Domestic Supply Obligation and Gas Pricing Policy€¦ · Nigerian Power Sector Infrastructure4 CSL Stockbrokers is a division of FCMB (UK) Limited which is authorised by the Prudential

Nigerian Power Sector

Infrastructure

CSL Stockbrokers is a division of FCMB (UK) Limited which is authorised by the Prudential Regulation Authority (PRA) and regulated by the Financial Conduct Authority (FCA) and the Prudential Regulation Authority (PRA) in the United Kingdom

Page 101

Domestic Supply Obligation and Gas Pricing Policy

Under the DSO, every gas producer must allocate a portion of their

production to the DSO before they can allocate any gas to other

commercial obligations. Non-compliance would result in significant

penalties. Once the gas producer has satisfied its DSO quota, any amount

of gas produced in excess of that can be sold on a willing buyer/willing

seller basis. The amount each supplier must allocate is not fixed but is

determined each year based on domestic demand and the number of gas

suppliers. Allocation to each supplier is done on an equitable basis

determined by the Minister for Energy.

Before the DSO was introduced and became operational in 2010,

practically all gas produced was exported because the price the PHCN

GenCos were willing (and able) to pay was too low to make it commercially

viable to supply gas to local GenCos. The situation could not persist if the

Nigerian government wanted to attract investment not only to the power

sector but also to the gas sector. It was accepted that the age of effectively

financially and structurally subsidising the power industry had passed.

However in order to ensure, as far as possible, a smooth transition to a

free-market system in the gas industry and in other strategic industries,

price increases would have to be managed rather than left to the market to

set the level.

The regulated pricing regime for the DSO (bulk of which is for power) is

based on determining the lowest cost of supply that will allow a 15% return

to the supplier. This floor price has been set at US$0.10 per Mcf31

. The

actual price paid for gas includes an escalation for inflation and an

indexation to the real time product price and/or any other indices that the

buyer and seller agree upon. The Ministry of Energy determined that the

cost reflective baseline was c.US$1.00 per Mcf by 2012. This was later

reviewed to US$1.50 per Mcf.

The main sticking point with the DSO has been on the issue of pricing

because the baseline price paid to the producers for DSO gas to

power has been below the market price (now US$3.80-4.00 per Mcf).

On 2 August 2014 the FGN announced a revision in the DSO gas-to-power

price for 2014 to US$2.50 from US$2.00 per Mcf as part of measures to

bridge this pricing issue. This brings the DSO price closer to, but still well

short of the market spot price of US$3.50-4.00 per Mcf. The DSO price is

expected to reach “export-parity” in 2016, thereby doing away with the need

for price regulation. MYTO II factors in a gas price of US$2.19 per Mcf by

2017

31

Thousand Cubic Feet


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Chart 21: DSO Gas Price to Power Profile (2010-2013), US$/Mcf

Chart 22: Old Gas Price to Power vs Annual Price of US LNG Imports from Nigeria, US$/Mcf

Source: NERC, CSL Research Source: NERC, US EIA, CSL Research

Figure 30: Operation of the Domestic Supply Obligation

Source: CSL Research

1.00

1.50 1.50

1.80 2.00

2.50

3.50

0.00

0.50

1.00

1.50

2.00

2.50

3.00

3.50

4.00

2010 2011 2012 2013 2014 2015 Est. 2016 Est.

US

$ p

er

Mcf

Current Market (Spot) Price Range

2.50

On 2 August 2014 the FGN revised the 2014 DSO gas-to-power price to

US$2.50 per Mcf Annual Price of US LNG Imports

from Nigeria Old Gas Price to Power

0

2

4

6

8

10

12

14

16

18

2000 2002 2004 2006 2008 2010 2012

US

$ p

er

Mcf

Gas Suppliers(International Oil Companies

& Independents)

Domestic Supply Obligation

(DSO)

Central Gas Processing Facility

(CGPF)

Gas for Own Export

Projects

Integrated LNG Plant

With Own CGPF

Domestic Buyers

Methanol

Plants

Fertiliser

Plants

Power

Plants

Regional

Pipelines

Pure Liquefaction

LNG Plants

Other Exports

Gas Transmission Line

Bilateral

Contracts

Excess Gas

Over DSO

Wet Gas


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Gas Aggregation Company

The Gas Aggregation Company Nigeria Limited (GACN) is the aggregator

of natural gas produced for domestic use in Nigeria. It acts as an

intermediary between suppliers and buyers of natural gas in the Nigerian

domestic gas market and ensures that the Strategic Sectors are supplied

with gas under the appropriate pricing schedule. Its responsibilities also

include managing receipts of payments and disbursement of an aggregate

gas price to suppliers and facilitating the execution of necessary securities

in respect of default of gas payments.

The only three entities permitted to buy gas through the GACN are:

GenCos whose sole business is to generate power to the national grid;

companies that use gas as feedstock for their end products; and local

distribution companies which sell gas to commercial and manufacturing

companies in the domestic market. A Gas Supply and Aggregation

Agreement (GSAA) between the buyer, seller and the GACN governs terms

of gas supply and purchase.

While the GACN is not itself a regulator, it interfaces with the Department of

Petroleum Resources (DPR)32

on the due diligence process it conducts on

buyers, demand rationing criteria and DSO management. The gas market

lacks a clear regulatory hierarchy as various organisations such as the

GACN, NGC, DPR and PPPRA33

all act as pseudo regulators to a greater

or lesser degree. It is hoped that the long-awaited Petroleum Industry Bill,

should it be eventually passed by the Legislature, will clarify the situation.

Figure 31: Operations of the Gas Aggregation Company of Nigeria

Source: CSL Research, GAGN

GBI: Gas-Based Industries LDC: Local Distribution Companies. Domestic sellers of gas to commercial and manufacturing companies.

32

Part of the Ministry of Petroleum Resources. 33

Petroleum Products Pricing Regulatory Agency

GACN

Power Sector Price

GBI Sector Price

LDC Sector Price Supplier 3

Supplier 2

Supplier 1

Ag

gre

ga

te P

ric

e

Cash Flows

Gas Flows


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Gas Flaring – Financial Waste & Environmental Scourge

In the current operating environment natural gas in Nigeria is essentially a

by-product of extracting crude oil. In 2011, having flared or vented 620 BCF

of natural gas, Nigeria was second only to Russia, a country that produces

over 10 times as much gas as Nigeria. There was slight improvement in

2012 when Nigeria claimed the no.3 spot, having flared 587 BCF of natural

gas. This amounted to 23% of gas extracted in 2012.

It is estimated that flaring gas costs Nigeria between US$2.5-3.0 billion a

year in lost direct revenues. Thus by reducing flaring to a minimum, the

Nigerian gas industry can be self-funding vis-à-vis the investment in

infrastructure that is required to bring the infrastructure up-to-scratch34

.

Chart 23: World’s Top Gas Flaring Countries, 2012* Chart 24: Nigeria Gas Production vs Flared, 2012

Source: US EIA, CSL Research

* Mexico, Kazakhstan, Brazil & Germany = 2011

Source: NNPC, CSL Research

Financial Loss

The real cost of gas flaring to the economy is greater if we include loss of

opportunity and production losses from the lack of gas supply to power

plants. We have used another proxy to indicate the extent of

financial/opportunity ‘waste’ resulting from flaring gas. We look at the ratio

of carbon dioxide (CO2) emissions from flaring alone to carbon dioxide

emissions from both consumption (a productive activity) and flaring. If we

compare Russia and Nigeria, both are responsible for about 14% of world

CO2 emissions from flaring gas. However, CO2 emissions from flaring

represent just 3% of Russia’s total CO2 emissions from both consumption

and flaring of natural gas. Russia at 3% compares to Nigeria at 75% (Chart

25).

34

Estimated at US$1.5-2 billion over the next five years.

646620

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8865 62 55

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26.3% 27.7%

24.3%25.8%

22.7%

0%

15%

30%

45%

0

500

1,000

1,500

2,000

2,500

3,000

2005 2006 2007 2008 2009 2010 2011 2012

Billio

n C

ubic

Fe

et (

Bcf)

Gross Production Flared/Vented % Flared/Vented


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Chart 25: Degree of Opportunity Loss from Flaring – ‘Productive’ CO2 Emissions (from Consumption) vs ‘Wasteful’ CO2 Emissions (from Flaring)

Source: US EIA, CSL Research

2011 Figures

3%

75%

9%

22%

91% 90%

1%

11%

5%10% 12%

6%2%

56%

90%

0%

20%

40%

60%

80%

100%

0

5

10

15

20

25

30

35

Russia

Nig

eria

Iran

Venezu

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Iraq

Ang

ola

US

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ic T

onnes

CO2 f rom f laring % CO2 f rom f laring vs. Total CO2 f rom consumption and f laringCO2 from Flaring CO2 from Flaring vs. Total CO2 from Consumption & Flaring


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Environmental Cost

The financial cost to a country of flaring is one thing but the overall cost to

the country is far higher. A more holistic approach would include the

environmental cost by way of air pollution, carbon emissions etc. Without

any suitable carbon-capture technologies in place, Nigeria also ranks high

in carbon dioxide emissions from flaring (Table 20).

Table 20: Carbon Dioxide Emissions from Gas Flaring, 2011 (MMT)

World Rank

CO2 Emissions from Flaring

1 Russia 31.2

2 Nigeria 31.1

3 Iran 30.6

4 Venezuela 17.3

5 Iraq 17.0

6 Angola 12.7

7 United States 11.7

8 Indonesia 9.6

9 Mexico 8.1

10 Algeria 7.1

11 Qatar 5.4

12 Brazil 3.2

13 Canada 3.0

14 Congo (Brazzaville) 2.7

15 Cameroon 2.7

WORLD 224.9

AFRICA 64.0

Source: US EIA

MMT – Million Metric Tonnes

Pragmatism on Green Electricity and the Environment

Having consideration of the environmental impact of any industrial activity

has become as critical as the evaluation of the economics. So much so that

major finance institutions such as the World Bank, the IMF and the African

Development Bank will not support a project without an environmental

impact assessment report. Nigeria, in looking to make more constructive

use of its gas reserves and reduce flaring, improves its environmental

awareness credentials significantly.

We acknowledge that thermal power generation is far from being carbon-

neutral, however it causes less environmental damage than flaring gas.

The thermal generating plants in situ and those planned are open-cycle gas

turbine (OCGT) plants rather than combined-cycle gas turbine (CCGT)

plants largely due to the fact that CCGTs have higher construction costs35

.

However it is anticipated that over time many will be converted to CCGT

plants as these are more energy efficient and have less impact on the

35

See Appendix 5: OCGT and CCGT Power Plants, page 189.


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environment. The advantage of having efficient electrical power supply to

households is easy to appreciate as it would alleviate the need to burn

biomass for light and heat. There are also benefits to industry by making it

more energy-efficient.

It is still early days and there are more ground-level activities to address

regarding power generation. Notwithstanding we consider it commendable

that the FGN’s plans have integral yet pragmatic considerations for

reducing the carbon footprint of the power industry. Renewable energy

such as solar power, wind and small hydro have dedicated resources at the

federal level to support and encourage the expansion of this sub-sector

under the aegis of the Federal Ministry of the Environment. We believe that

the incorporation into MYTO II of a specific tariff schedule for electricity

generation from renewables is a firm indication of the FGN/NERC’s long-

term commitment to green electricity.

Figure 32: Gas Processing and Transport in Nigeria


LPG – Liquefied Petroleum GasNGL – Natural Gas Liquids

Central Gas

Processing Facility

Gas processed and treated to remove

impurities

Gas

Compressor

Station

Gas

Compressor

Station

Gas, other hydrocarbons and impurities

extracted

LPG

&

NGL

Wet Gas

Ships

Trucks

Power Plants

Domestic

Buyers

LPG Storage

Gas Transmission Line

Dry Gas

Lean

Gas

Gas

Wells

Wet Gas


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Chapter 10:

The Privatised Power Sector

The Nigerian Electric Power sector has now been privatised to the extent

planned. The new owners took control of the Successor GenCos and

DisCos on 1 November 2013. But for nominal (non-participatory)

holding stakes retained in some GenCos and DisCos, the FGN is

effectively out of the power generation and distribution business. It

only maintains control over transmission system operation and market

operation, for now. Ideally, the FGN would have preferred to privatise the

entire electric power supply value chain and just retain regulatory oversight

and monitoring. However for a number of reasons, some alluded to in

previous chapters and others to be elaborated on in those ensuing, the

FGN has had to settle on privatising just the PHCN DisCos and GenCos

and, it hopes soon, the NIPPs.

Figure 33: The Privatised Nigerian Electricity Supply Industry


Credit Where and When Due

In our view it is already an achievement that long-held vaulted plans to

privatise the PHCN GenCos and DisCos per se have been seen through. In

any context privatising a state utility is no small feat. Irrespective of the

motives behind ‘allowing’ this attempt at reform (for there have been many)

to get as far as it has, it is a sine qua non that realism and pragmatism

enabled the FGN to see the raiment-less emperor NEPA in the bare state it

was. It is only from such a point that a workable plan could be devised.

NIPPsSuccessor

GenCos IPPs

Successor DisCos

TCN NBET

Private

Generators

Private

GeneratorsPrivate

Generators

EmbeddedGeneration

IPP

Distribution Licence Holder


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Leadership and Intellectual Capital Responsibility

Unlike the case of mobile telephony, it was impractical to start the entire

electricity system of the country from scratch. Transforming a moribund

industry into one with the culture, systems and technology fit for the twenty-

first century was going to require unwavering commitment and intellectual

brawn. Any hope of success in privatising the electricity sector was/is

dependent on getting the right professionals in to oversee the process and

to lead the new institutions. In our estimation, and gauging by the opinions

of numerous industry stakeholders we have canvassed, the FGN has done

well in this regard.

The intellectual and professional capital of key institutions like the regulator

NERC, NBET and TCN has been bolstered by recruiting skilled leaders

from within the domestic power industry and also from outside the domestic

market. However we have reservations about the amount of political

interference that could come from the country’s Executive and Legislative

arms going forward. Our concerns particularly relate to NERC and TCN.

The degree to which these two institutions are left to carry out their

statutory roles independently and for the benefit of all the

stakeholders in the electricity market and they actually do so, is the

degree to which the privatised industry will endure, will be efficient

and will be profitable.

The Privatisation Process – What, When & How?

The FGN sold 60% stakes in 11 successor DisCos to the private sector

raising US$1.46 billion. It also sold between 51-100% stakes in 5 successor

thermal GenCos and awarded 15-year concessions for 2 successor

hydroelectric power plants, raising US$1.65 billion.

Purchasers of Successor GenCos and DisCos

Table 21 and Table 22 below give the names of the winning bidders for the

successor GenCos and DisCos respectively. We expand these tables with

the salient details of the privatisation in Table 21 and in Table 22 at the end

of this chapter. In the tables we include the parties within the winning

consortia and have sought to identify, as far as possible, key individual(s)

connected with each of the winners.


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Table 21: Purchasers of Successor DisCos

Successor DisCo Purchaser Bid

(US$ mn) Stake

Acquired Distribution

(GWh)

Abuja Electricity DisCo KANN Consortium Utility Co. Ltd. 164.0 60% 1,802

Benin Electricity DisCo Vigeo Power Consortium 129.0 60% 1,855

Eko Electricity DisCo West Power & Gas Consortium 135.0 60% 1,440

Enugu Electricity DisCo Interstate Electric Consortium 126.0 60% 1,920

Ibadan Electricity DisCo Integrated Energy Distribution & Marketing 169.0 60% 1,989

Ikeja Electricity DisCo NEDC/KEPCO Consortium 131.0 60% 2,077

Jos Electricity DisCo Aura Energy Ltd 82.0 60% 714

Kaduna Electricity DisCo Northwest Power Ltd. 201.0 60% 1,233

Kano Electricity DisCo Sahelian Power SPV Consortium 137.0 60% 788

Port Harcourt Electricity DisCo 4Power Consortium 124.2 60% 1,164

Yola Electricity DisCo Integrated Energy Distribution & Marketing 59.3 60% 265

Source: BPE

Table 22: Purchasers of Successor GenCos

Successor GenCo Purchaser Bid

(US$ mn) Stake

Acquired Installed

Capacity (MW)

Afam Power Taleveras Energy Group 260.1 60% 776

Egbin Power NEDC/KEPCO Consortium 407.3 70% 1,320

Geregu Power Amperion Power Distribution Co. Ltd 132.0 51% 414

Kainji Hydro Electric Mainstream Energy Solutions Ltd. 237.9

A 15-yr concession, the fee structure being: 1) A commencement fee

(the bid price); 2) Yr1-Yr5 – a royalty

payment of 5% of plant annual revenues;

3) Yr6-Yr15 – a fixed annual fee US$50.8mn. 760

Sapele Power CMEC/EURAFIC Energy Consortium 201.0 100% 1,020

Shiroro Hydro Electric North South Power Consortium 111.7

A 15-yr concession, the fee structure being:

1) A commencement fee (the bid price);

2) Yr1-Yr5 – a royalty payment of 5% of plant annual revenues;

3) Yr6-Yr15 - a fixed annual fee US$23.6mn. 600

Ugheli Power Transcorp Consortium 300.0 100% 942

Source: BPE


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Industry Agreements

In February 2013 the preferred bidders and the BPE signed Shareholders

Agreements and Share Sale Agreements. They also executed Industry

Agreements which serve as the framework for the fully-commercialised

power sector. The following have emerged as some of the key documents

which will need to be in place and bankable for power sector financings:

Share Sale Agreements (DisCos and thermal GenCos)

Concession Agreements (Hydro GenCos)

Gas Supply and Aggregation Agreements

Gas Transportation Agreements

Power Purchase Agreements (GenCos; 15 year duration): capacity

and energy payments are broken into Naira and US Dollar

components. The foreign components are payable in naira at the

prevailing exchange rate.

Vesting Contracts (DisCos; 15 year duration)

Transmission Use of Network System Agreements

Grid Connection Agreements

Ancillary Services Agreements

Bulk Trader Credit Support

Deed of Assignment of Pre-Completion Receivables

Operations and Maintenance Agreement

Pre-Completion Liabilities Transfer Agreement

Future Performance Evaluation and Monitoring

The Nigerian Electricity Supply Industry (NESI) is now fully regulated.

NERC is charged with overall regulation and issuing of licences for

participants in the sector. The BPE is the FGN’s signatory to the

agreements with the new owners of GenCos and DisCos. The documents

that govern the monitoring and regulatory frame work are in Table 23.


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Table 23: NESI Monitoring and Performance Evaluation Documents

Governing Document Scope

Share Sale and Purchase Agreement (SSPA)

Terms and conditions of sale of shares to investors

Performance Agreements (PA) Contains terms of payment and Post-Acquisition Plans (PAP) implementation

BPE's Post Privatisation Monitoring Template

NERC's Reporting compliance Regulation

Outlines the level of compliance and standards expected of utilities

NERC's Terms and Conditions of Licensing

Sets out mandatory requirements for acquiring a licence and penalties for breach of terms.

Source: BPE

Post-privatisation monitoring by the BPE was expected to start in May

2014. But as TEM has not yet been declared, it is not likely that the full

scope of performance monitoring under the regulatory powers given to the

BPE and NERC will be in effect.

The Performance Agreement (PA) is the main document empowering the

BPE in its monitoring function. Compliance monitoring gives the BPE the

right to enter and monitor the privatised companies every six months upon

giving five days notice of such action. It also gives it the right to audit or

review the businesses every six months.

Performance Obligations Under the PA

General

The intent of these general provisions in the PA is to ensure that the

investor is held to the spending plans. The BPE retains these rights to

ensure that the development of the NESI remains on target. From a public

policy perspective, we consider this to be a shrewd arrangement by the

BPE/NERC given the FGN will no longer have direct control of the GenCos

or DisCos and will not be contributing any capital pro rata to its retained

stakes36

. Some general provisions of note include:

The investor must ensure the purchased DisCo or GenCo achieves the

Minimum Performance Targets;

The investor is liable to pay liquidated damages for performance falling

below the stipulated standard;

36

Thus in the case of any further capital raising by the GenCo or DisCo in which the FGN has retained a stake, the FGN’s holding with be diluted.


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The investor must comply with the initial budget and Post-Acquisition

Plans (PAP) set out in the Performance Agreement, to which they

agreed to enter when they signed the SSPA.

For the first 5 years, annual revisions to budgets and plans require the

consent of the BPE and thereafter the BPE reserves the power of veto

over certain expenditures;

The investor is not allowed to take on senior debt without the prior

consent of the BPE, which shall not delay or unreasonably withhold

consent. This provision is included to safe-guard against the Successor

Companies being laden down with debt;

The Debt to Equity ratio of the successor company cannot exceed

70:30 for the first 5-years. Thereafter it may only rise to 75:25;

Insurance cover must be maintained on the companies at all times;

Performance obligations are to be secured by Parent Company

Guarantee. In the case of a consortium, the parent company of the lead

investor is to provide the guarantee, subject to BPE approval in relation

to the technical and financial standing of the parent company.

Successor GenCos-Specific:

Successor GenCos’ capacities are expected to be increased from current

low available capacity levels to meet minimum target generation capacities

set out in the Industry Agreements.

Successor DisCos-Specific:

The performance of the business operations of the new owners of the

successor DisCos will be measured on the basis of their abilities to reduce

distribution losses to loss targets specified in their business plans. They will

also have targets for expanding their distribution networks and in

connecting new customers.

ATC&C Losses

The Successor GenCos were sold to the highest bidder for the specific

GenCos. Bidders for the Successor DisCos, on the other hand, were given

the figure the FGN was going to sell the DisCo for and the evaluation of

bids was on the basis of the projected reduction in Aggregate Technical,

Commercial and Collection Loss (ATC&C Loss) over the first five years of

acquisition. The DisCo was sold to the bidder with the highest reduction in

ATC&C Loss.

The ATC&C loss figure is a key performance indicator for power distribution

companies. It enables operators to monitor efficiency and profitability in

delivery of power to customers. ATC&C Loss is the difference between the

amount (in MWh) of electricity received by the DisCo and the amounts


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billed and received from customers (in ₦). The difference in electricity

received by the DisCo and electricity it bills the customer gives the

technical and commercial loss, while the difference in the amount billed and

the amount received/collected from the customer gives the collections loss.

Thus reduction in these losses improves profitability.

Each bid contained a 5-year ATC&C Loss reduction schedule based on a

starting loss figure provided by PHCN. The winning bidder had the lowest

end loss level for that particular successor DisCo. The purchasers ATC&C

Loss figure is very important because the purchaser’s end level figure is

then incorporated into the MYTO model, as each DisCo has its own MYTO-

determined tariff plan. If the purchaser does not achieve the loss target, it

will be less profitable than it has planned, and vice-versa should the target

be exceeded (i.e. the end ATC&C Loss figure achieved turns out lower than

targeted). If the purchaser consistently fails to meet its loss-reduction

targets, NERC may decide to revise the purchaser’s capex allowance

amount under its DisCo tariff.

