yemen_gas_to_power_options_report(2).pdf

hC:\A1 Files\Project\Yemen Gas\Docs\FirstReport\Yemen Options Report v2a.doc 11/2/09

Economic Consulting Associates Limited 41 Lonsdale Road, London NW6 6RA, UK tel: +44 20 7604 4545, fax: +44 20 7604 4547 email: [email protected]

Yemen: Models to Develop the Gas-to-Power Market

Options Report February 2009

Submitted to the World Bank by:

Economic Consulting Associates

Parsons Brinckerhoff

Yemen: Models to develop the gas to power market February 2009

Contents

i

Contents

1 Introduction 1

2 Availability of natural gas 3

2.1 Overview 3

2.2 Estimates of gas reserves accessible to NGP 4

2.3 Need for confirmation of the availability of gas 5

3 Technical issues 6

3.1 Introduction 6

3.2 Electricity demand and power investment plans 6

3.3 Comments on the distributed investment plan 8

3.4 Gas turbines in simple cycle or combined cycle 12

3.5 Gas demand 17

3.6 Size of the 1st stage of the NGP 19

3.7 Pipeline costs 23

3.8 Summary of conclusions on technical issues 25

4 Institutional options 27

4.1 Power sector reform 27

4.2 A framework favourable to competition in gas supply 28

4.3 Facilitating future private sector participation 30

4.4 Contractual arrangements between MPC and PEC 31

4.5 The price of gas to power, and the required subsidies 31

4.6 Summary of institutional options 33

5 Financing options 36

5.1 Regional experience of PSP in energy infrastructure 37

5.2 The financial sector in Yemen 40

5.3 Business environment in Yemen 40

C:\A1 Files\Project\Yemen Gas\Docs\FirstReport\Yemen Options Report v2a.doc 11/2/09


Contents

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5.4 Financing of recent or planned energy investments 42

5.5 Carbon credits 43

5.6 Financing options 44

6 Summary of options and next steps 48

6.1 Summary of options 48

6.2 Next steps in the current study 50

Annexes 51

A1 PEC base case electricity demand projection 51

A2 Economic value of gas 52

Tables and Figures

Tables

Table 1 Reserves of sales gas indicated in the Ramboll study (tcf) 5

Table 2 Electricity demand forecast from the 2006 Fichtner study 7

Table 3 Derating of power plants with altitude and temperature 10

Table 4 PB CCGT/OCGT capital cost estimates 13

Table 5 Estimates of gas transmission costs from Safer (US$/mmbtu) 15

Table 6 Gas demand projections for power (CCGT scenario) 18

Table 7 Gas demand projections for power (OCGT scenario) 19

Table 8 Pipeline diameter options 22

Table 9 Indicative costs and capacity for larger diameter 1st stage NGP 24

Table 10 Risk allocation for BOOT schemes in Egypt 38

Table 11 Next steps 50

Table 12 Base case electricity demand projections (MW) 51


Contents

iii

Figures

Figure 1 Energy map of Yemen 2

Figure 2 Yemen oil concession map 3

Figure 3 Planned pipeline route 20

Figure 4 Summary of institutional framework (who owns what?) 34

Figure 5 Access to credit Yemens world ranking 41

Figure 6 Protecting investors index 42

Figure 7 Border price of gas (LNG exports) 52


Contents

iv

Abbreviations

bbl barrel (of oil)

BOO Build-own operate

BOOT Build-own operate transfer

CCGT Combined-cycle gas turbine

CDM Clean Development Mechanism

DNA Designated National Authority

ECA Economic Consulting Associates

EIA Energy Information Administration (US)

EPC Engineering, procurement, construction

GoY Government of Yemen

HFO Heavy fuel oil

IEA International Energy Agency

IFC International Finance Corporation

IPP Independent Power Producer

MPC Mabar Power Company

MoE Ministry of Electricity

MoF Ministry of Finance

MOM Ministry of Oil and Minerals

MWE Ministry of Water and Environment

NGP National Gas Pipeline

NGPC National Gas Pipeline Company

OCGT Open-cycle gas turbine

PB Parsons Brinckerhoff

PDD Project Design Document (for carbon credits)

PEC Public Electricity Corporation

PEPA Petroleum Exploration and Production Authority

PIN Project Idea Note (for carbon credits)

PPP Public-private partnership

PPI Private participation in infrastructure

PSP Private sector participation

SPV Special Purpose Vehicle

RFP Request for Proposals

tcf trillion (standard) cubic feet

TOR Terms of Reference


Contents

v

UNFCCC United Nations Framework Convention on Climate Change

WASP Wien Automatic System Planning (generation planning software)

YGC Yemen Gas Company

YLNG Yemen LNG company

YPC Yemen Petroleum Company

YR Yemeni Rials

Currency equivalents US$1.00 = 199 Yemeni Rials (YR)


Introduction

1

1 Introduction

This Options Report has been prepared under contract to the World Bank for a project to assist the Government of Yemen (GoY) to develop the policy framework which best facilitates the development of the gas-to-power market in Yemen.

The work is being undertaken by a team comprising Economic Consulting Associates Ltd (ECA) and Parsons Brinckerhoff (PB), both of the United Kingdom, with legal support from Yemen Legal.

The primary purpose of the Options Report is to detail the specifications for the technical, institutional and financing options that will be examined in the more detailed analyses in the next phase of the project. These proposals have been prepared after our initial assessment during the inception visit in December and a second visit in January. We propose to discuss and agree our recommendations on options with the Supervision Committee during a visit in February following the submission of the 1st Report.

This Options Report is arranged as follows:

R Section 2 discusses the availability of natural gas

R Section 3 discusses technical options

R Section 4 discusses institutional options

R Section 5 discusses financing options

The last three of the above sections are concerned with both power and the national gas pipeline (NGP).

Finally, Section 6 provides a summary of the options that we propose to examine in greater detail.

To provide an overview of the projects under discussion, an energy sector map from the World Banks Project Appraisal Document for the Power Sector Project, 2006, is provided in Figure 1.


Introduction

2

Figure 1 Energy map of Yemen


Availability of natural gas

3

2 Availability of natural gas

2.1 Overview

There are approximately 17 tcf of proven gas reserves1 in Yemen. Of these proven reserves, 9.15 tcf has been allocated to the Yemen LNG project (YLNG) from specified fields in Block 182 in the Marib basin. The 9.15 tcf of gas has been independently certified.

Figure 2 Yemen oil concession map

Source: www.al-bab.com

YLNG is committed to providing 1 tcf of its allocation of 9.15 tcf for use in the domestic market in Yemen. According to YLNG there is another 0.7 tcf of probable reserves available from Block 18.

Gas is supplied to YLNG by the state-owned company Safer E&P Operation Company which took over the operation of Block 18 from the Hunt consortium when the concession expired in 2005.

1 Project Appraisal Document, Power Sector Project, April 2006, Report No: 35030-YE. This gives the proven reserves at 17.2 tcf.

2 YLNG website states that: The reserves within the Marib area which are currently dedicated to the project include 9.15 trillion cubic feet (TCF) of proven reserves with 1 TCF allocated for use in the domestic market, and an additional 0.7 TCF of probable reserves. The fields allocated to YLNG are specified in YLNGs Gas Development Agreement.



4

GoY has nominally allocated 5.2 tcf of gas for use in the domestic market but has not indicated from which blocks or operators this gas will come. This allocation is essentially a statement of intent to dedicate some gas to the domestic market.

Ramboll3 identified the main source of gas for the western part of Yemen and the National Gas Pipeline (NGP) as coming from Blocks 18 (Marib/Al Jawf), 5 (Jannah), S1 (Damis) and 20 (Al Sabatain or Upper Wadi al-Jawf), and, possibly, S2 (Uqla).

Concession agreements have, until now, been given exclusively for oil and the operators have had no rights to the gas and no framework has existed for developing and utilising the natural gas. This will change in future with eight concessions that are currently being reviewed by Parliament that include terms governing the development of natural gas4. However, the majority of the gas that is likely to be used for the domestic market, other than Block 18, will come from existing oil concessions but these concessions would need to be renegotiated to allow the gas to be developed. However, each concession, including amendments, needs to be approved by Parliament and amendments are likely to be slow.

The 1 tcf of certified gas from Block 18 would be sufficient to supply open-cycle gas turbines at Marib-I, Marib-II and Mabar for about 12 years at a plant load factor of 90%. However, if the three plants are combined-cycle gas turbine (CCGT) plants then the 1 tcf would last for approximately 17 years. A more realistic scenario, would involve the commissioning of the three plants spread over a few years with Mabar being commissioned in 2012 and perhaps Marib-II and Mabar being built as CCGT. On this basis, the 1 tcf would supply the three plants until nearly 20255. This should be a sufficient duration to provide assurance to developers of the power plants that the assets would not be stranded without a gas supply. However, it would not be sufficient for the developers of the NGP which, as discussed below, will be designed to carry gas beyond Mabar.

