Cost of Service study for the Swaziland Electricity Supply ... · • Tunisia: Model power purchase...

ECONOMICCONSULTINGASSOCIATES

www.eca-uk.com

Cost of Service study for the Swaziland Electricity Supply Industry

Final Workshop

27 September 2018

2

Content

Introduction and project overview

Demand forecast

Generation, transmission and distribution

least cost plan

SEC Revenue Requirements (Average tariff)

SEC Cost of Electricity Supply by customer

class

End-user tariffs and transition plan


Section 1 Introduction and project overview

Section 2 Demand forecastSection 3 Generation, transmission and distribution least cost plan Section 4 SEC Revenue Requirements (average tariff)Section 5 SEC Cost of SupplySection 6 End-user tariffs and transition plan

4

We are worldwide infrastructure economic consultants specialising in the energy sector

ECA provides economic consulting advice in infrastructure services for utilities,

investors, regulators, and governments worldwide

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regulators advised

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in

20 yearsin business

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60+ assignments

annually

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experience

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turnover

4Regional

representations

5

We specialise in providing economic and financial advice to energy utilities and regulators

Tariff studies and

regulatory methodologies

• Malawi and Zambia: Cost of service and tariff study

• Australia: Regulatory modelling of electricity networks

• Greece: Electricity network pricing study

• Southern Africa: Regional generation and transmission plan (SAPP)

• Papua New Guinea: Action plan for electricity grid expansion

• Malawi: Integrated Resource Plan (IRP) study

• Indonesia: Cost of service and financial impact study for PLN

• Vietnam: Economic and financial analysis of the power sector master plan

• Iraq (KRG): Private sector participation in transmission investments

• Mongolia: Renewable energy regulatory development roadmap

• Pacific: IFC guide to investing in RE power generation

• Croatia: Analysis of network’s wind power capacity and investment plan

❶

Power development and

least cost plans

Financial planning and

analysis❸

Integration of renewables❹

❷

6

We specialise in providing economic and financial advice to energy utilities and regulators

• Tunisia: Model power purchase agreement

• Kenya: Karura hydropower plant feasibility study

• Nigeria: Electricity DISCO privatisation due diligence

• George: Energy trading platform

• Ireland: I-SEM market monitoring strategy

• Ukraine: Intraday market rules development

• Oman: Electricity load forecasting model

• Egypt: Development of a load management program

• Armenia: Demand-side management study

• Cambodia: Rural electrification strategy and implementation plan

• Papua New Guinea: National electrification masterplan

• Ethiopia: Electrification program prospectus

Investments and power

purchase agreements❺

Market design and

operation❻

Rural electrification and

off-grid technologies❽

❼Load forecasts and

demand-side management

7

Project objectives and organisation of tasks

Project objectives

⚫ Develop a least cost plan

for generation,

transmission, distribution

and supply

⚫ Estimate SEC Revenue

Requirements (average

tariff)

⚫ Estimate the Cost of

Supply

⚫ Estimate End User tariffs

and the need to cater for

needy consumers

⚫ Develop a transition

strategy to move to cost

reflective tariffs

8

Work plan and deliverables

No Deliverable

1 Inception report

2 Report on the Revenue Requirement

3 Report on Medium-Long-term Least-cost plan

4 LRMC report

5 Report of transition strategy

6 Report on Recommendation for Future Studies

7 Draft report on electricity costs of service

8 Final report

9 Required Revenue model

10 LRMC and RS models 23

19

19

22

24

23

Due

end of

4

12

12

16

No Deliverable

W I Workshop 1: Task 1

W II Workshop 2: Tasks 2-4

WIII Workshop 3: Tasks 5-6

W IV Workshop 4: Final report

Current position


Section 1 Introduction and project overview

Section 2 Demand forecast

Section 3 Generation, transmission and distribution least cost plan Section 4 SEC Revenue Requirements (average tariff)Section 5 SEC Cost of SupplySection 6 End-user tariffs and transition plan

10

SEC’s 2017 demand forecast was adopted for the Cost of Supply study (CoSS)

Peak demand forecast

⚫ From 242 MW in 2017 to 334 MW in 2035

⚫ Average annual growth rate 1.9%

Energy demand forecast

⚫ From 1,358 GWh in 2017 to 1,852 GWh in

2035


Main facts

⚫ The country’s economy was on downward

trend since 2014

⚫ There were no big projects developed

since 2014 and the only growth in energy

demand is attributable to expansion of

sugar cane fields

⚫ The rural electrification programe has

marginal impact on the overall energy

demand.