The ATC&C Loss targets of the winning bidders are shown in Table 24.

Table 24: Distribution (ATC&C) Losses and Loss Reductions

Successor DisCo

Winning Bidder

Opening Loss

Bidder's Yr 5 Loss

Bidder's Yr 5 ATC&C Loss

Relative to Opening Loss

Abuja DisCo

KANN

35.00%

12.78%

-36.51%

Benin DisCo

Vigeo Power

40.00%

12.19%

-30.48%

Eko DisCo

West Power & Gas

35.00%

12.76%

-36.46%

Enugu DisCo

Interstate Electric

35.00%

6.70%

-19.14%

Ibadan DisCo

Integrated Energy

35.00%

12.71%

-36.31%

Ikeja DisCo

NEDC/KEPCO

35.00%

9.99%

-28.54%

Jos DisCo

Aura Energy

40.00%

18.09%

-45.23%

Kaduna DisCo

Northwest Power

40.00%

11.70%

-29.26%

Kano DisCo

Sahelian Power

40.00%

13.02%

-32.55%

Port Harcourt DisCo

4Power

40.00%

14.90%

-37.25%

Yola DisCo

Integrated Energy

40.00%

17.34%

-43.35%

Source: BPE

India’s Tata Power Delhi Distribution Limited (TPDDL) is a joint venture between Tata Power and

the Government of the National Capital Territory of Delhi, with the majority stake being held by

Tata Power (51%). Tata Power acquired its stake following the unbundling of the Delhi Vidyut

Board (DVB) in 2002. As is the case for investors in Nigeria’s DisCos, Tata also had five-year

ATC&C Loss reduction targets. Its opening ATC&C Loss was 53% and its target was 31%. TPDDL’s

ATC&C Losses stood at 11% at the end of the 2012/13 financial year. This compares to a world

average of about 15%.


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Table 25: Successor DisCo 5-Year Capex*

(US$ million)

2014-18 Capex

Abuja DisCo

180

Benin DisCo

119

Eko DisCo

134

Enugu DisCo

215

Ibadan DisCo

112

Ikeja DisCo

147

Jos DisCo

149

Kaduna DisCo

222

Kano DisCo

288

Port Harcourt DisCo

125

Yola DisCo

64

Total

1,755

Source: NERC

* MYTO II Model assumptions.

NGN:USD rate of ₦160

Table 26: CSL Estimated* Successor GenCo Capex

Installed Capacity

(MW)

2011 Available Capacity

(MW)

Estimated Capex

(US$ mn)

Afam Power 776 45 796

Egbin Power^ 1,320 880 430

Geregu Power 414 361 37

Kainji Hydro 760 359 653

Sapele Power 1,020 135 959

Shiroro Hydro 600 393 319

Ughelli Power 900 228 721

Total 5,790 2,401 3,915

Source: BPE, CSL estimates

* Please note boxed commentary within the main body of the report. ^ Not included in 2011 BPE presentation. Figures from market sources.

- NOTE - There have been varying reports over the last few months of the level of Available Capacity (AC) of these successor power plants and it continues to be difficult to get precise figures. Now that the GenCos are under private ownership, for the time being at least, we expect the precise figures to be considered privilege between the operators and NERC/BPE. This is especially so given the sensitivities surrounding the delay in the declaration of TEM and the operation of the Interim Rules Period.

Notwithstanding, we wanted to have a rough sense of how much capex could be required to get each GenCo's Available Capacity close to its Installed Capacity, as this is a key performance requirement of the new owners set out in the Performance Agreements signed with the BPE.

At the 2011 Bankers’ Conference Workshop for the PHCN privatisation, the BPE provided the AC of each PHCN GenCo. We have based our calculations on this figure and used the MYTO II model’s level for AC of 95% as our target. Given the 2011 AC date, we caveat our calculated figures because the reality on the handover date may have been higher or lower for any of the GenCos.

We have assumed that each MW added for the gas-fired plants costs US$1.15 million based on the industry

yardstick of US$1-1.3 million of capex per MW. We have used the MYTO II estimate of US$1.8m per MW for

the hydro plants.


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Current Market Stage – Interim Rules Period

Figure 34: Key Characteristics of the Market Stages in the Evolution of the Nigerian Electricity Supply Industry


Interim Rules

Period

(IRP)

Pre-TEM

Stage

Transitional

Electricity Market

(TEM)

Medium Term

Market

Long Term

Market

Unbundling of NEPA/PHCN;

Privatisation of PHCN GenCos and

DisCos;

Review and

subsequent application of the

Market Rules and procedures;

Establishment of performance incentives and

performance standards for the

distribution and generation companies;

Payments and

settlements based on Shadow Trading and Transfer Pricing;

NBET, TCN and

PRGs not yet operational;

TEM was expected to start at the end of January 2014. However a number of factors

made NERC deem it necessary to delay the start of TEM and

introduce a set of Interim Rules.

Notable points on the IRP:

i. As contracts of the

privatisation such as PPAs and VCs only become fully enforceable once TEM is

declared, Successor GenCos and DisCos are expected to

continue with their Pre-TEM trading arrangements during the IRP.

ii.GenCos bill the Market Operator (MO) for electricity

generated and available capacity based on MYTO II

tariffs. However as Pre-TEM contracts apply, Transfer Pricing and Estimated Billing

is in operation.

iii.The MO continues to bill the DisCos for electricity.

iv.The MO determines the allowable amount of funding

(the Minimum Funding Requirement) for the Successor DisCos, Successor

GenCos and for the Service Providers including NERC, the

Transmission Service Provider (TSP) and the System Operator (SO).

NBET and TCN roles within NESI become effective/operational;

Contracts of privatisation

signed between Successor Companies and State institutions including Power

Purchase Agreements (PPAs), Vesting Contracts (VCs) and

Partial Risk Guarantees (PRGs) become effective;

Payments and settlements based on prices and terms

contained in PPAs and in VCs.

No centrally-administered

balancing mechanism for the market;

Development of procedures for the management of inadequate

supply and shortage in the system;

Open access to the transmission network to

GenCos and DisCos.

Wholesale Electricity Market will be the balancing market for trading electricity in the

industry. It will be characterisedby a spot market where

electricity prices are set daily.

DisCos and GenCos will be

permitted to enter bilateral contracts for the purchase

and/or sale of electricity.

Open entry to the transmission

network to GenCos, DisCos and large power consumers. All

subject to technical and environmental obligations, and overseen and licensed by the

regulator NERC.

Retail competition - all consumers choose their suppliers;

Clear differentiation between

distribution (delivery) and retail activities;

Open access to the transmission and distribution

networks.


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Table 27: Pre-TEM and TEM Characteristics Compared

PRE-TEM TEM

Transmission, Distribution and System Operations retain their monopoly and regulated status during Pre-TEM and TEM.

Market Structure

Sellers:- Sellers:-

- Successor GenCos - Successor GenCos

- IPPs with PPAs - IPPs with PPAs

Buyers:- Buyers:-

- Successor DisCos - Successor DisCos (also licensed as marketers)

- International connections - International connections/customers

- Local large power consumers - Local large power consumers

Service Providers:- Service Providers

- TSP - TSP

- ONEM Market Operator - NBET

- System Operator - TCN System Operator

- Central (Headquarter) Services - TCN Market Operator

Pricing Regime

Transfer Pricing Vesting Contract and PPA Prices

Successor GenCos and IPPs sell to Successor DisCos

- Successor GenCos sell at Transfer Prices calculated every 3 months

- IPPs sell at their PPA prices

Buyers:-

- Successor DisCos buy at Transfer Prices

- International connections buy at prices in their Connection Agreements.

- Local large power consumers buy at regulated end-user tariffs

Service Provision

TSP TSP

- Provides transmission access to both GenCos and DisCos - Provides transmission access to both GenCos and DisCos

- Recognises and accounts for transmission losses - Recognises and accounts for transmission losses

ONEM Market Operator NBET

- Commercial administration of the market including settlements and payments using Market Rules

- Commercial administration of the market including settlements and payments using Market Rules

System Operator TCN System Operator

- Technical administration of the market using the Grid Code and provision of other services for grid stability.

- Technical administration of the market using the Grid Code and provision of other services for grid stability.

Central (Headquarter) Services - Pricing of transmission access

- Provides common services such as funding of special projects, emergency funding

Payment &

Settlement System

Market does not always balance Market in equilibrium - a debit by a DisCo has a

corresponding credit to a GenCo therefore NBET maintains a zero balance.

Shadow Trading Wholesale Electricity Market Trading

- MO receives payments into its market clearing account from DisCos and eligible customers

- NBET receives and transfers payments between GenCos and Successor DisCos

- Existing IPPs sell through PPAs with NBET

- MO transfers payments to GenCos and service providers - New IPPs may contract to sell either to NBET or with the DisCos directly

Settlement Settlement

- Per individual settlement calendar - Market settlement each month (M) for each DisCo

- DisCos sell at uniform prices and use estimated billing - Monthly payment (M+1 month)

- IPPs sell at PPA prices; Successor GenCos at various Transfer Prices .

Payment Payment

- Payment made into escrowed settlement accounts

- DisCos submit a Letter of Credit covering three months of payments to be drawn down (plus interest) in the event of non-payment by the DisCo.

- Based on Minimum Funding Requirement determined by the MO - Incomes in line with MYTO II Revenue Requirement provisions

- The Transfer Price is expected to cover the budget for operating costs only.

- Per MYTO II, capital costs and return on investments can also be recovered.



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PART III – The Investment Case


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Chapter 11:

Pitfalls and Opportunities

It is an indisputable fact that the supply/demand gap for power in a

country with a population of almost 170 million generating less than

4GW presents a prima facie investment opportunity. How the theory

(of the new regime) works in practice is the crux of the investment

case for the Nigerian power sector.

As with any such sector-wide endeavour, stakeholders (investors,

customers etc) and other commentators need to make allowances for the

journey not going entirely smoothly. This is not a Nigerian phenomenon

but is to be expected in the implementation of corporate or industry-wide

strategy the world over. The concern and hope is that these bumps

amount to minor, surmountable hiccoughs.

We ultimately want to identify where the equity is in the new sector and

assess how much funding is available to make the required investments.

This involves an initial evaluation of the main risks in the Nigerian

Electricity Supply Industry. We have grouped the risks methodologies

adopted and operating procedures in the NESI Financial and Systemic

Risks. The latter not least highlighted by and revealed in the Interim

Market and the delay in the declaration of the Transitional Electricity

Market (TEM). We then analyse the Structural Risks of the industry.

NERC

END-USERS

GAS

SUPPLIERSGENCOS

FGN

FINANCE

MARKETSTCN /

NBET

DISCOS


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Chapter 12:

Financial Risks

We will address two core financial risks in this chapter:

1. The skewness of risk allocation amongst counterparties;

2. Critical problems with MYTO II, which in practice results in a

tariff structure that is not commercially sustainable as it

currently stands.

Network Risk Allocation Skewed Against Discos

NERC insists that the pricing structure is set so that it spreads the risks

equitably among the users of the transmission network. It is intended to

assign the costs or charges to “the user or group of users incurring those

costs”37

. At the same it states that the rationale on risk allocation is that

the “pricing arrangements should allocate risks efficiently [which implies]

generally to those who are best placed to manage them.”38

These two phrases may strike one as incompatible because they both

claim to be the premise on which the transmission tariffs are set and load

allocated, yet on interpretation they could lead to different results. One

purports to allocate costs to the user(s) incurring the cost and yet for the

second to also hold true, it implies that costs are incurred by those best

placed to manage them. This is not necessarily the case.

If we then look at how this has worked in practice, in MYTO II the bulk of

the cost of the transmission network (build, management and

maintenance) is charged to the DisCos – 80% of the TUOS charge is

borne by the DisCos. It is not immediately apparent why:

(a) 80% of the cost of getting the energy from the generator to the

distributor/retailer should be incurred by the DisCo and/or

(b) the DisCo is considered to be better placed and more efficient than

the GenCo to manage transmission costs.

All these costs are ultimately passed onto the end-user, so it could be

said that neither GenCo nor DisCo are disadvantaged. However from a

cash management and capital structure perspective, to say the least, it

does matter. It has implication for the risk exposure of the businesses

hence their cost of capital and returns profiles.

37

NERC Multi Year Tariff Order for the Determination of the Cost of Electricity Transmission and the Payment of Institutional Charges for the Period 1 June 2012 to 31 May 2017 (herein after ‘MYTO II – Transmission’); p.19. 38

MYTO II – Transmission, p. 17.


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According to NERC, if GenCos were to be exposed to connection

charges, they would be more likely to choose locations that minimise

these charges. NERC contends that this could be detrimental to the even

distribution of access to electricity across the country.

GenCos Not Let Off in Entirety

NERC asserts that GenCos have an incentive to reduce the losses

associated with transmitting their generated energy. GenCos have limited

ability to effect improvements in transmission losses (and by equivalence

Marginal Loss Factors, MLFs). We believe the incentive to improve this is

limited since they do not bear the cost of system transmission loss. They

can minimise the losses associated with transmission up to their network

node connection point, however it is on a de minimis scale when

considering the vast bulk of transmission occurs after title/responsibility

passes from them at their node connection.

DisCos essentially pay for transmission losses however they too have no

means of reducing these losses. They are not in control of the spending

to improve and extend the transmission network even though they

provide the financing (through the TUOS charge).

Under the terms of the PRG, NBET/TCN bears the risk of Availability

Events. It essentially guarantees transmission. We understand the full

implication of this, in light of the realities of the market post handover,

might be weighing heavy on the FGN. Current negotiations,

renegotiations and discussions during the Interim Rules Period may well

be seized upon to adjust the blanket guarantee. However we believe this

would send a very negative signal to the market as it smarts of an

inclination of the FGN shifting the goal posts after the fact.

The MYTO II Powder Keg

We have analysed the methodology and assumptions used in the MYTO

II models for generation, transmission and distribution. In Chapter 5: we

talked about the theoretical soundness of the methodologies used and

pointed to similar examples in other electricity markets.

It goes without saying that the utility of a financial model is only as

good as the assumptions plugged into it. We have found the MYTO

II model does not stand up to scrutiny in this regard. The

components of the gun powder we have identified which we discuss in

detail next are:

A. Generation Technical Assumptions

(i) Available Capacity Factor assumptions need to be more conservative

(ii) Construction period for Large Hydro is too ambitious

(iii) Plant Availability needs to be lowered

(iv) Fuel cost assumption is too low

B. Miscalculation of Wholesale Prices leaves GenCos short

C. Transmission Capex is insufficient for actual requirements

D. Distribution ATC&C Losses assumptions are too low


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MYTO II Generation Technical Assumptions

The technical assumptions of GenCos are set out in ‘Table 1: Technical

Characteristics of New Entrant Plants – 2012’ of the MYTO document on

the determination of the generation tariff published by NERC on 1 June

2012. We have reproduced it below and discuss our findings:

Figure 35: MYTO II Generation – Technical Characteristics of New Entrants

Source: NERC, Multi-Year Tariff Order for the Determination of the Cost of Electricity Generation for the Period 1 June 2012 to 31 May 2017, ‘Table 1: Technical Characteristics of New Entrant Plants – 2012’, p.20.

The industry rule of thumb for construction costs of an OCGT plant is approximately US$ 1 million per megawatt (i.e.

US$1,000 per kilowatt). Hence this Unit should be per kW and not per kWh (kilowatt hour). Otherwise it would mean

NERC assumes that a 250 MW OCGT plant costs over US$ 2 trillion! (250 MW = 2.19 billion kWh)

As far as the calculations in the MYTO financial model is concerned, after analysing the calculations in the MYTO

financial model, we can confirm that the effect of this particular typographical error turns out to be merely cosmetic.

However, as we illustrate in Table 29 page 126 and Table 30 on page 127, other typographical errors led to a significant

miscalculation of the Revenue Requirement. This is notable because it is the (purported cost-reflective) Revenue

Requirement from which tariffs are set.


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(i) Available Capacity Factor Assumptions Need To Be More

Conservative

We have compared MYTO II plant Available Capacity Factors (ACF) with

those from more established and efficient markets (see Table 28 below).

As a result, we believe those in MYTO II need to be more conservative.

ACF is sometimes referred to as ‘Available Capacity’ or ‘Capacity Factor’

(as in the MYTO II financial model; item #5 in the MYTO table shown in

Figure 35). There is an inverse relationship between the ACF and the end

tariff. So MYTO assumes that as the ACF of plants increases, the end-

user tariff should decrease. This is not a one-for-one proportional

relationship as there are several other technical variables that also affect

the end-tariff and/or also affect each other.

Table 28: Comparison of Capacity Factors (Available Capacity)

Natural Gas Hydro Coal Comments

US 43% 40% 64% ‘Best In Class’ gas thermal plants have ACFs over 90%.

The inference from the MYTO II Capacity Factor assumptions for the gas plants is that they are akin to base load plants running at or very near full capacity (i.e. nameplate capacity). While this might not be such a stretch in situations where demand far exceeds supply, it is not a reasonable or realistic assumption in a situation like Nigeria’s where lack of maintenance, equipment inefficiencies and gas and transmission infrastructure issues result in a lot of downtime.

The world average for Hydro is 44% but the spectrum is wide (10-99%) due the variations in plant design. A small hydro plant in a small river, or one with a sufficiently large dam reservoir will always have enough water so won’t suffer downtime from fuel supply issues.

UK 57% 34% 45%

MYTO II Successor GenCos

65% New Entrants

85% 65% 70%

Source: NERC, US EIA (2009), UK Dept. Of Energy & Climate (2007-2012 Averages)

The seemingly low ACFs for UK and US gas plants are due to the number and variation of participants selling electricity in their open-traded wholesale markets. Electricity is offered for sale from power generating installations that use various fuels – nuclear, gas, coal, wind, solar, etc. The running costs of these generators vary and at a particular time it might not be economical for a particular plant to produce electricity at its optimal (possible) ACF level. Typically, those with the lowest running costs can offer the best prices but the major determinants of price are ultimately supply and demand and any regulatory price controls that might exist.

Available Capacity Factor = Actual Plant Output (in MWh)

Theoretical Nameplate Output (MWh)

Hence the ACF of a 1,000 MW plant generating 648,000 MWh of

electricity in 30 days, for example:

= 648,000 MWh

1,000 MW × 24hrs ×30 days

= 0.9 = 90%

Available Capacity Factor is the

ratio of the actual output of a

power plant over a period of time

versus the theoretical power

output were it possible to run the

plant at nameplate/installed

capacity indefinitely. Equipment

availability characterises the

operating reliability of the plant.


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(ii) Construction Period for Large Hydro Plants Is Too Ambitious

The construction period for Large Hydro plants is set at 4 years, just a

year longer than the construction period assumed for small hydro plants

under the feed-in tariff plan. The norm in most markets is a construction

period of 5-7 years.

(iii) Plant Availability Needs To Be Lowered

Plant Availability is the percentage of time the plant is available to

generate electricity over a period of time. It is affected by a plant’s

Available Capacity (AC)/Available Capacity Factor (ACF).

The MYTO II model sets Plant Availability at 95% of AC for both

successor and new entrant thermal plants. Most gas thermal plants have

high Plant Availability, about 80-99%. The new plants are more likely to

have such a high figure, but this is very unlikely for the Successor

GenCos. Furthermore the figure assumes that plants will not suffer fuel

supply or transmission issues that would effectively make them

unavailable even though technically they might be able to produce

electricity (at their ACF level), as is currently being faced by Successor

GenCos.

(iv) Fuel Cost Assumptions Are Too Low

The gas price is based on the regulated price for both the successor

GenCos and new entrant GenCos (Chart 26). In our view this is not a

plausible assumption for a number of reasons starting with the fact that

the current market price of gas is about US$3 per MMBtu39

:

The DSO price as incorporated in the successor GenCos’

privatisation GSA’s only applies to the Available Capacity at the

time of sale. There was a wide variation in ACs but the average

for the gas-fired plants was c.40%. Thus using MYTO II’s ACFs

of 65% the successor GenCos will need to buy gas for 35% of

their output at the market price.

The IPPs/new entrants do not benefit from the DSO price but buy

at the market price.

39

Million British Thermal Units.


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Chart 26: MYTO II Gas Price Assumptions vs Market and DSO Prices

Source: NERC, CSL estimates

Miscalculation of Wholesale Prices Leaves GenCos Short

The most significant problem we have found with the MYTO II model

stems from a miscalculation of the Capacity Charge component of the

Wholesale Generation price. On its own, not taking into account any of

our aforementioned adjustments in underlying assumptions, this error

resulted in the calculated tariff being c.30% lower that it should

been. This error affects successor gas GenCos, new entrant gas GenCos

(IPPs selling electricity to the grid), new entrant coal plants and successor

hydro plants.

Instead of calculating the Capacity Charge on the basis of naira per MW

per Hour, the model used naira per MW per Month. Table 29 and Table

30 show the MYTO II figures and the corrections which converts the ₦

per MW/month charge into ₦ per MWh by dividing the former by the

number of hours in a month.

Table 29: Miscalculation in MYTO II Model Underquotes Capacity Charge Tariff by c.30% - Successor Gas GenCos

Units 2012 2013 2014 2015 2016

MYTO II Capacity charge ₦'000/MW/month 3,515 3,789 4,084 4,403 4,747

MYTO II Energy charge ₦/MWh 5,389 5,758 7,290 7,944 8,658

MYTO II Wholesale contract price ₦/MWh 9,563 10,257 12,140 13,172 14,296

CORRECTION – MWh not MW/month Units

Capacity charge ₦/MWh 4,812 5,187 5,590 6,027 6,498

% Underestimation of Tariff -27% -27% -27% -27% -27%


1.80 1.802.30 2.37 2.44

1.531.84 2.05

2.56

3.58

0.00

1.00

2.00

3.00

4.00

2012 2013 2014 2015 2016

US

$/M

MB

tu

MYTO II price DSO price Avg. current market price


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Table 30: Miscalculation in MYTO II Model Underquotes Capacity Charge Tariff by c.30% - New Entrant Gas GenCos

Units 2012 2013 2014 2015 2016

MYTO II Capacity charge ₦'000/MW/month 4,359 4,701 5,071 5,470 5,902

MYTO II Energy charge ₦/MWh 5,568 5,951 7,499 8,169 8,902

MYTO II Wholesale contract price ₦/MWh 10,743 11,534 1,350 14,665 15,910

CORRECTION – MWh not MW/month Units

Capacity charge ₦/MWh 5,967 6,435 6,942 7,488 8,079

% Underestimation of Tariff

-27% -27% -27% -27% -27%


Allocation for Ancillary Services is Grossly Inadequate

The MYTO Model only allocates 1.5% of revenues of the system to

Ancillary Services. In an electrical system at the stage of development

that Nigeria’s is, at a bare minimum 10% of revenue needs to be put

towards Ancillary Services. Thus the under-provision understates the

Revenue Requirement of the sector.

