution

to further thinking in this area, the Authority would encourage OPWP to monitor the

costs of transmission system constraints based on an analysis of daily constrained and

unconstrained schedules that they receive from OETC. This analysis will make an

important contribution to understanding the nature and cost associated with

transmission network constraints.

Connection Operating Costs

3.30 The previous section described how connection operating and maintenance costs are

charged on the basis of the GAV of a customer’s connection asset. That is, a customer

with a GAV that represents 1% of total connection GAV would face a charge equal to 1%

of aggregate connection charge opex.

3.31 Aggregate connection charge opex is calculated in OETC’s price control by allocating

total controllable opex to transmission system assets (for recovery through TUoS

charges) and connection assets (for recovery through connection assets). This

allocation is done on the basis of the relative value of network and connection assets,

which for T&D-PCR4 resulted in a split of 80% of opex recovered through TUoS and

20% through connection charges.

3.32 As discussed in Table 1, this methodology for allocating connection operating costs

potentially discriminates between customers where connection O&M is not proportional

to the GAV of a customer’s asset.

3.33 This was an issue that the Authority was keen to seek views on and, as such, asked

stakeholders in the Consultation Paper whether the current methodology for calculating

the TRC resulted in an unfair allocation of costs across connections.

Stakeholder views

3.34 Both MEDC and Majan Electricity Company (“MJEC”) felt that the existing methodology

had the potential to create an unfair distribution of costs across entities. MJEC cited

the illustrative example of a high-usage industrial customer with connection assets of a

132kV breaker and underground cable. The GAV of this connection would be high but

MJEC argue that this would require little O&M costs. As such, this type of an entity

would bear a disproportionate share of connection O&M costs.

3.35 MEDC also noted that the age of connection assets could also impact on the

requirement for connection O&M. That is, a newer connection asset may be less costly

to maintain compared to an older asset. However, the current charging methodology

does not distinguish between assets based on age.

3.36 However, neither MEDC nor MJEC offered any evidence on the extent of this problem.

None of the other respondents felt that this was a substantive issue.

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3.37 OETC did argue, however, that the existing methodology is complex, which creates a

substantial administrative burden on them as well as uncertainty for connecting

entities. OETC noted that any change in connection assets (e.g., a new entity connects

to the transmission network, which increases aggregate connection GAV) will require

the recalculation of the TRC and a reapportioning of the connection O&M costs

between customers. OETC point out that this means that they have to await year-end

finalization before invoicing customers.

3.38 As such, OETC proposed that charges for connection O&M should be based on a fixed

2% of GAV (which would be a reversion to the previous methodology for charging for

connection O&M). OETC argued that this would represent a more straightforward

approach for them to administer and would ensure that charges were more transparent

and predictable for connecting entities.

Assessment

3.39 The Authority notes that the current methodology of charging for connection O&M may

in certain cases result in a less than optimal distribution of costs (e.g., where O&M is

not proportional, due to differences in the age or size of the assets, to a customer’s

actual connection asset’s GAV). Reforming the methodology so that connection O&M

costs more closely reflects the actual O&M costs of each connection could therefore

result in a more equitable distribution of costs.

3.40 Moving to a system where O&M charges more accurately reflect the costs of

maintaining each connection would result in an improvement in terms of cost

reflectivity. However, the Authority notes that a system of charging O&M on a more

cost-reflective basis would necessarily result in a greater administrative burden on

OETC and the Authority. In addition, this would increase the complexity of the system,

which would potentially make it more difficult for connecting entities to understand and

predict their connection O&M charges.

3.41 The Authority does not believe that this reform would have an impact (positively or

negatively) on the robustness of the transmission system to future changes in the

electricity sector.

3.42 The rationale for making this reform rests on the presumption that, in many cases,

connection O&M is not proportional to connection GAV. If this is not the case, the

argument for making this case on the grounds of distributional equity falls away.

Furthermore, the Authority notes that, based on the responses received from

stakeholders, the fairness of connection opex charges does not appear to be a

substantive issue.

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3.43 Indeed, the Authority notes that similar methodologies (i.e., where connection opex set

in a price control review is recovered based on a calculated TRC factor and individual

connection GAVs) is in use in other jurisdictions (e.g., Great Britain).10

3.44 The Authority understands that the existing methodology for calculating connection

O&M is more complex (and therefore entails an additional administrative burden) than

OETC’s proposed approach of charging based on a fixed 2% of GAV. However, the

Authority notes that the existing methodology is designed to ensure that OETC can

recoup the permitted level of connection O&M that is set in the price control review.

Furthermore, the Authority is concerned that charging for connection O&M based on a

fixed 2% of GAV could result in OETC under or over-recovering connection operating

costs.

3.45 This point is illustrated in Table 4, which shows the, permitted connection opex set in

OETC’s price control, TRC factor,11 the level of connection opex that would have been

recouped by OETC based on its proposed fixed 2% factor and the level of under or over-

recovery that would result if connection opex was charged on the basis of 2% of GAV.

3.46 As an example, in 2013, OETC were permitted to collect RO 2.6 million (2017 prices) in

connection charges based on a TRC factor of 3.13%. Had connection charges been

based on a fixed 2% of GAV, then OETC would have recovered only RO 1.6 million. This

would result in a substantial deficit against permitted connection O&M costs of RO 0.9

million.

Table 4: impact of fixed 2% on cost recovery (2017 prices)

Year

Connection

opex

(RO mn)

TRC factor (%) GAV x 2%

(RO mn)

Under/over

collection

(RO mn)

2013 2.6 3.13% 1.6 -0.9

2014 3.2 2.83% 2.3 -0.9

2015 3.5 2.19% 3.2 -0.3

2016 3.7 2.11% 3.5 -0.2

2017 3.8 1.83% 4.2 +0.4

Source: OETC

3.47 The figures presented in Table 4 show that the TRC factor has been falling over time

(which implies that aggregate connection GAV is increasing at a faster rate than

aggregate connection O&M), Indeed, this shows that, by 2017, charging based on 2%

10 See: https://www.nationalgrid.com/sites/default/files/documents/13630-

Guide%20to%20Connection%20Charging.pdf

11 As discussed in the previous section, the TRC factor is calculated based on OETC’s aggregate connection

opex (determined in the most recent price control review) and the aggregate connection GAV. The TRC factor

is then used to calculate the charge for each connection (based on each individual GAV) and, in doing so,

allows OETC to recoup exactly the amount of connection opex that is determined by the price control review.

https://www.nationalgrid.com/sites/default/files/documents/13630-Guide%20to%20Connection%20Charging.pdf

https://www.nationalgrid.com/sites/default/files/documents/13630-Guide%20to%20Connection%20Charging.pdf

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of GAV would result in a RO 0.4 million over-recovery of costs by OETC. The extent of

over or under-recovery in future would depend on the evolution of aggregate GAV and

aggregate connection O&M costs. The Authority notes that increasing numbers of

customers wishing to move from distribution to transmission-connected in response to

the CRT may result in some upward pressure on connection GAV in the coming years.

Initial proposal

3.48 As discussed above, the Authority has carefully considered the responses from

stakeholders on this issue. Combining the points above, a summary of the Authority’s

assessment of this reform against the assessment criteria is shown in Table 5.

Table 5: Authority’s assessment of changing the basis for charging connection

operating costs against assessment criteria

Criteria

Changing the basis for charging connection

operating costs



Fairness √

Simplicity X

Transparency X

Future proofed -



3.49 In principle, it appears that the existing methodology for calculating connection O&M

charges could result in some connections bearing disproportionately high costs (e.g.,

when GAV is high relative to actual operating costs). In principle, therefore, a change to

the methodology so that connection O&M charges more closely reflected the actual

O&M costs of each connection could result in a more cost-reflective and equitable

approach. However, it is not clear from the responses received that this is, in practice,

a substantive issue, which in the Authority’s view weakens the case for making this

reform.

3.50 Furthermore, the existing methodology is designed so that it ensures that OETC can

recoup exactly the level of connection O&M allowance set in its price control review.

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3.51 The Authority acknowledges that OETC’s proposal to move to charging customers

based on a fixed 2% would offer a simpler solution that would be easier to understand

and administer for OETC. However, the Authority believes that this will create additional

complexities that will need to be managed. For example, it appears that charging based

on a fixed 2% would inevitably result in some under or over-recovery of opex by OETC.

This disparity would then need to be accounted for through some adjustment to the

TUoS charges, which (depending on the time lag between the under/over-recovery and

the correction through TUoS) may require further adjustment to account for the time

value of money. In the Authority’s view this would create an additional layer of

complexity and unpredictability within the methodology.

3.52 Based on this assessment, the Authority does not consider the benefits that could be

realised to be commensurate with the costs that would be created through this reform.

As such, the Authority is not minded to consider this option further at this time.

Up-front charging of connection capex

3.53 As set out in the previous section, connection charges are made up of a capital charge

(which allows OETC to recoup the capital cost of the connection asset) and a

transmission running charge (which allows OETC to recoup the connection operation

and maintenance costs). Under the existing CUSC methodology, connecting entities are

permitted to decide on whether they will pay for the capital costs of their connection

up-front (through a lump sum payment) or over time (through an annuitized charge).