242 259 285316 334

050

100150200250300350400

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03

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03

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6

MW

Peak demand likely (sent-out) MW

1,358 1,4521,601

1,776 1,872

0

500

1,000

1,500

2,000

2,500

201

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GW

h

Energy demand likely (sent-out) GWh


Section 1 Introduction and project overviewSection 2 Demand forecast

Section 3 Generation, transmission and distribution least cost plan

Section 4 SEC Revenue Requirements (average tariff)Section 5 SEC Cost of SupplySection 6 End-user tariffs and transition plan

12

Currently SEC is heavily dependent on imports

Total domestic available

generation capacity for grid

supply is 72.5 MW. Total domestic

generation capacity is 141 MW.

⚫ 43% hydro generators,

⚫ 56% biofueled power plants,

⚫ 2% is thermal

Approximately 85% of energy is

covered by imports

Main issues for Swaziland

⚫ Security of supply

⚫ Price taker – electricity prices

depend significantly on import costs

Government’s plan is to increase

domestic generation capacity

13

Domestic committed and candidate power plants

Plant Name Status Owner Type Fuel

Installed

capacity(MW)

Available

Capacity (MW) Lifetime

Year

avail.

Lower Maguduza Committed Private Hydro Hydro 13.6 13.6 50 2021

Ngwempisi Candidate SEC Hydro Hydro 80 80 50 2027

Small hydro Candidate SEC Hydro Hydro 1.9 1.9 50 2021

Mpaka 1-6 Candidate SEC

Subcritical

Steam Coal6x50 6x42.5 30 2025-27

RSSC Mhlume Candidate RSSC

Subcritical

Steam Bagasse50 28 25 2024

RSSC Simunye Candidate RSSC

Subcritical


USL Bagasse Candidate USL

Subcritical


Usuthu Saw Mills Candidate IPP

Subcritical

Steam Woodchip37 33 25 2020

Lavumisa Candidate SEC Solar PV Solar 10 10 25 2020

AES Solar PV Candidate SEC Solar PV Solar 10 10 25 2020

SPL Solar PV Candidate SEC Solar PV Solar 10 10 25 2020

Generic OCGT Candidate Private OCGT HFO 30 30 25 2020

14

Bagasse and small hydros are the least cost options for base load (excluding imports)

PVBagasse

OCGT Woodchip

Mpaka

Ngwempisi

Levelised Costs of Electricity Screening analysis

15

Least cost options

Scenario Description NPV

Capex

(mUS$)

NPV

Fixed

O&M

(mUS$)

NPV

Variable

(mUS$)

NPV Total

(mUS$)

Rank Total costs

/ Energy

served

(US$/MWh)

Scenario 1 No new capacity 0 272 649 920 2 31.0

Scenario 2 Small Hydros 3 273 645 920 1 31.0

Scenario 3 PV + Small Hydros 30 275 624 930 3 31.3

Scenario 4Bagasse + Small Hydros

76 293 580 949 6 31.9

Scenario 5OCGT30 + Small Hydros

25 278 638 941 5 31.7

Scenario 6OCGT 2x30 + Small Hydros

25 278 630 934 4 31.4

Scenario 7PV+ Bag + Small Hydros

103 295 560 958 8 32.2

Scenario 8PV + OCGT + Small Hydros

53 281 617 950 7 32.0

Scenario 9 Mpaka 1 + Small Hydros 80 283 605 969 10 32.6

Scenario 10 Ngw + Small Hydros 312 276 587 1,174 11 39.5

Scenario 11 Full Independence 1 445 346 429 1,220 12 41.0

Scenario 12 Full Independence 2 590 326 418 1,333 13 44.9

Scenario 13 Partial Independence 103 295 560 958 8 32.2

Base case

least cost

Full independence

case least cost

Partial

dependence case

16

Generation least cost options

Full independence –

15% reserves margin

by 2025

Partial dependence –

develop domestic PV

and Bagasse

Base case – without

any constraints to

imports

• Lavumisa, AES and SPL

Solar PV in 2020 (30 MW)