Ancillary Services consist of system capacity allowances vital to the

stability of the entire electrical network. They include:

Spinning Reserves: This is back-up energy production capacity which

can be made available to the system operator (for transmission) within

ten minutes of a power system failure and can operate continuously for at

least two hours once brought online. It is done by increasing the power

generation output of power plants already connected to the system.

Voltage Support: This is used to maintain the voltages in the

transmission system within a secure, stable range. It is an essential

service for the security of equipment and people. Its proper management

ensures cost and operational efficiency of the transmission system.

Black Start Capability: It is the process of restoring a power plant to

operation without relying on power from the grid in the event of a major

system collapse or system wide blackout. In the event of a power

blackout, black start system capability is critical.

Transmission Capex Insufficient for Actual Requirements

Capital expenditure on transmission feeds into the TUOS charge

component of the tariff however MYTO II only assumes ₦56 billion

(US$350 million) per year for the capital which is less than a quarter of

The Roadmap’s (and the industry’s) estimate of US$1.5 billion per

year over the next five years.


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In the Transmission Tariff Order, NERC expressed reservations with the

capital expenditure figure initially provided by the then management of

TCN when MYTO II was being prepared. So much so that it rejected the

figure presented on the basis that TCN’s management had not be able to

justify its projected figures to NERC’s satisfaction. As a result, NERC

nominally included the ₦56 billion figure in the MYTO II Model in the

expectation that when Manitoba Hydro International took over the reins at

TCN, they would be able to provide and justify capex projections.

Distribution ATC&C Losses Assumptions Too Low

The starting point for Aggregate Technical, Commercial and Collection

Losses assumed in the Model is too low based on the Opening Loss

levels given by the BPE. The figures provided by the BPE are the levels

on which bidders for DisCos were to benchmark their 5-year ATC&C Loss

reduction targets in 2013 (Table 31 and Table 32).

It has transpired that the reality faced by the new owners of the DisCos

upon taking control of operations was far worse than the BPE figures.

This is discussed in detail in Chapter 13: Systemic Risks (page 129).

Table 31: MYTO II ATC&C Loss Assumptions Table 32: Opening ATC&C Losses

(GWh) 2012 2013 2014 2015 2016

Successor DisCo Opening Loss

Energy received 26,830 36,587 44,201 49,128 51,568

Abuja 35%

Energy billed to customer 21,249 29,964 37,412 42,948 45,560

Benin 40%

Energy sales collected 19,975 28,766 36,664 42,089 44,649

Eko 35%

Agg. Tech. & Commercial Loss 21% 18% 15% 13% 12%

Enugu 35%

Collections Loss 6% 4% 2% 2% 2%

Ibadan 35%

ATC&C Losses 26% 21% 17% 14% 13%

Ikeja 35%

Source: NERC

Jos 40%

Kaduna 40%

Kano 40%

Port Harcourt 40%

Yola 40%

Average 38%

Source: BPE

Discrepancy between the MYTO II Model and the BPE

Figures on which bidders for the Successor DisCos based

their ATC&C Loss reduction targets. Achievement of

these targets is one of the performance obligations of

the Successor DisCos and their Investors.


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Chapter 13:

Systemic Risks

We have identified three main systemic risks relating to:

1. Load allocation between the DisCos by the System Operator;

2. Implications of the delay in declaring the Transactional

Electricity Market (TEM) and operation of the Interim Rules

Period (IRP);

3. Legacy issues of the monitoring and reporting standards of

the old system; notably the discovery that the state of the

newly-acquired assets was worse than investors expected,

based on information provided to bidders in the Data Room.

Load Allocation Mechanism

Load allocation of the first 3,200 MW among the 11 DisCos is based on a

number of factors including projected demand. The limited amount of

energy available has necessitated the System Operator (SO) having a

system to ration between the DisCos. The DisCos will be evaluated and

scored on achievement of minimum customer service performance

standards and NESI Key Performance Indicators (KPIs). The criteria used

and their respective weightings are depicted in Chart 27.

While some of the criteria have more objective parameters than others,

there is still a significant degree of subjectivity in the evaluation criteria.

This is an area of concern, in our view, due to the potential for political and

other vested interests to use this an opportunity to create a bias in favour of

one or other DisCo. The political in-fighting that already has been

demonstrated over the Manitoba Hydro International matter and the

machinations surrounding the composition of the TCN board does not bode

well in our view.


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Chart 27: Weighting of Energy Allocation Evaluation Criteria

Source: NERC, CSL Research

IRP and Delay in Declaration of TEM

The winning bidders of the successor GenCos and DisCos were

announced in February 2013. These new owners were due to be handed

full control of the purchased assets on 1 November 2013 after which there

was to be a 4 month shadow-management period. In the months leading to

the handover, some stipulated conditions-precedent to declaration of TEM

(originally planned for October 1 2013) were still outstanding. So as not to

stall the handover of the Successor Companies to the new owners on

November 1, NERC developed a set of Interim Rules to govern the market

in the pre-TEM, post-handover market. The Interim Rule Order (IRO)

committed to a maximum duration of the IRP of 3 months. The IRO was

issued in December with retroactivity to November 1.

The 3-month deadline has come and gone and the market continues to

operate under Interim Rules with no firm indication on when it will end and

TEM will begin. The prolongation of the IRP creates several problems for

the new owners of the Successor Companies because:

1. The expected, unbundled market with NBET and TCN as the link

between GenCos and DisCos is yet to become effective. There is little

difference operationally between the previous vertically-integrated

PHCN market and the status quo. A no-man’s land post-handover is

not what investors and the market subscribed to;

2. The no-man’s land situation has been compounded by discoveries

made by the new owners relating to the state of the assets themselves

and concerns raised over the validity of certain agreements central to

the privatisation.

35%

30%

15%

15%

5% — Reduction of losses

— Attainment of metering targets

— Customer service ratings based onbiannual customer surveys

— Achievement of distribution networkexpansion targets

— Distribution Capacity


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No-Man’s Land Suffocates Cash Flow Management

While the bidders of the Successor Companies were not permitted to use

the target company’s assets as surety to raise funds for the bid process,

they were permitted to secure contingent finance against the cash flows.

The anniversary for repaying these loans is in August 2014.

Operation of the Interim Rules

At the heart of the matter, the operation of the IRO itself can negatively

impact the sustainability of the NESI. Clause 3 of the IRO states that:

During the Interim Period, PPAs and Vesting Contracts executed by

the Successor Companies shall not be effective.

This has profound implications for cash flows expected by the owners of

the Successor Companies, not least:

i. Ultimately it means that the Successor Companies cannot raise the

project or corporate finance to fund capex and their operations as

expected because banks will only lend to them if they have

bankable PPAs, Vesting Contracts, GSAs, etc which underpin

their respective business plans.

ii. The MO handles settlements as before. The MO invoices and receives

payments from Successor DisCo on behalf of Successor GenCos and

IPPs. In the event that DisCos do not pay invoices in full, GenCos do

not get full payment but are settled based on an ‘Allowable Revenue’

formula to arrive at a ‘Minimum Funding Requirement’.

Table 33: Allowable Revenue During the Interim Rules Period

The adjustments made to the Revenue Requirement (RR) that underpins MYTO II for the MO to arrive at the allowable amount of funding are as follows:

DisCos

Fixed and variable costs 20% of MYTO II revenue requirement

Admin costs 100% of MYTO II revenue requirement

Return on Capital 50% of MYTO II revenue requirement

Depreciation 10% of MYTO II revenue requirement

GenCos

Energy charge 100% of energy generated and supplied to grid

Capacity charge 45% of Available Capacity

Those that have existing PPAs which would have been operational during the IRP will have any difference reimbursed once TEM is declared.

Other Service Providers

TSP 70% of MYTO II market revenue

NERC 70% of MYTO II market revenue

MO 60% of MYTO II market revenue

SO 60% of MYTO II market revenue

NBET 20% of MYTO II market revenue

Source: NERC


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iii. NBET, purportedly, is meant to make up for any shortfalls in PPA

amounts for GenCos (IPPs and Successor GenCos) “that have

effective PPAs during the Interim Period”. We believe this to be at best

an ambiguous provision because ‘Effective Contracts’ for the purpose

of the IRO are those that for which all conditions-precedent have been

met. Furthermore, it is unclear where NBET is going to get these funds

from as not only are there concerns over if and how the FGN subsidy

will be disbursed during the IRP, the other purported sources of funds

appear less than certain at this stage, in our opinion.

Power Shortfall – the Gas Supply Red Herring

During the IRP GenCos are now expected to pay for their gas supplies

directly. This contrasts with the former practice where the MO deducts gas

costs from the GenCos’ receivables. Gas is supplied on a take-or-pay basis

so come what may, the GenCos must pay for their gas offtake obligations

under their GSAs. Other than the take-or-pay arrangement, the gas

suppliers have willing buyers for any gas not taken up by the GenCos.

Furthermore, those willing buyers will purchase the gas at market prices as

opposed to the GenCos which pay the DSO price for gas.

An operating fact of the IRP (and one of the main reasons that necessitated

an IRP in the first place) is that NBET and the MO are not functioning (or

funded) as they should and were expected to be at that time. In particular,

as previously stated, they are not paying for all the capacity generated by

the GenCos nor making up shortfalls in the PPAs. Caught between a

proverbial rock and a hard place, the GenCos’ cash flows are strained.

Shortfalls in settlements meant gas suppliers weren’t being paid,

“everybody owes everybody money”. This eventually resulted in the gas

suppliers turning off/limiting flow from their taps to the GenCos, hence the

recent decline in generation.

In Chapter 9: Gas Supply – Fuel-to-Power (on page 101), we talked about

the 2 August 2014 announcement made by the FGN via the Ministries of

Power and Petroleum and NERC on the upward revision of the DSO gas-

to-power price. In the same announcement it was stated that in conjunction

with the Central Bank of Nigeria (CBN), they would be setting up a facility to

settling outstanding gas-to-power debts owed to the gas suppliers,

estimated at ₦25 billion (US$156.3 million). These developments are

certainly welcome; however it is very early-days. Moreover, the precise

mechanism for managing this process is yet to be finalised as the CBN

plans to engage the banking sector in the bid to settle these accounts.


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Figure 36: Gas to Power Cash Flows


When Is A Contract Not A Contract....?

Numerous inconsistencies in the Industry Agreements and operating

manuals signed between the investors of the successor Companies and

the authorities have come to light. There are inconsistencies within the

same document and between the documents and the MYTO Financial

Model. The range spans from typographical errors on Units of

measurement, wrong calculations and formulae to ambiguous and

contradictory terms.

These are legal documents on which investors have based their decisions.

Consequently, other legal documents at the heart of transactions in the

privatisation have incorporated these inconsistencies. The effect of each

error individually and collectively could be of sufficient degree to argue that

some of these contracts could be rendered void or voidable at law. As they

stand, these transaction documents, which are essential to raise finance

are not bankable.

Gas

Producers / Transporters

Transmission

Bulk

Trader

Customers

Gas

Supply

Bill

Bill

Payment

PPA

Payment

TUOS Payment

PPA

Gas

Payment

Bills

Transmission

Bill

GenCos

DisCos


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Reality of Acquired Assets Worse Than Expected

We have already discussed concerns regarding the assumptions used in

MYTO II as they stand. Notwithstanding, the new owners and NERC have

discovered that the reality has been far worse.

When Is A Data Room Not A Data Room...?

The Successor GenCos were sold to the highest bidders. On the other

hand the BPE set the price for each successor DisCo and based the

selection on the basis of the bidder with the highest reduction in ATC&C

Losses in their business plan for a particular DisCo. It was generally

accepted that the information required to conduct due diligence on the

Successor Companies provided in the Data Room was not entirely

accurate. With this in mind, bidders made what they thought were

adjustments for this in their valuation of the assets. However even these

adjustments proved to be insufficient.

There was reassurance from NERC that if after the handover of the assets

a winning bidder discovered any liabilities that had been overlooked in the

transfer of PHCN liabilities to NELMCO, this will be rectified. Furthermore,

the IRO stated that NERC will review the tariff and make adjustments that

are to be implemented at the start of TEM.

In NERC’s defence, it has been in a running battle with the old PHCN

culture on transparency and reporting. When NERC embarked on its

mandate in 2005, it required PHCN to carry out an audit of the entire

industry – statistics, financials, etc – for all successor DisCos, GenCos,

infrastructure and tariffs. The information provided was used as the basis to

plan the new regimes of the NESI including MYTO. As we discussed,

PHCN had to redo its homework, and MYTO II was one of the outcomes of

the re-submitted data.


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Table 34: The Reality of the Successor Companies Has Been Worse Than Expected

SOURCE

OF ISSUE CRITICAL ISSUE DISCOVERED CURRENT IMPACT

MY

TO

II

1. Miscalculation of Wholesale Tariff 30% cut in Capacity payments

2. Tariffs are based on an assumption that there will be c.4,500 MW of capacity by now. The reality is has been more than 35% short.

Successor Companies are not earning as much as they projected in their business plans

MYTO II costs and WACC assumptions are not in-line.

3. Customer numbers for the DisCos are inaccurate

Range of disparities discovered is between 15-35%

4. Customer segmentation is not suitably balanced

R1&R2 tariffs are subsidised by the FGN. Customer groupings need to be reclassified because it looks like R2 is too wide as some well-off customers appear to be categorised as R2.

5. Transmission losses are much higher than stated

MYTO II assumes 8.05% but the reality is over 13%

6. ATC&C Losses are much higher than stated

MYTO II assumes ATC&C losses for the system to be 21%. DisCos are reporting ATC&C losses of 50-70%.

DisCo ATC&C loss reduction targets are based on a starting point of between 35-40% depending on the particular DisCo. Each winning bidder's 5-year loss reduction target was incorporated into the performance targets in their Performance Agreement. But with a 10-20% discrepancy in the baseline, the performance targets of the DisCos are not achievable.

7. Available generation capacity of some generation assets are less than expected

More capital expenditure than expected could be required to renovate the assets. Each winning bidder's 5-year generation capacity target was incorporated into Performance Agreements. The baseline will need to be re-set.

Inte

rim

Ru

les

8. Successor Companies are being paid less than the Revenue Requirement as indicated in MYTO II

Under the Interim Rules, the MO only pays the equivalent of 60% of the Revenue Requirement. Note the Revenue Requirement is based on 4,500 MW. The reality has been well under 3,500 MW.

The rate paid for energy in MWh has been cut by c.20% as part of efforts to manage cash flow in the system in the interim.

9. Estimated billing and transfer pricing in operation

Under TP there is no capital recovery at all. Total cost of generation and transmission are fixed on a de minimis standard.

Under the current attenuated state of operations, there is limited if any scope to recover central costs. Low collection efficiency of the system makes the squeeze even tighter.

In the current working environment where delivered energy is far less than planned, and issues with metering and collections persist, the DisCos may be slightly better off with estimated billing in some respects.

10. GenCos are only being paid for a fraction of their capacity.

They are also not being paid for capacity (MW) power stations are to reserve for Ancillary Services (Spinning Reserves, Voltage Support, Black Start Capability).

GenCo cash flows have been squeezed and they have struggled to pay their gas suppliers as during the IRP GenCos pay their gas suppliers directly rather than via the MO.

Not surprisingly, as they are already paid short on MW for power generation, committing vital capacity to Ancillary Services could be viewed as a luxury as far as their profit and loss and cash flow statements go, especially in the short term. Hence Spinning Reserves have gone from 10-15% to 0%. As a benchmark, Spinning Reserve in the US is between 13-20%.



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Figure 37: Transfer Pricing in the Interim Rules Period


Figure 38: The Theory of Transfer Pricing – There is No Recovery of Capital Costs


Successor

Discos

National

Uniform

Tariffs

Market Operator

Receives

payments

f rom DisCos

and Eligible

Customers

Transfers

Payments

to GenCos

and service

providers

Clearing Accounts

Successor

GenCos

IPPs

Transmission

System Operation

Headquarters

At PPA price

DisCos Transfer Payments

At an end-user

tariff deduced energy purchase

price

MO Transfer Payments

At an end-user

tariff deduced energy sales price

Eligible

Customers

Wheeling charges

Px – Wholesale Price of... O&M – Operations and Maintenance

Generation

Px 1

Generation

O&M costs

Transmission

Px 2

Transmission

O&M costs

Distribution

Distribution

O&Mcosts

Px 3

Wholesale Price

Px 4

End-UserTariff

The Theory of Transfer Pricing (TP): TP is used to arrive at Px 4. Only operating costs are used to determine Px.

There is no capital cost recovery.

Px 1 and Px 2 are f ixed based on minimum funds required to keep the entity operational i.e. a de minimis standard. Px 3 is determined

every 3mths in line with projected improvements in revenue management.

TPs are ultimately derived f rom and limited by DisCo takings based on the end-user tarif f which in Nigeria were f ixed, national uniform

end-user tarif fs. But if the tariffs are not cost-reflective, full cost recovery of generation, transmission and distribution O&M

costs is not possible.

Historical low collection ef f iciency in the system makes the squeeze on the Successor Companies margins even tighter under TP.

The only way to recover central (HQ) costs under a TP regime is through improvements in revenue management (i.e. ef f iciency)beyond

projected levels.

Px

3

Px

2

Px

1

Distribution

O&M costPx

4

Px

3

Compare with costs recovered, including capital

costs, under MYTO II Methodology shown in

Figure 15 on page 23.


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Hobson’s Choice – Take It or Leave It

The stark reality of the due diligence and bidding process is that the bidders

and other stakeholders in the industry were given very limited amount of

time to review and comment on documentation. The FGN’s approach was

essentially that there were a vast number of documents (PPAs, VCs, GSA,

GPO, Market Rules, Grid Code, etc, etc) and there wasn’t much room for

negotiation. The FGN was only willing to budge minimally on the issue of

risk allocation.

It was not an altogether comfortable state of affairs but the bottom line as

far as the FGN was concerned was that potential investors could either

accept the process and documents as they were (with the minor FGN

concession on review) or not get involved at all. It is little wonder that this

amount of uncertainty and obfuscation put off international banking

institutions from participating directly in the bidding process.

Amidst protests, and wanting to keep to its schedule, the FGN made a

concession by appending a review clause which stated that based on

certain conditions, key documents such as PPAs and VCs can be reviewed

within a year. This was signed in February 2013, so technically-speaking,

this window has now closed. However we understand that pragmatism has

prevailed and negotiations are ongoing.


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Chapter 14:

Structural Risks

We have identified two main structural risks associated with:

1. Investment in TCN and investment by TCN in the expansion

of the transmission network.

2. Gas supply and transportation.

Transmission – GenCos & DisCos at the Mercy of the FGN

TCN is in charge of transmission – wheeling power around the grid and

installing transmission lines. For reasons outlined in Chapter 8: , it remains

in government hands for the foreseeable future. One of the main reasons

the FGN privatised the sector was because NEPA/PHCN had not kept up

with investing in the electricity transmission infrastructure – the critical link

between generating and supplying electricity to the end-user. Our concern

here is that the NEPA/PHCN pattern of non-performance will continue.

Generation and distribution are now in private hands. Private companies

have their shareholders and lenders to answer to for the profitability of their

businesses. The figurative and literal bottom line for the GenCos and

DisCos is that if they do not supply electrical power to the end user, the

consumer, they will not make money. But they are not in complete control

of one essential element needed to attain and then increase profitability –

transmission. If the power generated is not delivered or transmitted around

the national grid, cash does not flow as expected in the system. Consumers

pay a fixed charge which covers 75% of the DisCo’s costs/payments, but

they also pay for the amount of electricity they receive by way of an energy

charge. It only takes so long of not being given the service for which the

fixed charge is paid for the customer to begin to protest and refuse to pay

thereby putting the stability/viability of the entire system at risk.

TCN is obligated to network build-out targets under the Industry

Agreements signed with the GenCos and DisCos. In the event of non-

performance, NERC has penalties it can impose and the DisCos and

GenCos have some legal recourse. Notwithstanding, in the meantime,

expenses must still be settled, debt must still be serviced.

Wide Impact of Harvesting Low-Hanging Fruit

As far as the main body of the current transmission infrastructure is

concerned, if brought to optimal wheeling capacity, it is capable of

transmitting 6,000 MW of power, which is practically twice as much

electricity currently being supplied. Getting to 6,000 MW wheeling capability

is the low-hanging fruit for TCN, the easy win. This will make a noticeable

difference to the end user. Experiencing such an improvement in electricity


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supply will give confidence in the system and make further tariff increases,

which are invariably necessary, much easier for the end customer to

stomach.

Financing TCN

Less than 40% of the country is connected to the National Grid and about

US$1.5 billion per year over the next five years needs to be invested in the

transmission infrastructure in order to make the system more reliable and

stable. In Chapter 8: (Chart 17, page 91) we explained that on a five-year

view, TCN’s capital requirement is over US$780 million short. Additional

sources of funds might come from bilateral arrangements, via funding

consortia and turnkey solution providers.

Chart 28: External Sources of Funds for TCN, 2013-2017

Source: The Roadmap, CSL Research

^ France's overseas development agency. * Part of the trio of China’s finance institutions designed to promote state policies in foreign trade, industry, diplomacy and economy, and promote Chinese products and services. Of the trio (China Development Bank, Exim and Sinosure), Exim is the sole provider of Chinese government concessional loans. “ Japan’s overseas development agency. NDPHC - Niger Delta Power Holding Company, the parent company of the NIPP power plants.

i. Sovereigns or Copper?

With TCN’s chequered track record of financial management, we believe

that the FGN will have to be prepared to take on the credit risk of TCN for

some time. This being the case, investors may rather take on sovereign risk

directly rather than taking on TCN with its uncertain return profile, should

the FGN decide to establish a commercial investment vehicle to fund TCN,

for example. The FGN could make investing in the transmission sector

more attractive by issuing infrastructure bonds or selling units in an

infrastructure investment fund, for example. The mechanics and

African Development Bank

Agence Française de Développement^

China Exim Bank*

FGN 2013 US$1bn Eurobond Issue

Islamic Development Bank

Japan International Co-operation Agency"

NDPHC transaction investment

World Bank/China Loan


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configurations of these structured finance options can be complex and are

beyond the scope of this report. What we would say, however, is that

avoiding/minimising the risk of creating an arbitrage opportunity between

sovereign debt and such sovereign-backed finance structures is one that

would be at the forefront of the mind of the Central Bank and the Ministry of

Finance.