2.2 Estimates of gas reserves accessible to NGP

Apart from Block 18, information on gas available to the NGP is limited (ie., from Blocks 5, S1 and 20). Information on proven gas in Block 5 is noted in the Ramboll study but the Report suggests that proven reserves of sales gas are only 0.54 tcf - see Table 1 below. These estimates were based on previous studies by Gasunie (1992), INTERA (1993), and DeGolyer & MacNaughton (1995). Ramboll noted that the latter source provided the most detailed estimates of reserves in Blocks 18 and 5.

3 Gas Utilization and Pipeline Feasibility study, Natural Gas Reserves and Supply, Internal Memo, June 2005.

4 Including a price of gas with a floor price of US$1.5/mmbtu and a ceiling price of US$2.5/mmbtu. The ceiling is reached when international oil prices reach US$45/bbl.

5 ECA estimates. If the plants are open-cycle gas turbines then the gas would last until nearly 2022.



5

Table 1 Reserves of sales gas indicated in the Ramboll study (tcf)

Proven Probable Possible

Block 18 9.125 1.054 0.072

Block 5 0.544 0.108 0.23

Total block 5 and 18 9.669 1.162 0.302

Source: Ramboll, Natural Gas Reserves and Supply, Internal Memo, June 2005.

2.3 Need for confirmation of the availability of gas

Confirmation of the availability of natural gas for the power plants at Mabar and proposed plants along the coast, as well as at Mareb, will be critical before substantial financial commitments are made to invest in pipelines and power plant projects downstream of the gas fields. Without this confirmation private sector participation will be limited. Even regional and international funding institutions as well as state-owned Yemen companies may be reluctant to take the risk of pipeline and power assets that are stranded without a supply of natural gas.

There is also an urgent need to agree with the operators of Blocks 20, S1 and 5 and potentially operators of other blocks the arrangements to access the available natural gas and to make the investment (or enable the investment) in the natural gas gathering and processing facilities to allow the collection, processing and delivery of the gas to the NGP. Agreement will need to be reached on responsibility for investment in the gas gathering and processing facilities, the mechanism for recovery of the investment costs, the terms for delivery of the gas and the rights to non-gas liquids. There is also a need for a framework for coordination among the operators where multiple operators supply gas to common facilities. We understand that discussions are underway with some operators for this purpose. However, even when agreement is reached, concession amendments may need to be agreed at Parliamentary level.

MOM confirmed in January 2009 that independent international consultants will be contracted by MOM to certify the availability of natural gas from Blocks 20 and S1. While the outcomes of this assessment will not be available ahead of the Final Report for this study, MOM indicated that it is confident that at least 3 tcf of gas will be certified from Blocks 18 (after taking account of the volumes allocated to YLNG), 5, S1, 20 or other blocks accessible to the NGP, and that for the purposes of developing a framework for the Mabar power plant and for NGP, MOM proposed that the Consultant should assume that at least 3 tcf will be certified in due course.


Technical issues

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3 Technical issues

3.1 Introduction

This Section addresses some technical options associated with the choice of power plant and the size of the pipeline from Marib to Mabar which will be the first stage of the NGP.

3.2 Electricity demand and power investment plans

Below we review the electricity demand projections, least-cost power sector investments and the selection of Mabar as the location of the next generation investment after Marib-II.

3.2.1 Electricity demand projections

Fichtners 2006 study6 updated the electricity demand forecast prepared in the 2001 Integrated gas and electricity masterplan (see below). The forecast aggregates forecasts for the grid substations and applies a diversity factor of 80% to give an aggregate peak demand before transmission losses. Losses are then added to give the system peak demand. Fichtners 2006 forecast, updated from the 2001 masterplan is shown in Table 2 below. The forecast includes large consumers that PEC anticipated would be connected to the unified grid once generation capacity is adequate, but this has not yet been possible and demand continues to be suppressed.

Recorded peak demand includes an estimate of disconnected load which, in 2008, was 151 MW but does not reflect load that would have been supplied. Supply has not kept pace with demand and therefore comparisons between the recorded peak demand and the Fichtner forecast cannot be used to comment on whether the Fichtner forecast remained accurate in 2008.

PEC continues to use this forecast for planning purposes. The year-by-year forecast for the years 2009 to 2020 are shown in Annex A1.

6 Fichtner, Marib Power Project, 2nd Stage, Study Final Report, Volume 1, January 2006.


Technical issues

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Table 2 Electricity demand forecast from the 2006 Fichtner study

Year 2004 2005 2007 2008 2013 2018 2025Total regional peak dem and [MW]

887.9 957.6 1269.3 1369.9 1804.2 2254.7 3081.8

Sys tem dem and [MW] (utilization factor 80 %) 710.3 766.1 1015.4 1095.9 1443.4 1803.8 2465.4

Generation and trans -m iss ion losses [%] 9.1 9.0 8.5 8.5 8.0 8.0 8.0

Sys tem peak dem and (Generation) [MW] 781.4 841.8 1109.8 1197.7 1568.9 1960.6 2679.8

Total regional peak dem and [MW]

887.9 968.7 1310.5 1431.2 1970.9 2549.7 3658.3

Sys tem dem and [MW] (utilization factor 80 %) 710.3 775.0 1048.4 1145.0 1576.7 2039.8 2926.6



Total regional peak dem and [MW]

887.9 924.7 1156.6 1204.1 1385.1 1559.8 1842.2

Sys tem dem and [MW] (utilization factor 80 %)

710.3 739.8 925.3 963.3 1108.1 1247.8 1473.8



Ad.

Bas

e C

ase

Ad.

Hig

h C

ase

Ad.

Low

Cas

e

Source: Fichtner, Marib Power Project, 2nd Stage, Study Final Report, Volume 1, January 2006.

3.2.2 Integrated gas and electricity masterplan (2001)

A comprehensive integrated gas and electricity masterplan was prepared by Kennedy & Donkin (later Parsons Brinckerhoff) on behalf of the Ministry of Electricity and Water and completed in November 2001.

At that time, natural gas was considered to have an economic value based on its marginal production cost of around US$0.3/mmbtu at Marib and power plant technologies using other fossil fuels (primarily coal-fired steam and oil-fired steam) were ruled out through a preliminary screening analysis that shortlisted gas turbines in either open-cycle or combined-cycle. The primary focus of the analysis was therefore on the location of the power plants when considering the investment cost of gas pipelines and the investment cost and losses associated with the power transmission network.

After considering various alternative locations for gas-fired power plants and the corresponding power transmission investment costs, the consultant recommended that the least-cost integrated investment plan should comprise 2,900 MW of open-cycle gas turbines concentrated in Marib to be developed over the period 2025. The Report concluded that the development of power generation at Sanaa (at that time


Technical issues

8

the Mabar site had not been identified) would increase the overall present-valued costs by US$96 million7. The Report also concluded that a separate 10 pipeline to supply non-power consumers in Sanaa appeared to be justified but they concluded this did not justify constructing a larger pipeline and locating power generation at Sanaa but recognised that this conclusion might be modified if more substantial gas demand were identified in Sanaa.

3.2.3 Distributed generation investment plan (2005)

A new least-cost generation investment plan was prepared by PEC in 2003-04 which recommended a distributed generation investment, with power plants located in Marib, Mabar, Al Hodeidah, Al Mocha and Aden. (An associated transmission investment plan was prepared for PEC by Fichtner in 2005). A short report was prepared for PEC management in Arabic in 2004 which recommended this generation investment plan and a WASP summary printout associated with the optimal solution was attached to this report. The distributed power investment plan is described in the World Banks Power Sector Project Appraisal Document of 11 April 2006 (Report 35030-Ye).

WASP is able to select the least-cost generation investment plan based on capital and operating costs of power plants but cannot choose an investment plan that simultaneously optimises the capital costs of electricity and gas transmission. The WASP printout viewed by the Consultant indicated that gas transmission costs had been included in the analysis by incorporating different gas costs at different power plant locations (high costs for gas delivered to power plants in Aden, low costs for gas delivered to the power plants at Marib, etc). However, power transmission costs had not been incorporated. To choose between alternative power plant location scenarios such as a distributed generation scenario and the Marib-only generation scenario proposed in the 2001 Masterplan - would require that WASP be run at least twice once with distributed generation scenario and once with the concentrated generation scenario. The transmission capital costs associated with these two scenarios would then need to be added to the present-valued generation costs. Such an analysis may have been undertaken in 2004 or 2005 but is no longer available to review.