• OCGT in 2020 (60 MW)

• USL Bagasse in 2021 (15

MW)

• Small Hydros in 2021 (1.9

MW)

• RSSC Simunye in 2024 (22

MW)

• Mpaka 1,2,3 in 2025 (150

MW)

• Mpaka 4 in 2028 (50 MW)

• Lavumisa, AES and SPL

Solar PV in 2020 (30 MW)

• USL Bagasse in 2021 (15

MW)

• Small Hydros in 2021 (1.9

MW)

• RSSC Simunye in 2024 (22

MW)

• Develop small hydros

earliest year possible

(Lusushwana River,

Mpuluzi River, Great

Usuthu River, Mbuluzi

River, Lubovane Dam)

• Imports cover most of

demand requirements.

NPV = mUS$ 920 NPV = mUS$ 958 NPV = mUS$ 1,220

17

Transmission constraints – Key findings

Main projects addressing key constraints on the existing grid

North-east grid 66 kV reinforcement 132 kV line Moses Hlope – Sihhoye T

Edwaleni PS 66 kV reinforcement 132/66 kV substation extension linking

Edwaleni PS and the 400/132 kV subst.

Stonehenge N-1 reinforcement 132 kV line Edwaleni II – Stonehenge

South-east grid 66 kV reinforcement 132 kV line Sithobela – Ncandweni

Furthermore, several large projects with new transmission lines are

required to support rural electrification

18

Transmission development plan

Transmission Network

Expansion

2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Total

Cost

1 Ongoing Projects 0.9 0.9 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 1.7

2Substation transformer

uprating4.7 1.6 0.7 0.0 0.0 0.0 0.9 0.0 6.1 2.8 0.0 0.0 0.0 16.8

3Substation upgrade

projects2.5 4.2 6.9 3.3 0.7 1.1 0.0 1.4 2.3 0.0 0.0 0.0 0.0 22.4

4Subst. transformer

maintenanceCosts included as part of general Operation and Maintenance costs. -

5 Network reinforcement projects 98.7

5.1 HV Network 9.2 13.8 3.2 4.8 0.0 0.0 5.8 8.7 0.0 0.0 0.0 0.0 0.0 45.5

5.2 Rural Electrification 6.5 9.8 1.7 2.5 3.2 4.8 0.0 6.3 9.4 0.0 0.0 0.0 0.0 44.2

5.3 New Loads (excl.

customer contribution)2.3 3.5 0.0 0.0 1.3 1.9 0.0 0.0 0.0 0.0 0.0 0.0 0.0 9.1

6Transmission reliability

projects2.0 3.0 1.2 0.9 0.7 1.5 1.7 1.8 0.8 0.0 0.0 0.0 0.0 13.6

7 SCADA 0.2 0.1 0.1 0.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.5

8Reactive power

compensation0.0 0.0 4.0 0.0 4.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 8.0

Total 28.3 36.9 17.7 11.6 9.8 9.3 8.4 18.2 18.7 2.8 0.0 0.0 0.0 161.7

19

Distribution least cost plan

Key findings

⚫ Most feeders on the distribution

system are lightly loaded

Some thermal constraints

need to be addressed

⚫ Long feeders in some areas

cause excessive voltage drop

⚫ Improving reliability in some

areas seems justified

New in-feeds and

strengthening of the system

required to

⚫ address these constraints

⚫ increase electrification ratio

Distribution least cost plan


Section 1 Introduction and project overviewSection 2 Demand forecastSection 3 Generation, transmission and distribution least cost plan

Section 4 SEC Revenue Requirements (average tariff)

Section 5 SEC Cost of SupplySection 6 End-user tariffs and transition plan

21

What is Tariff level (cost-recovery) and Tariff design (cost-reflectivity)?