Current plans for TCN factor in US$125 million FGN budget appropriation

per annum but in our view this is likely to prove overly conservative.

ii. NIPP injection in question

We also understand that TCN has assumed that US$1.6 billion of NIPP

transmission assets will be transferred to TCN in exchange for shares in

TCN. But this is by no means a certainty as we presume the winning

bidders will need to agree to take equity in TCN in exchange for their

transmission assets. This may well be a tough sell for the BPE because

one of the advantages and strengths of the NIPP companies vis-à-vis

others is that they also have control over transmission in their locale.

iii. Rural Electrification Programme

Rural electrification is less than 20% and the FGN has a target of 75% by

2020. Wary of rural areas getting neglected in the expansion of the

distribution networks, the Electric Power Sector Reform Act 2005

established the Rural Electrification Agency to regulate the expansion of

electricity in rural areas.

The Rural Electrification Programme is funded separately by the Rural

Energy Fund and we would expect TCN to benefit from co-ordinated build-

out plans. However cost synergies might be elusive in the medium term

because of the REA’s poor track record of meeting key performance

milestones and effective financial management. Its chequered history

includes a portfolio of over 1,500 unfinished rural electrification projects.

The REA has been restructured recently and a new “Light-Up Rural

Nigeria” strategic plan was inaugurated by President Jonathan at the start

of the year. However only time will tell...

iv. The United States’ Power Africa Initiative

Another source of funding for TCN, as well as other operators in the sector

is the US Power Africa initiative launched in June 2013. It aims to double

access to power in Sub-Saharan Africa and has committed US$7 billion

over the next five years (to 2018) to six African countries including

Nigeria40

. Financing provided under this programme will be in the way of

financial support and loan guarantees. The US and other international

finance institutions such as the World Bank and the African Development

Bank together constitute a US$21 billion project finance, direct loan and

equity investment package aiming to increase power generation in sub-

Saharan Africa by 10,000 MW in the next five years.

40

Others are Ghana, Liberia, Ethiopia, Kenya and Tanzania)


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Page 141

Figure 39: 6 African Countries in the US Power Africa Initiative


Man Management – The Old Guard’s Last Stand?

The FGN has brought in Manitoba Hydro International to manage and

implement a root and branch overhaul of TCN – a very commendable and

astute decision, in our view. However as we outlined in Chapter 8: the early

days jamboree surrounding their appointment, ongoing political interference

with the composition of the supervisory board and operational brick walls

over control of the Market Operator budget all make us concerned that the

old guard is more entrenched than we would like or indeed than it should

be permitted to be. A management contractor must be left to bring in and

implement to the full extent the expertise and skill for which it was hired. If it

is failing in that role, contractual terms provide the avenue for it to be

replaced by a more suitable firm.

As with other key institutions such as NERC, in our opinion the FGN would

be following a recipe for failure if they are not left to operate as they are

designed to do, without political or vested interest interference. The rules

and regulations to ensure transparency and accountability are already in

place and are well detailed (as such regulations usually are in Nigeria).

Ethiopia

Kenya

Tanzania

Nigeria

GhanaLiberia


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Gas Supply and Transportation

Additional GSA Will Be Required

The Successor GenCos were sold with Gas Supply Agreements. But the

GSAs only cover the pre-existing available generating capacity and not

installed capacity. Available Capacity of the Successor GenCos was at

about 40% at the time of sale so the successor GenCos will need to

negotiate additional GSA, GTA etc with gas producers as they increase the

Available Capacity of their plants towards Installed Capacity. Raising

Available Capacity closer to Installed Capacity is an obligation contained in

the Performance Agreement.

The new GSAs will not be on the regulated (DSO) price as supplied by the

Gas Aggregation Company of Nigeria (GACN). They will be bilateral

contracts between the GenCos and the gas producers on a willing buyer-

willing seller basis, at a commercial price.

Chart 29: Installed vs Available Generation Capacity (MW)

Source: BPE, CSL estimates

^ Not included in 2011 BPE presentation. Figures from market sources.

776

1,320

414

760

1,020

600

900

45

880

361 359

135

393 228

Afam Power

Egbin Power^

Geregu Power

Kainji Hydro

Sapele Power

Shiroro Hydro

Ughelli Power

Installed Capacity (MW) 2011 Available Capacity (MW)


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Gas Supply Contracts Set On Take-Or-Pay Basis

The payment and settlement terms in GSAs are on a take-or-pay basis. In

other words, as long as the gas producer/supplier is ready and able to

supply the amount of gas contracted for, the gas must be paid for. Fuel

costs are passed through to the DisCos and ultimately to the end customer,

so the DisCos bear the payment risk.

Gas Transportation Infrastructure Adequacy is of Concern

The current gas supply infrastructure is just adequate to support 4,000-

5,000 MW of power generation. Thereafter, especially beyond 6,000 MW,

there will need to be a significant increase in investment in gas

transportation infrastructure.

GSA’s are typically of 10-15 year duration so gas producers make

investment decisions based on the GSAs they enter into. The contract price

takes into account any infrastructure investment that is required such as

gas pipelines to the buyer’s facility. Thus those plants that are closer to the

gas producer’s processing facility are likely to get more favourable prices.

Beyond a certain distance, the gas is transported via the FGN-owned

Nigerian Gas Company’s (NGC) transportation pipeline network.

Investors should note that the Gas Master Plan is expected to address the

infrastructure issue, but the GMP:

(b) Has been behind the curve from a pricing and market operations

perspective. In fact market participants expect the relevant sections of

the Petroleum Industry Bill that relate to gas too be drafted to reflect

current practice; a case of the tail wagging the dog.

(c) Has manifested little success in building out infrastructure in line with

targets in the named Strategic Sectors such as power and gas-reliant

manufacturing.

The market is already leading on the commercial trading/open market

aspects so for the time being we believe it makes more sense for the raison

d’être of GMP to be a gas infrastructure plan. Regulatory oversight can

remain with the Department of Petroleum Resources or put in the hands of

a separate independent regulator, as was done with the creation of NERC

for the power sector.


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3-year Countdown to Gas Supply Crisis Started Yesterday

The supply shortfall will come to a head in about 3 years time if a radical

effort is not put into expanding the gas pipeline infrastructure. Demand for

gas-to-power is going to more than double to 3 BCF per day by 2017. And

it takes 3 years to make the investments in plant facility, gas transportation

infrastructure etc.

Recently-issued NERC regulations state that no new IPP licences are

going to be issued until the operator has secured core industry agreements

such as GSAs and GTAs. This ought not to be a hindrance in the short

term as most of the new IPPs being built over the next few years will be

situated near the gas facilities. They should therefore by-and-large not have

to rely on the infrastructure-building efforts under the GMP.

We have stated that the Successor GenCos were sold with GSAs already

in place for the available capacity at the time of sale, so they are covered.

The NIPPs will be sold with GSAs but it is not yet clear if this will cover all

their generation. It will take the NIPPs and Successor GenCos 2-3 years to

reach optimum capacity and hence peak fuel demand. In the meantime the

IPPs being constructed will also be competing for gas. We believe that this

increase in competition will invariably have the effect of raising gas prices.

Cash Effect of the Infrastructure Gap

In the chapter on MYTO (Chapter 5: ) we described end-user tariffs as

consisting of a fixed charge and an energy charge. The fixed charge of the

end-user tariff only covers 75% of generation and transmission costs. It

covers the GenCos’ capacity charge and the DisCos’ transmission and

O&M charges.

The fixed charge cushions against “Availability Events” that reduce the

amount of electricity generated. Availability Events could be due to issues

with gas infrastructure affecting supply to the GenCos or problems with the

transmission infrastructure affecting off-take/evacuation of electricity which

could result in the plants scaling down production. This would have

implication for cash flow and ultimately profitability.


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Chapter 15:

Financing the Power Sector

Over the next five years, the Nigerian power sector will need to raise

US$13-15 billion for capital expenditure in transmission, distribution and

generation. Another US$7.5-10 billion is required for supporting gas

infrastructure. Of these amounts, the FGN is responsible for US$800 million

which it has committed to NBET’s capitalisation fund for its proper

functioning. The FGN is also responsible for the US$1.5 billion annual

requirement for transmission infrastructure and US$1.5-2 billion per annum

for the gas infrastructure. The Successor GenCos and DisCos require a

capex spend of US$5-6.5 billion over the next five years.

The privatisation of the Successor GenCos raised US$1.65 billion for the

FGN, while the Successor DisCos raised US$1.46 billion, hence there

should not be any conceivable financial reason that the FGN cannot fund

NBET. Furthermore, in February 2014 TCN announced it had received

US$665 million of funding for transmission projects from various

international finance agencies and from the FGN budget allocation41

.

Bank Exposure in Acquisition of Successor Companies

Questions have been raised about the extent of the exposure of domestic

banks to the power sector due to the fact of the operations of the

Successor Companies were not as expected and that the duration of the

IRP is open-ended.

The investors in Successor Companies

were not permitted to use the target assets

as surety for monies borrowed to fund their

bids. However, they were permitted to use

their prospective shares in the target

companies and/or also prospective cash

flows from the operations (a type of bare

securitisation instrument) based on their

business plans and financial projections.

For those who pledged shares or cash

flows, the lending banks typically also

required secondary form of recourse using

on non-target related assets of the

investor.

Due to the perceived high risk profile of the

industry – the new institutions had no track

record of creditworthiness, NEPA/PHCN’s

41

See page 78 for sources of TCN funds.


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history of operational and financial management was abysmal and some

early-day concerns thrown up by political interference and contractual

irregularities – banks were reluctant to get involved. It is one thing if the

borrower is looking to invest in an already profitable enterprise, even

without security against the target assets. It is quite another looking

to put money into one of the most defunct ex-government enterprises,

in an untested new regime, which was still going to rely on the same

FGN involvement at the critical points in the value chain. Thus it came

as little surprise that the only banking institutions involved in the

privatisation were local. We also understand that all but one or two of the

technical partners in the consortia were involved in financing the bids.

So far, local banks have invested over ₦750 billion (over US$5 billion) in

the power sector (privatisation, rehabilitation, other power-related assets,

etc). But the major spend is capital expenditure from here

How Big is the Pool of Finance Available for the Sector?

Theoretically speaking, in the world of cross-border financing and free

movement of capital, the answer to the question is, “As big as it needs to

be”. In the wake of the global financial crisis, balance sheets of have been

rebuilt, Long Only funds have built up higher cash balances which they now

want to put to work, trade buyers are looking further afield to acquire growth

and international development agencies have begun to step up their

commitments. Add to this the renaissance of Africa as a place to do

business, in particular sub-Saharan Africa and the continent does not seem

as remote as it did a decade ago. There is no denying that risks are higher

than in more developed markets, that fact is inherent in its classification,

hence investors require higher returns for taking on the extra risk.

However, irrespective of how attractive the macro and sector fundamentals

look, the sector (and country) has to compete with other calls on

international finance – other sub-Saharan Africa countries and sectors,

other fast-growing regions in the world. International financial investors

will not buy alpha (growth/performance) at any price, even those that

invest in emerging and frontier markets which have higher risk

profiles. There are certain basic requirements that need to be in place, and

that are robust enough legally and structurally. These all go into the

investor’s assessment of the risk profile of the market.


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Financing and Risk Matrix for Nigerian Power

In Figure 40 we have set out a financing and risk matrix to indicate the

sources or pools of finance that become available as the risk profile of the

sector/market changes. Individual sectors within a particular market can be

deemed to have higher risk profile than the overall market. It is arguable

that at the onset of the power sector privatisation, the sector had a higher

risk profile than the Nigerian market as a whole – it was a sector on its

knees, it was unprofitable, it was having a completely new, untested regime

introduced and the FGN was going to keep control of vital aspects of the

system.

Figure 40: Power Sector Financing and Risk Matrix


Government,

Local Banks

& Local

Private

Sector

International

Development

Agencies

Frontier

Market Funds

International

Banks

International Private

Equity Investment

Funds, Sovereign

Wealth Funds

Typical IRRs of 15-20%

E

Q

U

I

T

Y

Government Local private sector

Government Local private sector Foreign & local trade

partners Frontier market funds

Government Local private sector Foreign & local trade partners

Frontier market funds Global emerging market funds

Pension funds Capital markets

Local banks Development Finance

Institutions (DFI)

Multilateral agencies

Local banks Regional banks International banks

Development Finance Institutions (DFIs) Multilateral agencies

Export credit agencies Capital markets Sovereign Wealth Funds

Private Equity Infrastructure funds

Debt service coverage

ratios of up

to 1.5-2.0x may be

required depending

on position in

value chain.

D

E

B

T

Local banks

STAGE I STAGE II STAGE III

NOTE:

The spheres are not proportional but merely representative of the size of the

particular pool of capital.

The balance between government and other sources of finance shifts to the latter

during later stages.

In the later stages, projects tend to be large and require greater capital

commitments beyond those available from the State. Furthermore, local financial

institutions do not have large enough balance sheets to absorb the funding

needs of this stage. Hence the demand for external borrowings increases.

$$$

$

FIN

AN

CE

CA

PIT

AL

Financing/Risk Disconnect? The size of capital required for

the Nigerian power sector is of Stage III proportions. However

these doors tend not to open if the market and/or execution

risks are perceived to be high.

High MARKET RISK Low[EXECUTION RISK]


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Characteristics of Power Sector Financing

Table 35: Characteristics of Power Sector Financings

Long Tenor

Term of debt depends on the project, plant time and location

Recent financings have called for 8-30 year term debt.

Bridge funding is available but is expensive

High Leverage

Amount of debt to equity banks would permit is constrained by the forecast cash flows of the project, which are expected to service repayments.

Debt tends to be between 60-90% of project costs. However for the Successor Companies the BPE has put a cap of 70% for the first 5-years.

Multi-Source Includes Local and international banks, DFIs and Export Credit Agencies. (See Figure 40: Power Sector Financing and Risk Matrix).

Multi-Currency Naira and US Dollar mix is recommended. However FX risk mitigation must be addressed.

Security of Finance

Credit enhancements and supports include guarantees, warrantees and other covenants for the project sponsor, affiliate and other third parties.

Strength of the guarantee ensures the transaction secures the optimal debt structure (pricing, tenor, etc.) and demonstrates commitment from the sponsor.



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Key Documents in Nigeria Power Sector Financing

These are some of the key documents that are required to be in place for

financings in the Nigerian power sector:

Table 36: Documents Essential to Securing Power Sector Financing

Document Application

Share Sale Agreements DisCos and thermal GenCos

Equity financing commitments

Share transfer restrictions

Dispute resolution

Concession Agreements Hydro GenCos

Gas Supply and Aggregation Agreements Gas-fired GenCos

Gas Transportation Agreements Gas-fired GenCos

Power Purchase Agreements GenCos – 15-years typical

Includes plant specifications and performance standards

Penalties for late commissioning or failure to meet performance targets

Revenue write downs for under performance

Default and termination provisions

Details of credit quality of the off-taker and payment guarantees.

Vesting Contracts DisCos – 15-years typical

Includes plant specifications and performance standards

Penalties for late commissioning or failure to meet performance targets

Revenue write-downs for under performance

Transmission Use of Network System Agreements DisCos and GenCos

Grid Connection Agreements DisCos and GenCos

Ancillary Services Agreements GenCos

Bulk Trader Credit Support A combination of FGN letter of support for NBET meeting payment obligations and the World Bank/AfDB Partial Risk Guarantees

Deed of Assignment of Pre-Completion Receivables Successor DisCos and GenCos

Operations and Maintenance Agreement Allocates operational risks

Details penalties and incentives

Operator must be bankable i.e. credit-worthy and experienced

Pre-Completion Liabilities Transfer Agreement Successor DisCos and GenCos



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Cost of Capital in the Power Sector – MYTO II

One of the components of the Revenue Requirement for the sector used to

arrive at the tariffs is the Weighted Average Cost of Capital (WACC). It is

included so that the tariff takes into account a return on the value of capital

invested in the Successor Companies. NERC’s objective was to arrive at a

figure that attracts investment funds into the industry but “is not sufficient to

produce super profits”.

The MYTO Model uses the Capital Asset Pricing Model (CAPM) to

calculate the WACC. WACC provides an estimate of the returns on equity

and debt. The returns to equity in the power sector are measured in relation

to the risk premium on the Nigerian equity market as a whole. The measure

of the relative risk of the sector to the Nigerian equity market is expressed

as Beta (ß).

Power Sector Risk Relative to the Nigerian Equity Market

The MYTO Model assumes a sector Beta of 1. In other words it assumes

the risk of investing in the power sector is no higher or lower than the risk of

investing in the Nigerian stock market as a whole (i.e. market-weighted

fund). NERC has indicated that it will review the figure it uses for Beta when

enough data exists for statistically significant estimates to be made. It does

not have sufficient data because electricity supply in Nigeria is not an area

that has a history of steady supply of private investments to deduce the risk

of return relative to the market.

MYTO II WACC Assumptions and Estimate

Assumptions:

Risk free rate 18%

Nominal return on equity 29%

Beta 1

Nominal cost of debt 24%

Gearing (Debt : Equity) 70:30

Total corporate tax rate 32%*

*statutory corporation tax of 30% plus 2% education tax

WACC Estimates:

Nominal pre-tax WACC 25.5%

Nominal post-tax WACC 17.3%


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While NERC’s position is theoretically valid, from an investor’s perspective

it might be prudent to apply a Beta for the sector in the estimation of cost of

capital. The electricity generation sector in emerging markets have been

estimated to have a Beta of 1.34, while emerging market electricity

distribution companies have a Beta of 1.2842

.

Power Sector Risk Premium Factors

Some of the notable risk factors in the power sector we have discussed

which we consider would justify the application of a premium to the market

Beta include:

In Chapter 13: Systemic Risks we pointed to certain inconsistencies,

contradictions and ambiguity in key documents of the privatisation

which rendered them effectively unbankable. Hence the doors of

finance for future capex are very unlikely to be opened until this is

rectified.

We have also covered concerns over the need to rely on the FGN to

deliver on transmission and gas transportation infrastructure. As far as

the MO function goes, the machinations we have seen so far creates

grave uncertainty about whether the payments and settlements system

will be allowed to function freely and fairly.

The shortcomings of the MYTO model assumptions mean that the

Revenue Requirement, hence the computed tariffs, are too low. Yet

there is no indication that the tariff will be adjusted to reflect this before

national elections in 2015.

The open-ended IRP and the lack of a definitive date for the

declaration of TEM and the full functioning of the core institutions

of the NESI. This is the most significant factor, in our view.

The longer the transition plan stays off track, and the more unexpected

variations are introduced after the fact, the greater the uncertainty and the

42

Ian H. Giddy, Aswath Damodaran; New York University Stern School of Business.

Sector Return on Equity Investment

Re = Rf + ße(Rm – Rf)

Where:

Re Return on Equity

Rf Risk free rate (yield on 10-yr Nigerian Treasury bonds)

ße Power sector risk relative to the Nigerian market

Rm Return on the Nigerian market portfolio

Rm – Rf Market risk premium


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greater the justification for a higher risk factor (Beta) to be applied to the

Nigerian power sector. Ultimately this could cripple investors’ ability to raise

the finance required to fund the development of the sector as doors of the

broader international sources of finance do not open until the risk level

lowers (Figure 40). Without those doors being opened, the transition and

development of the Nigerian power sector cannot come to fruition as

planned.

Has the BPE Declared Nigeria Closed For Business?

Under our discussion of the Progression of Economic Value43

in Chapter 3:

we explained how successful reform of the power sector and increasing

power generation is an immovable condition-precedent to Nigeria’s

transition to an industrialised economy. Thus the future profitability and

competitiveness of every essential sector/industry in the country to a

notable extent rests on the power sector and its regulatory regime being fit

for purpose. In light of this we were especially taken aback by a BPE press

release on concerns raised by local lending banks at an industry

conference on 21 May 2014.

Local Banks and the Stress of the August Anniversary

There have been general concerns over what impact the stresses in the

sector will have on the Nigerian banking industry. It is a fact that the

privatised power sector is not running as expected, resulting in significant

variations in the cash flows and profit forecasts of the Successor

Companies’ business plans (and incidentally the BPE’s own financial model

for the industry). Thus local banks have expressed fear of default on the

loans taken out to fund the bids for the Successor Companies when

payments fall due in August 2014. The BPE press release, referring to the

fact that Successor Company assets were not (permitted to be) used as

collateral, stated:

"The banks lent to the Core Investors based on their capability to

pay. The investors are supposed to have made adequate provisions

to take care of their obligations to their financiers from the outset.

They knew that they were not going to make profit immediately on

takeover of the [Successor Companies]. Their financiers also were

aware of this"44

We indicated at the opening of this chapter that investors could borrow

against their shares in the Successor Companies and/or against forecasted

cash flows of the businesses. These financial projections were based on

information on the fundamentals of the Successor Companies that was

provided by the BPE. The financials were incorporated into the investors’

business plans and initial budgets which, naturally, were presented as part

of the loan applications. Furthermore, these financials were also an integral

part of their submissions to the BPE in their bids. The new owners would

43

Page 37 44

Bureau of Public Enterprise Press Release, 22 May 2014. (See Appendix 7: )


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not have been successful had their business plans not been thought to be

sound by the BPE and in line with the FGN’s targets for the power sector.

The Post Acquisition Plans and Initial Budgets as shown in the business

plans presented by the winning bidders were incorporated into

Performance Agreements and other Industry Agreements signed by the

investor, the Successor Company and the BPE. So investors and their

financiers proceed on the basis that all parties will keep up with their end of

the bargain and took actions in reliance of information provided by the

various counterparties.

Many banks would have taken secondary (or primary) non-power related

collateral. But even with recourse, in the event of a default, banks will

record a non-performing loan and there are costs involved in enforcing the

claim against the asset.

The banks did not lend blind. Investors did not borrow blind. Thus in the

first instance we would agree with the BPE that “[the investors] knew that

they were not going to make profit immediately on takeover of the

[Successor Companies]…..[and their] financiers also were aware of this”.

However, as any reasonable counterpart to an agreement would, they were

also expecting the BPE, NERC and the FGN to do what they had promised

to do. The investors did not anticipate:

(a) The degree of disrepair of the assets and other technical issues

discovered post-handover; nor

(b) That the start of TEM, with all its FGN-provided safeguards and

sureties, would be delayed so long; and

(c) That an IRP would be imposed after handover with a different set

of rules and procedures relating to operations and settlements.

The unexpected institution of a no man’s land that is the IRP and the

uncertainty that currently exists leaves the investment community

feeling rather nervous. Everyone expects a few bumps along the way

in such privatisations thus stakeholders proceed on the

understanding that they will work towards resolution to get the project

back on track as soon as possible. This usually involves some give-

and-take, as there are often issues on both sides, mostly unforeseen.

However in Nigeria’s case, in our view the balance of responsibility is

heavily weighted on the FGN/BPE/NERC’s side due to the degree of

inconsistencies and errors discovered by the new owners of the

Successor Companies after handover. (See Table 34: The Reality of the

Successor Companies Has Been Worse Than Expected).