3.3 Comments on the distributed investment plan

3.3.1 Transmission benefits from distributed investment

The electricity demand in Yemen is distributed among the three load centres of Sanaa, Aden and Al Hodeidah, with these three representing approximately 75% of the total demand on the intereconnected grid8. Load in Sanaa represents 35% of the

7 It also concluded that locating generation at Al Hodeidah would add US$150 million to the present-valued costs compared with the least-cost solution of power concentrated at Marib.

8 Fichtner (2005): Transmission plan to 2025


Technical issues

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total, Aden consumes approximately 26% and Al Hodeidah consumes 14%. With PECs major power plants located along the coast at Al Hodeidah, Al Mocha and Aden, the main direction of flow of power has, until now, been from the coast northward and eastward to Sanaa. However, with the commissioning of 180 MW of diesel plants in Sanaa over the past three years, the expected commissioning of gas-fired power plants at Marib-I and II and the planned closure of oil-fired power plants at Al Hodeidah, Al Mocha and Aden, the primary flow of power will be from Marib through Sanaa and on to the coastal load centres of Aden and Al Hodeidah. Replacement gas-fired power stations on the coast will reduce the flow of power through the central grid and minimise losses and may avoid future investment in transmission reinforcement. However, a power station located at Mabar will add to the flow of power from the centre to the coast and will not therefore benefit the transmission network or avoid transmission investments on the main grid.

3.3.2 Derating of plants with altitude and temperature

Mabar is located south of Sanaa (see Figure 1 in Section 1) at an altitude of 2,333 metres above sea level9 with temperature ranges of between 0 and 35 degrees C. Altitude and ambient temperature both have a negative impact on the maximum output of gas turbines in simple or combined cycle and on their heat rates (fuel efficiency). Kuljians Feasibility Study for Mabar provided an estimate of the derated capacity based on an ambient temperature of 35 degrees C the maximum for this location. The 2001 Masterplan estimated the derated capacity and heat rate for plants located at Marib, Sanaa and the coast. Plants located on the coast benefit from lower altitude but suffer from higher ambient temperatures while the inland locations have higher altitudes and lower ambient temperatures. Mabar is slightly higher than Sanaa (which is 2,200 meters above sea level compared with Mabars 2,333 metres but the two are broadly comparable). The Masterplan derating factors for capacity and heat rates based on average ambient temperatures are shown in Table 3.

9 Kuljian Feasibility Study and Engineering Report, 2008.


Technical issues

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Table 3 Derating of power plants with altitude and temperature

Relative to a plant on the coast

Sanaa (proxy for Mabar) Marib

Capacity Heat rate Capacity Heat rate

CCGT -10.4% +0.7% -5.7% +1.7%

OCGT -12.3% -3.5% -4.8% -2.0%

Altitude (m) 2,200 950

Avg. temperature (0C) 17 23

Source: Parsons Brinckerhoff Integrated Masterplan Study, 2001

Compared with a plant located on the coast, an OCGT plant at Mabar (or Sanaa) would lose about 12% of its available capacity on average but, in its favour, its heat rate would be 3.5% lower. The output from a CCGT plant at Mabar would be about 10% less than a CCGT plant on the coast and, additionally, its heat rate would be slightly worse (by 0.7%).

A plant located at Marib also has lower output than a plant on the coast, but the loss in output is less than that at Mabar. Similarly, an OCGT at Marib has a worse heat rate than at Mabar or the coast, and a CCGT has an intermediate heat rate if located at Marib.

System peak demands typically occur during the summer months10 when ambient temperatures will tend to be above average, but between 18:30 and 21:00 in the evening, when ambient temperatures will be below average. Unlike countries where air conditioning load drives the peak demand, the peak demand in Yemen does not coincide with the hottest times of the day.

3.3.3 Water supply constraints

As discussed later in this Section, water supply at Mabar is heavily constrained, requiring that the power plant be designed for air cooling. This tends to add to the capital and operating costs relative to a coastal location. Similar water supply constraints arise at Marib.

3.3.4 Security considerations

Fichtners transmission study identified the need for a second double-circuit 400 kV transmission line from Marib (in addition to the 400 kV transmission line that is

10 Fichtner, Marib Power Project, 2nd Stage, Study Final Report, Volume 1, January 2006. In 2004 the peak occurred at the end of September.


Technical issues

11

under construction) to provide additional security in the event of a failure of the first double-circuit. This transmission line is expected to cost US$218.5 million by 2013 (US$176.1 million in the first phase and US$42.4 million in a second phase to be commissioned in 2013)11. The investment in the second 400 kV transmission line is not included in the funds approved12 for Marib-II. The absence of Marib-II strengthens the need for new power plants directly connected to the national grid in the central or coastal areas of Yemen (ie., such as Mabar).

3.3.5 Transmission costs or benefits associated with Mabar

The ongoing World Bank Power Sector Project includes investment in transmission lines, new sub-stations and expansion of existing sub-stations in the Dhamar area (south of Mabar) and, when complete, these investments will allow the power from Marib and Mabar to flow south and west to Aden and Taiz. This is now committed and considered a sunk cost.

Investment will be required in transmission to connect the Mabar power plant to the network and this is incorporated in the project cost. PEC has confirmed that no other transmission investment is needed to allow the output from the Mabar power plant to be absorbed by the network.

3.3.6 Conclusions on the selection of Mabar

Concentrating the power plants at Marib, as proposed in the 2001 Integrated Masterplan study, does risk security problems arising either from outages of the power transmission line(s) from Marib or problems with gas supply to the power plants. Coastal locations would allow the possibility of plants designed to run on alternative base-load fuels13 (crude oil in gas-turbine plants or coal or heavy fuel oil (HFO) in steam plants) or quickly converting them to burn alternative fuels once problems arise with gas supply. Because of Maribs inland location, dual-fuel options (other than distillate) are not feasible.

Coastal locations would:

R maximise plant output and, for CCGT, minimise fuel consumption,

R be beneficially located for the power transmission grid,

R allow the possibility of dual fuel.

The main alternatives to a power plant at Mabar are, therefore, coastal locations.

11 Information updated by PEC in December 2009 from the Fichtner Transmission Plan.

12 Funds have been approved by the Arab Fund, the Saudi Fund and the Sultanate of Oman.

13 OCGT and CCGT will be able to burn distillate but it will not be feasible to burn distillate fuel in base load for extended periods.


Technical issues

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The 2003-05 analyses that recommended locating a power plant at Mabar rather than on the coast, was not clearly documented or, if it was documented, the documentation was not retained, but the factors affecting this choice are as follows one negative, one neutral and one positive:

R Output will be between 10% and 12.5% lower at Mabar than at a coastal location. These are significant losses in output. The lower ambient temperature at Mabar outweighs the negative altitude affect such that the heat rate of an OCGT at Mabar will be slightly better compared with a plant on the coast, but the heat rate for a CCGT will be about 3.5% worse.

R A plant at Mabar will not cause additional transmission costs in the near future, other than the costs of connection to the grid14, but neither will it save on transmission costs on the main grid.

R In favour of a central location, at least until a second 400 kV transmission line is built from Marib, the Mabar plant will have benefits in terms of system security to guard against an outage of the one double-circuit 400 kV line connecting Marib to the main grid. Since the cost of the second 400 kV transmission line is estimated at nearly US$220 million, there could be a significant saving if the commissioning of the Mabar power plant could avoid or delay the development of the second 400 kV transmission line.

3.4 Gas turbines in simple cycle or combined cycle

As discussed in our Inception Report, the 2001 Integrated Masterplan and the 2005 distributed generation investment plan prepared by PEC, both concluded that gas-fired power plants selected for Yemen should be open-cycle gas turbines (OCGT) rather than gas turbines in combined-cycle (CCGT).

3.4.1 Factors affecting the choice

OCGT have lower capital costs than CCGT but burn gas less efficiently. For this reason, OCGT may be chosen either because:

R the plant is to be used for peaking or backup duties for a small number of hours per year, and where the savings in fuel costs from investing in a CCGT would be relatively small compared to the extra capital costs; or

R the value of gas is so low that the fuel cost savings from a more efficient CCGT do not outweigh the extra capital costs.

14 The transmission component of the project is US$65 million but this includes the cost of a 400/132 kV substation to connect to the proposed second 400 kV transmission line from Marib.


Technical issues

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Previous least-cost planning studies had selected OCGT because, at the time, the value of gas was assumed to be below US$1/mmbtu and at these prices OCGT would certainly be optimal.

3.4.2 Threshold value of gas for adopting CCGT

Various threshold levels have been suggested that would trigger a decision to adopt CCGT rather than OCGT:

R The 2001 Integrated Masterplan concluded that the threshold value for gas at which CCGT would be selected is US$1.5/mmbtu.