Electricity tariffs have two main

aspects

1. Tariff level

The average level of tariff determined

by the Required Revenues.

2. Tariff design

Customer categories

Type of charges

Ratios of charges between customer

categories and ratios of charges

within each category.

The tariff structure (i.e. ratios

among charges) can be kept

constant to reflect economic costs

while the tariff level can be scaled

to ensure revenue recovery.

“Cost-recovery”

Revenues from tariffs fully recover

efficient costs (Required Revenues)

Cost-recovery ≠ Cost-reflective

Co

st

of

Se

rvic

e

Avg

Co

sts

Co

st

of

Se

rvic

e

Customer A Customer B

“Cost-reflective”

The tariffs charged to different customers

reflect differences in the costs of service

between those customers

22

Revenue Requirements model are estimated using SERA’s tariff methodology

Asset base

Historic asset

base

Capital

expenditures

DepreciationAsset lives

Return (‘profit’)

Operating

expenditures

+

+

Cost of debt

Return on equity

Gearing

(debt/equity)Allowed Revenues

=

Cost of capitalx

Building Blocks model

23

Overall revenue requirement increases by an average of 4.1% per year

All figures presented in

2018 real terms (i.e.

excluding inflation)

Power Purchase costs

contribute most to the

revenue requirement

⚫ mE 1,139 in 2018-19

⚫ Followed by distribution

(mE 500) and transmission

(mE 291)

Highest annual average growth rate forecast in transmission

costs (10.7%)

⚫ Followed by power purchase costs (4.6%)

24

Tariffs are expected to increase by an average of 0.97% annually

Average annual tariff first increases and then decreases over the

forecast period

⚫ From 1.86 E/kWh in 2018-19 to 2.02 E/kWh in 2020-21 and then to 1.92

E/kWh in 2022-23

⚫ Tariff increase is mainly attributed to growing power purchase costs and

transmission investment costs.

25

Generation costs contribute to 60% of total tariffs

0.94 0.98 1.03 0.99 0.98

0.00

0.50

1.00

1.50

2.00

2.50

2018-192019-202020-212021-222022-23

E/k

Wh

Generation average tariff Transmission average tariff

0.23 0.28 0.31 0.31 0.30

0.00

0.50

1.00

1.50

2.00

2.50

2018-192019-202020-212021-222022-23

E/k

Wh

0.51 0.50 0.49 0.47 0.45

0.00

0.50

1.00

1.50

2.00

2.50

2018-192019-202020-212021-222022-23

E/k

Wh

Distribution average tariff Contribution to total

26

Alternative generation investment scenarios impact tariff levels

Partial independence case

⚫ Tariffs are expected to grow

from 1.86 to 1.92 E/kWh

⚫ Average annual growth rate

0.97%

Full independence case

⚫ Tariffs are expected to grow

from 1.86 to 1.94 E/kWh


Least cost case

⚫ Tariffs are expected to grow from 1.86 to 1.88 E/kWh



Section 1 Introduction and project overviewSection 2 Demand forecastSection 3 Generation, transmission and distribution least cost plan Section 4 SEC Revenue Requirements (average tariff)

Section 5 SEC Cost of Supply

Section 6 End-user tariffs and transition plan

28

Economically efficient pricing requires marginal cost based tariffs

Economically efficient or cost-

reflective pricing requires that the

tariff paid by a customer should

be equal to the marginal costs of

supply of that customer. If this is

not the case, then the outcome is

inefficient.

Tariff below marginal cost

⚫ It costs SEC more to meet an increase

in demand from that customer than the

corresponding revenue that it will earn.

⚫ The result is to force SEC into losses or

for it to refuse to meet demand.

Tariff above marginal cost

⚫ A customer must pay more for an

increase in demand than it costs SEC

to supply that increase.