3.54 In a situation where an entity decides to pay their connection capital costs over time,

OETC is required to fund the up-front costs of the connection. OETC will then recover

these costs over the annuity period chosen by the connecting party. The Consultation

Paper raised the issue of whether annuitizing connection costs could create cash flow

and financeability issues for OETC and, as such, sought stakeholder views on this

issue.

Stakeholder views

3.55 The majority of respondents felt that they did not have sufficient understanding of the

financing arrangements for new connections to offer a view to this question. However,

both MJEC and the Mazoon Electricity Company (“MZEC”) pointed out that while

shifting to up-front payment of connection capital costs would improve the cash flows

of OETC, it may create cash flow challenges for generators and transmission-connected

customers.

3.56 OETC reported that, under the current arrangements, entities have the choice to pay

their connection costs up-front or to annuitize them over a period of 5, 10, 15 or 20

years (with relatively few choosing to pay the costs up-front and the majority choosing

to repay the costs over a 20 year period). The split between up-front and annuitized

connection costs are shown in Table 6. This shows that 92% of all connections by

number (and 98% by value) chose to annuitize their connection capital costs rather

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than pay up-front.

Table 6: up-front and annuitized connection asset values (2017 prices)

Payment method Number of connections Total value of connection

assets (RO mn)

Up-front 10 4.8

Annuitized 112 221.8

Source: OETC

3.57 In spite of this, OETC noted that they do not have major concerns with the current

approach to annuitizing connection capex costs. OETC felt that this had not caused

them any financeability issues to date (not least because it is permitted to collect a

WACC element in the annuitized payment which adjusts for the time value of money).

However, OETC did feel that this could become an issue in future, particularly if there

was an increase in the number of transmission-connected customers.

3.58 Specifically, OETC stated that its own funding plan is typically based on a 10—year

repayment period and argued that there would be a benefit in capping the annuity

period to the same timescale, in order to more closely match connection capex

payments with OETC’s repayment schedule.

Assessment

3.59 The Authority notes that, in principle, allowing connecting entities to pay their

connection costs over time (rather than up-front) could create financeability challenges

for OETC, although this had not been shown to create any problems to date. There is

also the potential that it could discourage entities from wanting to connect. The

Authority notes that the decision about whether to charge connection costs up-front or

over time does not alter the present value of the costs that a connecting entity is

required to pay. As such, the Authority does not believe that this reform will impact

(positively or negatively) in terms of the cost-reflectively of the charges, or the efficiency

of the transmission system. Similarly, the Authority does not believe that this reform

would have a substantive impact on the transparency or simplicity of the system of

charges. Nor would it impact on the robustness of the transmission system to future

changes in the electricity sector.

3.60 As was noted in the Consultation Paper, changing to up-front charging would impact on

the profile of connection cost for distribution companies. Connection charges are a

pass-through for the distribution companies, which means that a shift towards paying

for the cost of connections up-front would result in a large increase in pass-through in

certain years (and, therefore, in the subsidy requirements for that year). The Authority

notes that this is contrary to the typical treatment of asset purchases, for which the

costs tend to be recovered over time.

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3.61 This is illustrated by Figure 1, which shows the ‘lumpy’ distribution of connection capex

over time for MEDC, MJEC and MZEC.

Figure 1: profile of connection capex for Muscat, Majan and Mazoon distribution

companies (values based on nominal value of asset at the time of installation)

Source: OETC

3.62 The Authority also notes that (in common with a system of deep connection charges), a

move towards requiring greater up-front payment of connection capex could reduce the

attractiveness of Oman as a place to do business.

3.63 The Authority has also considered the potential incentives that could be created by

changing the approach to recouping connection capital costs. For example, a longer

annuity period potentially creates a greater risk of a company defaulting on their

connection payments (although OETC report that this is a relatively rare occurrence),

while a shorter period potentially undermines the incentive for OETC to maintain the

connection asset once the capital costs have been fully repaid.

3.64 Finally, the Authority notes that similar methodologies for charging the capital costs of

connections are used in other jurisdictions. For example, in Great Britain, connecting

entities have the flexibility to repay the capital cost of connection up-front or over the

lifetime of the asset (which is based on a 40 year useful lifetime).

Initial proposal




0

2

4

6

8

10

12

14

OM

R M

illio

ns

Muscat Majan Mazoon

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Table 7: Authority’s assessment of up-front charging of connection opex against

assessment criteria

Criteria Up-front charging of connection opex

Cost-reflectivity / Efficiency -


Fairness X

Simplicity -

Transparency -

Future proofed -



3.66 The Authority understands OETC’s perspective on the potential financeability issues

that could result from longer annuity periods. However, given OETC has indicated that

the current arrangements have not, to date, caused it any financial issues, the

Authority considers that there is insufficient rationale for this reform.

3.67 Taking all of the above into account, on balance, the Authority is not minded to

consider this reform further at this stage.

3.68 The Authority proposes to retain the current arrangements for capital charging as set

out in the CUSC Statement.

Conclusion

3.69 In this section we have reviewed the potential reforms to the connection charging

methodology in light of the responses received to the Consultation Paper, as well as

our own analysis of available data, review of economic theory and regulatory

precedent. As discussed above, the Authority is not minded to make any of the reforms

that were raised in the Consultation Paper.

3.70 However, the Authority invites stakeholders to comment on these initial proposals and

on any aspect of the Authority’s assessment of the reform options.

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4. Potential reforms to the transmission use of system charging

methodology

4.1 In this section, we provide an overview of the assessment of the TUoS charging

methodology presented in the Consultation Paper and consider whether any

modifications to the TUoS charging methodology may be appropriate.

Assessment of transmission and use of system charging methodology

4.2 The Consultation Paper discussed the features of the existing TUoS charging

methodology against a set of objectives which transmission charging should deliver. A

summary of that discussion is presented in Table 8. A more comprehensive discussion

can be found in the Consultation Paper.

Table 8: summary of the assessment of the existing TUoS charging methodology

presented in the Authority’s Consultation Paper

Criteria Assessment

Cost

reflectivity/

Efficiency

While the CUSC methodology allows OETC to recover its full

economic costs through its MAR, there are several aspects

of the charging methodology that may not be fully cost-

reflective and may be reducing the efficiency of investment

and operating decisions. These are: (1) charges are levied

on demand only; (2) TUoS charges do not vary by location;

(3) TUoS charges do not vary by generation technology; and

(4) the treatment of costs associated with balancing and

dispatch are recouped through the TUoS charges (but might

more appropriately be distributed across network users in a

different fashion).

It is also important to note that charging on the basis of

MTSD provides a strong signal for customers to contribute

to overall system efficiency by reducing demand at system

peak times, though it is worth considering whether a more

powerful incentive to reduce peak demand could be created

through moving from a charge based on a single snapshot

of peak demand to one based on multiple snapshots. The

allocation of TUoS charges entirely on the basis of peak

transmission system demand also means that large

customers do not face a strong incentive to reduce their

overall demand (i.e., Regulated Units Transmitted (RUT)).

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Criteria Assessment

Fairness

It could be argued that the way in which costs are allocated

across users (i.e., generators versus suppliers) and network

locations (i.e., congested versus unconstrained parts of the

network) does not fairly and accurately represent the costs

of providing transmission services to those users.

However, the allocation of costs does appear to be relatively

fair from an inter-generational perspective (i.e. in broad

terms, all customers who benefit from the assets, current

and future, are required to contribute).

Transparency

The Consultation Paper discussed whether market

participants were able to predict future changes in

connection and transmission charges and whether it is clear

to participants how they can reduce their costs.

The way in which TUoS charges are allocated to suppliers

based on their demand at system peak is transparent and

helps to create a clear incentive for reducing consumption

at peak periods for certain customers and enables them to

take actions to reduce their costs.

Future proofed

A substantial increase in the penetration of renewables may

require changes to the way in which the costs of the

transmission system are allocated (in a scenario where part

of the TUoS charges are levied on generation). Intermittent

renewables tend to have lower capacity factors than

conventional generation sources. Allocating the costs of

transmission based on the share of peak system usage may

not be representative of the costs that renewable

generation places on the transmission system throughout

the year.

Source: Connection and Use of System Charge Methodology: Consultation Paper

4.3 In the Consultation Paper, the Authority asked stakeholders whether they agreed with

the Authority’s assessment of the TUoS charging methodology.

Stakeholder views

4.4 There was a high level of support for the Authority’s assessment of the TUoS charging

methodology among respondents to the Consultation Paper. OETC, suppliers and

generators all, in general, agreed with the Authority’s assessment of the existing TUoS

charging methodology. As was the case with the assessment of the connection

charging methodology, OPWP noted that the Authority had made a reasonable

qualitative assessment but that it would be beneficial to supplement this where

possible with quantitative analysis.