R Our own calculations suggest that the breakeven value is US$1.28 per mmbtu at an economic discount rate of 12% and a plant load factor of 75%15. Even at a discount rate of 20% - for example, if major difficulties in obtaining financing are factored into the calculation of the discount rate the threshold for switching to CCGT is only US$2/mmbtu. This is based on the assumption that the capital cost per kW for a CCGT plant is 47% greater than the capital cost of an OCGT.

We note that Kuljian provided advice to PEC which suggested that a) the capital cost of a CCGT plant is three times the capital cost of an OCGT plant and, consequently, that the threshold value of gas is US$6/mmbtu. We therefore reviewed estimates of the relative capital costs of CCGT and OCGT plants.

3.4.3 Capital costs of CCGT and OCGT plants

Parsons Brinckerhoff, the technical experts for the current project, have prepared their own estimates of the relative capital costs for similar sized plants to those selected by Kuljian, similar manufacturer (based on 2 Siemens SGT5-2000E), and at the same location (Mabar) and based on air cooling are shown in Table 4 below. The calculations are based on PBs modelling software.

Table 4 PB CCGT/OCGT capital cost estimates

Kuljian Parsons Brinckerhoff

OCGT unit size (MW) 113.5 112.4

CCGT unit size (MW) 170.6 166.8

Ratio of CCGT to OCGT capital costs 2.94 1.27

15 75% is relatively low for the first gas-fired plants operating in base load but as more gas-fired plants are added, the average plant load factor will fall. Higher plant load factors would favour CCGT still further.


Technical issues

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PBs calculations indicate that the cost of a CCGT plant is only 27% greater than the cost of an OCGT plant.

To confirm the capital cost ratio values indicated by PB above, we also reviewed internationally published information on capital cost differences between CCGT and OCGT. The US Energy Information Administration's (EIA) database gives the cost of typical CCGT and OCGT plants in the US16. These indicate that the capital cost per kW of CCGT plants is only 44% more than the capital cost of OCGT plants. The International Energy Agency's (IEA) generation cost database gives the cost of an average CCGT at 58% more than OCGT.

PB, EIA and IEA figures are taken from actual tenders, whereas Kuljian's figure was taken from the GT World Handbook. We believe the PB, EIA and IEA figures to reflect real-world prices.

Based on the capital cost ratios of between 1.27 (PB) and 1.58 (IEA), the threshold gas value ranges from a low of US$0.65/mmbtu to a high of US$1.6/mmbtu based on a discount rate of 12% and a 75% plant load factor.

3.4.4 The economic value of natural gas

In the period since the two least-cost planning studies were undertaken, international energy prices have increased and, additionally, LNG will very soon be exported from Yemen. The economic value of natural gas is no longer the marginal cost, as used in the two previous least-cost planning studies, and instead, at least initially, it is the international opportunity cost netted back to Yemen17.

A study18 undertaken under the World Banks ESMAP programme in 2006 confirms that while gas reserves are relatively scarce compared to the potential demand, the economic value of gas is the opportunity cost of selling that gas in international markets (ie., as LNG)19. This is illustrated in Annex A2. The study estimated the opportunity cost, based on international market prices, netted back to the Marib wellhead. The international market prices for LNG were based on gas price forecasts up to 2030 using EIA and IEA gas and crude oil price forecasts. Based on those forecasts, the average US natural gas price between 2006 and 2030 was estimated to be US$5.5/mmbtu. The economic value of gas when netted back to Marib was estimated to average US$2.65/mmbtu over a 25-year period.

The economic value of gas delivered to users is the opportunity cost plus the marginal cost of transmission to various points in Yemen. Implicit or explicit

16 Not necessarily air cooled plants.

17 The economic value might in future return to the marginal cost if, as reserves are depleted, the marginal cost rises above the opportunity cost.

18 Gas Incentive Framework in Yemen, a Draft Report, World Bank, October 2006.

19 This is true until the marginal cost of production rises above the opportunity cost and then the economic value is the marginal cost of production. This may happen soon given the terms for gas development in new production sharing agreements.


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estimates of transmission costs have been given from various sources in Table 5 below.

Table 5 Estimates of gas transmission costs from Safer (US$/mmbtu)

Sanaa/Mabar Al Hodeidah Aden

Integrated masterplan (2001)

0.14 0.80 n/a

PEC update of masterplan (2003)

0.50 1.05 1.22

World Bank Project Appraisal Document (2006)

0.29 0.38 0.85 0.8520 0.91

Our own, preliminary estimates of transmission costs, based on a capital cost for a 22 first stage pipeline from Safer to Mabar, of US$240 million, and initial utilisation of the pipeline only for gas to supply the CCGT plant at Mabar, is US$2.6/mmbtu. This would fall to US$1.5/mmbtu when the plant at Al Hodeidah is commissioned and to US$0.8/mmbtu when the plant at Aden is commissioned21. Altogether, combining the opportunity cost at Marib and the cost of transmission, the delivered value of gas would be at least US$3/mmbtu based on most estimates of transmission costs.

We have also checked the threshold price (of gas) beyond which it would be economic for PEC to build coal-fired plants rather than use natural gas in a CCGT plant. The threshold price of gas, assuming a delivered coal price of US$60 US$70/tonne, is estimated at US$5.43/mmbtu. This would set the upper limit on the value of gas (if the marginal cost of production plus transmission exceeds this level then the gas should not be produced and, instead, PEC should build coal-fired power plants).

Further support for the suggestion that the economic values are well above the threshold that would trigger a switch to CCGT come from the prices that are proposed to be offered to incentivise the development of gas reserves. MOM has proposed that gas be purchased from the field operators in new concessions at between US$1.5 and US2.5 per mmbtu (depending on the international oil price) and sold to PEC at US$3.2/mmbtu (with transportation charges additional to this). Though this has not yet been agreed by PEC or the Ministry of Electricity, it strongly indicates that the value of gas is well above the threshold level of around US$1.5/mmbtu that would be required to trigger the selection of CCGT in preference to OCGT.

20 Assuming the pipeline is routed via Dhamar rather than along the coast as currently proposed.

21 This calculation refers only to the transmission charges for the Safer-Mabar section of the NGP.


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While the price of gas need not necessarily reflect the economic value of gas, investment decisions should be made on the basis of the economic value and the economic value is certainly above the level that would normally trigger the choice of CCGT rather than OCGT. The pricing of gas to PEC is discussed in Section 4.5 below.

3.4.5 Other constraints to CCGT at Mabar

Water supply constraints are said to be severe at Mabar and consideration was therefore given to whether this would constrain the choice of CCGT at Mabar if there is insufficient make-up water for the boilers in the CCGT plant.

The teams technical experts note that the Al Qatrana CCGT power plant under construction in Jordan has severe water supply limitations and that while the normal water make-up requirements for the boiler would be about 120 tonnes per day, water conservation measures might reduce the consumption to less than 40 tonnes per day (making supply by road tanker feasible). We note that Kuljian, who prepared a feasibility study for the Mabar power plant, did not consider that water supply constraints ruled out CCGT at Ma'bar.

3.4.6 Other factors affecting the choice of CCGT

Though the value of natural gas used in the least-cost planning analyses should be increased and base-load power plants should be CCGT, it does not automatically follow that all new power plants should be CCGT. Some plants are used for peaking and this role is best suited to OCGT. A distinction between peaking plants and base-load plants was unnecessary in previous investment plans because all plant were OCGT. However, a least-cost investment planning study undertaken with higher economic values of gas today may choose some OCGT plants for peaking duties. However, a preliminary review of the power plants that are expected to remain in operation in the period from 2015 to 2019 shows that there is approximately 285 MW of capacity in smaller units that could be used in peaking roles which gradually diminishes over time (255 MW from 2019 to 2022, dropping to 120 MW by 2025) but probably sufficient to supply Yemens peaking requirements in the medium term.

It should also be noted that Marib-I has already been developed as an OCGT plant. While it has been designed such that it could be converted to CCGT, and it probably should be converted to CCGT, PEC might give consideration to retaining this as an OCGT to operate as a peaking plant in the mid-term when other CCGT plants are developed along the coast (as well as developing Marib-II and Mabar as CCGT plants).

Another factor affecting the choice of CCGT is that CCGT plants may be eligible for carbon credits under the clean development mechanism of UN Framework Convention on Climate Change (UNFCCC). This is discussed in Section 5.


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3.4.7 Conclusions

The above implies that all new base-load power plants selected for Mabar and elsewhere in Yemen should be CCGT rather than OCGT. It also suggests that consideration should be given to converting Marib-I to CCGT and the plant planned to be developed at Marib-II should also be changed to a CCGT as soon as is feasible22.