⚫ The implication is that customers will

cap their demand at a point below that

where it is still profitable for SEC to

meet demand growth. Tariff > Marginal cost

Tariff = Marginal cost

Tariff < Marginal cost

Quantity

Tariff/Cost

Customer demand curve

Losses to SEC (customer supplied at

price below cost)

customers cap their demand where it is still

profitable for SEC to meet demand growth Marginal cost

curve

29

What are the efficient price signals to consumers based on the cost of supplying an extra unit of energy?

To do this, we derive long-run marginal costs of capacity

and energy for generation and networks for the system.

Network losses are also taken into account to estimate the

costs at the delivery points of the HV, MV and LV networks.

Then we estimate the long-run marginal costs of supply for

each customer class.

30

Seasonal pattern of generation long

run marginal costs (USc/kWh)

Cost of supply is higher between mid-June and mid-August

The highest Marginal Costs are

observed between mid-June and

mid-August.

Marginal Costs during February,

March and April have an

increasing trend over years.

Two tariff seasons can be

identified:

⚫ High Cost Season – starting

from June and ending in August.

⚫ Low Cost Season – starting from

September and ending in May.

2021

2022

31

Cost of supply in the morning and in the evening is higher than other times

c/kW

h SRMC for an average day

Hig

h S

eas

on

Lo

w S

eas

on

Marginal costs of energy

during High Season Peak

hours are 7 time more those

for off-peak hours.

Marginal costs of energy

during Low Season Peak

hours are double than

those for off-peak hours.

Customers with high demand

during peak hours have a

higher cost of supply.

32

Customers with more ‘peaky’ demand have a higher marginal cost of service

Morning peak

Eveningpeak

33

What is the cost of supply by customer class?

Residential customers have the

highest cost of supply

The cost of supply of Commercial,

Large Commercial and Industrial

and TOU LV

Irrigation customers have LRMCs

that are 20% below average

TOU MV customers have LRMCs

that are 30% - 40% below average

34

What would be a cost reflective tariff design on 2016-17 tariffs?

Domestic customers paid 0.8

E/kWh less than their cost

reflective level. For cost

reflectivity, their tariff should

increase by 66%.

Customers in classes S3 and

K5 paid 0.5-0.7 E/kWh more

than their cost reflective level.

For cost reflectivity S3 should

be paying 33-35% less and

class K5 should be paying

25% less.

LV TOU customers paid 0.4

E/kWh more than their scaled

total LRMC. For cost

reflectivity, they should pay

22% less.

Actual 2016-17 tariffs

Cost-reflective 2016-17 tariffs

35

What would be a cost reflective tariff design on 2016-17 tariffs?

MV TOU and HV TOU

supplied at MV customers

paid 0.4 and 0.7 E/kWh

more than their scaled total

LRMC. For cost reflectivity,

they should pay 26% less

and 43% less.

Irrigation customers pay

approximately the same

rate as their scaled total

LRMC. Customers in class

K6 and T4 paid 0.4-0.5

E/kWh more than their

scaled total LRMC. For

cost reflectivity, K6 should

pay 26% less and T4 30%

less.

Actual 2016-17 tariffs

Cost-reflective 2016-17 tariffs

36

Proposed changes to the tariff structure

SEC may consider

⚫ Merging the General Purpose with Small Commercial tariff class to simplify the

tariffs.

⚫ Introduce TOU capacity charges.

Demand charges apply equally to all periods - no incentive to consumers to shift

their demand away from peak.

⚫ Drop the Access charge and recover the equivalent revenue through the demand

charge.

⚫ Rebalance the ratio of charges to enhance cost-reflectivity

Facility charge to reflect costs of retail activities

Demand charge to reflect capacity costs

Energy charge to reflect energy generation costs.

⚫ Allow domestic customers to LV TOU tariff if they are willing to pay the extra costs of

TOU meter.