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Possible reforms to the transmission use of system charge methodology

4.5 The following sections discuss the range of potential reforms to the TUoS charging

methodology that were proposed in the Consultation Paper. These are:

Charging a share of TUoS to generators: currently, TUoS charges are paid

entirely by suppliers. Given that generators also impose costs on the

transmission system, charging them a share of TUoS would in principle be cost

reflective;

Charge a share of TUoS to generators based on location: should a share of TUoS

charges be levied on generators, then some consideration would need to be

given as to whether charges should vary by location. For example, charging a

higher rate for use of the transmission network in constrained zones or nodes

could help to encourage generators to locate in less congested parts of the

network (and, therefore, reduce the costs of the transmission system);

Accommodating an increase in renewable generation: should a share of TUoS

charges be levied on generators, then some consideration would need to be

given to how the methodology may need to evolve in order to accommodate the

anticipated increase in renewable generation in Oman. TUoS is currently

charged on the basis of contribution to MTSD. However, this may not be

appropriate for some types of renewables. For example, intermittent renewable

generation tends to have a lower capacity factor than conventional generation,

which means that allocating the costs of the transmission network based on the

share of peak system usage may not be representative of the costs that

renewable generation places on the transmission system throughout the year;

Reforming the methodology for levying TUoS on suppliers: TUoS charges are

currently levied on suppliers based on contributions to MTSD (i.e., the one hour

of maximum transmission system demand in a year), on the basis that peak

demand is the key drivers of the requirement for new transmission

infrastructure. In principle, alternative allocation methodologies could create a

more sustained incentive for customers to manage their peak demand and

overall demand; and

Creating a separate charge for balancing and dispatch costs: costs associated

with system balancing and dispatch are currently recouped through TUoS

charges. In principle, a more cost-reflective approach could be to separately

identify the costs associated with transmission from those associated with

balancing and dispatch and have separate charges for each.

4.6 For each possible reform, we present the range of views presented by stakeholders as

well as the Authority’s assessment and Initial Proposals.

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Charging a share of TUoS to generators

4.7 The existing methodology does not require generators to contribute to the costs of the

system. In principle this means that they will not take system costs into account when

taking decisions about when and how to operate and could make sub-optimal

decisions, from an overall system perspective. On the other hand, generators in Oman

are subject to a centralised dispatch system operated by the OETC Load Dispatch

Centre (“LDC”) through which planned plant outages are scheduled and agreed as part

of an overall co-ordinated generation and transmission outage programme.

4.8 Against this background the Consultation Paper sought views on whether generators

should pay a share of TUoS charges.

Stakeholder views

4.9 Responses to this question tended to consider together whether to charge TUoS to

generators and whether those charges should vary according to location (i.e., should

TUoS charges be higher in parts of the network that are subject to material

constraints). The responses showed a variety of views. All of the generators who

responded were of the view that they should not have to pay TUoS charges. Many

noted that, in the case of locational charges, there was little or no flexibility about

location, meaning that they are effectively unable to respond to such signals.

4.10 OPWP concurred with this view. They argued that there are a range of binding

constraints (e.g., availability of land, access to fuel) that were of greater importance

than transmission costs in determining the location of new generation. As such, OPWP

felt that there would be limited value in charging TUoS to generators at this time, but

that this decision should be kept under review.

4.11 While they were typically silent on the issue of locational prices, some of the

distribution companies were in favour of charging TUoS to generators. They argued that

the activities of generators are imposing costs on the transmission network and, as

such, they should be required to bear a proportion of the cost.

4.12 OETC noted that locational transmission charges were frequently used in other

jurisdictions and that applying TUoS charges to generators was worthy of further

consideration. They argued that under the current market structure, where all power is

being procured through power purchase agreements (PPAs), any charge on generators

would simply be passed on through to the distribution companies (which would likely

not result in any benefit to customers in terms of lowering system costs). However,

once substantial volumes of power are being procured through the spot market, the

application of TUoS to generators could help to drive more efficient dispatch outcomes.

Assessment

4.13 As discussed above, TUoS charges are currently paid by licensed suppliers and

generators do not face any economic signals with respect to their use of the system. In

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theory levying TUoS charges on generators could result in more cost-reflective

transmission charging and costs savings in the energy system. However, the realization

of these benefits relies on: (1) transmission costs varying across generators; and (2)

power procurement arrangements that are sufficiently flexible to respond to such cost

variations.

4.14 The Authority notes, however, that under the current market structure, generators are

required to operate as per the terms of their PPA and that planned plant outages are

scheduled and agreed with the OETC Load Dispatch Centre. As a result, generators are

effectively unable to respond to economic signals related to their use of the system.

4.15 In its response to the Consultation Paper, OETC set out how the inception of the spot

market will impact on the way in which power is contracted and dispatched. A summary

of considerations under the current and future (i.e., once substantial quantities of

energy are being procured through the spot market) market structures for power

procurement is shown in Table 9.

Table 9: current and future market structures for power procurement

Scenario How is power procured? Impact of levying TUoS on generators

Current

state

All power is procured

by PWP through Power

Purchase Agreements

Levying TUoS on generators would

qualify as a change of law under

existing PPAs. New and existing

PPAs would be permitted to pass-

through the TUoS charges into the

price charged to OPWP for power

generated.

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Future state

(i.e., post

start of spot

market)

OPWP will continue to

procure some

generation capacity

through PPAs (in order

to ensure security of

supply)

All generators will be

required to submit an

offer to the spot

market, which will

establish the merit

order

Dispatched generation

that has a PPA will

receive a price for its

power based on that

PPA

Dispatched generation

that does not have a

PPA will receive a price

determined by the

spot market

Generators’ offers into the spot

market should incorporate the

costs of transmission (that they will

have to pay) based on TUoS

charges.

In principle, the levying of TUoS

charges could change the merit

order (i.e., generators that impose

lower costs on the transmission

system would be more likely to be

dispatched) and result in lower

overall power production costs.

In the short to medium term the

savings would be limited if most

generators continue to receive a

price for power based on PPA, but

the savings may increase over time

as increasing volumes of power are

procured on the spot market.

Source: Authority analysis of OPWP information

4.16 As discussed in the Consultation Paper, the present arrangements for transmission

charging arguably reduce the fairness of charges to different users of the transmission

system. That is, the way that costs are currently allocated across generation and

demand may not fully reflect the costs of transmission.

4.17 The Authority notes that the current methodology spreads costs over time consistent

with achieving inter-generational equity. The Authority would not expect that this would

be affected by a move to charge generators a share of TUoS costs.

4.18 The Authority notes that, if TUoS were to be levied on generators, then decisions would

need to be taken on the proportion of TUoS costs to be charged to generation as well

as the appropriate way of levying TUoS charges (i.e. based on contribution to peak or

annual energy production). For example, as discussed in Section ‎3, the anticipated

increase in the volume of grid-connected intermittent renewable electricity in Oman

could impact on the required transmission network capacity. Should the decision be

taken to allocate a share of TUoS charges to generators the Authority notes that

consideration should be given to how costs are allocated to different generation

technologies, given that intermittent renewables tend to have lower capacity factors

than conventional generation sources.

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4.19 However, although the levying of TUoS charges on generation could have an impact on

the order of dispatch under certain circumstances, given that all power is currently

procured through PPAs and generators would be able to pass through the full TUoS

cost in the price they charge to OPWP, the savings associated with this reform could be

limited in the short term. Indeed, the impact would likely continue to be muted even

after the spot market commences operation in 2020, given that the volumes of power

procured based on the spot market price are, at least in the initial years, likely to be

relatively low.

4.20 Furthermore, the Authority does not believe that a move to charging generators a share

of TUoS charges will substantively impact (positively or negatively) on the simplicity or

transparency of the system. There would, however, be some administrative burden

associated with implementing these changes (e.g., overseeing the necessary changes

to the PPAs).

4.21 In considering the case for reform of the CUSC methodology, the Authority has also

examined precedent from other markets. The approach to transmission charging in

Europe provides an interesting case study. The share of TUoS that was charged to

generators in European countries in 2017 is shown in Table 10.

4.22 For the purpose of this analysis, the sample is split into two: jurisdictions where TUoS

charges do not vary by location; and jurisdictions where TUoS charges vary by location.

The data shows that in the majority of counties that do not vary TUoS charges by

location (i.e., where TUoS charges are uniform across geographies) also do not levy any

TUoS charges on generators (i.e., all of TUoS costs are recouped from demand).

Indeed, Table 10 shows that 19 of 28 do not levy any TUoS charges on generation and

do not apply any TUoS charges on generation while the average share of TUoS charges

on generation was just 4% for these countries. This is in stark contrast to the countries

where TUoS charges vary according to location. For these countries, the average share

of TUoS on generation was 24% in 2017.

4.23 Based on the range of countries surveyed, this suggests that regulators tend to levy a

relatively small share of TUoS charges on generators and that the extent of these

charges tends to be larger in jurisdictions where TUoS charges are intended to give

generators a price signal that varies by location.

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Table 10: share of TUoS charges to generators in European countries (2017)

Country

Proportion of TUoS

charged to generators

(%)

Jurisdictions where TuoS charges do not vary by location

Austria 35%

Belgium 7%

Bosnia & Herzegovina 0%

Bulgaria 0%

Cyprus 0%

Czech Republic 0%

Denmark 3%

Estonia 0%

Finland 19%

France 3%

Germany 0%

Greece 0%

Hungary 0%

Iceland 0%

Italy 0%

Latvia 0%

Lithuania 0%

Luxembourg 0%

Macedonia 0%

Montenegro 36%

Netherlands 0%

Poland 0%

Portugal 7%

Serbia 0%

Slovakia 3%

Slovenia 0%

Spain 10%

Switzerland 0%

Average (arithmetic mean across all countries in sample) 4%

Jurisdictions where TUoS charges vary by location

Great Britain 17%

Ireland 25%

Northern Ireland 25%

Norway 38%

Romania 3%

Sweden 36%

Average (arithmetic mean across all countries in sample) 24%

Source: ENTSO-E12


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4.24 In terms of the way in which TUoS is levied on generators, the Authority notes that a

range of approaches can be observed across international jurisdictions (although the

majority of countries surveyed opted for an approach based on MTSD). For example,

Great Britain, Ireland, Northern Ireland and Sweden all levy TUoS on generators based

on generation at system peak, whereas Australia levies TUoS based on a combination

of peak and annual demand.