Note, a switch to CCGT would reduce the required size of the NGP since less gas would be needed to supply a given demand for power and this would reduce the capital cost of the pipeline. Switching to a CCGT at Mabar would add up to 50% to the capital cost of the plant. If the Kuljian capital cost estimates remain accurate (capital costs may fall following the decline in investment activity worldwide) then this would add approximately US$150 million to the investment cost of Mabar, bringing the total to approximately US$535 million (excluding the pipeline costs but including transmission costs, compared with the current figure of US$ 380 390 million).

3.5 Gas demand

3.5.1 Power sector gas demand CCGT scenario

We have estimated gas demand for the power sector based on the distributed generation investment plan (Section 3.2) but assuming that, other than Marib-I, the base-load power plants will be CCGT. Mabar (352 MW derated output) is assumed to be commissioned in 2012, Aden (500 MW) in 2013 and Al Hodeidah (250 MW) in 201423. Gas is assumed to have a calorific value of 1,030 BTU/scf. The 2001 Integrated Masterplan and the summary WASP results from the 2003-04 PEC distributed generation plan do not provide information on the plant-by-plant power production24 and we have therefore made assumptions of the possible production by each of the plants based on its likely position in the merit order.

Our indicative gas demand projections are shown in Table 6.

The Yemen power sector has a relatively low system load factor of approximately 65% with a peak occurring in the evening, driven primarily by residential demand. When gas-fired plant is first introduced, these plants will have the highest ranking in the merit order and will operate in base load, but as more and more gas-fired capacity is introduced and the older HFO and diesel plant are retired, the gas-fired

22 Funding has already been identified, tender documents prepared and a shortlist selected for Marib-II as an OCGT. PEC would need to consider whether it is feasible to switch to a CCGT at this stage, or whether it would delay the project still further, which could result in even greater economic losses for Yemen.

23 In practice, Al Hodeidah is likely to be commissioned before Aden but the current version of the power development plan assumes the sequence is reversed.

24 Though this information would have been provided by WASP.


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units will potentially operate in all positions on the load curve base load, mid-merit and peaking.

The gas demand projections measured in mmbtu and tcf in the first part of Table 6 assume that the gas-fired plants operate at high positions in the merit order without constraint from gas supply. The lower part of Table 6 shows three power operation and gas utilisation strategies or scenarios for operation of the gas-fired power plants at peak times. The maximum NGP pipeline utilisation scenario is based on the pessimistic assumption that unforeseen outages occur at the Marib plant coincident with the time of the system maximum demand and that the other gas-fired power plants on the system that are all served by NGP need to operate at maximum output (other non-gas-fired plants are available but in this scenario they do not operate). The normal scenario involves the Marib and other gas-fired plants sharing the peak demand more-or-less equally. The third the managed power operation scenario - would be used if there are constraints on the use of the NGP and PEC maximises the use of the plants at Marib and the non-gas-fired plants at peak times in order to minimise the use of the NGP. Further reductions in gas demand could be achieved for short periods at peak times, if needed, through the use of distillate fuel in gas plants and large users may also be able to switch fuels at peak times. Considerable flexibility therefore exists on the demand-side.

Table 6 Gas demand projections for power (CCGT scenario)

2012 2013 2014 2015 2020 2025

Total (mn. mmbtu/year)

55 61 69 68 .. 88 .. 111

Cumulative tcf 0.05 0.11 0.18 0.24 .. 0.64 .. 1.13

Stage 1 of NGP (mn. mmbtu/year)

17 23 38 40 .. 61 .. 83

Peak gas demand on Stage 1 of NGP (maximum mmscfd)

Maximum if outages occur at Marib plants

45 61 124 140 .. 217 .. 303

Normal production of power plants

45 61 116 127 .. 186 .. 247

Managed power production

1 1 10 12 .. 70 .. 190

3.5.2 Power sector gas demand OCGT scenario

If the power plants are simple cycle gas turbines or the plants along the coast are steam plants (with similar efficiencies to OCGT) then the gas demand would be higher. This alternative demand projection is shown in Table 7.


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Table 7 Gas demand projections for power (OCGT scenario)

2012 2013 2014 2015 2020 2025

Total (mn. mmbtu/year)

78 87 98 97 .. 126 .. 159

Cumulative tcf 0.08 0.16 0.26 0.35 .. 0.91 .. 1.61

Stage 1 of NGP (mn. mmbtu/year)

24 33 54 56 .. 87 .. 118

Peak gas demand on Stage 1 of NGP (maximum mmscfd)

Maximum if outages occur at Marib plants

64 87 178 200 .. 310 .. 433

Normal production of power plants

64 87 165 181 .. 266 .. 353

Managed power production

1 1 14 17 .. 100 .. 271

If dual-fuel steam plants are developed along the coast then this would allow even greater flexibility in the use of gas at peak times than those shown in Table 7 and operating strategies could be adopted to optimise the size of the pipeline.

3.5.3 Non-power gas demand

Estimates have been made of potential demand from outside the power sector and these are described in the Ramboll Gas Utilization and Pipeline Feasibility study in 2005 and, before that, in the 2001 Integrated Masterplan study. The primary potential users of gas are cement plants. For the purpose of estimating the aggregate demand for gas on the NGP, we assume that this would add a further 30 mmscfd in 2012, rising to 50 mmscfd by 2017 and staying constant thereafter. We note that this is more pessimistic than the forecasts in Integrated Masterplan which indicate a demand of 89 mmscfd by 202525.

3.6 Size of the 1st stage of the NGP

The planned route of the NGP is indicated in Figure 3. Eventually, the pipeline should follow the route of the existing oil pipeline toward the coast and supply gas to Al Hodeidah, from there it would follow the coast south to supply the power plant at Al Mocha and the city of Taiz, and from there it would continue round the

25 Base case, Table 4.9.


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coast to Aden. The overall cost of this project was estimated by Ramboll in 2005 at US$941 million26.

In the current study we are concerned with the first stage of the pipeline from Safer to the power plant at Mabar.

Figure 3 Planned pipeline route

Source: Ramboll, Gas Utilization and Pipeline Feasibility study, 2005.

3.6.1 Sizing considerations

The 240 km first stage of the NGP, from Safer to Mabar, will take around three years to build and must be completed at more-or-less the same time as the Mabar power plant. It is therefore urgent to specify the main characteristics of the pipeline in order to allow the preparation of front end engineering studies and tender documents. However, crucial to the sizing and specification of the pipeline will be:

R the level of demand for the gas over time,

R the availability of gas,

26 This cost is for a larger capacity pipeline from Safer to Mabar than is currently proposed and includes among other things spurs and local distribution networks. However, pipeline costs increased after 2005. The Ramboll costs are therefore no longer strictly accurate but they provide an indication of the overall levels of costs for the full network.


Technical issues

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R the calorific value of the gas, and

R the pressure and pressure depletion profile for the gas.

There are risks of both over-sizing a pipeline and under-sizing it.

An oversized pipeline with excess capacity will:

R be expensive and will waste Yemens scarce capital resources,

R lead to partially stranded assets that are underutilized, and/or

R the transmission use-of-system charges will be unnecessarily high.

On the other hand, an undersized pipeline will:

R constrain the utilisation of natural gas, and/or

R require investment in compression to boost the capacity of the pipeline, or

R require investment in a second parallel pipeline.

Furthermore, as discussed below, it is much cheaper to add capacity by increasing the design diameter of the pipeline than to build a second pipeline or add compression.

3.6.2 Demand uncertainties

As estimated in the previous sub-section, the level of potential demand is large the power development plan proposes 2,500 MW of gas-fired power plant by 2020 and 3,300 MW by 2025 and additional demand for non-power users. However, demand forecasts are inevitably wrong27. Furthermore, financing constraints could delay the development of the stage 2 pipeline to the coast and/or delay the construction of gas-fired power plants; this uncertainty affects the realisable demand.

The analysis in Section 3.5 indicated that there is potentially a degree of flexibility in the operation of gas fired plants in order to reduce gas demand if the size of the pipeline that is chosen turns out to be too small to supply the potential peak demand. A pipeline that is not sized to supply all gas-fired plants 100% of the time throughout the year may be optimal.

3.6.3 Uncertainties over gas availability

MOM indicates that in addition to the 1 tcf certified from Block 18 another 2 tcf will be certified from other blocks. Since the cumulative demand from the power sector

27 Demand forecasts are, of course, necessary, but it must be recognised that only by very good luck does the outturn match previous forecasts.


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until 2025 is likely to be approximately 1.1 tcf (see Table 6) and another 0.2 tcf for industry, supply is not likely to be a constraint in the mid-term.

3.6.4 Specification of the available gas

Table 8 below indicates how pipeline sizes would differ for different source pressures and calorific values to approximately meet the normal 2025 demands indicated in Table 6 above plus the non-power gas demand (50 mmscfd) assuming a 240 km pipeline and a minimum off-take pressure of 50 barg.