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Long Reach of the BPE’s Summary Dismissal of Concerns

The BPE’s summary dismissal of what we consider to be valid concerns by

the banks has potentially a far-reaching and profound impact beyond the

power sector. At a basic level it raises questions over the BPE’s regard for

the sanctity of the contracts it enters into. Another question mark is cast

over the degree of the BPE’s realisation that both counterparties (FGN and

private investors) have skin-in-the-game, hence something to lose.

Finally, it sends a message of caveat emptor to the local and international

investment community considering getting involved with any FGN

privatisation. It drastically raises the execution risk of the project, which

historically has been a perennial criticism of FGN enterprises. We believe

such a stance by the BPE could threaten the FGN’s medium and long term

plans to attract private investment into the power sector, which in turn will

have a knock-on effect on the evolution of the Nigerian economy.


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Chapter 16:

Investment Opportunities in the Sector

Generally speaking, the issues that persist in the Nigerian power

sector are not without precedents in other markets and can be

resolved. Thus provided there are clear indications that all the current

stakeholders are working together to get the schedule back on track,

and allowances are made for shortfalls suffered so far, the sector

demand story and macro opportunity can be fully realised.

There are a number of ways to gain exposure to the Nigerian power sector

directly (generation and distribution) and indirectly. We highlight a few of

those we believe have the greatest potential below:

Direct Investments

Other than through debt financing to the Successor Companies or taking

equity stakes, should that option become available, there are four direct

ways to invest in generation and distribution:

NIPPs

The privatisation of the National Integrated Power Project GenCos is

currently underway. We will cover this in detail in the next chapter.

IPPs

NERC’s risk allocation in the industry appears more favourable to

generation companies. Provided the IPP in question does not have to rely

on the national gas infrastructure to get going, which means it will be

situated close to its gas supplier, it has better control over its potential

output. However as it will need to be connected to the national grid, it would

potentially face similar off-take issues faced by the Successor GenCos.

Independent Electricity Distribution Networks

Licences for this are granted by NERC. At the moment these are

associated with embedded generators but could be used as means to

connect rural communities to the national grid.


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Embedded or On-site Generation

In our view this currently represents the most favourable play on

generation, provided fuel supply is not an issue. The embedded GenCo is

directly connected to the distribution network operated by a distribution

licensee.

Excess power generated and not used can be sold via the national grid. It

also benefits from lower capital costs, reduced connection costs and

avoidance of the TUOS cost. The customer benefits from increased and

more reliable supply of electricity and potentially lower tariffs.

Figure 41: Embedded Generation and Independent Distribution Networks


Independent Distribution Network

Distribution Network

Distribution Network

Commercial

Residential

Industrial

Grid Supply Points

Independent Distribution Network

Embedded Generation

Direct Supply Customer

Direct Supply Customer

NATIONAL GRID

On-Grid Generation


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Small-Medium Hydroelectric Plants

They are typically 5-60 MW embedded hydroelectric power plants. Over

300 potential small and medium hydro-power projects have been identified

and feasibility studies have been carried out on 12 dams. The FGN is open

to private investors’ submissions of interest to invest in these projects.

Figure 42: Small Hydro-Power Plants Figure 43: Potential Sites for Hydro-Power Plants

Source: Vallibel Power Source: CSL Research

Indirect Investments – A Piece Meal Approach

We believe that there are opportunities to gain exposure to potential growth

in the power sector and make decent returns other than by electricity

generation and distribution. In the immediate post-handover environment,

indirect exposure might better suit investors with lower risk appetite

than that required for the power sector as it currently stands.

Industries such as equipment manufacturing and other service providers

should also benefit from the procurement and capital spend that the power

companies and the FGN will embark on. There is no going back for the

FGN at this point. The main unknown thrown up by the issues in

generation, transmission and distribution that we have highlighted is

the pace of progress. This in turn has a bearing on the optimisation of

returns within an acceptable timeframe for investors and banks operating in

a developing market.

We believe investors looking to get indirect exposure to power should look

to companies that have close-ended, piece-meal interactions with the

Abuja

Dadinkowa Mambilla

MakurdiLokoja

Onitsha

Gurara

Zungeru

Ikom

KainjiJebba

Shiroro

Hydroelectric Power Plant Site

(Existing or Being Developed)

Large Hydroelectric Power Plant Site


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power sector, providing products and services. The main areas we would

point to are in:

Power transmission infrastructure

Gas transportation infrastructure

Technology and engineering, including metering

Technical capacity and knowledge services


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PART IV – Privatisation of NIPPs


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Chapter 17:

The NIPP Investor:

Second-Mover Advantage?

Private investors are to get another opportunity to acquire publicly-owned

power generation assets by way of the privatisation of National Integrated

Power Project (NIPP) GenCos. The NIPP programme is a separate and

distinct enterprise from the PHCN companies and privatisation process.

The Niger Delta Power Holding Company (NDPHC) was incorporated in

2005. It was set up to wholly own, manage and operate 10 new GenCos

(with the necessary transmission lines connecting to the national grid) to be

built under the NIPP programme using private sector best practices. The

programme was instigated to ensure that the FGN did not stall on adding

generation capacity at a time when the rest of the FGN-controlled sector

(PHCN) was focused on readying to be privatised.

Figure 44: Location of NIPP Assets Being Privatised


Calabar

Omoku

GereguOmotosho

Olorunsogo

AlaojiOgorode

Gbarain

BeninEgbema


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The Status Quo

The NIPPs privatisation is at an advanced stage. On 13 March 2014, 19

Preferred and Reserved Bidders were shortlisted by the BPE. Not entirely

unexpected for such processes, there has been some drama which has

temporarily scuppered the privatisation of three of the NIPPs – Alaoji

Generation Company Limited, Gbarain Generation Company Limited and

Omoku Generation Company Limited.

On 17 March, the Federal High Court issued an interim order which

enjoined the BPE from proceeding with the privatisation of Alaoji, Omoku

and Gbarain GenCos. Ethiope Energy Ltd (EE), one of the pre-qualified

bidders for these three assets, challenged its disqualification as a bidder for

failing some aspects of the due diligence process and requirement. It

accused the BPE of bias, prejudice, conflict of interests and manipulation of

the technical bid evaluation due diligence process.

EE’s Statement of Claim against the BPE et al., it accused the Chairman of

the Due Diligence Committee, Mr Atedo Peterside, of having immense

influence on the BPE. It asserted that Mr Peterside should have excluded

himself from the Technical Bid evaluation process as it related to EE

because he had a bias against its Chairman, Chief Johnson Arumeni. EE

said Mr Peterside had been having a running legal battle with Chief

Arumeni in the courts of their home state, Rivers State, and that Mr

Peterside was “hostile” and felt “animosity” towards Chief Arumeni.

At the end of March, the parties to the case informed the court that they

were in discussions to reach an out-of-court settlement. However on 30

April Counsel for EE informed the Court that the parties had not been able

to reach an amicable settlement. This was confirmed by Counsel for the

Defendants. Meanwhile the second Defendant, NDPHC, has filed an

appeal at the Federal Court of Appeal seeking to have the Interim Order set

aside so that the privatisation of the three NIPPs can proceed.

At a hearing at the beginning of July, the sitting judge adjourned the case

until October 7 for ruling.


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Table 37: Preferred and Reserved Bidders for 7 of 10 NIPPs*

Preferred Bidder

Reserved Bidder

NIPP Asset Organisation

Bid (US$ mn) Organisation

Bid (US$ mn)

Benin GenCo EMA Consortium

580.0

Index Consortium 575.0

Calabar GenCo EMA Consortium

625.0

Nebula Power Generation Consortium 623.8

Egbema GenCo Dozzy Integrated Power Ltd

415.1

AITEO Consortium 392.0

Geregu GenCo Seoul Electric Power Ltd

690.2

Yellow Stone Electric Ltd 613.1

Ogorode GenCo Daniel Power Consortium

531.8

ESOP Power Ltd 510.0

Olorunsogo GenCo ENL Consortium

751.2

Index Consortium 730.0

Omotosho GenCo Omotosho Electric Power

660.0

ENL Consortium 645.2

OPTIMAL SALE VALUE

4,253.3

LEAST SALE VALUE 4,089.1

Source: BPE, CSL

* Privatisation of Alaoji, Omoku and Gbarain GenCos temporarily suspended pending ruling on Ethiope Energy Ltd's High Court case against the BPE et al. for EE's disqualification as a bidder for these assets.

Ogorode Generation Company Ltd owns the Sapele II Power Plant

The Bidding and Selection Processes

This is being handled along the lines of those done for the PHCN

companies’ privatisation. There are three key stages:

Stage 1: Expression of Interest (EOI)

The key requirements here were that prospective bidders be existing local

or international power companies or investors with power O&M operators

as long term technical partners. Other stipulations included that the EOI

must state the prospective bidder’s number of years of experience in power

generation and distribution. The BPE also required evidence of such

ownership/activities, especially in developing countries. Other submissions

included clear evidence of the bidder’s having sufficient resources to

finance the acquisition.

Pre-qualified bidders were required to pay a US$20,000 fee for each NIPP

asset/GenCo of interest and sign a confidentiality agreement. They then

received the relevant Information Memoranda and Request for Proposals

(RFPs).


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Stage 2: Bid Proposal Submission

This involved a two-envelope system. Bidders were to submit one

containing their Technical Bid and one containing their

Commercial/Financial Bid, in accordance to requirements set out in the

RFP.

On submission of their Technical and Financial Bids, the bidders were

expected to submit a security deposit of a US$4 million on-demand

payment bond.

Stage 3: Two-Step Bid Evaluation

The BPE conducted a full technical evaluation and scored each Technical

Bid on criteria set out in the RFP. Those that passed the threshold moved

onto the next stage and their Financial Bids were then evaluated. The most

attractive financial proposal was declared the Preferred Bidder and the next

attractive proposal declared the Reserved Bidder.

Once the Preferred and Reserved Bidders were announced, the BPE and

the Preferred Bidder immediately began negotiations to finalise the

privatisation of the NIPP GenCo.

Within 15 business days of being notified of selection as the Preferred

Bidder and the Reserved Bidder, both bidders were required to lodge a

bank guarantee equal to 15% of the amount bid by the party. The bank

guarantee can be reimbursed if the bidder does not:

a) agree to the terms of the final drafts of the Share Sale Agreement

or Shareholders' Agreement; or

b) on signing the SSA and SA, pay the initial deposit, which is 25% of

the bid price for NIPPs that have reached full commissioning stage

on the date of signing or 10% of the bid price for NIPPs that are not

at full commissioning stage at the date of signing.

NIPPs Privatisation Package

The plants will be sold with Power Purchase Agreements with NBET in

place as well as fuel supply agreements. The PPA covers low levels of

dispatch for both capacity payments and obligations under take-or-pay

provisions under the Gas Supply and Aggregation Agreement. The PPA

capacity payment is designed to be sufficient to cover debt and return on

equity (ROE) in the event of problems in dispatching electricity not caused

by the power plant. The level is based on the 70/30 debt to equity ratio and

ROE assumptions used by NERC in MYTO II.

The new owners of the NIPP plants are able to enter into bilateral fuel

supply agreements for additional fuel. They can also negotiate PPAs with


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embedded networks not connected to the national grid, to which the plants

will be connected before handover.

Interim operations and maintenance agreements are currently effective.

The new owners can either take these over or can replace them.

Government Involvement in NIPPs Post-Privatisation

NDPHN is owned by the FGN, and state governments and Local

Government Authorities in their respective locations. After privatisation,

NDPHC will retain 20% stake in the NIPP GenCos. Notwithstanding we

would advise investors in the NIPP GenCos not to rely on NDPHC for

further injections of capital. In contrast to the position of the FGN in this

matter vis-à-vis its retained stakes in privatised PHCN companies, NDPHC

has been equivocal about injecting further capital/contributing to costs pro-

rata. Should NDPHC elect not to co-invest, it is prepared to have its holding

diluted. Similar to the FGN, NDPHC expects to have board representation

commensurate with its shareholding.

Figure 45: Ownership of NIPP Assets – Pre and Post Privatisation


Federal Government

of Nigeria

36

State Governments

774

Local Governments

Niger Delta Power Holding

Company

47% 35% 18%

NIPP GENCOS

Niger Delta Power

Holding Company

Private Investors in

Specific NIPP GenCos

NIPP GENCOS

20% 80%


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Other Salient Terms

Foreign Exchange Risk and Debt Financing

The provisions for these two elements are similar to those for the PHCN

plants as MYTO II schedule applies. To summarise:

FX risk

Payments by NBET under PPAs are in local currency. As discussed

previously, MYTO II has factored in some foreign exchange components in

the tariff computations so investors have a degree of exchange risk

protection. The naira/US dollar exchange rate used in MYTO II is set at 1%

above the official Central Bank rate as during the review of MYTO I,

investors informed NERC that the CBN rates were not always accessible to

them. MYTO II model assumes a steady increase in the NGN/USD over the

years and also provides for bi-annual reviews. NERC has stated that US

dollar indexation will be covered as far as possible, although payments will

be made in local currency.

Debt finance

Shareholder loans made in the course of the bid for the NIPPs and

thereafter cannot be secured against the NIPP assets. The regulations

allow shareholder loans to be treated as equity provided that (i) the loans

are unsecured and enjoy no priority over the claims of all other creditors of

the company and (ii) there are no scheduled repayments falling due within

the first 3-years of private ownership.

Like the PHCN companies, the level of gearing for NIPP companies is

capped at 70%. Similarly, any debt raised for the NIPPs can only be

secured against cash flow (i.e. securitised) and not NIPP assets. This

restriction endures for the first three years of private ownership.

Credit Enhancements to the Transaction

Partial Risk Guarantee

Once TEM starts, monthly PPA payments by NBET are backed by a PRG.

NBET is expected to have an US$800 million capitalisation fund to support

its payment obligations. NBET has also secured a 3-month DisCo payment

security backed by a Letter of Credit.

PCOA

As with the case of PHCN GenCos and IPPs, there will be a Put-Call

Option Agreement in place. The parties to the NIPPs PCOAs will be the

NIPP investor, NDPHC and NBET. The PCOA allows NDPHC to

repurchase the investor’s shares in the NIPP GenCo Company thereby

protecting the investor and lenders in the event of buyer default. The buy-


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out price will be determined post-arbitration. The shares thus bought will be

transferred back to NDPHC.

Operation of the NIPP Put-Call Option is analogous to those of the PHCN

GenCos and the IPPs45

.

Table 38: Key Dates for NIPPs

June 2013 NIPP roadshow

July 2013 Deadline for submission of EOIs for NIPP Companies

August 2013 Pre-qualified bidders for NIPP Companies announced

27 September 2013 Deadline for NIPPs pre-qualified bidders to submit comments on Industry and Transaction Agreements and the RFP.

[1 October 2013 Date initially planned for the declaration of TEM]

1 November 2013 Start of INTERIM RULES PERIOD

11 November 2013 Public opening of NIPP bid proposals

1 March 2014 Extended IRP expected to have ended and TEM declared.

TEM expected to start before end of June 2014

4 March 2014 42 technically qualified bidders for NIPP GenCos announced

7 March 2014 NIPP financial bid opening

May 2014 TEM is likely to be delayed further

[June 2014 Date initially planned for privatisation (hand over to new owners) of NIPPs]


Committed to the Process – In for a Penny, In for a Pound

The handover of privatised NIPP assets to new owners was initially

scheduled for June 2014 by which time the plants were expected to have

been completed. However the timetable has been extended. The Preferred

and Reserved bidders were only announced on 21 March. In the PHCN

privatisation schedule, Industry Agreements between the BPE and

Preferred bidders were not signed until four months after the

announcement of Preferred and Reserved bidders. No doubt the NIPP

schedule is likely to gain some time advantage based on PHCN precedent

vis-à-vis construction and terms that both parties can agree on,

nonetheless there is still a six month period between the winning bidder

paying their deposit and paying the balance of the bid amount.

By the time the preferred bidders for the NIPPs were selected, and by the

due date of payment of their bank guarantees (14 April 2014), the PHCN

companies had been privatised and were operating under the Interim Rule

Order. In Chapter 10: we explained that the Interim Rule Period was

instigated as a stop-gap before TEM was declared to give time to resolve

45

Page 41.


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significant issues concerning the business operations and the electricity

market at large that emerged post handover of assets to investors.

The PHCN privatisation process was not going as planned. The problems

discovered, hence the need to delay TEM, would no doubt be of particular

concern to the NIPP investors. The second-mover advantage that would

have been anticipated at the start – the NIPP assets are newer, there is

precedent in the process, TEM would have been well-underway.... – now

seem illusionary because the investors are already fully-committed to the

process. Thus they must travel in faith that NERC, BPE and the FGN will

resolve all issues before too long.

The NIPP bidders are in a difficult position. An apt analogy would be a

journey on an amusement park thrill/horror train ride. The train is hurtling

towards a brick wall and at the moment prospective NIPP investors are

travelling in the hope that the wall will be removed in time. They are not

welded into their seats so while they can abort mid-journey and jump off the

train, it will not be without incurring significant injury. The damage would be

financial as the financial commitment to the process in terms of fees and

man-hours is not inconsiderable. Furthermore, the damage might be by

way of opportunity loss should the wall be removed before the train hits but

after the bidder has jumped off the train.


Infrastructure


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Infrastructure


Page 169

PART V - Conclusions


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Page 170

Chapter 18:

Outlook for the Nigerian Power Sector

The reform of Nigeria’s financial and telecoms sectors have been radical.

The feted reforms of the oil and gas sector, to be heralded by the long-

awaited passing of the Petroleum Industry Bill, are likely to be even more

so in its impact. However it is evident that Nigeria has not seen a more

comprehensive reform to an industry since independence in 1960 than has

been done to the power sector.

As we mentioned in the opening chapter, the FGN deserves no prizes, to

say the least, for being in the position it was when it embarked on the

reforms. Privatising a power sector before it is anywhere near profitable is a

tacit admission of a government’s failing in its social contract with its

citizens. However since the President of Nigeria, Goodluck Jonathan,

established the Presidential Action Committee on Power (PACP) in 2010,

the reform programme has picked up pace and has been enshrined in the

Roadmap for Power Sector Reform. The concerted efforts of the electricity

regulator (NERC), the Bureau for Public Enterprises (BPE), the Ministry of

Finance and others culminated in the privatisation of the GenCo and DisCo

companies that were part of the moribund state-owned behemoth

NEPA/PHCN.

Venerunt, Viderunt, Noluerunt Vincere.46

After over five decades of stops and starts, of numerous reform agenda,

the FGN can be commended for getting the reforms and structures to the

current point of having sold controlling interests the Successor Companies

to private investors. The new institutions that are to feature in the system

have been established and staffed and to a greater or lesser extent have

begun to implement their mandates. We believe a number of features of the

new privatised regime ought to be singled out including:

The Regulatory Framework

The regulations, rules, operating codes and plans are detailed and

comprehensive. They have also been drafted in such a way that allows

them to be amended to meet market realities without having to go through

superfluous levels of bureaucracy. Online access to the governing

instruments and documents of the sector has been made possible.

However the information is yet to be accessible from a centralised point

which makes referencing time-consuming and inefficient. Improvements are

ongoing thus we believe that in time this will be put in order.

46

They came, they saw, they refused to conquer.


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The Regulator – NERC

The working relationship between NERC, the DisCos and GenCos has

been collaborative and consultative. NERC has shown itself willing to take

advantage of its latitude to change, adapt and introduce regulations to fit

the realities of the market where required. Even in the wake of the major

problems that have emerged post handover of the Successor Companies,

NERC has been viewed favourably. It is considered to understand the

requirements of the stakeholders in the market and what is necessary

to make the NESI work. It has also flexed its muscles as the regulator

of the industry to take to task entrenched interests of the old guard at

PHCN.

NERC has demonstrated commitment to carrying out its duties as a

regulator independently. Its withdrawal from the Supervisory Board of TCN

is good indication of this, in our view. Exclusion from TCN’s board ensures

arm’s-length, dispassionate, yet pragmatic oversight. Thus it can focus on

the goal to have an efficient, effective, profitable market to the benefit of all

stakeholders (customers, GenCos, DisCos, TCN, NBET) while navigating a

political system with challenging characteristics like that in Nigeria.

A hallmark of the legal and regulatory framework of successful deregulated

industries is the existence of a single central regulatory authority furnished

with comprehensive powers. Private investors and consumers rely on the

certainty provided by a clearly-identified single arbiter. The existence of a

plurality of regulatory institutions creates uncertainty and confusion for the

private investor base and we believe is likely to put off private investment,

especially in an industry with as chequered a history as Nigeria’s electricity

sector. Hence the establishment of NERC early on in 2005 was viewed as

a key win for the FGN by investors.

Intellectual Capital at Central Institutions

The intellectual and professional capital of key institutions like the regulator

NERC, NBET and TCN has been bolstered by recruiting into leadership

positions those most skilled from within the domestic power industry and

also from outside the domestic market. The FGN should be given credit for

this. Irrespective of potential, it is only with the right leadership and

management that an organisation’s goals can be realised.

Execution Risk Amplified by Inertia and Interference

Getting the right leadership, management, regulations and regulatory

structures is one thing; execution of plans is a different matter altogether.

Poor execution can relegate what is a strategic competitive advantage to

mere window-dressing.


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The industry is reliant on the FGN to follow through on transmission and

gas infrastructure build-out, wheeling of power and settlement and

payments functions. For better or for worse, some vestiges of the necrotic

NEPA regime still exists and its organisational inertia and ineffectiveness

cannot be changed overnight, even with new management. However, much

has been done to cut out the dead wood and the skill base is being

improved through investment in staff training.

Political interference in the running of commercial enterprises has been an

unfortunate hallmark of the Nigerian market, more so in the case of the

privatisation of a large country-wide utility that has had billions of US dollars

of FGN budget appropriation at its disposal. We believe that the proper

operation of the central state-controlled organisations of the NESI is

hobbled by the palpable degree of political interference that still exists. TCN

is an ideal case in point.

The issues surrounding the Market Operator and handing over control to

Manitoba Hydro International are frustrating to progress. We fail to

understand why TCN’s closing books and accounts are so opaque as to be

virtually impenetrable to audit. MHI needs to be given its full requisite

powers to fix TCN and the transmission infrastructure. Any concerns over

MHI having control over TCN’s finances should have been resolved before

the decision to go down the outsourced management route was taken in

the first place. After all, control of finances is inherent in the outsourced

management model.

The place for ongoing monitoring of MHI’s progress is via the TCN’s

Supervisory Board, which has been constituted with a sufficient number of

members to ensure very thorough supervision and oversight.

Similarly we are yet to find persuasive arguments from the FGN about why

NBET is yet to be properly funded. The FGN planned for the US$800

million to fund its operations; the FGN raised over US$3.5 billion from the

sale of the Successor Companies...