4.25 Beyond the considerations of how generation TUoS charges could impact dispatch and

generation costs, it is also important to understand the potential distributional impact

across customers and Government. Under the current system, all TUoS costs are levied

on the suppliers, with the level of the charge based on contribution to MTSD. Suppose

instead that a share of TUoS is levied on generators. Generators would pass these

costs through in the price charged to OPWP and, in turn, OPWP would reflect this cost

in the BST. Ultimately, all of the TUoS costs are passed through to the suppliers (who in

the case of their CRT customers pass them directly on in customer bills).

4.26 While the total value of TUoS charges is unchanged, shifting some of the TUoS cost to

generators means that these costs are being recouped on a per MWh basis (rather

than a MW basis as under the existing methodology), which could impact on the

distribution of TUoS costs across customer types.

4.27 This is illustrated in Table 11, which uses 2017 RUT and MTSD data for MZEC to show

how the burden of TUoS costs would fall across large customers who are facing the

cost reflective tariff (CRT) and other customers who are not currently facing a CRT. This

is significant as it has implications for the amount of cost that paid by customers

(through tariffs) versus the Government (through subsidy). That is, Government subsidy

decreases as a greater share of TUoS costs is levied on CRT customers.

4.28 The MZEC RUT and MTSD data in Table 11 show that, while CRT customers accounted

for 19% of total MZEC supply (MWh) in 2017, they only accounted for 9% of peak

demand (MW). This is to be expected, as CRT customers include many electricity-

intensive users who will be consuming significant amounts of electricity throughout the

year (and not just at summer peak). Based on the current TUoS charging methodology,

MZEC CRT customers will pay for 9% of TUoS costs that are levied on MZEC.

4.29 If, on the other hand, a share of the TUoS charges are levied on generators (and

therefore recouped on a MWh-basis through the BST), then CRT customers will pay a

larger share of the costs. For example, if 20% of TUoS costs are levied on generators,

then the share of MZEC’s TUoS costs paid by CRT customers increases from 9% to

11%. The fact that a greater share of costs is now being paid by customers that are

paying a cost-reflective price will in turn reduce the requirement for Government

subsidy.

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Table 11: illustration of the distribution of TUoS costs across customer types (based

on MZEC data)

2017 Large (CRT) customers Other (non-CRT) customers

RUT (MWh) 1,651,428 6,873,599

RUT (%) 19% 81%

MTSD (KW) 194,497 1,926,303

Share of TUoS costs based

on existing methodology

(%)

9% 91%

Share of TUoS costs based

on charging a share of

costs to generators:

20%13 11% 89%

50% 14% 86%

100% 19% 81%

Source: OETC, MZEC, Authority calculations

4.30 The Authority notes this would increase electricity costs faced by CRT customers. Based

on outturn electricity consumption and CRT rates in 2017, a 20% share of TUoS levied

on generators would increase the energy costs of transmission-connected customers

by around 2.2%. This could negatively impact on the attractiveness of Oman as a

destination for internationally mobile capital.

Initial proposal

4.31 The Authority has carefully considered the responses from stakeholders. A summary of

the Authority’s assessment against the assessment criteria is shown in Table 12.

13 For clarity, the share of TUoS costs faced by CRT customers in the 20% scenario is calculated by:

20% x {MWh (CRT customers) / MWh (non-CRT customers)] +

80% x {MW (CRT customers) / MW (non-CRT customers)]

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Table 12: Authority’s assessment of charging TUoS to generators against

assessment criteria

Criteria Charging TUoS to generators



Fairness -

Simplicity X

Transparency X

Future proofed √



4.32 The Authority notes that there are theoretical benefits associated with levying TUoS

charges on generators. Generators impose costs on the transmission system through

their actions. To the extent that those costs vary across generators it is possible that

levying TUoS charges on generators could help to ensure more efficient use of

available generation resources.

4.33 Charging a share of TUoS to generators could also reduce the requirement for public

subsidy, though this would create an additional cost burden on CRT customers.

4.34 However, the Authority notes that the current set-up of the generation market in Oman,

where power is procured through PPAs and dispatch is governed through the terms of

those agreements and instructions from the OETC LDC. Thus, while the beginning of

the spot market will begin to alter the way in which power is procured and dispatched,

this will be a gradual process. The Authority is therefore unconvinced that levying TUoS

on generators will yield material efficiency benefits at this time and is not minded to

levy a share of TUoS on generators at this time.

Charge TUoS to generators based on location

4.35 Given the decision not to charge generators a share of TUoS costs, the question of

whether those costs should vary by location is less significant. However, were a share

of TUoS costs levied on generators at some future point, consideration would also need

to be given as to whether such charges should vary by location. Where TUoS charges

are uniform geographically they would not provide signals to users about where on the

system to connect. Under certain conditions, this could increase system costs.

Stakeholder views

4.36 As discussed in the previous section, OETC felt that locational transmission charges

were worthy of further consideration (though benefits would be limited until substantial

amounts of power were being procured through the spot market). OPWP and the

generators all noted that there is a lack of flexibility for generators to respond to

locational signals, which would limit the potential benefits of the reform.

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Assessment

4.37 Many of the same considerations that apply to the assessment of applying TUoS

charges to generators are also relevant here. That is, whether this reform would yield a

benefit (in terms of lowering the costs of the transmission system) would depend on:

(1) transmission costs varying across locations; (2) the method of procuring power

being sufficiently flexible to respond to these variations in cost; and (3) generators

being able to responds to transmission signals in terms of where they locate.

4.38 As discussed under the previous option, levying a share of TUoS costs on generators

could ensure that the market reaches the most efficient outcome by ensuring the

lowest-cost generation (inclusive of transmission costs) is dispatched to meet demand.

4.39 In a system with material transmission system constraints, cost-reflective TUoS charges

would be expected to vary across regions (i.e. charges should be higher in parts of the

system with greater network constraints). Where this is the case, it is possible that the

application of location TUoS charges could change the order of generation dispatch

(i.e., capacity in highly constrained parts of the network are less likely to be

dispatched).

4.40 Conversely, in a system without material system constraints, we would expect TUoS

charges to be uniform across regions. Where this is the case, the application of TUoS

charges will not alter the order of dispatch.

4.41 As discussed in the Section ‎3, OETC’s response to the Consultation Paper indicated

there are currently no material constraints in the transmission system. This being the

case, we would not expect that levying TUoS charges on generators would have an

impact on dispatch.

4.42 As discussed in Section ‎3 (in the discussion of deep connection charges), generators

do not appear to be able to exercise much choice in terms of where they locate (either

due to a lack of available sites or because of the importance of other factors, such as

the proximity to fuel). What this means is that a locational TUoS charge is unlikely to

impact on site selection because generators are unable to respond to the incentive.

Furthermore, responses to the Consultation Paper suggested that transmission system

costs associated with different potential sites are already factored into the process

through which OPWP determine the sites for new generation. As such, it is unlikely that

the application of locational TUoS charges will have an impact on site selection.

4.43 The move towards greater cost-reflectivity under this reform arguably results in a fairer

distribution of costs across users of the transmission system. Indeed, this reform could

result in substantial variation in TUoS charges across generators. As was discussed

under the previous section, the Authority does not consider that this would create an

issue with respect to non-discrimination as the charges reflect the burdens that

different users are placing on the system. The Authority also considers that charging

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generators TUoS based on their locations would not have any impact on

inter-generational equity.

4.44 The Authority notes, however, that a system of locational charges could substantially

increase the complexity of the TUoS methodology given that different charges would

apply across geographies depending on the extent of system constraints. The Authority

believes that this will make the system of charging less transparent and the charges

less predictable for users.

Initial proposal

4.45 As noted above, the decision of the Authority not to charge a share of TUoS to

generators means that this reform is not necessary. However, the Authority considers it

is worthwhile to summarise the merits and drawbacks of locational charges in case it is

decided at some point in the future to levy TUoS charges on generators.




Table 13: Authority’s assessment of charging TUoS to generators based on location

against assessment criteria

Criteria Charging TUoS to generators based on location



Fairness √

Simplicity X

Transparency X

Future proofed √



4.47 Although there are arguments both in favour of and against locational charging we

reiterate that the Authority is not at present minded to levy TUoS charges on

generators.

Accommodating an increase in renewable generation

4.48 Similar to the case of varying TUoS charges by location, the question of whether to vary

charges by generation technology is contingent on firstly charging a share of TUoS to

generators. Given the decision not to charge generators, the issue of whether the

charges need to reform in order to accommodate renewables is a moot point. However,

should the decision ever be taken to levy a share of TUoS on generators, some

consideration should be given as to whether to vary such charges by technology.