Table 8 Pipeline diameter options

Source pressure (barg)

Btu/scf 80 100 120 140

800 48 26 22 20

900 42 26 22 20

1,000 40 24 20 18

1,100 40 24 20 18

Source: PB estimates based on hydraulic studies. Demand of 283 mmscfd.

Table 8 indicates that gas supplied to the NGP should have a minimum source pressure of approximately 100 barg if very large pipe diameters are to be avoided. This will probably require compression at source to ensure a stable minimum source pressure required by the power plants. The above Table also indicates the importance of identifying the source pressure and calorific value before firm decisions are taken on the pipeline sizing.

3.6.5 Flexibility of pipeline capacity and demand

Compression could increase the maximum flow on the NGP at peak times but an average compressor would consume a substantial quantity of gas (approximately 0.1 tcf over 20 years if used continuously for base load operation), so the pipeline should not be sized at a level that would require future compressors that have to be operated continuously.

As indicated above, there is flexibility in the operation of the power system that could reduce the maximum flow on the NGP. At peak times, some of the peaking oil or diesel plants should be operating, so this would reduce the maximum gas flow requirements. If necessary, gas-fired plants could use distillate fuel for short periods and large industrial users could be asked to switch to alternative fuels temporarily (or schedule their annual maintenance to coincide with periods of peak electricity and gas demand). Also, if the plants at Al-Hodeidah and Aden are, as IFC proposes, dual fuel, then these could switch to oil/coal at times of constraint on the gas


Technical issues

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pipeline (though this would also increase the consumption of gas since steam plant is less efficient than CCGT).

Given that flexibility exists in the operation of the power system, that demand-side measures can be used to limit peak demand, and compression can be used to increase the capacity of the pipeline at times of peak demand, the pipeline need not necessarily be sized to meet the absolute peak demand.

3.7 Pipeline costs

3.7.1 Review of previous cost estimates

Pipeline cost data from various sources has been reviewed:

R YLNG allocated a sum of US$ 110 million to construct a 210 km pipeline with a diameter of 12 from Marib to Sanaa. This implies a unit cost of US$ 44 per inch-diameter /metre length of pipeline.

R The Ramboll study carried out in 2005 proposed a network comprising of 362 km of 32 pipeline, 496 km of 24 pipeline, 66 km of 16 pipeline and 100 km of 14 pipeline at an estimated cost of US$ 855 million, excluding design and project management. This implies a unit cost of US$ 33 per inch-diameter /metre length of pipeline.

R MOM reported that an estimate of US$ 260 million had been prepared for laying a 240 km pipeline with a 24 diameter from Safer to Mabar. This results in a unit cost of US$ 45 per inch-diameter /metre length of pipeline.

R UK data indicates current pipeline costs of US$ 50 per inch-diameter /metre length of pipeline.

R A review of current Middle East / North Africa ITT bids suggest a unit cost of US$ 40 per inch-diameter /metre length of pipeline.

From the above, we conclude that the MOM estimate of US$ 45 per inch-diameter /metre length of pipeline for a 24 pipeline from Safer to Mabar is likely to be reasonable under recent market conditions.

3.7.2 Pipeline cost estimates

Using the above per-unit cost as a benchmark, indicative pipeline costs are provided below.

Pipelines with a diameter of 12 or 14 that were originally proposed in negotiations between GoY and YLNG would clearly be inadequate to meet demand


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unless the gas pipeline stops at Mabar which would not make economic sense28. Such a pipeline, though costing only US$130 to US$150 million, would have a capacity of only 100 to 140 mmscfd and would be unable to meet demand beyond 201329.

Table 9 shows indicative costs and approximate required pipeline diameters to supply the gas demands indicated in Section 3.5 above and assuming a source pressure of 130 barg and a terminal pressure at Mabarg of 75 bar (designed to allow onward transmission to the coast). 30

Table 9 Indicative costs and capacity for larger diameter 1st stage NGP

Demand (mmscfd) Pipeline diameter31

Cost (US$ mn.) Sufficient until year32

200 16 175 2016

220 18 195 -

240 18 - - -

260 18 - - 2022

280 20 215 -

300 20 - - -

..

350 20 - - > 2025

..

400 22 240 > 2025

This assumes a source pressure of 130 bar and a terminal pressure of 75 bar.

Table 9 indicates that an 18 pipeline would be sufficient to meet the normal demand described in Section 3.5 until 2022 when demand, including industry, would be 250 mmscfd. A 20 diameter pipeline could meet a demand of between 350 and 400 mmscfd and would be adequate to meet the normal demand shown in

28 It would then make sense to build the plant at Marib instead, as proposed in the Integrated Masterplan.

29 Based on normal demand in Table 6. This assumes a calorific value of gas of 1030 Btu/scf, a source pressure of 130 bar and terminal pressure of 50 bar. The latter would be inadequate for onward transmission to Al Hodeidah.

30 Eventually pipe diameters should be specified more precisely having regard to most economic standard.

31 Note, these estimates are very approximate and should be verified with hydraulic modelling at the time the system parameters are known.

32 Based on normal demand in Table 6. Assumes calorific value of gas of 1030 Btu/scf.


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Section 3.5 until beyond 2025. Similarly, a 22 pipeline would have adequate capacity to meet demand until well beyond 2025.

3.7.3 Initial conclusions on pipeline sizing

An 18 pipeline would cost approximately US$195 million and would allow unconstrained operation of the gas-fired plants and industrial users until 2022; thereafter some measures would need to be introduced to reduce peak demand for gas or, alternatively, compression would need to be added. With managed power plant operation (see Table 6), the 18 pipeline would be adequate until beyond 2025 (when the peak demand would be 240 mmscfd, including industrial demand, compared with a pipeline capacity of between 260 and 280 mmscfd). With compression the 18 pipeline would be adequate for even longer.

However, the incremental cost of a 22 pipeline rather than, say, an 18 pipeline is relatively low. Whereas the investment in a 12 pipeline would have provided capacity at a cost of US$0.77/mmscfd, the investment in capacity by adding diameter to the pipeline at the time of construction (and changing the design from an 18 pipeline to a 22 pipeline) would cost only US$0.32/mmscfd and would ensure a virtually unconstrained supply of gas for peaking power as well as base load for many years. It would, however, bring the capital cost from US$ 195 million to US$ 240 million (adding US$45 million to the capital cost). A 20 pipeline would also provide unconstrained capacity but would cost only US$215 million (US$20 million more than an 18 pipeline).

Subject to confirmation of the source pressure, pressure depletion profile and calorific value of the gas, the primary choices of pipeline diameter are likely to be between a 20 pipeline at a cost of US$215 million that will be adequate for base-load and mid-merit operation of gas-fired plants and unconstrained use by industrial users at peak times, or a 22 pipeline at an extra cost of US$25 million that will also allow unconstrained operation of power plants for many years and allow the possibility of substantial expansion of supply to other gas users.

3.8 Summary of conclusions on technical issues

We conclude the following on the technical options to be assumed in the subsequent analyses:

R The power plant at Mabar should be a CCGT and we propose that the subsequent financial analysis should be based primarily on this assumption. The analysis will also consider an alternative option that the plant is an OCGT.

R Other new base-load gas-fired plants should not be OCGT. Instead they should be CCGT unless they are to be peaking plants using distillate fuel or steam plant located on the coast and able to burn natural gas as well as coal/HFO. We suggest that the least-cost plan is updated to identify the optimum combination of peaking and base load gas-fired plants. For


Technical issues

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the purposes of our subsequent financial analysis of the 1st stage of NGP, and the gas transportation through the pipeline, we propose that the primary assumption is that new power plants along the coast will be CCGT. We will also consider an alternative scenario where they are OCGT or steam plants (with similar efficiencies).

R Clearly, gas availability needs to be certified and amendments to production sharing agreements, and the arrangements for gathering and processing the gas need to be identified before any major downstream investment can take place33. However, for the purposes of subsequent analyses we propose to assume that upstream gas supply from the gas fields accessible to the NGP will be sufficient and will not constrain the downstream choices (pipeline size and use of gas).

R Decisions on the size of the 1st stage of the NGP require information on the source pressure, source depletion profile and calorific value of the gas. Subsequent financial analyses as part of the current study can continue without finalizing the pipeline size but we note that a decision is urgent to allow preparatory work to begin. This therefore requires further analysis by MOM of upstream arrangements. For the purposes of the financial analysis, we propose to assume that the primary option is a 22 pipeline. We will also consider an alternative of an 20 pipeline.

33 Likewise, the arrangements downstream need to be identified before major upstream investments can take place.


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4 Institutional options

This Section is concerned with some of the institutional options for the arrangement of gas to power in Yemen. This addresses issues such as:

R Which entity will own the Mabar power plant and what will be the role of this entity?