The Political Cycle and The Voter

Unfortunately we believe that Nigeria’s political cycle has amplified the

perception of the level of execution risk in the power sector. Presidential

elections are scheduled for February 2015 and concerns over how the

public would react to the drastic changes needed in the power sector,

especially increasing tariffs, is making matters particularly difficult for

NERC, NBET etc.


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Surmountable Issues but Action Required Anon

The issues and problems that have emerged are not without precedents in

other markets that have gone through similar processes. They are not fatal

to Nigeria’s privatised electric power industry, for now. However the window

for taking decisive action to rectify and resolve the problems will not stay

open indefinitely. There will soon be a point when the extent of obfuscation,

shifting of goalposts, variance from plans and overall uncertainty results in

the conclusion that the execution and/or systemic risks are too high to be

offset by potential returns.

TCN and Transmission Infrastructure

The system stands and falls with the transmission infrastructure. The

current network, were it in optimal condition, is capable of

transmitting 6,000 MW of power, practically twice as much electricity

currently being supplied. Getting to 6,000 MW wheeling capability is the

low-hanging fruit for TCN, the easy win. This will make a noticeable

difference to the end user. Experiencing such an improvement in electricity

supply will give confidence in the system and make further tariff increases,

which are invariably necessary, much easier for the end customer to

stomach.

MHI needs to be allowed to do what it is contracted to do to the full extent

without a hobbling degree of political interference. If not, and transmission

targets are not met, we believe it would be difficult for NERC or TCN’s own

supervisory board to take MHI to task for any future non-performance.

MYTO Tariffs

It is an unequivocal fact that MYTO tariffs were not set at the right

level to begin with: they were set too low. Even after the adjustments

made in the Minor Review which took effect on 1 Jun 2014, they are still too

low.

The data about the network provided to NERC, which was used in the

model was incorrect. In our view it would be an exercise in futility and will

detract from finding and implementing a solution to the morass to try to lay

blame at this stage. Doing so causes delays and is unproductive. Where

the market stands now, essentially in limbo, it is not important whether data

inaccuracies were due to operational laxity, administrative errors or that

redundancies in the system precluded the execution of a comprehensive

audit. That is not to say that transparency and accountability should not be

a high priority; far from it. Even though the system is being overhauled, it is

important to note where the infrastructure and manpower weaknesses in

the system have been and to address them appropriately to prevent a

recurrence in the brave new world of the privatised NESI.


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Tariffs Must Increase – Ground Zero Needs to be Reset

The inaccurate underlying technical assumptions have been compounded

by the generation capacity being off-target. Current generation capacity is

(3,400 MW versus the 9,000 MW MYTO projected):

1. Tariffs must increase so that they are cost-reflective and meet

the Revenue Requirement of the industry. Otherwise the NESI is

not sustainable and will not be investable.

2. The FGN is likely very sensitive to adverse reception by the

electorate to increasing tariffs. In view of this it might be reluctant to

raise tariffs to the cost-reflective level the industry requires. The

solution, therefore, would be for the FGN to accept that it will

need to make up the difference by funding deeper tariff

subsidies for longer than the two to three years it initially

anticipated.

Lending banks will need to see that the businesses are viable. They are not

viable if the tariffs do not cover the Revenue Requirement. As in other

privatisations where tariff controls have existed, banks and lending

institutions are pragmatic and they would by and large be willing to proceed

on the guarantee from the authorities that within a defined timeframe, tariffs

(ex-subsidies) will be cost-reflective.

Bankability and Raising Expansion Capex

The essential industry agreements need to be bankable or else investors

will not be able to raise the capital required from financing institutions. By

its own admission, the FGN does not have the financial leverage to fund

the industry. The Nigerian power sector will need to raise US$13-15 billion

for capital expenditure over the next five years and another US$7.5-10

billion is required for the supporting gas infrastructure.

The Nigerian banking sector on its own or in conjunction with the FGN will

not be able to fund the power sector’s expansion plans. Furthermore, even

if the local banking sector could fund it, the financial regulatory authority

and the banks’ internal risk management would require bankable

documents to extend financing beyond what has been done so far. Current

plans will not be realised without external (non-local) financing and the

NESI will not be able to tap the international finance market without

bankable documents.


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Transitional Electricity Market

The current no-man’s land of the Interim Rules Period needs to be wound

up. TEM is too long overdue. The uncertainty that currently exists will put

off further investment in the sector, in our view. There will be teething

issues when TEM starts. We understand that the authorities could be using

the opportunity of the post-privatisation kerfuffle and morass to anticipate

some of TEM issues and resolve them ahead of its. Notwithstanding, the

market must be in TEM in order to know the full measure of the issues of

TEM.

The full operation of NBET, credit enhancements such as the PRG and the

other laudable aspects of the reformed system do not come into force until

TEM. So at the moment there is little change from the old NEPA/PHCN

regime other than the fact that private investors have now committed to the

sector.

The FGN cannot hide behind the fact that control now lies in private hands

so the onus of performance is on the new owners. For good reasons, the

FGN still regulates tariffs. In addition, the state of the industry necessitated

that it retain control and responsibility for transmission infrastructure. Thus

investors have their hands tied vis-à-vis the commercial flexes they can

wield to compensate for unexpected shortfalls, for example. For the time

being the FGN is somewhat cushioned from public backlash over the lack

of power. As far as the public is concerned, the industry has been

privatised so the blame lies with the new owners. However, the laudable

increase in transparency and information flow in the sector means that

there is only so long this perception will persist before the spotlight shifts to

also encompass the FGN once more.

A Phased Transition to TEM?

One of the factors holding up TEM is that some DisCos clearly require

more time than others to get the houses they were sold in sufficient order

for the starting line. A solution to prevent further delay to TEM could be to

institute a 2-phased entry to the new regime. The bulk of DisCos and

GenCos can begin under the full operation of the TEM regime, while the

second group will be introduced within a strictly-defined time period. We

believe that this could necessitate the FGN providing specific financial

support for the second group during their transition and qualifications of

some of the bilateral obligations of TEM as they apply to the second group.

Notwithstanding, the overall benefit to the industry would surpass the

additional cost in our view. It would be more efficacious to pull the second

group over the starting line than to wait to push the entire group over the

line.


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Market Idiosyncrasies and the Future of the NESI

The FGN must make the new NESI regime work. It has gone too far down

the process for it not to. It will have to accept that the costs of the process

to the national account will be higher than anticipated but it will have to

chalk that up to the price it has to pay for privatising the industry at this

stage of development. The future benefits to all stakeholders far outweigh

any short-term discomfort the FGN might have. Crucially though, we do not

believe the NESI will flourish unless it is left to work without undue political

interference and operation of vested interests.

Frontier Market with Potential for Sizeable Returns, But...

From investors’ perspective the high risk profile is inherent in Nigeria

having the characteristics of a Frontier Market. Nigeria itself has particular

idiosyncrasies that may warrant an additional risk premium. It is also

inherent in those very idiosyncrasies that when it comes to an initiative so

critical to the future prosperity of the nation, and that of key individuals

invested in it, the Nigerian system has a way of muddling through, of

making it all come right in the wash, as the saying goes.

The road will be bumpy but the potential returns on a ‘mass market’

product/service in a country the size of Nigeria could more likely than

not outweigh the higher risks. We could point to Nigeria’s liberalised

mobile telecommunications sector as demonstrating this dialectic;

however we do not imply that the trajectory will necessarily be the

same for power.

As far as affordability of the product/service (the tariff level) for the mass

market is concerned, the experience of the mobile operators in the

privatised telecommunications market just so happens to serve as a good

example as well. The National Bureau of Statistics (NBS) reported monthly

household expenditure on mobile pre-paid cards was ₦20,874 (US$130)

per household. Compared with this, many households, in our experience,

pay ₦4,000-6,000 (US$25-38) per month in electricity bills for less than 12

hours of electricity per day. In our view this is probative empirical evidence

that on the specific issue of affordability, the end-user is willing and able to

pay a higher tariff provided the service is being supplied.


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Winners and Losers

In the long run, the different starting points and addressable markets of the

DisCos means that some will struggle to meet their payments more than

others, especially if TEM continues to be delayed. The GenCos are in a

less perilous position due to the fact that risks are skewed in their favour.

Moreover the links to market for generation are simpler (gas power

generator transmission network); they do not have to contend with

numerous connections to the end customer. The FGN is also under

pressure to perform, not least due to the severe financial penalties it will

incur should a PRG become engaged.

Cautionary Tale

The key take-away is that if tariffs do not rise to a level that covers

costs and offers a reasonable return to investors (the Revenue

Requirement), the Nigerian electricity supply industry will not be a

viable long term investment opportunity. We understand political

sensitivities about the effect of tariff increases on the public however we

believe this threat to be overstated. We would strongly encourage NERC

and the FGN against resisting raising tariffs and would cite the California

Electricity Crisis of 2000 and 2001 as a cautionary tale.

In the years leading up to the denouement, the US state of California like

Nigeria, suffered from blackouts brought on by a shortage of electricity. The

reasons for the shortage differ in both cases but the economic principles at

work are the same. The California state government had a cap on retail

prices but the wholesale price was set by the market. Thus when a severe

electricity supply-demand gap opened, there followed a drastic rise in the

wholesale price of electricity i.e. the costs of the GenCos and DisCos doing

business. As end-user tariffs were capped, the industry’s revenue margins

were squeezed. This eventually led to more blackouts, the eventual

bankruptcy of the state’s largest electricity company and the near

bankruptcy of several more. The economic fallout of the crisis had a

considerable negative impact on the political standing of the then state

governor Gray Davis and was material to his eventual recall. In October

2003 he became the second governor to be recalled in American history.


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Investment Conclusion

Irrespective of the rhetoric, given what has transpired over the last nine

months and noting more recent public pronouncements by governing

bodies, we would advise caution for the time being. For us to have a more

bullish view on investing in the Nigerian Electricity Supply Industry we

would need:

1. To see the MYTO model take into account the reality of the

Successor DisCos and GenCos; we believe this will invariably

mean that the Revenue Requirement will increase.

2. Higher Revenue Requirement would mean higher tariffs and we

would need to see a clear schedule showing commitment to get the

tariffs to the required level and/or FGN commitment to subsidies to

make up the gap in the interim.

3. TEM needs to start and we need to see NBET and TCN

demonstrating they are capable of operating as they are set out to.

We are pragmatic and appreciate that there will be minor teething

problems. This to be expected under the circumstances.

In the long run, we believe that while the Nigerian electricity supply market

could become an open-traded market, as planned, the market could likely

end up with a two-tier structure. One would have customers relying on

power from the national grid and the other with customers in an

IPP/embedded generator framework. What the former lacks in reliability

would be off-set by lower tariffs than the IPP/embedded framework. The

IPP/embedded framework will exhibit high reliability of service in exchange

for higher tariffs than the grid-connected system.

Mille viae ducunt homines per saecula Romam47

There are numerous paths to improving the generation and delivery of

power in the Nigerian Electricity Supply Industry. It matters little to the end

customer, be they households or industry, whether their electricity comes

from the national grid or from embedded generator IPPs. The system has

to deliver what it has been set up to deliver. This will involve all

stakeholders in and connected to the industry delivering on their declared

obligations in time and within reasonable financial parameters. As the

driver and overseer of the new market, it behoves the FGN to ensure

that the NESI works in practice as the paper says it says it should and

would. At this stage the onus of management of the execution risk of

the system lies with the FGN.

47

“A thousand roads lead men forever to Rome” in Liber Parabolarum,591 (1175), by Alain de Lille.


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APPENDICES


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Page 180

Appendix 1: Winning Bidders of

Successor (PHCN) DisCos and GenCos

Co

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(Sta

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me

nt fe

e (

the

bid

price

);

2)

Y1

-Y5

- a

ro

yalty p

aym

ent

of

5%

of

pla

nt re

ve

nue

s;

3)

Y6

-Y1

5 -

a f

ixe

d a

nnual fe

e

of

US

$5

0,7

60

,66

5.1

8.

19

68

, 1

97

8+

Vic

e-C

hairm

an: Is

maila I

sa F

untu

a,

+ C

ol. S

ani B

ello

(rt

d.)

, fo

rme

r m

ilitary

ad

min

istr

ato

r o

f K

ano

Sta

te.

+ O

khai A

khig

be

, fo

rme

r C

hie

f o

f G

ene

ral S

taff

.

+ T

und

e O

gb

eha, fo

rme

r S

enato

r.

+ R

ussia

's R

usH

yd

ro =

te

chnic

al p

art

ne

r.

+ F

inance

d b

y G

uara

nty

Tru

st B

ank a

nd

Afr

ican F

inance

Co

rpo

ratio

n.

5..

Sa

pe

le P

ow

er P

lc

[Gas]

De

lta

1,0

20

24

0O

n-G

rid

CM

EC

/EU

RA

FIC

Ene

rgy

Co

nso

rtiu

m

[Chin

a M

achin

ery

&

Eng

ine

ering

Co

rp. +

EU

RA

FIC

Ene

rgy N

ig. L

d.,

British P

ow

er

Intl.+

First

Bank]

2

01

.0

10

0%

19

78

, 1

98

3+

To

ny O

no

h h

ead

s E

UR

AF

RIC

Ene

rgy, an o

il a

nd

gas f

irm

invo

lve

d in e

xp

lora

tio

n a

nd

pro

ductio

n. It

is p

art

of

G-E

ura

fric

, a

Nig

erian g

roup

of

co

mp

anie

s invo

lve

d in e

ne

rgy, p

etr

oche

mic

als

,

avia

tio

n, p

rop

ert

y a

nd

co

mm

od

ity tra

din

g.

+ C

ME

C is a

n inte

gra

ted

eng

ine

ering

firm

eng

ag

ed

in p

roje

ct

co

ntr

acting

, in

tern

atio

nal tr

ad

e a

nd

re

late

d s

erv

ice

s. It

s m

ain

are

as

of

op

era

tio

n a

re p

ow

er

ge

ne

ratio

n a

nd

dis

trib

utio

n, tr

ansp

ort

atio

n,

min

ing

and

re

so

urc

e e

xp

lora

tio

n a

nd

ho

usin

g d

eve

lop

me

nt.

6..

Sh

iro

ro

Hy

dro

Ele

ctr

ic P

lc

Nig

er

60

01

11

On-G

rid

No

rth S

outh

Po

we

r

[Nig

er

Sta

te g

ove

rnm

ent +

XS

Ene

rgy L

td. +

BP

Inve

stm

ent L

td. +

Urb

an

She

lte

r L

td. +

Ro

ad

Nig

eria

Plc

+ C

hin

a I

nte

rnatio

nal

Wate

r E

lectr

ic +

Chin

a

Thre

e G

org

es C

orp

ora

tio

n]

1

11

.7

No

t an o

utr

ight sale

but a 1

5-

yr

co

nce

ssio

n, th

e f

ee

str

uctu

re b

ein

g:

1)

A c

om

me

nce

me

nt fe

e (

the

bid

price

);

2)

Y1

-Y5

- a

ro

yalty p

aym

ent

of

5%

of

pla

nt re

ve

nue

s;

3)

Y6

-Y1

5 -

a f

ixe

d a

nnual fe

e

of

US

$2

3,6

02

,48

4.4

7.

19

89

+ V

ice

-Chairm

an: O

lub

unm

i P

ete

rs.

+ U

BA

arr

ang

ed

de

bt financin

g.

+ C

hin

a T

hre

e G

org

es C

orp

ora

tio

n a

lso

ove

rse

es the

Zung

eru

70

0M

W h

yd

roe

lectr

ic p

ow

er

pro

ject in

Nig

er

Sta

te.

7..

Ug

he

lli P

ow

er P

lc

[Gas]

De

lta

94

23

20

On-G

rid

Tra

nsco

rp C

onso

rtiu

m

[Tra

nsnatio

nal C

orp

ora

tio

n

of

Nig

eria +

Wo

od

rock

Sym

bia

n +

Me

de

a +

PS

L +

Tho

masse

n]

3

00

.0

10

0%

19

66

+ C

hairm

an: T

ony E

lum

elu

(via

He

ir H

old

ing

s L

td. H

H c

om

mitte

d

US

D2

25

mn thro

ug

h d

eb

t financin

g u

nd

erw

ritte

n b

y A

fric

an F

inance

Co

rp., U

BA

and

FC

MB

).

+ W

oo

dro

ck is a

n A

me

rican m

ulti-se

rvic

es f

irm

.

So

urc

e: C

SL

Re

se

arc

h

TH

E P

RIV

AT

IST

ED

PH

CN

GE

NC

OS


Infrastructure


Page 181

Co

mp

an

y N

am

e

Lo

ca

tio

n

(Sta

te)

Co

ve

rag

e

Are

as

Po

pu

lati

on

De

ns

ity

(pe

r k

m2)

Dis

trib

uti

on

(GW

h)

Win

nin

g B

idd

ers

Bid

(US

$ m

n)

5-y

r

Ca

pe

x

Sta

ke

Ac

qu

ire

d

Oth

er

De

tails

1

,45

7.5

1..

Ab

uja

Ele

ctr

icit

y D

istr

ibu

tio

n C

o.

FC

T, N

ige

r,

Ko

gi ,

and

Nassara

wa

Gark

i, L

afia,

Lo

koja

, M

ina

83

1

,80

2

KA

NN

Co

nso

rtiu

m U

tility

Co

. L

td.

[Co

pp

erb

elt

Ene

rgy

Co

rpo

ratio

n (

CE

C)

+

Xe

rxe

s G

lob

al I

nve

stm

ents

]

1

64

.0

1

83

.0

60

%+

Chairm

an: S

he

hu M

ala

mi (

form

er

Chair o

f C

osta

in a

nd

PZ

Cusso

ns)

+ M

anag

ing

Dire

cto

r: N

eil

Cro

uche

r o

f Z

am

bia

-base

d C

EC

. C

EC

ge

ne

rate

s, tr

ansm

its a

nd

dis

trib

ute

s e

lectr

icity

to

the

min

ing

se

cto

r in

Zam

bia

, D

R C

ong

o a

nd

So

uth

Afr

ica.

+ 5

0/5

0 J

V w

ith N

ige

ria's

Xe

rXe

s G

lob

al I

nve

stm

ents

.

+ N

eil

Cro

uche

r o

f Z

am

bia

base

d C

EC

has b

ee

n a

pp

oin

ted

Manag

ing

Dire

cto

r o

f K

AN

N.

+ S

tand

ard

Bank

of

So

uth

Afr

ica (

SB

SA

) and

Sta

nb

ic I

TC

pro

vid

ed

de

bt financin

g a

nd

fin

ancia

l ad

viso

ry s

erv

ice

s.

2..

Be

nin

Ele

ctr

icit

y D

istr

ibu

tio

n C

o.

Ed

o, D

elta

,

Ond

o, and

part

of

Eki

ti

Ad

o-E

kiti,

Akp

akp

ava

,

Aku

22

9 1

,85

5

Vig

eo

Po

we

r C

onso

rtiu

m

Ltd

.

[Vig

eo

Ho

ldin

gs +

Tata

Po

we

r D

elh

i Dis

trib

utio

n L

td

+ C

alc

utta E

lectr

ic S

up

ply

Co

rp. +

Afr

ican F

inance

Co

rpo

ratio

n]

1

29

.0

2

50

.0

60

%+

Chairm

an: V

icto

r G

bo

lad

e O

sib

od

u

+ C

EO

: F

unke

Osib

od

u. F

orm

er

Manag

ing

Dire

cto

r o

f U

nio

n B

ank;

wife

of

Vic

tor

Osib

od

u.

+ V

ige

o H

old

ing

s is

a d

ive

rsifie

d in

dustr

ial c

om

pany,

with

one

of

its

sub

sid

iarie

s b

ein

g G

lob

al U

tiliti

es M

anag

em

ent C

om

pany.

GU

MC

has p

rovi

de

d m

ete

ring

sys

tem

s to

the

Be

nin

Ele

ctr

icity

Dis

trib

utio

n

Co

. fo

r th

e la

st fe

w y

ears

, und

er

the

Natio

nal P

rep

aym

ent M

ete

ring

Pro

gra

mm

e.

+ S

tanb

ic I

BT

C p

rovi

de

d d

eb

t financin

g a

nd

assis

ted

in r

ais

ing

eq

uity

fo

r th

e a

cq

uis

itio

n.

3..

Ek

o E

lec

tric

ity

Dis

trib

uti

on

Co

.L

ag

os

Fe

sta

c, Ijo

ra,

Isla

nd

s,

Bad

ag

ry

2

,48

3

1

,44

0

We

st P

ow

er

& G

as

Co

nso

rtiu

m

[Alp

ha C

onso

rtiu

m L

td +

Atla

ntic

Me

rid

ean L

td. +

Afr

ica I

nfr

astr

uctu

re

Inve

stm

ent M

anag

ers

]

1

35

.0

2

50

.0

60

%+

Chairm

an, C

harle

s M

om

oh. H

e is

als

o M

anag

ing

Dire

cto

r o

f

Atla

ntic

and

oil

ind

ustr

y se

rvic

es c

om

pany.

+ T

unji

Olo

wo

lafe

is the

Chairm

an a

nd

Manag

ing

Dire

cto

r o

f D

eux

Pro

ject L

td a

civ

il e

ng

ine

ering

, co

nstr

uctio

n a

nd

co

nsulta

ncy

co

mp

any.

De

ux

is in

volv

ed

in s

eve

ral P

PP

infr

astr

uctu

re p

roje

cts

.

+ E

rne

st O

rji c

hairs A

lpha, a u

tiliti

es o

uts

ourc

ing

, m

ete

ring

and

pro

ject m

anag

em

ent firm

.

+ G

erm

any'

s S

iem

ens L

td is

the

te

chnic

al p

art

ne

r.

+ A

IIM

is a

priva

te e

quity

infr

astr

uctu

re in

vestm

ent firm

co

-ow

ne

d b

y

Macq

uarie

and

Old

Mutu

al I

nve

stm

ent G

rp.

4..

En

ug

u E

lec

tric

ity

Dis

trib

uti

on

Co

.E

nug

u, A

bia

,

Imo

,

Anam

bra

and

Eb

onyi

Ab

a,

Ab

aka

liki,

Aw

ka,

Ab

akp

a

56

6 1

,92

0

Inte

rsta

te E

lectr

ic L

td

Co

nso

rtiu

m

[Chro

me

Co

nso

rtiu

m

Ene

rgy

Ltd

. +

Po

we

rho

use

Inte

rnatio

nal L

td. +

Me

tro

po

litan E

lectr

icity

Auth

ority

of

Thaila

nd

]

1

26

.0

1

36

.0

60

%+

Chairm

an: E

me

ka O

ffo

r w

ho

is a

lso

chair o

f C

hro

me

Ene

rgy

Ltd

a

co

mp

any

eng

ag

ed

in o

il and

gas s

erv

ice

s, te

leco

mm

unic

atio

ns a

nd

log

istic

s.