4.49 Accordingly, the Consultation Paper discussed how the TUoS charging methodology

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may have to evolve in light of the anticipated increase in the level of renewable

electricity in Oman. The paper noted that intermittent renewables tend to have lower

capacity factors than conventional generation. Allocating the costs of transmission

based on the share of peak system usage may not be representative of the costs that

renewable generation places on the transmission system throughout the year. As such,

the Authority considered whether the method of allocating TUoS charges should be

amended to reflect the characteristics of different generation technologies (and,

specifically, the demand that different technologies place on the transmission system)

and the Consultation Paper sought the views of stakeholders on whether the existing

system of TUoS charges should be reformed.

Stakeholder views

4.50 There was general consensus across responses that (were TUoS to be charged to

generators) the existing methodology of charging based on a share of MTSD would not

be suitable for intermittent renewable generation.

4.51 Both OETC and DPC felt that the method for allocating TUoS to generators should

reflect the lower average load factors of renewables. OPWP, on the other hand, favored

an approach based on capacity use during system peak (measured using a larger

number of system snapshots rather than a single point in time) rather than an

adjustment based on average load factors.

4.52 Both OPWP and MEDC noted that a substantial increase in renewable generation was

still a number of years away. However, OPWP felt that it remained prudent to consider

these issues at this stage in anticipation of the increased penetration.

Assessment

4.53 As discussed above, the proposal to vary the way that TUoS is allocated based on

technology is grounded in the assumption that charging all technologies based on

contribution to MTSD may result in an unfair distribution of costs across technologies.

4.54 The Authority notes that the allocation of TUoS costs would be likely to differ between

renewable technologies. For example, solar generation is likely to be generating power

during system peak (i.e., maximum system demand in 2017 occurred on the 31st May

at 15:00), wind will only be generating to the extent that the wind is blowing at this

point of time. As such, solar and wind technologies would potentially need to be treated

differently under a system that charged TUoS based on contribution to MTSD.

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4.55 Judging the case for reform therefore requires that we are satisfied that the current

charging methodology is not appropriate for all technologies. The Authority notes that

the approach of varying TUoS charges by technology is adopted in some other

jurisdictions. For example, in Great Britain, TUoS charges are levied on generators in a

way that distinguishes between the burdens that intermittent renewable generation

and conventional generation place on the transmission system (see Box 1 below for a

more detailed discussion of the GB charging methodology). The TUoS charges act to

reduce the charges that are paid by renewable generators (and facilitate the meeting of

an ambitious renewable energy target).

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Box 1: TUoS charges in Great Britain

Following a process of consultation and review, the electricity regulator (Ofgem) decided to

reform the TUoS charging methodology in Great Britain (GB) in 2016 in order to better reflect

the burden that different users were placing on the transmission system. In particular, Ofgem

felt that intermittent renewable generation tended to result in lower requirements for

transmission investment than conventional generation and that this should be reflected in the

TUoS charges that different generation technologies were required to pay.

Transmission requirements in GB are driven by the Security and Quality of Supply Standards

(SQSS), which includes two components: (1) Demand security criterion: which describes the

minimum transmission capacity required to ensure that conventional generators can meet

demand at times when intermittent generators cannot run (i.e., when there is no wind); and (2)

Economy criterion: which describes the additional capacity needed above that to meet peak

demand to efficiently manage the system taking into account the need to manage constraint

costs in an effective and economic manner.14

The TUoS tariff for generators was therefore split into two parts: (1) a ‘peak security’ tariff; and

(2) a ‘year-round’ tariff. All generators pay the year-round tariff but only conventional

generators pay the peak security tariff.

The peak security tariff is only paid by conventional generators. This is because, under the

SQSS, intermittent renewable generators are assumed not to contribute to peak security and

therefore do not drive investment on the transmission network.

All generators are required to pay the year-round tariff. However, this tariff is split into two

parts: a ‘shared’ and ‘non-shared’ element. This refers to a generators ability to ‘share’

transmission capacity, which depends on the concentration of types of generators in a

particular area. This recognizes that it is efficient to build more transmission capacity for areas

with high-concentrations of renewable generation because this plant is likely to be generating

at the same time (i.e., when the wind blows) and is expensive to constrain off. Once the

proportion of low-carbon generation in an area exceeds 50%, then a part of the year-round

tariff will be classified as non-shared.

A final adjustment is made to the shared element of the year-round tariff to reflect the

generator’s average annual load factor for the past five years. This recognizes that there is a

link between the level of constraint costs and the level of transmission investment.

Source: Ofgem (2014) ‘Project TransmiT: Decisions on proposals to change the electricity

transmission charging methodology’

14 Constraint costs are the payments made to a generator by the system operator to manage constraints on

the system where there is insufficient network capacity.

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4.56 The TUoS charging methodology that is in place in Great Britain provides an example of

how charges can be set in a way that more closely reflects the burden that different

generation technologies are placing on the transmission system and this could bring

efficiency improvements in relation to plant dispatch. However, the Authority notes that

this is part of a more comprehensive transmission planning and operation philosophy

for large capacities of renewable generation that has not yet been needed in Oman.

The approach also adds significant complexity into the calculation of transmission

charges and, potentially, makes the costs less transparent and predictable for market

participants.

4.57 The Authority also notes that the issue of the fairness of TUoS charges across

generation technologies only becomes relevant once a share of TUoS charges is levied

on generators. If, as under the current methodology, all TUoS costs are levied on load,

no generators can be disadvantaged.

4.58 As discussed under the previous two options, this reform could result in large variations

in the transmission costs that are paid by different generators. However, this would not

create an issue with respect to non-discrimination (and arguably results in a fairer

distribution of costs) as the charges would more accurately reflect the costs that

different generators are imposing on the transmission system.

4.59 Finally, the Authority notes that renewable generation is currently at an embryonic

stage in Oman. In its most recent 7-year statement, OPWP set its plans to procure new

renewable generation capacity (see Figure 2). This shows that renewable capacity is

expected to grow from less than 1% of total generation capacity in 2021 to over 7% in

2025. The 7-year statement also suggests that the majority (75%) of the new capacity

in 2025 will be solar generation.15

15 PWP 7-Year Statement (2018-2024)

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Figure 2: expected renewable generation as a share of all capacity (MIS & Dhofar)

Source: OPWP (2018), OPWP 7-Year Statement 2018-2024

Initial Proposals

4.60 As noted above, the decision of the Authority not to charge a share of TUoS to

generators means that the Authority does not intend to charge different TUoS to

different types of generating plant.

4.61 The summary in Table 14 below reflects the Authority’s summary assessment of the

merits and drawbacks of differential charging for generation technologies should it be

decided in the future to levy TUoS charges on generators.

Table 14: Authority’s assessment of reforming TUoS to accommodate an increase in

renewable generation against assessment criteria

Criteria Accommodating an increase in renewables



Fairness √

Simplicity X

Transparency X

Future proofed √



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4.62 In principle, the Authority understands that the characteristics of renewables may

require these types of generators to be treated differently (than conventional

generation) under a TUoS charging regime. The Authority notes that this practice can

be observed in some other jurisdictions (e.g., Great Britain)

4.63 However, given that the penetration of renewables within the sector over the short to

medium term remains relatively low, the Authority believes that it would be premature

to consider this reform at this point in time.

Reforming the methodology for levying TUoS charges on suppliers

4.64 In the Consultation Paper, the Authority discussed whether the way in which TUoS

charges are levied on suppliers (i.e. based on shares of MTSD) gives appropriate

signals to customers to manage their peak and overall demand.

4.65 As discussed above, TUoS charges are currently levied on load (suppliers and large CRT

customers) based on shares of MTSD (i.e., the one hour of highest transmission system

demand in a given year). That is, a transmission-connected customer that is

responsible for 5% of maximum system demand will face 5% of the total TUoS costs. It

is possible that a more powerful incentive could be created through moving from a

charge based on a single snapshot of peak demand to one based on multiple

snapshots. Moving to a system of charges based on multiple snapshots of system

demand (e.g., transmission costs based on the average share of the two hours of

highest transmission system demand in a year) can help to intensify the incentive on

customers to manage their demand. That is, customers will need to manage their peak

demand over a longer period to increase their chance of minimising their consumption

during both hours.

4.66 The Consultation Paper also raised the issue that allocating TUoS charges entirely on

the basis of peak transmission system demand means that large customers may not

face a strong incentive to reduce their overall demand (i.e., MWh).

4.67 Noting these issues, in the Consultation Paper the Authority sought views of

stakeholders on whether TUoS charges should be calculated based on multiple

snapshots of MTSD or whether TUoS charges should reflect the RUT for each supplier.

Stakeholder views

4.68 Reponses indicated a high level of support for changing the basis for TUoS charging

from a single to multiple snapshots. Many respondents noted that this could result in a

more sustained incentive for customers to manage peak demand but pointed out that

the multiple snapshots would need to be separated by a substantial period of time

(OPWP proposed that periods were at least one week apart) to ensure that the multiple

peaks are not concurrent.

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4.69 OETC noted that, prior to the implementation of the CRT for large customers, the TUoS

charges on peak demand had no discernable impact on reducing peak load and that

since the introduction of the CRT, only a small number of customers (i.e., steel mills at

Shadeed, Sohar, Muscat and Modern Steel) had taken measures to manage their peak

demand. OETC argued therefore that a move to allocating TUoS based on multiple

snapshots would not necessarily have a dramatic impact on peak demand. However,

OETC remained in favor of the reform as they argued that it was potentially a fairer way

of allocating costs, as it could reduce the chance of anomalies (e.g., when a customer’s

demand is, by chance, abnormally low during system peak, resulting in that customer

facing a low share of TUoS costs).