R Which entity will own the NGP and what is the role of this entity?

When considering these issues, we take account of the following important guiding principles:

R the arrangement should allow future competition to the extent that this is feasible and should be consistent with planned power sector reforms and with possible future competitive gas markets;

R even though private sector participation (PSP) may not immediately be feasible in power or for the gas pipeline, the arrangement that is introduced should facilitate possible PSP in future;

R the arrangement should be flexible in order to allow state ownership initially but the possibility of a range of PSP options later.

4.1 Power sector reform

4.1.1 GoY policy

A power sector reform strategy, approved by GoY in 2001 (Cabinet Resolution #112), consisting of the following:

R Separation of generation and transmission from distribution (G+T, D) initially followed eventually by full functional separation into generation, transmission and distribution. This is designed to achieve increased commercial focus, accountability, and clear definition and lines of authority and responsibilities.

R Creation of an independent regulatory agency.

R Introduction of competition in generation initially via the procurement of new generation capacity through a purchasing agent (a single buyer). The Single Buyer will initially be a unit within the transmission business unit of PEC, but eventually would be a fully independent agent of PEC.

R Full corporatization of PEC to make it autonomous and accountable, and commercialization of the operations and administration of PEC. Ministerial responsibilities will be focused on policy-making.



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R Introduction of unbundled tariffs for electricity into the functional components generation, transmission and distribution with appropriate commercial arrangements between the PEC businesses.

R Eventually privatising one or more of the electricity businesses or introduction of management contracts or joint venture arrangements.

The first version of an Electricity Law incorporating these policies was drafted and presented to Cabinet in 2002. Subsequently, the draft went through several revisions. The latest version is currently under review by GoY.

4.1.2 Implications of GoY policy for the gas to power project

While the detailed implementation of GoY policies on power sector reform may be subject to some uncertainty, the policies themselves are clear and the institutional arrangements proposed for the gas to power project should respect those policies. In particular, the intent of the policies is to create an environment in which, to the extent possible, competition is possible and this requires the separation of activities that could potentially undermine competition. For this reason, GoY policy is to separate generation, transmission and distribution so that the monopoly businesses of transmission and distribution do not have incentives to restrict competition in the two areas where competition is possible generation and supply (linked, initially at least, with distribution).

While GoY policies do not say anything about separation of power and gas, it is clear that arrangements that combine gas pipelines with power generation would have the strong potential to restrict future competition. A Mabar power plant that also owned the gas pipeline that would supply all future, potentially independent, power plants along the coast would be in a very strong position to restrict competition. Similarly, ownership of NGP by PEC would give PEC complete control over the supply of gas and the potential to restrict competition. In the longer term it would be possible to combine a fully independent power transmission company with the NGP to create a gas and power transmission company (as in the UK), but this is an option that could be considered later.

Recognising GoY policy to encourage competition in electricity generation, combined ownership of the gas pipeline and of power generation businesses would undermine this policy.

4.2 A framework favourable to competition in gas supply

4.2.1 Independence of gas transmission from power generation

The pipeline from Safer to Mabar is planned to be the first stage of a national pipeline network. For the reasons described above, the ownership of NGP should be independent of power:



29

R it must supply more than one power plant, including possible IPPs and should also supply other gas users, and

R common ownership of power generation and NGP would be an obstacle to future competition in generation.

Although we are not aware of a GoY strategy with regard to competition in the domestic gas market, it would be reasonable to assume that GoYs policy with regard to power would be replicated in the gas sector. It would therefore be reasonable to establish the institutional framework for the gas sector with a view to creating the conditions for competition wherever possible. Common ownership of the NGP and power generation would be an obstacle to competition in the gas market just as it would be an obstacle to competition in power generation.

4.2.2 Independence of gas transmission

In the power sector, GoY has proposed the unbundling of transmission from generation and distribution. This ensures that the owner of the power transmission network is concerned solely with transporting electricity from generator to consumer (or distribution company) and will not favour one generator over another or one consumer over another in terms of access to the network or dispatch of power plants on the system. The same argument would hold in the gas sector, with separation of gas transmission from either upstream interests (producers) or downstream (power plants or eligible consumers).

4.2.3 Independence of gas supply (trading) from transmission

In the electricity sector it has been proposed that a Single Buyer should be created as an agent of the distribution company/eligible consumers34. In this case, the Single Buyer is misnamed since it is not a trader of the gas but, instead, acts like a broker with responsibility for arranging contracts that are signed between the actual buyers the distribution company (or companies) and, possibly, eligible consumers. Initially the electricity Single Buyer would be part of the electricity transmission company but later it would be separated and become fully independent.

The arguments for the separation of the wholesale supply function (buying/selling) from the transportation function in the power sector, also apply to the gas sector. But in the gas sector there is the option of establishing a framework from the start that is favourable to future competition in gas supply. This suggests that the wholesale buying and selling function for gas should be separate from the gas transportation business (NGP).

The natural responsibility for wholesale buying and selling of gas lies with the Yemen Gas Company (YGC) since it is already responsible for trading LPG and the buying and selling of gas is a natural extension of this activity.

34 Eligible consumers are those who are entitled to enter into direct contracts with generators for the purchase of power and with third-party access to the transmission network.



30

While Yemen has opted for the electricity Single Buyer as an agent rather than an actual buyer/seller, other countries have chosen to create their single buyer as a true buyer/seller. In the gas sector it is arguable whether there are benefits in making YGC an agent of the power generators and other consumers for the purchase of gas or whether YGC should actually own the gas that it on-sells to the gas consumers. This is a level of detail to be discussed in the next Report.

4.3 Facilitating future private sector participation

To allow the greatest flexibility in future in attracting PSP in both the Mabar power plant (and subsequent power plants) and in the NGP, we propose that two entities be established, initially as 100% state-owned companies, which for the purposes of discussion we have labelled:

R the Mabar Power Company (MPC), and

R the National Gas Pipeline Company (NGPC)

MPC would be 100% owned by PEC while NGPC would, probably, be 100% owned by MOM.

This arrangement has no disadvantages compared with, say, creating the Mabar power plant as a division within PEC. However, the advantages of this arrangement are:

R it is easier to invite simple PSP options at an early stage (for example, operation contracts),

R clearly defined contractual arrangements between the companies and other parties and clean sets of accounts will demonstrate to potential future investors in MPC or NGPC that the two entities are viable,

R the two financially viable, state-owned companies, will demonstrate to investors in other power plants and investors in subsequent sections of the pipeline that infrastructure projects in Yemen can be financially viable,

R it is consistent with the spirit of the power sector reforms.

We note also that international funding agencies have been cautious about agreeing to finance the Mabar power plant until the problems at Marib-I and II have been sorted out. Creating the Mabar power plant as a company will signal to the funding agencies that PEC and GoY are taking steps to reform and improve performance.



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4.4 Contractual arrangements between MPC and PEC

The power sector reforms propose that a Single Buyer be created to act as the agent of the distribution company or companies and eligible consumers. The exact details have not been finalised but the arrangement suggests that the Single Buyer will not be a signatory to the power purchase and sale agreements and instead the contracts will be between the generators and the distribution companies/eligible consumers.

PEC is not creditworthy at present and power purchase agreements signed between PEC and MPC would not be bankable for private investors unless backed by sovereign guarantees which, in turn, would need to be backed by escrow accounts giving MPC access to secure revenue streams. However, bilateral power purchase agreements between MPC and large, private eligible consumers of electricity could potentially be bankable. Unfortunately, there are few large private power consumers in Yemen that could individually or jointly contract with a power plant of the size of Mabar. We understand that PECs largest customer, a state-owned cement plant in Taiz, has a contracted capacity of only 14 MW.

The precise trading arrangements for power are currently uncertain and it is therefore too early to consider bilateral contracting arrangements when analysing the options in subsequent stages of the current study. We therefore propose to assume that the agreements for the sale of power by MPC are signed with PEC. It is possible that these agreements could be backed by the revenues from large customers in virtual bilateral contracts and this will be considered later in the study.

4.5 The price of gas to power, and the required subsidies

Section 3.4 above noted that the average economic value of natural gas over a 25 year period has been estimated at US$2.65/mmbtu at the wellhead at Marib and the delivered price is likely to exceed US$4/mmbtu and downstream investment decisions need to be taken on the basis of this economic value. However, consideration needs to be given to the current subsidy framework and the rent that will be earned from the sale of natural gas.

4.5.1 Subsidy framework

Average electricity tariffs to end-users are heavily subsidised and, unlike most countries, bear little relation to the costs of supply. Subsidies take three forms:

R GoY financing of PECs capital investment and relief from debt servicing obligations.