⚫ Eliminate cross-subsidies and target subsidies only to needy consumers (Subsidy

Framework)


Section 1 Introduction and project overviewSection 2 Demand forecastSection 3 Generation, transmission and distribution least cost plan Section 4 SEC Revenue Requirements (average tariff)Section 5 SEC Cost of Supply

Section 6 End-user tariffs and transition plan

38

Overall Approach

39

How would cost-reflective and cost-recovering end-user tariffs look in 2019? (including the Subsidy Framework)

Tariff category Facility

charge

Energy charge Demand

charge

Total

average

Total

averageSingle rate ToU

High Season Low season

Peak Shoulder Off-peak Peak Shoulder Off-peak 2019-20 2018-19

estimate

E/customer/

month E/kWh E/kWh E/kWh E/kWh E/kWh E/kWh E/kWh

E/kVA/

month E/kWh E/kWh

S10 Lifeline - pre-pay

-

(0-75 kWh) 1.708

- - - - - - - 1.708 1.653(75-150 kWh) 2.846

(>150 kWh) 4.554

S1 Domestic - pre-pay - 2.903 - - - - - - - 2.903 1.750

S3 Small Commercial -

pre-pay 64.6 1.712 - - - - - - - 1.838 2.809

S3 Small Commercial -

Credit Meter 61.5 1.768 - - - - - - - 1.810 2.683

K4 Small Holder

Irrigation 61.5 0.397 - - - - - - 772.0 1.532 1.395

K5 Large Commercial

and Industrial 307.5 0.517 - - - - - - 609.2 1.834 1.882

K6 Large Irrigation 307.5 0.520 - - - - - - 790.7 1.694 1.586

T4 TOU small irrigation

< 100 kVA 307.5 - 2.240 0.565 0.308 0.636 0.376 0.267 772.0 1.597 1.616

T3 TOU at LV 307.5 - 2.297 0.622 0.365 0.692 0.433 0.323 609.2 1.809 1.988

T2 TOU at MV 615.0 - 2.163 0.598 0.352 0.654 0.417 0.312 520.8 1.473 1.789

T1 TOU at MV at HV

network 615.0 - 2.080 0.583 0.344 0.631 0.407 0.305 457.5 1.193 1.693

S0 Street light 61.5 2.729 - - - - - - - 2.739 0.862

Average 2.064 1.914

40

What would be the impact from the introduction of cost-reflective and cost-recovering tariffs?

Most significant changes would be

for category S1 both in terms of the

tariff increase (doubling of the tariff)

and the number of customers

affected.

All other customers would see

decreases with most significant

decreases for T1 and S3.

The tariff redesign provides

information on what the tariffs should

be if pure economic principles of cost

reflectivity were to apply.

Next step is to:

⚫ Develop a transition strategy

from the current tariffs to cost-

reflective and cost-recovering

tariffs.

Existing against cost-reflective and cost

recovering-tariffs in 2019-20

41

Gradually increase tariffs that require increasesKeep constant tariffs that require decreases

SERA could consider the

following steps to gradually

introduce cost-reflective

and cost-recovering tariffs:

⚫ Tariff increases could be

gradually absorbed in the

next years.

⚫ Consumers tariffs that pay

more in comparison to their

cost reflective levels could be

kept constant over the next

four years until the tariff of

each customer category

reaches its cost reflective

tariff level.

⚫ Revenue for SEC recovery

should be ensured through

this period

Tariff category Forecast Forecast Forecast Forecast

2019-20 2020-21 2021-22 2022-23

Forecast inflation 6.1% 6.4% 5.5% 5.5%

Increase/Decrease (%)

S10 Lifeline - pre-pay 3.3% 10.8% 2.4% 3.4%S1 Domestic - pre-pay 25.4% 27.8% 3.9% 5.6%S3 Small Commercial -

pre-pay0.0% 0.0% 0.0% 0.0%

S3 Small Commercial -Credit Meter

0.0% 0.0% 0.0% 0.0%

K4 Small Holder Irr. 9.8% 11.3% 2.4% 3.5%

K5 Large Commercial and Industrial

0.0% 8.2% 2.4% 3.4%

K6 Large Irrigation 6.8% 11.1% 2.4% 3.4%T4

TOU small irrigation 0.0% 9.9% 2.4% 3.4%

T3 TOU at LV 0.0% 1.2% 2.4% 3.4%T2 TOU at MV 0.0% 0.0% 0.0% 0.0%T1 TOU at MV at HV