+ T

echnic

al p

art

ne

rs a

re P

ow

er

Ho

use

Inte

rnatio

nal a

nd

Me

tro

po

litan

Ele

ctr

icity

Auth

ority

of

Thaila

nd

.

5..

Iba

da

n E

lec

tric

ity

Dis

trib

uti

on

Co

.O

yo, O

gun,

Osun, K

wara

and

part

of

Eki

ti

Ab

eo

kuta

,

Dug

be

, ije

bu-

Od

e

17

2 1

,98

9

Inte

gra

ted

Ene

rgy

Dis

trib

utio

n &

Mark

etin

g

Co

mp

any

1

69

.0

2

19

.0

60

%+

17

.46

% A

TC

&C

loss r

ed

uctio

n

+ F

orm

er

Pre

sid

ent A

bd

uls

ala

m A

bub

aka

r chairs I

ED

MC

an o

il and

gas c

om

pany.

+ V

ice

Chairm

an: T

und

e A

yeni.

On the

bo

ard

s o

f S

kye

Bank

and

Aso

Savi

ng

s &

Lo

ans P

lc.

+ M

anila

Ele

ctr

ic C

om

pany

is T

he

Phili

pp

ine

s' l

ead

ing

ele

ctr

icity

dis

trib

utio

n c

om

pany,

is the

te

chnic

al p

art

ne

r.

6..

Ike

ja E

lec

tric

ity

Dis

trib

uti

on

Co

.L

ag

os

Alim

osho

,

Ike

ja,

Iko

rod

u,

2

,48

3

2

,07

7

NE

DC

/KE

PC

O C

onso

rtiu

m

[Ne

w E

lectr

icity

Dis

trib

utio

n

Co

mp

any

+ K

ore

an E

lectr

ic

Po

we

r C

orp

. +

Sahara

Ene

rgy

Re

so

urc

es]

1

31

.0

2

93

.0

60

%+

Chairm

an: K

ola

Ad

esin

a.

+ T

op

e S

onub

i and

To

nye

Co

le v

ia S

ahara

Oil

& G

as, a

do

wnstr

eam

se

rvic

es c

om

pany.

TH

E P

RIV

AT

ISE

D P

HC

N D

ISC

OS

So

urce

: CS

L R

ese

arc

h


Infrastructure


Page 182

Co

mp

an

y N

am

e

Lo

ca

tio

n

(Sta

te)

Co

ve

rag

e

Are

as

Po

pu

lati

on

De

ns

ity

(pe

r k

m2)

Dis

trib

uti

on

(GW

h)

Win

nin

g B

idd

ers

Bid

(US

$ m

n)

5-y

r

Ca

pe

x

Sta

ke

Ac

qu

ire

d

Oth

er

De

tails

1

,45

7.5

7..

Jo

s E

lec

tric

ity

Dis

trib

uti

on

Co

.P

late

au,

Bauchi,

Be

nue

and

Go

mb

e

Bauchi,

Go

mb

e, Jo

s,

Maku

rdi

10

7 7

14

A

ura

Ene

rgy

Ltd

.

Co

nso

rtiu

m

[Aura

Ene

rgy

Ltd

. +

Ayd

em

Ele

ktrik

Dag

itim

A.S

.]

8

2.0

1

13

.0

60

%+

Mo

ham

me

d N

om

a c

hairs A

ura

. H

e is

the

fo

rme

r sp

eake

r o

f th

e

Ho

use

of

Asse

mb

ly in

Bauchi S

tate

in the

First R

ep

ub

lic.

+ A

yde

m E

lekt

rik

is a

we

ll-e

sta

blis

he

d e

lectr

icity

dis

trib

uto

r in

Turk

ey.

8..

Ka

du

na

Ele

ctr

icit

y D

istr

ibu

tio

n C

o.

Kad

una,

So

koto

,

Ke

bb

i and

Zam

fara

11

3 1

,23

3

No

rthw

est P

ow

er

Ltd

. 2

01

.0

1

49

.0

60

%+

Kad

una D

isco

and

Afa

m G

enC

o w

ere

no

t p

riva

tise

d a

long

with

the

oth

er

PH

CN

co

mp

anie

s b

ecause

no

bid

de

rs m

et th

e te

chnic

al

crite

ria. In

ord

er

no

t to

sta

ll th

e s

ale

s, th

e B

ure

au o

f P

ub

lic

Ente

rprise

(B

PE

) in

itiate

d a

Pla

n B

whe

re the

pre

-qualif

ying

bid

de

rs

we

re a

ske

d to

re

sub

mit

the

ir b

ids. N

ort

hw

est P

ow

er

em

erg

ed

as the

win

ne

r fo

r th

e K

ad

una D

isco

with

+ 2

9.2

6%

A

TC

&C

loss r

ed

uctio

n

(and

Tale

vera

s G

roup

the

win

ne

r o

f A

fam

).

+ T

ransactio

n d

ue

to

clo

se

be

fore

end

of

Q1

20

14

.

+ C

hairm

an o

f N

ort

hw

est P

ow

er

is Y

usuf

Ham

isu A

bub

aka

r, a

Co

mm

issio

ne

r at th

e N

ige

rian C

om

munic

atio

ns C

om

mis

sio

n (

NC

C),

bo

ard

me

mb

er

at N

ige

r In

sura

nce

Co

mp

any.

He

is a

lso

the

CE

O/M

D

of

Sahe

lian P

ow

er

Co

nso

rtiu

m, w

innin

g b

idd

er

of

Kano

Dis

co

.

9..

Ka

no

Ele

ctr

icit

y D

istr

ibu

tio

n C

o.

Kano

,

Jig

aw

a a

nd

Kats

ina

Dala

, D

uts

e,

Funtu

a, K

ati

29

1 7

88

S

ahe

lian P

ow

er

SP

V L

td.

Co

nso

rtiu

m

[Incar

Po

we

r L

td. (I

PL

) +

Danta

ta I

nve

stm

ents

&

Se

curitie

s +

Sahe

lian

Ene

rgy

& I

nte

gra

ted

Se

rvic

es (

SE

IS)

+ H

ighla

nd

Ele

ctr

icity

Ltd

. (H

EL

) +

Kays

eri V

e C

ivari E

lekt

rik

T.A

.S. (K

CE

TA

S)]

1

37

.0

1

51

.0

60

%+

Chairm

an o

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Infrastructure


Page 183

Successor Company Consortium/SPV Listed Investor* Ticker Exchange Comment

Abuja DisCo KANN Consortium Utility Co. Ltd.

[Copperbelt Energy Corporation (CEC) + Xerxes Global

Investments]

Copperbelt Energy Corp. CEC.ZM Lusaka Stock Exchange

Afam GenCo Taleveras Energy Group

[Alstom Nig. Ltd. + Rivers State government + Taleveras

Petroleum Trading]

Alstom (parent of Alstom

Nig.)

ALO:EPA Euronext Paris

500400:BOM Bombay Stock Exchange

TATAPOWER:NSE National Stock Exchange of India

CESC Bombay Stock Exchange

CESC:IN National Stock Exchange of India

015760:KRX Korea Exchange

KEP:NYSE New York Stock Exchange

OML.L London Stock Exchange

OMLJ.J Johannesburg Stock Exchange

Maquarie via AIIM MQG:ASX Australia Securities Exchange

SIE:GR Deutsche Börse

SIE:LON London Stock Exchange

SIE:VX Schweizer Börse

Enugu DisCo Interstate Electric Ltd Consortium

[Chrome Consortium Energy Ltd. + Powerhouse

International Ltd. + Metropolitan Electricity Authority of

Thailand]

Geregu GenCo Amperion Power Distribution Co. Ltd

[Forte Oil Nig. Ltd. + BSG Resources + Shanghai

Municipal Electric Power Company]

Forte Oil FO:NL Nigerian Stock Exchange

Ibadan DisCo Integrated Energy Distribution & Marketing Company Manila Electric (MERALCO) MER:PM The Philippine Stock Exchange MERALCO is the

technical partner

015760:KRX Korea Exchange

KEP:NYSE New York Stock Exchange

Jos DisCo Aura Energy Ltd. Consortium

[Aura Energy Ltd. + Aydem Elektrik Dagitim A.S.]

Kaduna DisCo Northwest Power Ltd.

Kano DisCo Sahelian Power SPV Ltd. Consortium

[Incar Power Ltd. (IPL) + Dantata Investments &

Securities + Sahelian Energy & Intergrated Services

(SEIS) + Highland Electricity Ltd. (HEL) + Kayseri Ve

Civari Elektrik T.A.S. (KCETAS)]

CESC Bombay Stock Exchange

CESC:IN National Stock Exchange of India

CMEC 1829:HKG Hong Kong Stock Exchange

FBN Holdings (First Bank) FBNH:NL Nigerian Stock Exchange

Shiroro Hydro GenCo North South Power

[Niger State government + XS Energy Ltd. + BP

Investment Ltd. + Urban Shelter Ltd. + Road Nigeria Plc +

China International Water Electric + China Three Gorges

Corporation]

Ughelli GenCo Transcorp Consortium [Transnational Corporation of

Nigeria + Woodrock Energy + Symbion Power + Medea

Development + PSL + Thomassen Holding]

Transcorp TRANSCORP:NL Nigerian Stock Exchange

RusHydro HYDR:RM Mosco Exchange (MICEX)

HYDR:LON London Stock Exchange

Yola DisCo Integrated Energy Distribution & Marketing Company


* NOTE: This table is meant to be representative. We have aimed to be as comprehensive as possible. However detailed information on the nature and structure of stakeholdings within the various

consortia is limited and not always readily availabe. Thus it is not always possible to identify all the direct interests of listed entities.

Eko DisCo

Ikeja DisCo NEDC/KEPCO Consortium

[New Electricity Distribution Company + Korean Electric

Power Corp. + Sahara Energy Resources]

Korean Electric Power Corp.

Port Harcourt DisCo 4Power Consortium

[Taleveras Grp. + Lilleker Bros. Nig. Ltd. + Income

Electrix Ltd./CESC Ltd JV + Skyview Power

Technologies Ltd + Akwa Ibom Investment & Industrial

Promotion Council (AKIIPOC) + Paradise Power Nig. Ltd.

+ Bayelsa Electricity Company + Calcutta Electric Supply

Corporation Ltd. (CESC)]

CESC

West Power & Gas Consortium

[Alpha Consortium Ltd + Atlantic Meridean Ltd. + Africa

Infrastructure Investment Managers]

Siemens is the technical

partner

Old Mutual via OMIG in AIIM

Siemens

LISTED INVESTORS IN WINNING CONSORTIA FOR SUCCESSOR COMPANIES

CMEC/EURAFIC Energy Consortium

[China Machinery & Engineering Corp. + EURAFIC

Energy Nig. Ld., British Power Intl.+ First Bank].

Sapele GenCo

Kainji Hydro GenCo Mainstream Energy Solutions Ltd.

[Col.Sani Bello + RusHydro]

AIIM is co-owned by

Macquarie and Old

Mutual Investment Group

CESC

Benin DisCo Vigeo Power Consortium Ltd.

[Vigeo Holdings + Tata Power Dehli Distribution Ltd +

Calcutta Electric Supply Corp. + African Finance

Corporation]

Tata Power via TPDDL Tata Power owns 51% of

TPDDL

NEDC/KEPCO Consortium

[Korean Electric Power Corp. + Sahara Energy

Resources]

Korean Electric Power Corp.Egbin GenCo


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Appendix 2: Key Regulatory Institutions

Nigerian Power Sector – Key Industry Participants

Energy Commission of Nigeria (ECN) Established in 2008 for the strategic planning and co-

ordination of policies in the energy industry.

Federal Ministry of Power Concerned with policy and oversight of the Nigerian

Electricity Supply Industry (NESI)

Gas Aggregation Company of Nigeria (GACN)

Established in 2010 to manage the implementation of domestic gas supply obligation regulations.

Will act as the facilitator between suppliers and purchasers of natural gas.

Independent Power Producers (IPPs) Eight power plants with an installed capacity of 2,127 MW of

which 1,320 MW is available.

Plants use either gas or oil.

Niger Delta Power Holding Company Ltd (NDPHC)

Holding company of NIPP Companies

Nigeria Electricity Regulatory Commission (NERC)

Independent agency established to regulate the power sector in Nigeria.

Led by seven Commissioners representing six geopolitical zones and one Commissioner who serves as the Chairman and Chief Executive Officer.

Responsible for, inter alia: - The issuance and renewal of generation, transmission

and distribution licences. - The determination of tariffs that sector participants may

charge for their products and services. - Monitor the operation of the Nigerian Electricity Supply

Industry (NESI) - Setting and amending, where necessary, rules and

standards of the industry.

Nigeria System Operator (NSO)

Primarily responsible for the planning, dispatch and operation of the transmission system.

Also charged with maintaining the security and reliability of the national electricity grid.

Once the Transitional Electricity Market (TEM) is declared, TCN will assume this role.

Nigerian Bulk Electricity Trading PLC (NBET)

Once the Transitional Electricity Market (TEM) is declared, NBET will be the State entity responsible for purchasing electricity from generation companies under long term Power Purchase Agreements and selling it to distribution companies.

Nigerian Electricity Liability Management Company (NELMCO)

Established in 2006 to assume and manage the liabilities and non-core assets of the PHCN successor companies in order that they be sold to private investors with clean balance sheets.

It is a company limited by FGN guarantee.

Nigerian Gas Company Limited (NGC)

One of the subsidiaries of Nigerian National Petroleum Corporation.

Responsible for the transportation of natural gas through its pipeline network.



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Nigerian Power Sector – Key Industry Participants (continued)

NIPP Generation Companies (NIPPs)

10 Companies, each owning one gas-fired plant and transmission infrastructure in associated distribution zones.

Launched in 2004 under separate independent holding company, (NDPHC) to the PHCN power plants.

Intended as a fast-track initiative to provide 4,500 MW of power.

The NIPPs are currently in the process of being privatised.

Operator of the Nigerian Electricity Market (ONEM)

Licensed to function as the Market Operator of the wholesale electricity market until the start of the Transitional Electricity Market (TEM) when TCN will assume this role.

It is the administrator of the metering system among generation, transmission and distribution companies.

Settlements and overall operation of the electricity market are within its remit.

PHCN Successor Distribution Companies (Successor DisCos)

11 distribution companies covering all 36 states and the Federal Capital Territory.

Privatised in February 2013. Assets handed over to new investors in November 2013.

Power Holding Company of Nigeria (PHCN) Successor Generation Companies (Successor GenCos)

Six power generation companies created in the unbundled state power company PHCN, the successor company to the vertically-integrated Nigerian Electric Power Authority (NEPA).

Two hydroelectric plants and four gas fired plants.

Privatised in February 2013. Assets handed over to new investors in November 2013.

Presidential Task Force on Power (PTFP)

Created in 2010 as the implementing arm of the Presidential Action Committee on Power (PACP)

It is responsible for coordinating the activities of the numerous agencies in the promotion of private sector involvement in the Nigerian power sector. In this vein, a key part of its role is to eliminate red tape and inefficient decision-making in government.

Another key duty is to monitor the planning and execution of various short-term projects in generation, transmission, distribution and fuel-to-power that are essential to achieving the targets of the power industry as set out in the Roadmap to Power Sector Reform.

Rural Electrification Agency

A parastatal under the Ministry of Power, it was established under the EPSR Act and charged to promote, support and extend the supply of electricity to rural and semi-urban areas of the country.

It administers the Rural Electrification Fund (REF)

Transmission Company of Nigeria (TCN)

State entity responsible for the transmission of electricity from power plants to distribution companies, eligible customers and for export.

Acts as both the market operator and system operator.

Managed by Manitoba Hydro International of Canada under a three-year management contract.



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Appendix 3: Australia’s Tariff Methodology

The methodology adopted by NERC for MYTO is most typically used in electricity markets where the regulator

imposes a degree of control over prices. For example, in Australia the retail tariff in most states is set at a level

generation and distribution companies can recover their costs plus a “reasonable” margin, here between 3-

10%. The costs are those the regulator deems an efficient retailer would expect to incur.

The components of the costs that feed into retail tariffs are depicted in Table 39:

Table 39: Costs that Feed into Retail Electricity Prices in Australia’s National Electricity Market (NEM)

Approx. % of Retail Prices Recoverable Costs

Retail Operating Costs plus a Margin

Reset every 1-3 years 20% Customer acquisition and retention expenses, meter reading, billing and marketing

Network Costs

Reset every 5 years.

Network revenues capped by the Australian Energy Regulator

51%

Transmission Charges

10% Operational & maintenance expenditure e.g. wages, rent; return on capital (the largest components for both transmission and distribution networks); asset depreciation costs; tax liabilities

Distribution Costs

~35-50%

Wholesale Electricity Generation Costs

Determined every 5 minutes.

Set in the National Electricity Market.

Price cap exists but is rarely binding.

20%

Carbon Price 9%

Source: CSL Research, Australian Energy Market Operator

The NEM interconnects five regional market jurisdictions (Queensland, New South Wales, Victoria, South Australia and Tasmania). West Australia and Northern Territory are not connected to the NEM.

NEM infrastructure comprises both state and private assets managed by many participants. It has a total electricity generating capacity of around 50,000 MW.


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Appendix 4: MYTO II Methodology in Detail

MYTO II Electricity Generation Prices

Method Used for the Revenue Requirement for Generation:

Long Run Marginal Cost (LRMC). This method looks at the full life cycle costs of the lowest (cost) efficient

new entrant generator.

Application

1. Benchmark costing creates a proxy market price for an efficient generator.

2. Individual LRMC for each generator depending on its location and plant-specific characteristics.

Component Costs that Need to Be Covered:

Fuel, capital (capex and depreciation), fixed and variable operating and maintenance, company tax and

transmission costs.

Other considerations:

WACC – Weighted Average Cost of Capital of the GenCo.

Plant Capacity factor – ratio of actual output (MWh) to potential output at Nameplate capacity (MWh)48

Plant Availability factor – ratio of available capacity to installed (nameplate) capacity.

Conversion efficiency – efficiency in converting gas thermal energy into electrical energy.

Internal energy use – of the plant

Marginal Loss Factor (MLF) – the reciprocal of Transmission Loss (1 – MLF). Losses vary depending on

the position of the GenCo in relation to the load/connection point (node) to the transmission network. They

also vary depending on the location of new generation and load growth.

Generators are expected to cover the losses associated with transmission. Therefore they must supply

enough electricity at the supply point to cover their contractual (PPA) obligations and losses associated

with the connection point. MLF is calculated by estimating the losses pertaining to injecting an additional

unit of energy at that point. NERC has set a uniform MLF for the TCN network at 0.9195, reflecting the

technical losses on the transmission system estimated at 8.05%.

.

48

For example if a 1 MW generator produced 4,000 MWh over a year, its capacity factor would be 0.46 (4000 MW ÷ [1MW × 8760hrs per year]).


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Page 188

MYTO II Transmission Prices

Method Used for the Revenue Requirement for Transmission:

Building Blocks Approach. The building blocks are:

A. Return on capital – at a level NERC deems necessary to achieve “a fair (market based) rate of

return” on capital employed (assets, LT debt service).

B. Depreciation – to recoup the actual capital invested over the lifetime of the asset.

C. Operating costs and overheads – only those that an “efficient” operator would incur.

Application

There are three categories of payments made by users of transmissions services:

1. A connection charge for new generators and load customers;

2. Transmission Use of System (TUOS) charge paid by distributors/retailers;

3. A transmission loss factor applied to generation so generators cover costs associated with

transmission losses. (Generators pass this cost on as it is included in the generation tariff).


Cost of connecting new generators and load customers to the network; The fixed costs of building and

maintaining the network, depreciation and a return on capital employed; network operating and

maintenance costs.


To calculate the annual value to each of the components of the building blocks (A-C above), estimates of

the following were required:

Initial value of NESI’s invested capital – historical to date.

Future Capex – based on forecast foreseeable growth.

WACC – applicable Weighted Average Cost of Capital

Depreciation – an appropriate method

Operating expenses and overheads – an efficient level.

Improvement of industry losses – the rate of improvement over the tariff period.


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Page 189

MYTO II Distribution Prices

Method Used for the Revenue Requirement for Distribution:

Building Blocks Approach. The building blocks are:

A. Return on capital – at a level NERC deems necessary to achieve “a fair (market based) rate of return”

on invested capital.

B. Depreciation – to recoup the actual capital invested over the lifetime of the asset.

C. Operating costs and overheads – only those an “efficient” operator would incur.

Application

1. MYTO II sets Distribution Use of System (DUOS) charges.

2. The annual revenue requirement for the entire distribution network was calculated. This was then divided

by the amount of power projected to be delivered to each of the 11 DisCos. From their respective

allocations, the DisCos produce a DUOS charge per unit of energy on which basis electricity is sold within

their area.

3. MYTO II distribution tariff also includes DisCos’ return on working capital so that cash flows are sufficient

to service their debt.


- Payments to GenCos – based on the wholesale tariff or price set in the relevant PPA for electricity

injected into the transmission network.

- TUOS charge for each MWh delivered to the DisCo’s bulk supply point.

- Cost of electricity distribution through the DisCo’s own network to the end customer.

- Marketing, metering, billing and revenue collection.

- Institutional charges

- FGN tariff subsidy for the most vulnerable customer tariff classes.


To calculate the annual value to each of the components of the building blocks (A-C above), estimates of the

following were required:

Initial value of NESI’s invested capital – historical to date.

Future Capex – based on forecast foreseeable growth.

WACC – applicable Weighted Average Cost of Capital

Depreciation – an appropriate method

Operating expenses and overheads – at an efficient level.

Improvement of industry losses – the rate of improvement over the tariff period.