4.70 There was substantially less support amongst stakeholders for allocating a share of

TUoS costs based on overall demand or energy (i.e., MWh). Many stakeholders noted

that the incentive to manage their total consumption is already present in the energy

component of tariffs (bz/MWh) charged to both CRT and non-CRT customers. They

argued that allocating a share of the TUoS costs based on energy (MWh) could

potentially undermine the incentive on customers to manage peak demand, which is

the key driver of transmission system costs.

Assessment

4.71 The Authority can see that there is an in-principle case for reforming the methodology

for charging TUoS to one based on multiple snapshots. While it is arguable that a move

away from charging solely on the basis of MTSD (i.e. the one hour of maximum system

demand, which is the key driver of transmission capacity demand) represents a

departure from cost-reflectivity, the Authority considers that it is plausible that the use

of multiple snapshots could create a more sustained incentive to manage peak

demand. To the extent that this is the case, this reform could drive efficiencies and

cost reductions in terms of network infrastructure.

4.72 The Authority notes that a move to allocating TUoS based on multiple snapshots will

marginally increase the complexity and administrative burden associated with

calculating charges, which could make it more difficult for customers to understand

and anticipate the level of their TUoS charges.

4.73 The Authority does not consider that this reform will have any substantive impact

(positive or negative) in terms the extent of non-discrimination or fairness of the

charges.

4.74 The Authority notes that this reform could potentially help to make the transmission

system more robust to future changes in the electricity sector. For example, should

there be an increase in the amount of distributed generation using renewables, a

system of multiple snapshots could help to reduce the chance of anomalies in the

allocation of charges. For example, under a system with a single snapshot, the TUoS

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charge for a customer that is generating its power using renewables would be highly

dependent on whether the sun was shining or the wind was blowing during the hour of

maximum system demand. This risk is mitigated somewhat by using multiple

snapshots.

4.75 However, the case for making this reform rests on the presumption that customers will

be more responsive to a system of multiple snapshots in terms of the way that they

manage their demand during peak periods.

4.76 The Authority notes that, given the way in which customers are charged for their

electricity, most will not see a difference in their charges following this reform. This

means that, only customers facing the CRT will have an incentive to respond to this

price signal. It is particularly relevant, therefore, to consider how this reform would

impact upon this group of customers.

4.77 The reform also rests on there being multiple system peaks throughout the summer

season. That is, if the profile of demand over the year was, in fact, relatively flat with a

single well-defined peak, then there would be limited benefit of making this reform.

4.78 Figure 3 shows the pattern of hourly peak demand in Oman during 2017, which shows

that there is a sustained period of higher demand during the summer months. Figure 4

shows the pattern of hourly peak demand in 2017 just for the months of May, June and

July. The data shows that maximum system demand in late May (specifically the hour

of highest peak demand occurred on the 31st May). While the data shows that there is

a clear system peak, it also shows that there is a period throughout May, June and July

that is characterized by multiple peaks in system demand (albeit somewhat lower than

maximum system peak). That being the case, there appears to be some merit in

considering the case for switching to allocating TUoS based on multiple system

snapshots, in order create a more sustained incentive on customers to manage their

peak demand.

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Figure 3: hourly peak demand in 2017 (MW)

Source: OETC

Figure 4: peak demand in 2017 (May-July) (MW)

Source: OETC

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4.79 Figure 5 shows the same hourly demand data (as Figure 3) but for 2016. This shows a

very similar pattern of demand as the 2017 data – i.e., a period of peak demand

throughout the summer months, punctuated by multiple system peaks. However, the

data shows that the hour of maximum system demand occurred slightly later in the

year, on the 12th June.

Figure 5: hourly peak demand in 2016 (MW)

Source: OETC

4.80

4.81 Figure 6 shows the pattern of demand for transmission-connected customers in 2017.

This data shows that these customers are consuming larger amounts of electricity in

the off-peak months and dramatically reduce their consumption in the summer

months. Indeed, some transmission-connected customers are exporting power during

peak periods and have some flexibility in managing their load.

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Figure 6: hourly peak demand for transmission-connected customers in 2017 (MW)

Source: OETC

4.82 Allocating TUoS based on multiple snapshots of system demand requires decisions on

both the number of snapshots and the duration between snapshots. Snapshots that

are too close together could undermine the objective to create a more sustained

incentive to manage peak demand. Conversely, snapshots that are too far apart will be

of less relevance to the management of system peak demand (as they will capture

‘peaks’ that are substantially lower than the maximum peak).

4.83 Some analysis of the alternative options is presented in Box 2. This suggests that a

system based on either: (a) two snapshots separated by a six-week period; (b) or three

snapshots that are separated by a three-week period will cover the May to July peak

period. The latter option would potentially create a marginally higher administrative

burden (given the higher number of snapshots) but the smaller duration between

snapshots helps to mitigate the risk of snapshots falling outside of the May to July peak

period.

Box 2: allocating TUoS based on multiple snapshots

The figure below shows the period captured by a system based on 2 snapshots with either: (1)

1 week between snapshots; (2) 3 weeks between snapshots; and (3) 6 weeks between

snapshots. This shows that, based on the 2017 demand data, 2 snapshots separated by a 6-

week gap would have covered the May, June and July peak period.

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The figure below shows the period captured (i.e., the period between the first and last

snapshot) by a system based on 3 snapshots with either: 1 week between snapshots; (2) 3

weeks between snapshots; and (3) 4 weeks between snapshots. Under this approach, a

system based on 3 snapshots separated by a 3-week gap would have covered the May, June

and July peak period.

4.84 Turning to the case for allocating a share of TUoS charges based on MWh. The case for

making this reform rests on the assumption that this will create a more powerful

incentive for customers to manage their energy demand and that it does not

undermine the incentive for customers to manage their peak demand.

4.85 Understanding the incentives that this reform would create for customers requires an

assessment of the extent to which TUoS charges are passed through to end users and

the balance between capacity (MW) and energy (MWh) charges in current tariffs.

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4.86 The balance between energy and capacity in existing tariffs varies across CRT and non-

CRT customers. The cost reflective tariff includes elements reflecting: (1) the cost of

energy (charged on a per KWh basis); (2) transmission costs (charged on the basis of

contribution to peak demand); (3) distribution costs (charged on a per KWh basis); and

(4) supply costs (charged on a per customer basis). The permitted tariff (charged to

non-CRT customers) charges customers solely on a per KWh basis.

4.87 Figure 7 shows how 2017 energy costs for transmission-connected CRT customers and

non-CRT customers break down by fixed (per customer charges), capacity and energy

charges.

4.88 This shows that the majority of cost for CRT customers and all costs for non-CRT

customers are charged on the basis of energy consumed and that the share of demand

charges in the overall tariffs are less than 5% for CRT customers and 0% for non-CRT

customers. This suggests that customers are already mainly paying on the basis of the

amount of energy that they use and, as such, these customers already have an

incentive to try to reduce energy consumption. That being the case, allocating a share

of the TUoS charge on a MWh basis would have only a marginal impact on the incentive

for customers to change their consumption behaviours.

Figure 7: capacity and energy charges across CRT and non-CRT customers

Note: fixed costs for CRT customers are only RO 50 per account, so are not visible on

the above chart

Source: OETC

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4.89 The Authority notes, however, that allocating a share of TUoS charges to energy is a

common practice in many jurisdictions. The share of TUoS levied on the basis of

capacity and energy in European countries that levy all of TUoS charges on demand in

2017 is shown in Figure 8. This shows that most countries charge a share of TUoS on

the basis of MWh, in order to provide an incentive for customers to manage their

energy demand throughout the year.

Figure 8: share of TUoS charges to energy and capacity in European countries

(2017) (only countries which levy all TUoS charges on demand)

Source: ENTSO-E16

Initial proposals





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Table 15: Authority’s assessment of changing the basis on which TUoS is allocated

against assessment criteria

Criteria Multiple snapshots Allocating based on

RUT

Cost-reflectivity / Efficiency √ -

Non-discrimination - -

Fairness - -

Simplicity X X

Transparency X X

Future proofed √ -



4.91 Responses to the Consultation Paper suggest that there has not been a substantial

change in behaviour from most customers with respect to their energy use. As such, it

is not clear that changing the approach to allocating TUoS will result in a step change in

the way in which customers manage their peak demand. However, the load data for

large energy users suggests that these customers are able to exercise some flexibility

in managing their load and the Authority considers that it is plausible that a system of

multiple snapshots could create a more sustained incentive to manage peak demand.

As such, the Authority believes that this reform could help to reduce peak demand and

lower the costs of the transmission system.

4.92 The Authority notes that this reform increases the complexity and administrative

burden of the system of allocating TUoS charges. However, the Authority considered

that this impact will be modest and, therefore, commensurate with the potential

benefits of the reform.

4.93 As such, the Authority is minded to change the basis of charging from a single snapshot

to multiple snapshots in order to create a more sustained incentive to manage

demand.

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4.94 As discussed earlier, the snapshots cannot be too close together as it is possible (as in

2017) that peaks could fall on consecutive days, which would undermine the objective

to create a more sustained incentive. Nor should the snapshots be too far apart, as this

may mean that snapshots fall far from the system peak, and undermine the incentive

to manage peak demand. The choice of the number of system snapshots and the

length of time between snapshots needs to take into account these considerations.