R Subsidies for HFO when the international market price rises above the equivalent of YR 25/litre (approximately US$130/tonne). This is settled directly between the Ministry of Finance (MOF) and the Yemen Petroleum Company (YPC).



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R Subsidies for diesel to supply the mobile plants contracted by PEC to fill the capacity deficit until gas-fired power plants begin operating. A 2005 agreement between PEC and MOF states that PEC will be charged the market price for diesel, PEC will be required to pay only YR17/litre and the balance will be paid by MOF directly to YPC35. This subsidy will be treated as equity contribution to PEC by GOY.

Fuel subsidies are estimated to cover approximately 60% of PECs operating costs36.

MOF plans that when the gas-fired plants begin to operate, the fuel subsidies would cease. However, as long as end-user tariffs continue to be unrelated to actual costs incurred by PEC, then the possibility of eliminating subsidies to PEC depends on the price charged to PEC for gas consumed in its power plants.

MOM has proposed that gas be priced at US$3.2/mmbtu. When allowance is made for the cost of transmission from Marib to PECs power plants, the delivered price will probably exceed US$4/mmbtu.

The cost per kWh for electricity produced in a new CCGT plant, based on the capital cost estimated by Kuljian for Mabar (but adjusted to a CCGT), and at a gas price of US$4/mmbtu would be approximately US$0.057/kWh37. This compares with US$0.045/kWh for the variable costs of electricity produced in the Al Mocha steam plant using HFO priced at YR25/litre. Thus, PEC would actually lose from a switch from subsidised HFO to unsubsidised natural gas.

On the other hand, Yemen will certainly gain from the introduction of natural gas. The fuel cost of electricity produced at Al Mocha at an oil price of US$70/bbl and an HFO price of YR63/litre (US$0.31/litre), is approximately US$0.114/kWh. MOFs costs of subsidising PEC will therefore fall substantially when gas-fired plants are introduced.

While total electricity production costs will fall when gas is used for power generation, care must be taken in assuming that the introduction of natural gas will mean that subsidies to PEC can end. Later in the project we will review the level of subsidy necessary to make PEC financially viable after the introduction of gas-fired plants and/or the amount by which the electricity tariff should be increased if the subsidy is eliminated. We will also estimate the amount by which MOFs subsidy costs will fall.

4.5.2 Rent from the production and sale of gas

We note also that while the economic value of gas delivered to users in Yemen is likely to exceed US$4/mmbtu, there are likely to be substantial economic rents

35 World Bank Project Appraisal Document for the Power Supply Project, 2006.

36 World Bank Project Appraisal Document for the Power Supply Project, 2006.

37 The variable fuel and O&M cost would be US$0.031/kWh.



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from the production and sale of natural gas. Rent or surplus refers to the difference between the cost of gas and the economic value of gas.

In Yemen, the initial supply of gas is likely to come from relatively low cost sources in Blocks 18 where the infrastructure has already largely been developed to gather the gas for use by YLNG. The 1 tcf of gas dedicated to the domestic market might, for example, cost only US$0.5/mmbtu to produce38 and could be sold at, say, US$3.0/mmbtu (at the entry to the pipeline at Marib). This would give a surplus or rent to the seller of perhaps US$170 million per year. Depending on the fiscal terms for the development of the gas, the rent or surplus should be captured and transferred to MOF and then some of this could be distributed to PEC as a subsidy. Ideally, of course, there should be no subsidy, and the surplus from the sale of gas should be used for normal state budgetary activities such as schools, hospitals and roads. But the current reality in Yemen is that electricity is subsidised and it is recognised that the subsidy should be removed over a period of time rather than instantaneously. The surplus from the sale of gas could therefore flow through to MOF and from MOF to PEC.

Alternatively the gas could be sold to PEC at cost. In some respects this would be equivalent but it runs a number of risks. The economic outcome would be the same provided that:

R PEC makes investment decisions (eg., in relation to CCGT plants) on the assumption that the true value of the gas is, say, US$3/mmbtu, and

R that end user prices for electricity, particularly to larger consumers, are calculated on the assumption that the true cost of gas is, say US$3/mmbtu (this discourages electricity users from using electricity wastefully), and

R crucially, it is recognised that gas prices to PEC will rise in the future to encourage the development of gas reserves and the exploration for new reserves.

There is a major and very serious risk with the second pricing strategy that potential gas operators will see that prices paid for gas are low and will not take the risk of investing in development and exploration. The first approach is therefore much safer and the outcome for PEC should be the same provided that the existence of the surpluses is recognised and they are transferred to PEC through MOF.

4.6 Summary of institutional options

In summary, we propose to base the subsequent analyses on the institutional framework described in Figure 4.

38 In Block 10, where the gas would otherwise be flared, the operator virtually gives the gas away.



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Figure 4 Summary of institutional framework (who owns what?)

Hodeidah

Key OwnerYLNGPECYGCSAFEROil companiesPlanned, under constructionor under consideration

Balhaf

Ma'rib-IIMa'bar power company

PEC

Block 18(> 1 tcf)

10km

gasplants

Blocks 5, 20, S1, .. (> 2 tcf)320km

240km

Ma'rib-I

National gas pipeline company

MoE MOM

gasplants150km

We propose to assume the following:

R ownership of power plants will be independent of the ownership of the NGP;

R NGP will be a gas transportation company;

R YGC will either:

R buy gas from the gas producers and sell to the power generators and gas consumers, or

R act as a broker on behalf of the gas consumers for arranging purchases of gas on behalf of gas consumers;

R MPC39 will be established to own and operate the Mabar power plant and will initially be 100% owned by PEC;

R MPC will sign a contract with PEC for the sale of power40;

R a National Gas Pipeline Company (NGPC)41 will be established, initially 100% state owned.

39 Or some other name.

40 Or other contractual arrangements - to be considered in the next Report.

41 Or some other name.



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Regarding the price for gas sold to PEC, MPC and other generators, we propose to assume:

R A price will be agreed by GoY that approximates to the economic value of gas (the exact price is yet to be finalised).

R Until such time as the average end-user tariff for electricity is set at a level that allows PEC and the power sector to be financially viable, MOF will continue to provide subsidies for power. The level of subsidy will, however, fall dramatically once gas-fired power plants begin to operate and purchases from diesel power plants and production from steam plants burning HFO begin to be eliminated.

R Revenues received by MOM for gas sold to PEC will, at least initially, greatly exceed the actual cost of gas. These surpluses will flow into the Treasury and from there may be used, indirectly, to provide subsidies to PEC. MOF will therefore gain both from an increase in revenues from the sale of gas and a fall in direct subsidies to PEC.


Financing options

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5 Financing options

The capital costs of the two components of the gas-to-power project that will require financing are:

R The Mabar power plant, as a CCGT (rather than as an OCGT), including transmission, will cost approximately US$ 540 million.

R The 1st stage of the NGP, if it has a 22 diameter, is estimated to cost US$240 million. US$110 million has been committed by YLNG, leaving a balance of US$130 million to be financed.

Upstream, there is also the cost of the gas gathering and gas processing to be financed but our focus is on the mid-stream and down stream segments of the chain. There are major constraints to private sector financing of these two components of the gas-to-power project - national and international.

National factors affecting the feasibility of private financing include:

R Difficulties of coordinating the simultaneous development of upstream gas development, the mid-stream gas pipeline and the downstream gas-fired power plants at Mabar and along the coast, and the need to develop these projects simultaneously.

R PEC is not creditworthy as buyer of power.

R Security risks for international companies working in Yemen.

R Limited experience of private sector participation in infrastructure (though the LNG project is a good example of a successful private project).

R Possibly macroeconomic instability this was perceived by investors as the top concern of firms that constrained investment in Yemen42.

International factors affecting possible private financing include:

R There is limited appetite for risk by strategic investors in the current international climate. Investors currently favour safer, low risk investment opportunities.

R Strategic investors have a wide choice of infrastructure projects worldwide and can pick-and-choose the most favourable projects.

42 Draft Investment Climate Assessment, 2006, reported in the World Banks Country Assessment Report, 2005. This is based on a survey of 488 formal firms in manufacturing, services and commerce in four locations of Yemen.


Financing options

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Though it is now widely accepted that because of the above constraints, it is unlikely that private sector financing for the Mabar power plant and the 1st stage of the NGP will be feasible in Yemen in the immediate future, nevertheless, in the Section below we consider the broader options for financing the Mabar power plant and the 1st stage of the NGP. First we begin by noting some regional experience of PSP in gas to power projects and the investment environment in Yemen.

5.1 Regional experience of PSP in energy infrastructure

5.1.1 Egypt

Three privately developed build-own operate transfer (BOOT) plants in operation in Egyp

yemen_gas_to_power_options_report(2).pdf

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