network0.0% 0.0% 0.0% 0.0%

S0 Street light 39.1% 39.1% 39.1% 39.1%

Tariffs above cost reflective level kept constant

Cost reflectivity achieved tariffs follow average cost

increases

Tariffs that require significant tariff

increases to achieve cost reflectivity

Adjusted tariff increases to

moderate impact

ECONOMICCONSULTINGASSOCIATES

www.eca-uk.com

Peter Robinson <[email protected]>

Grigorios Varympopiotis <[email protected]>

Andrew Tipping<[email protected]>

Marta Chojnowska <[email protected]>

43

Annex 1 – Description of generation scenarios

Scenario Candidate power plants Details / Comments

Scenario 1 No new capacity This scenario assumed that no new domestic power plants will be developed and checks system costs

with full dependency on imports from ESKOM/SAPP.

Scenario 2 Small hydros Scenario to check if the inclusion of small hydro power plants can reduce system costs.

Scenario 3 Solar PV and Small hydros Candidate solar PV power plants together with small hydro power plants were included in the simulations.

Solar PV power plants are likely to generate power during the morning and evening hours (ESCOM

Peak), and midday hours (ESCOM Standard). Benefits may appear if the savings from variable costs from

ESCOM imports are higher than the capital costs from the introduction of PVs.

Scenario 4 Bagasse and Small hydros Bagasse fired power plants operating at very high capacity factors could economically displace Standard

and Peak ESKOM imports. This scenario examines if operating benefits from the inclusion of bagasse

power plants could outweigh investment costs for the development of the bagasse power plants.

Scenario 5 30 MW OCGT and Small hydros This scenario checks if the inclusion of 30 MW OCGT HFO power plant could economically displace

imports during peak hours.

Scenario 6 2 x 30 MW OCGT and Small

hydros

This scenario checks if the inclusion of 60 MW OCGT HFO power plant could economically displace

imports during peak hours.

Scenario 7 Solar PV and Bagasse and Small

hydros

This scenario is a combination of scenarios 3 and 4. This scenario examines if the combination of

bagasse (for base load) and solar PV could produce higher benefits than scenarios 3 and 4 on their own.

Scenario 8 Solar PV and 30 MW OCGT and

Small hydros

This scenario is a combination of scenarios 3 and 5. This scenario examines if the combination of OCGT

(for peak load) and solar PV (for base load) could produce higher benefits than scenarios 3 and 5 on their

own.

Scenario 9 Mpaka 1 (1 x 50 MW) and Small

hydros

Coal fired power plants operating at very high capacity factors could economically displace Standard and

Peak ESKOM imports. This scenario examines if operating benefits from the inclusion of coal power

plants could outweigh investment costs for the development of the Mpaka power plant.

Scenario 10 Ngwempisi and Small hydros Scenario to check if the inclusion of Ngwempisi hydro power plants can reduce system costs. Benefits

may be introduced from the displacement of expensive imports during peak hours.

Scenario 11 Full independence option 1 This scenario requires 15% reserves margin from domestic resource from 2025. To achieve this, Mpaka

1-3 (3 x 50 MW), Small hydros, Solar PV and 30 MW OCGT will have to be developed.

Scenario 12 Full independence option 2 This is an alternative to scenario 11 to achieve full independence. This scenario requires 15% reserves

margin from domestic resource from 2025. To achieve this, Mpaka 1 (50 MW), Ngwempisi, Small hydros,

Solar PV and 30 MW OCGT will have to be developed.

Scenario 13 Partial independence The investment costs under the full independence scenario are expected to be very high. Hence this

scenario checks the costs of an intermediate strategy that has partial dependence on imports rather than

almost full independence. This scenario reflects Governments position to develop domestic PV (up to 40

MW) and Bagasse (up to 40 MW) generation.

Cost of Service study for the Swaziland Electricity Supply ... · • Tunisia: Model power purchase...

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