Based on the analysis of the yearly demand data presented earlier, the Authority

proposes to change the method for allocating TUoS to one based on the share of total

transmission system demand averaged across the three hour one-hour periods in

which total system demand is at its highest. The three snapshots of highest

transmission system demand should be at least three-weeks apart. The Authority

believes that this will create an incentive for customers to continue to manage their

peak demand throughout the summer peak season.

4.95 With respect to the question of whether to allocate a share of TUoS based on RUTs,

(rather than MTSD), while the Authority notes that charging a share of TUoS based on

MWh is common practice in many jurisdictions, it is clear energy charges already make

up a sizeable proportion of the overall electricity tariffs and that customers already face

an incentive to manage their energy demand through the existing CRT and Permitted

tariffs. It is not clear therefore that allocating some of TUoS to RUT will have a

significant impact on the pattern of demand. As such, the Authority is not minded to

allocate a share of TUoS costs on the basis of RUT.

Creating a separate charge for balancing and dispatch costs

4.96 As discussed in Table 8, another potential issue related to cost-reflectivity of the

current transmission charging methodology relates to the fact that the costs of system

balancing and dispatch (i.e., the costs incurred by OETC for undertaking the functions

related to system balancing and dispatch of electricity17) are currently recouped from

suppliers through the TUoS charges.

4.97 In principle, a more cost-reflective approach could be to separately identify the costs

associated with transmission network activities from the costs associated with

balancing and dispatch and have separate charges for each that reflect the full cost of

providing these distinct services. Accordingly, in the Consultation Paper the Authority

sought views from stakeholders on whether there could be a benefit to introducing a

separate charge for dispatch and balancing.

17 These costs represent the operating costs of running OETC’s Load Dispatch Centre.

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Stakeholder views

4.98 Responses indicated a high level of support for introducing a separate charge for

balancing and dispatch. Many respondents felt that this would give supplier and

generators the correct signals for efficient dispatch and load balancing.

4.99 OETC noted that the costs that they incur for undertaking balancing and dispatch

activities are driven by aggregate demand as well as individual customer demands.

Specifically, they argued that the resources required for balancing varies across power

stations, with a fixed component across each power station and a variable component

that varies based on the number of plant units (rather than the output of the plant).

4.100 OETC proposed that separate charges should be levied on: (a) generators: where the

charge includes fixed and variable components based on the number of plant units; (b)

suppliers: where the charge is based on demand; and (c) transmission connected

customers above a certain capacity threshold. OETC noted that they did not as yet have

a methodology for calculating the precise charges that should be levied on different

market participants but they offered to work with the Authority to develop the approach

to charging if required.

4.101 OPWP felt that there would be advantages in separating the balancing and dispatch

costs from TUoS charges as it would allow for charges to be levied on the entities that

are responsible for generating the costs. Specifically, they felt that the costs of certain

ancillary services could be charged to a generator, when the generator is the driver of

the requirement for ancillary services (e.g., by generating less power than is

requested/anticipated by the market operator).18 However, given that the market for

ancillary services is likely to develop alongside the spot market and given that the costs

of ancillary services are at present included in power purchasing rather than

transmission system costs, OPWP felt that further development of balancing and

dispatch charges should be done alongside the spot market to ensure consistency.

18 Ancillary services refer to the range of services that transmission system operators can procure from

generators or other third parties in order to maintain system security (e.g., black start capability; frequency

response and fast reserve).

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Assessment

4.102 The Authority notes that there are some potential benefits from creating a separate

charge covering balancing and dispatch activities performed by OETC. These costs are

currently recouped through the TUoS charges levied on and paid by suppliers and CRT

customers based on shares of MTSD. Based on the responses to the consultation, the

Authority notes that this approach of recouping these balancing and dispatch costs

does not appear to be cost-reflective. That being the case, a separate charge for

balancing and dispatch that charges users based on the extent to which they are

responsible for generating these costs, would in future be more cost-reflective

(allocatively efficient) and help to encourage more efficient behaviours from generators

and customers.

4.103 As is the case for many of the charges discussed in this section, the creation of a

separate balance and dispatch charge could result in different charges for different

users of the transmission system. However, this could be considered to result in a

fairer allocation of costs as the level of charges would better reflect burdens that

entities are placing on the system.

4.104 However, the Authority notes that the creation of a separate charge for balancing and

dispatch would increase the complexity and administrative burden compared to the

current system of TUoS charges for OETC activities and would need to be consistent

with spot market developments and modifications to OPWPs power procurement costs,

This could result in charges being more difficult to understand and predict for users of

the transmission system and needs considerable more thought.

4.105 One of the considerations for whether to create a separate charge for dispatch and

system balancing relates to the materiality of the cost of these services. The split of

OETC’s costs across business functions in 2017 is shown in Figure 9. This shows that

dispatch and system balancing accounted for around 10% of OETC operating costs in

2017. These activities therefore represent a small, but not insignificant, share of total

TUoS costs.

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Figure 9: OETC opex split by function (2017)

Source: OETC

4.106 OETC have indicated to the Authority that they expect these costs to become more

material over time. OETC also contend that the introduction of CRTs and the

anticipated increase in renewable generation will increase uncertainty on both the

demand and supply side and will, therefore, increase balancing costs over time.

4.107 The Authority also notes that balancing and dispatch are separately charged for in a

number of international jurisdictions. As discussed in the Consultation Paper, Great

Britain, Germany and the Netherlands all have separate balancing and dispatch

charges that charge generators and suppliers based on the extent to which these users

are responsible for creating the system imbalance (e.g., a supplier demands more

energy than anticipated, which requires additional generation to be dispatched at short

notice).

4.108 The Authority notes that (based on the international examples surveyed) balancing and

dispatch charges are typically levied on both generators and suppliers, as both types of

entities are responsible for generating balancing and dispatch costs. As was discussed

in ‎4.15, we might expect that the levying of a charge for balancing and dispatch to

have an impact on the way in which generators are dispatched where those charges

vary across generators (which we would expect them to as costs will be levied on

generators who cause those costs). However, the potential cost savings of levying an

additional charge on generators is unlikely to impact behaviours whilst the majority of

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power continues to be procured through PPAs.

4.109 Finally, the Authority notes that a separate charge for dispatch and balancing would

have an impact on the shares of costs paid by different types of customers (specifically

between CRT and non-CRT customers). The costs of balancing and dispatch are

currently recouped through suppliers and CRT customers through the TUoS charges. As

discussed in ‎4.25 to‎4.30, levying some of this cost on generators could change the

balance of costs across CRT and non-CRT customers (and potentially on the

requirement for subsidy). As was shown in Table 11, levying a share of costs on

generators would increase the proportion of costs faced by CRT customers (and also

the amount of subsidy required).

Initial proposals




Table 16: Authority’s assessment of creating a separate charge for balancing and

dispatch against assessment criteria

Criteria

Creating a separate charge for balancing and

dispatch



Fairness √

Simplicity X

Transparency X

Future proofed -



4.111 The responses from stakeholders suggest that balancing and dispatch costs vary

across market participants and that the way in which these costs are recouped is not

cost-reflective. Given the materiality of these costs and the expectation that they will

grow over time, the Authority believes that a separate charge for balancing and

dispatch could help to encourage more efficient behaviour from generators and

suppliers. The Authority is therefore minded to create a separate charge for system

balancing and dispatch at an appropriate point in time.

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4.112 However, it is clear that the full benefit of the reform will be realized only when the spot

market has been implemented (and when substantial volumes of power are being

procured on that market). As such, the Authority believes that the rationale for

implementing this reform at this point of time is weak. Instead, the Authority proposes

to maintain a watching brief on this reform to monitor the evolution of the spot market,

the market for ancillary services and the costs of balancing and dispatch. The Authority

will then consider making a change to the CUSC methodology at a later date.

4.113 As a first step in this direction and recognizing that robust separate identification of the

costs of undertaking balancing and dispatching activities the Authority is, as separately

discussed in OETC’s T&D-PCR5 Initial Proposals, intending to create a separate term in

OETC’s Maximum Allowable Revenue to separately capture and account for the

economic costs for these balancing and dispatch costs.

Conclusion

4.114 In this section we have reviewed the potential reforms to the TUoS charging

methodology in light of the responses received to the Consultation Paper as well as our

own analysis of available data, economic theory and regulatory precedent. A summary

of our Initial Proposals for the various reform options is as follows:

Charging a share of TUoS to generators: the Authority is not minded to charge a

share of TUoS to generators but intends to keep the issue of network system

constraints under review;

Charge TUoS to generators based on location: the Authority is not minded to

make this reform;

Accommodating an increase in renewable generation: the Authority is not

minded to vary TUoS charges by technology at this time, but intends to keep this

issue under review should it decide in the future to charge a share of TUoS to

generators;

Reforming the methodology for levying TUoS on suppliers: the Authority is

minded to alter the methodology for levying TUoS to one based on three

snapshots of peak demand separated by a three-week gap. The Authority is not

minded to levy a share of TUoS based on energy/MWh; and

Creating a separate charge for balancing and dispatch costs: the Authority is

minded to create a separate charge for balancing and dispatch but intends to

pause until the spot market is more established before deciding on the

appropriate course of action. As a first step, the Authority intends to separately

identify these costs within OETC’s MAR formula in the T&D-PCR5 price control.

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4.115 These reforms will impact on both the way in which TUoS charges are levied and on

who pays those charges. The key characteristics of the current system and the

proposed system (including reforms to accommodate renewables and to create a

separate charge for balancing and dispatch) is set out in Figure 10 and Figure 11.

4.116 The Authority invites stakeholder to comment on these initial proposals and on any

aspect of the Authority’s assessment of the reform options.

Figure 10: schematic of the current system of TUoS charges

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Figure 11: schematic of the proposed system of TUoS charges

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5. Interactions between the CUSC and the price control review

5.1 In this section, we summarise the issues that were raised in the Consultation Paper in

relation to the interactions between the CUSC methodology and OETC’s price control

and consider if any changes may be required either to the CUSC methodology or to

OETC’s price control.

Interactions between CUSC methodology and OETC’s price control review

5.2 It is important to ensure that the transmission charging methodology is not creating

incentives for OETC, generators and/or transmission-connected customers that leads

to inefficiencies in the overall transmission costs and in turn, OETC’s MAR. As such, the

Consultation Paper considered the interdependencies between the CUSC and the

current price control review.

5.3 A number of areas of interaction were discussed:

Speculative requests: that is, entities requesting a connection but, for whatever

reason, deciding not to connect (or connecting later than expected) and/or

inappropriately sized connection (e.g., an entity requests a connection based on

an expectation of generation capacity or load which turns out to be too high). In

this case, the entity will pay the cost of the connection but the cost of any

required network reinforcement will be recovered from suppliers through the

TUoS charges. This means that OETC need to undertake effective due diligence

on all connection applications in order to make sure that it is only responding to

necessary and appropriately sized connection requests.

Default: that is, the extent to which connecting entity defaults on its connection

agreement. For example, when a transmission-connected customer goes out of

business and cannot pay any of the remaining capital costs for their connection

(assuming it was paying over-time rather than up-front). In this case, OETC will

need to recover the residual capital costs through another route.

Efficiency of procuring and delivering connections: in developing, procuring and

delivering connections based on Minimum Scheme, OETC is bound by its license

conditions, which obligate OETC to ‘develop, operate and maintain an efficient

and economic transmission system in accordance with the Transmission

Security Standard and the Grid Code’.19 There is, however, no economic

incentive to encourage OETC to deliver connections as efficiently and quickly as

19 The technical specification of the connection is based on the Minimum Scheme. The Minimum

Scheme is defined in the CUSC as the design with the lowest cost to provide the requested connection

capacity.

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possible (as the full cost and risk is borne by the connecting entity), which could

result in inefficiently incurred capex.

5.4 In the Consultation Paper the Authority sought the views of stakeholders on whether

any of the issues above were actually present in practice and, if so, whether any

changes to the CUSC methodology or OETC’s price control should be considered in

order to address these issues.

Stakeholder views

5.5 A small number of responses highlighted cases where they felt that there had been

speculative and/or inappropriately sized connections. For example, MEDC cited two

cases: the Almouge project (which they felt had an inappropriately sized connection);

and the Al Salm Yity Project (which they considered speculative and, ultimately, was

cancelled). OPWP referred to the case of the Saitic petrochemical company in Dhofar,

which OPWP felt was a speculative request (and was eventually cancelled following

substantial delays).

5.6 OETC commented that connection applications are usually based on justified project

needs rather than being speculative in nature. They noted that, in some cases, the

take-up of load at a given installation is slower than originally planned, but they argue

that this was likely due to inefficiencies (of the connector) rather than a speculative

application. They also argue that, over the medium term, the installed capacity will be

appropriately utilized. Furthermore, OETC felt that their own improvements in demand

forecasting and the established connection management processes are such that

speculative and inappropriately-sized connections is not seen as a concern for the

present or the future.

5.7 On the issue of the efficiency of the connection process, each of OPWP, MEDC and

MJEC felt that there was a case for incentivizing OETC to deliver connections in a more

efficient manner. For example, MEDC referred to instances of delays in connections in

previous years that had led to them having to incur additional costs in order to meet

customer demands and the Distribution Security of Supply Standard (DSSS) – i.e.,

delays in the completion of new grid stations resulted in additional costs associated

with balancing the load across existing infrastructure.

5.8 The Authority notes that OETC’s work to connect new entities is guided by the

requirements of the Grid Code. OETC have provided evidence of well-defined Standard

Operating Procedures (SOP) that describe how they respond to connection requests

and select the most appropriate connection option. Specifically, OETC described the

following SOPs:

SOP-M-003 (modifying and applying for a connection): this outlines the

timescale for a connection application processing and the associated

connection fees. It also sets out the data that needs to be submitted along with

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the application.

SOP-M-002 (handling connection application and releasing connection offer):

this outlines the process through which OETC responds to the applicant in a

timely manner and without discrimination or bias.

SOP-M-007 (preparing the pre-investment appraisal document) describes the

process of selecting the most cost-effective connection option considering

factors such as Transmission Security Standard (TSS) compliance, deliverability,

cost, risk analysis, losses and environment impact.

5.9 OETC argued that, through their adherence to these SOPs, they have performed well in

terms of the cost and timeliness of new connections. The Authority recognises the

processes that OETC has in place in order to ensure that connections take place in a

prompt and efficient manner. Furthermore, the Authority notes the evidence submitted

by OETC setting out the details of the new connections that they have made over the

past three years, which shows that, in many cases, the connections were completed

and energized ahead of the connection date agreed with the customer. The data also

showed that in the majority of cases, the costs of the connection was less than the

amount in the indicative connection offer. A summary of this evidence is presented in

Table 17.

Table 17: OETC recent transmission connections (2015-17)

Connection Date

energized

Date of

connection

Actual cost

less than

offered cost

Madinat Nizwa Grid Station 31-Mar-15 2016 Yes

Amerat Grid Station 04-May-15 2016 No

Ghala Grid Station 01-Jul-15 2016 Yes

A’salam Grid Station 15-Jul-15 2016 Yes

Al Ayjah Grid Station 30-Jul-15 2016 Yes

Ibra Grid Station 30-Apr-16 2016 Yes

Izki Grid Station 04-Jul-16 2017 Yes

Dhofar Generating

Company Connection 08-Mar-17 2017 No

Salalah Free Zone Grid

Station 28-Mar-17 2017 Yes

Khadhra Grid Station 03-Jul-17 2017 Yes

Hay Asim Grid Station 22-Jul-17 2017 No

Upgrading Mawalleh North 25-Jul-17 2017 Yes

Madinat Bakra Grid Station 18-sep-17 2017 Yes

Suwaiq Grid Station 16-Oct-17 2017 No

Source: OETC Narrative Business Plan Questionnaire responses

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5.10 OETC noted that, once the connection is agreed, the connecting party does carry the

pricing risk. However, OETC argued that it has no ability to influence the prices for the

agreed and defined once the works are underway and therefore should not carry this

risk. On the basis of this, OETC argued that there would be no benefit to be gained from

introducing such an incentive into its price control.

Initial Proposal

5.11 The Authority has carefully considered the responses received from stakeholders. The

Authority is satisfied that OETC has a robust process in place to verify, assess and

deliver new connections, which has in general resulted in connections that are

efficiently delivered. As such the Authority is not minded to make changes to the CUSC

methodology, Grid Code or to introduce a new incentive into OETC’s price control in

these areas at this time. If any issues are identified with the connections process in

future, the Authority may re-consider this issue.

Conclusion

5.12 In this Section, we have reviewed evidence related to the interactions between the

CUSC methodology and OETC’s price control. As discussed above, the Authority is not

minded to create an incentive in OETC’s price control to incentivise efficient and timely

connection.

5.13 The Authority invites stakeholders to comment on these initial proposals and on any

aspect of the Authority’s assessment of the reform options.

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6. Timetable for review of the CUSC methodology

6.1 The preceding sections set out a summary of the issues raised in the Consultation

Paper, the responses received from stakeholders on that paper and the Authority’s

initial proposals for reforming the CUSC methodology. The Authority now invites

stakeholders to comment on any aspect of its Initial Proposals.

6.2 OETC and other stakeholders are invited to respond to this these Initial Proposals by 30

June 2018.

6.3 The Authority will consider any responses received and issue its Final Proposals by xx

2018.

6.4 Once the final proposals are agreed, OETC shall commence the modification procedure

as set out in the CUSC methodology.

6.5 These stages will be conducted according to the timetable illustrated in Table 18

below.

Table 18: Timetable for the review of transmission and use of system charges

Initial Proposals

Authority issues initial proposals 31 May 2018

Response to initial proposals 30 June 2018

Final proposals

Authority issues final proposals 25 October 2018

OETC to respond to final proposals

OETC to undertake modification process (as required)

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Appendix A: list organizations that responded to the CUSC Consultation Paper

Oman Electricity Transmission Company

Oman Power and Water Procurement Company

Dhofar Power Company

Muscat Electricity Distribution Company

Majan Electricity Distribution Company

Mazoon Electricity Distribution Company

Rural Areas Electricity Company

Al Kamil Power Company

Al Rusail Power Company

Al Suwadi Power

Barka Power Company

Al Batinah Power

Phoenix Power Company

Sohar Power

United Power Company

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