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Page 190

Appendix 5: OCGT and CCGT Power Plants

Figure 46: Operation of an Open Cycle Gas Turbine Plant

Source: Power Generation – Siemens, CSL Research

Figure 47: Operation of a Combined Cycle Gas Turbine Plant

Source: Power Generation – Siemens, CSL Research


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Page 191

Table 40: Key Data and Figures for Natural Gas-Based Power Technologies

Technical Performance Typical Current International Values and Ranges

Energy input Natural gas

Output Electricity

Technologies OCGT CCGT

Efficiency, % 35 – 42% 52 – 60%

Construction time, months Minimum 24; Typical 27; Maximum 30

Technical lifetime, yr 30

Load (capacity) factor, % 10 – 20 20 – 60

Max. (plant) availability, % 92

Typical (capacity size, MW (est.) 10 – 300 60 – 430

Installed (existing) capacity, GW (est.) 1,168 (end of 2007)

Average capacity aging Differs from country to country. CCGT construction started end of 1980s

Environmental Impact

CO2 and other GHG emissions, kg/MWh

480 – 575 340 – 400

NOx, g/MWh 50 30

Costs (US$ 2008)

Investment cost, inc. IDC, US$/kW 800 – 1,000; Typical 900 (2010) 1,000 – 1,250; Typical 1,100 (2010)

O&M cost (fixed and variable), US$/k/W per annum

36 44

Fuel cost, US$/MWh 45 – 70 30 – 45

Economic lifetime, yr 25

Interest rate, % 10

Total production cost, US$/MWh 200 – 225 / Typical 210 65 – 80 / Typical 72.5

Market share 20

Data Projections 2010 2020 2030

Technology OCGT CCGT OCGT CCGT OCGT CCGT

Net Efficiency (LHV), % 35-42 52-60 ≤ 45 ≤ 64 ≤ 45 ≤ 64

Investment cost, incl. IDC, US$/kW 900 1100 850 100 800 900

Total production cost, US$/MWh 100 72.5 95 70 95 70

Market share, % global electricity output

20 18 15

Source: International Energy Agency, ETSAP Technology Brief E02 – April 2010

O&M – Operation & Maintenance

LHV – Lower Heating Value

GHG – Green House Gas

IDC – Interest during construction


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Page 192

Appendix 6: Other Electricity Sector Licensees

Source: NERC, NDPHC, CSL research

Licensees as at 31 July 2014

StateLicence

Issued

Licence

ExpiresExtension/ Review

1 Aba Power Ltd. Abia State 07/12/2006 06/12/2006 Extended to 06/12/2021

2 Abuja Electricity Distribution Co Plc FCT, Niger, Kogi and

Nassarawa States

04/09/2012 03/09/2022 Extended to 03/09/2027

3 AES Nigeria Barge Ltd. Generation On-Grid 270MW FCT 15/08/2000 14/08/2025 Licence issued by Federal

Ministry of Power & Steel

4 Afam Power Plc Generation On-Grid 987.2MW Rivers State 04/09/2012 03/09/2027

5 African Oxygen & Industrial Gases Ltd. Generation On-Grid 19MW Lagos State 02/12/2011 01/12/2021

6 Agbara Shoreline Power Ltd. Generation On-Grid 100MW Ogun State 28/09/2007 27/09/2017

7 Akute Power Ltd. Generation Off-Grid 13MW Lagos Water Corporation,

Lagos State

25/03/2010 02/03/2011 Renewed 02/12/2011 to exp.

01/12/2021

8 Alaoji Generation Co. Ltd. (NIPP) Generation On-Grid 1074MW Abia State 29/11/2011 28/11/2021

9 Anita Energy Ltd. Generation On-Grid 90MW Lagos State 12/04/2007 11/04/2017

10 Azura Power West Africa Ltd. Generation On-Grid 450MW Edo State 30/11/2011 29/11/2021

11 Benin Electricity Distribution Co Plc Edo, Delta, Ondo and Ekiti

States

04/09/2012 03/09/2022 Extended to 03/09/2027

12 Benin Generation Company Ltd. Generation On-Grid 450MW Ihonvbor, Edo Sate 09/01/2013 08/01/2013

13 Calabar Generation Company Ltd. Generation On-Grid 561MW Cross Rivers State 09/01/2013 08/01/2023

14 Century Power Generation Ltd. Generation On-Grid 495MW Anambra State 20/09/2012 19/09/2022

15 CET Power Projects (Ewekoro) Generation Off-Grid 6MW Lafarge WAPCO (Ewekoro,

Ogun State)

03/05/2011 02/05/2021

16 CET Power Projects Ltd. Generation Off-Grid 20MW Cross River State 28/09/2007 27/09/2008 Renewal being processed

17 CET Power Projects Ltd. Generation Off-Grid 5MW Nigerian Breweries Limited

(Lagos State)

16/01/2009 15/01/2010 Renewed 04/10/2010 to exp.

03/10/2020

18 CET Power Projects(Sagamu) Generation Off-Grid 7MW Lafarge WAPCO Sagamu

(Ogun State)

03/05/2011 02/05/2021

19 Contour Global Solutions (Nig) Ltd. Generation Off-Grid 10MW NBC Bottling Plant (Ikeja,

Lagos State)

04/06/2010 03/06/2020

20 Contour Global Solutions (Nig) Ltd. Generation Off-Grid 4MW NBC Bottling Plant (Apapa,

Lagos State)

04/06/2010 03/06/2020

21 Contour Global Solutions (Nig) Ltd. Generation Off-Grid 7MW NBC Bottling Plant (Edo State) 04/06/2010 03/06/2020

22 Coronation Power and Gas Ltd. Generation Off-Grid 20MW Sona Group (Sango Ota

Industrial Area, Ogun State)

03/11/2009 02/11/2010 Renewal being processed

23 Delta Electric Power Ltd. Generation On-Grid 116MW Oghareki, Etiope West LGA,

Delta State

29/11/2011 28/11/2021

24 DIL Power Ltd. Generation Off-Grid 114MW Cement factory, (Ogun State) 13/04/2012 12/04/2022

25 DIL Power Plc Generation On-Grid 135MW Kogi State 26/10/2009 25/10/2019

26 Egbema Generation Company Ltd. (NIPP) Generation On-Grid 338MW Imo State 09/01/2013 08/01/2023

27 Egbin Power Plc Generation On-Grid 1320MW Lagos State 04/09/2012 03/09/2022 Extended to 03/09/2027

28 Eko Electricity Distribution Co Plc Lagos South, Lagos State 04/09/2012 03/09/2022 Extended to 03/09/2027

29 Eleme Petrochemical Company Ltd. Generation On-Grid 135MW Eleme Complex - Port

Harcourt, (Rivers State)

22/08/2011 21/08/2021

30 Energy Company of Nigeria (NEGRIS) Generation On-Grid 140MW Lagos State 29/09/2011 28/09/2021

31 Energy Company of Nigeria Ltd. Generation Off-Grid 3MW Nestle (Ogun State) 29/08/2011 28/08/2021

32 Energy Company of Nigeria Plc Lagos State 15/12/2011 14/12/2021

33 Enersys Nigeria Ltd. Generation On-Grid 10MW Ekiti State 26/09/2012 25/09/2022

34 Enugu Electricity Distribution Co Plc Enugu, Abia, Imo, Anambra

and Ebonyi States

04/09/2012 03/09/2022 Extended to 03/09/2027

35 Ethiope Energy Ltd. Generation On-Grid 2800MW Delta State 24/08/2006 23/08/2016

Licensee Licence

Distribution

Distribution

Distribution

Distribution

Distribution

Distribution


Infrastructure


Page 193



StateLicence

Issued

Licence


36 Ewekoro Power Ltd. Generation Off-Grid 12.5MW WAPCO (Ogun State) 07/12/2006 06/12/2008 Renewal being processed

37 Farm Electric Supply Ltd. Generation On-Grid 150MW Ogun State 24/08/2006 23/08/2016

38 First Independent Power Co. Ltd. Generation On-Grid 150MW Omoku, Rivers State 21/05/2007 20/05/2017

39 First Independent Power Co. Ltd. Generation On-Grid 136MW Trans-Amadi, Rivers State 21/05/2007 20/05/2017

40 First Independent Power Co. Ltd. Generation On-Grid 95MW Eleme, Rivers State 21/05/2007 20/05/2017

41 Fortune Electric Power Co. Ltd. Generation On-Grid 500MW Odukpani, Cross River State 21/11/2012 20/11/2022

42 Gateway Electricity Ltd. Certain locations not covered

by PHCN in Ogun State

30/09/2010 29/09/2020

43 Gbarain Generation Company Ltd. Generation On-Grid 225MW Gbarain, Bayelsa State 09/01/2013 08/01/2023

44 Geometric Power Ltd. Generation On-Grid 140MW Aba, Abia State 06/12/2006 06/12/2016 Extended to 06/12/2021

45 Geregu Generation Company Ltd. Generation On-Grid 434MW Geregu, Kogi State 09/01/2013 08/01/2023

46 Geregu Power Plc (BPE) Generation On-Grid 414MW Geregu, Kogi State 21/11/2012 20/11/2022

47 Hudson Power Ltd. Generation On-Grid 150MW Warawa, Ogun State 23/05/2007 22/05/2017

48 Ibadan Electricity Distribution Co Plc Oyo, Ogun, Osun and Kwara 04/09/2012 03/09/2022 Extended to 03/09/2027

49 Ibafo Power Station Ltd. Generation On-Grid 200MW Ibafo, Ogun State 23/05/2007 22/05/2017

50 Ibom Power Ltd. Generation On-Grid 190MW Ikot Abasi, Akwa Ibom State 12/05/2008 11/05/2018

51 ICS Power Ltd. Generation On-Grid 624MW Alaoji, Abia State 24/08/2006 23/08/2016

52 Ikeja Electricity Distribution Co Plc Lagos North Lagos State 04/09/2012 03/09/2022 Extended to 03/09/2027

53 Ikorodu Industrial Power Ltd. Ikorodu, Lagos State 07/12/2006 06/12/2016

54 Ikorodu Industrial Power Ltd. 39MW Ikorodu, Lagos State 07/02/2006 06/02/2016

55 Ilupeju Power Ltd. Generation Off-Grid 2MW Academy Press, (Lagos

State)

06/05/2011 05/05/2021

56 Income Electrix Ltd. Generation Off-Grid 6MW NPA, PH, Rivers State 02/06/2012 01/06/2021

57 Island Power Ltd. 10MW Marina, Lagos State na na

58 Isolo Power Generation Ltd. Generation On-Grid 20MW Isolo Lagos State 04/10/2012 03/10/2022

59 JBS Wind Power Ltd. Generation On-Grid 100MW Maranban Pushit, Mangu,

Plateau State

11/10/2012 10/10/2022

60 Jos Electricity Distribution Co Plc Plateau, Bauchi, Benue and

Gombe State

04/09/2012 03/09/2022 Extended to 03/09/2027

61 Kaduna Electricity Distribution Co Plc Kaduna, Sokoto, Kebbi and

Zamfara States

01/07/2006 na

62 Kaduna Power Supply Company Ltd. 84MW Kudenda Industrial Area,

Kaduna State

04/09/2012 03/09/2022 Extended to 03/09/2027

63 Kainji Hydro Electric Plc (Jebba Station) Generation On-Grid 570MW Jebba, Niger State 04/09/2012 03/09/2022 Extended to 03/09/2027

64 Kainji Hydro Electric Plc (Kainji Station) Generation On-Grid 760MW Kainji, Niger State 04/09/2012 03/09/2022 Extended to 03/09/2027

65 Kano Electricity Distribution Co Plc Kano, Jigawa and Katina

States

04/09/2012 03/09/2022 Extended to 03/09/2027

66 Knox J&L Energy Solutions Ltd. Generation On-Grid 1000MW Ajaokuta, Kogi State 01/10/2011 10/11/2021

67 Lotus & Bresson Nigeria Ltd. Generation On-Grid 60MW Magboro, Ogun State 12/04/2007 11/04/2017

68 Mabon Ltd. Generation On-Grid 39MW Dadinkowa, Gombe State 07/12/2006 06/12/2016

69 MBH Power Ltd. Generation On-Grid 300MW Ikorodu, Lagos State 28/11/2011 27/11/2021

70 Minaj Holdings Ltd. Generation On-Grid 115MW Agu-Amorji Nike, Enugu East

LGA, Enugu State

13/02/2008 12/02/2018

LicenceLicensee (continued)

Distribution for Ewekoro Cement Ltd

Embedded Generation

Distribution

Distribution

Distribution

Embedded Generation

Distribution Off-Grid

Distribution

Distribution

Embedded Generation


Infrastructure


Page 194



StateLicence

Issued

Licence


71 Nigerian Agip Oil Co. Ltd. Generation On-Grid 480MW Okpai, Delta State 29/11/2017 28/11/2027

72 Nigerian Bulk Electricity Trading Plc (NBET) 15/11/2011 14/11/2021

73 Nigerian Electricity Supply Corporation

(Nigeria) Ltd. (NESCO)

Generation On-Grid 30MW Bukuru, Plateau State 09/08/2000 08/08/2025 Licence issued by the Federal

Ministry of Power & Steel

74 Notore Power Ltd. Generation On-Grid 50MW Onne, Rivers State 25/09/2008 24/09/2018

75 Ogorode Generation Co. Ltd. (NIPP) Generation On-Grid 450MW Ogorode, Delta State 29/11/2011 28/11/2021

76 Olorunsogo Generation Co. Ltd. (NIPP) Generation On-Grid 750MW Oluronsogo, Ogun State 29/11/2011 28/11/2021

77 Olorunsogo Power Plc (BPE) Generation On-Grid 335MW Olorunsogo, Ogun State 21/11/2012 20/11/2022

78 Omoku Generation Company Ltd. Generation On-Grid 250MW Omoku, Rivers State 09/01/2013 08/01/2023

79 Omotosho Generation Company Ltd. Generation On-Grid 500MW Omotosho II, Ondo State 09/01/2013 08/01/2023

80 Omotosho Power Plc (BPE) Generation On-Grid 335MW Omotosho, Ogun State 21/11/2012 20/11/2022

81 Paras Energy & Natural Resources

Development Ltd.

Generation On-Grid 96MW Ogijo,Ogun State 04/06/2010 03/06/2020

82 Port Harcourt Electricity Distribution Co Plc Rivers, Cross River, Bayelsa

and Akwa Ibom States

04/09/2012 03/09/2022 Extended to 03/09/2027

83 PZ Power Company Ltd. Generation Off-Grid 4MW PZ Cussons Aba Factory -

Abia State

06/12/2012 05/12/2022

84 Sapele Power Plc Generation On-Grid 1020MW Sapele, Delta State 04/09/2012 03/09/2022 Extended to 03/09/2027

85 Shell Petroleum Development Co. Ltd. Generation On-Grid 642MW Afam VI - Delta State 13/06/2007 12/06/2017

86 Shiroro Hydro Electricity Plc Generation On-Grid 600MW Shiroro, Niger State 04/09/2012 03/09/2022 Extended to 03/09/2027

87 Shoreline Power Company Ltd. Generation Off-Grid 9MW Lafarge Wapco - Sagamu,

Ogun State

05/05/2011 04/05/2021

88 Supertek Electric Ltd. Generation On-Grid 500MW Ajaokuta, Kogi State 06/12/2012 05/12/2022

89 Supertek Nig. Ltd. Generation On-Grid 1,000MW Akwete, Abia State 24/08/2007 23/08/2017

90 Tower Power Abeokuta Ltd. Generation Off-Grid 20MW Abeokuta, Ogun State 26/08/2011 25/08/2021

91 Tower Power Utility Ltd. Generation Off-Grid 20MW Ota Industrial Estate - Ota,

Ogun State

07/05/2009 06/05/2010 Renewed on 04/10/2010 to

expire 31/10/2020

92 Transmission Company of Nigeria 04/09/2012 03/09/2022 Extended to 03/09/2027

93 Ughelli Power Plc Generation On-Grid 942MW Ughelli, Delta State 04/09/2012 03/09/2022 Extended to 03/09/2027

94 Unipower Agbara Ltd. Generation Off-Grid 6MW Unilever - Agbara, Ogun State 02/11/2011 01/11/2021

95 Wedotebary Nigeria Ltd. Generation Off-Grid 5MW Kuru, Jos, Plateau State 03/11/2009 02/11/2010 Renewal being processed

96 Westcom Technologies & Energy Services

Ltd.

Generation On-Grid. 1000MW Sagamu, Ogun State 23/02/2007 22/02/2017

97 Yola Electricity Distribution Co. Adamawa, Borno, Taraba and

Yobe States

04/09/2012 03/09/2022 Extended to 03/09/2027

98 Zuma Energy Nigeria Ltd. (Gas Plant) Generation On-Grid 400MW Ohaji-Egbema, Owerri, Imo

State

02/12/2011 01/12/2021

99 Zuma Energy Nigeria Ltd. (Coal Plant) Generation On-Grid 1200MW Itobe, Kogi State 30/11/2011 29/11/2021

Distribution

Licensee (continued) Licence

Distribution

Bulk procurement and resale of electricity

Transmission and wheeling of electricity covering 36 States of the

federation


Infrastructure


Page 195

Appendix 7: Official Press Releases

TH

E PR

ESID

ENCY

Bu

reau

of P

ublic

Ent

erpr

ises

Th

e Se

cret

aria

t of N

atio

nal C

ounc

il on

Priv

atis

atio

n 11

, Osu

n Cres

cent,

Off I

brahim

Bab

angid

a Way

Ma

itama

Dist

rict, P

.M.B

442,

Garki

, Abu

ja, N

igeria

Te

lefax

(234

-9) 41

3886

1 E-

mail:

janich

ebe@

bpen

g.org

Web

Site

: http

://www

.bpen

g.org

Th

e Di

rect

or G

ener

al o

f th

e Bu

reau

of

Publ

ic E

nter

prise

s (B

PE),

Mr.

Benj

amin

Di

kki

has

faul

ted

clai

ms

of t

he i

mm

inen

t co

llaps

e of

com

mer

cial

ban

ks i

n th

e co

untr

y ov

er th

eir e

xpos

ure

to th

e po

wer

sec

tor.

Spea

king

at

an a

ll-pa

rtie

s m

eetin

g on

Wed

nesd

ay,

May

21,

2014

in

Abuj

a at

a

pres

enta

tion

to t

he o

wne

rs o

f th

e Po

wer

Hol

ding

Com

pany

of

Nige

ria (

PHCN

) Su

cces

sor

Com

pani

es (

SCS)

by

the

Afric

a En

ergy

Tea

m o

f th

e W

orld

Ban

k, D

ikki

no

ted

that

the

fea

rs b

y so

me

of t

he e

min

ent

take

over

of

SCS

due

to t

he

purp

orte

d no

n se

rvic

ing

of lo

ans

or a

bout

the

pros

pect

of s

tres

s to

the

bank

s du

e to

the

ir ex

posu

re t

o SC

S, w

ere

mis

plac

ed a

s th

e Su

cces

sor

Com

pani

es d

id n

ot

borr

ow d

irect

ly f

rom

the

ban

ks f

or t

heir

own

book

s. F

urth

erm

ore,

no

asse

ts o

f th

e SC

S w

ere

pled

ged

as c

olla

tera

l. It

sho

uld

be n

oted

tha

t it

was

the

acq

uirin

g co

mpa

nies

or

SPV'

s th

at b

orro

wed

bas

ed o

n th

eir

cash

flo

ws

and

acco

unts

. Th

e SP

A sig

ned

also

req

uire

s th

at t

he c

onse

nt o

f the

BPE

is o

btai

ned

befo

re th

e Co

re

Inve

stor

s ca

n bo

rrow

. "T

he b

anks

len

t to

the

Cor

e In

vest

ors

base

d on

the

ir ca

pabi

lity

to p

ay.

The

inve

stor

s ar

e su

ppos

ed t

o ha

ve m

ade

adeq

uate

pro

visio

ns t

o ta

ke c

are

of t

heir

oblig

atio

ns t

o th

eir

finan

cier

s fro

m t

he o

utse

t. T

hey

knew

tha

t th

ey w

ere

not

goin

g to

mak

e pr

ofit

imm

edia

tely

on

take

over

of

the

SCS.

The

ir fin

anci

ers

also

w

ere

awar

e of

this

", h

e st

ress

ed.

Durin

g th

e pr

esen

tatio

n en

title

d "R

efor

m o

f th

e po

wer

sec

tor

in L

atin

Am

eric

an

coun

trie

s in

the

199

0s",

aim

ed a

t sh

arin

g e

xper

ienc

es o

f t

he p

ower

sec

tor

priv

atiza

tion

in t

hese

cou

ntrie

s, M

r. Pe

dro

Ant

man

n re

min

ded

the

inve

stor

s th

at

thei

r pr

imar

y fo

cus

shou

ld b

e to

pro

vide

ade

quat

e an

d ef

ficie

nt p

ower

sup

ply

to

Nige

rian

cons

umer

s.

He

said

th

at

ther

e w

ere

unus

ually

ch

alle

nges

at

th

e in

itial

st

ages

of

th

e pr

ivat

isat

ion

exer

cise

but

that

with

det

erm

inat

ion

and

the

right

str

ateg

y, it

wou

ld

be s

urm

ount

ed.

Antm

ann

urge

d th

e in

vest

ors

not

to a

im a

t m

akin

g pr

ofit

now

but

to

ende

avou

r to

dev

elop

infra

stru

ctur

e an

d to

mee

t the

cos

t of s

uppl

y.

The

Wor

ld B

ank

offic

ial

advi

sed

the

Nige

rian

Elec

tric

ity R

egul

ator

y Co

mm

issio

n (N

ERC)

to m

ake

a pr

ovisi

on in

its

rule

s to

adj

ust

tarif

fs in

tim

es o

f low

gen

erat

ion

and

shor

tage

of g

as s

uppl

y.

Mr

Antm

an,

draw

ing

from

exp

erie

nces

in o

ther

cou

ntrie

s, s

aid

thes

e ch

alle

nges

ar

e no

rmal

at

the

early

sta

ges.

Urg

ing

Inve

stor

s no

t to

foc

us o

n sh

ort

term

ga

ins,

but

inve

st in

infra

stru

ctur

e th

at w

ill g

uara

ntee

sus

tain

ed fu

ture

pro

fits.

It

wou

ld b

e re

calle

d th

at N

iger

ian

bank

s ha

d ex

pres

sed

conc

ern

over

the

po

ssib

ility

of

losin

g ab

out

N1 t

rillio

n th

ey i

nves

ted

in t

he a

cqui

sitio

n of

the

pr

ivat

ized

asse

ts o

f th

e Po

wer

Hol

ding

Com

pany

of

Nige

ria (

PHCN

) Su

cces

sor

Com

pani

es (

SCs)

. Th

e ba

nks

expr

esse

d fe

ars

that

the

y m

ay b

e un

able

to

reco

up t

heir

inve

stm

ent

follo

win

g th

e m

yria

d of

pro

blem

s fa

cing

the

sect

or.

Grou

p M

anag

ing

Dire

ctor

/Chi

ef E

xecu

tive

Offi

cer,

Diam

ond

Bank

Plc

, Dr

. Al

ex

Otti

, had

at

a po

wer

inve

stor

s' fo

rum

in A

buja

, sai

d th

at a

s at

201

3, t

he b

anki

ng

indu

stry

had

in

vest

ed w

ell o

ver

N750

bill

ion

in t

he p

ower

sec

tor

and

that

the

y w

ere

read

y to

do

mor

e.

Cons

eque

ntly

, the

ban

ks c

alle

d fo

r an

incr

ease

in e

lect

ricity

tarif

f and

in th

e pr

ice

of g

as,

sayi

ng i

t w

ould

boo

st t

he r

even

ue p

rofil

e of

the

pow

er c

ompa

nies

and

th

eir

abili

ty t

o re

pay

thei

r de

bts.

Som

e of

the

chi

ef e

xecu

tives

of

bank

s, w

ho

spok

e at

the

jus

t co

nclu

ded

Seve

nth

Lago

s Ec

onom

ic S

umm

it, t

agge

d Eh

ingb

eti

2014

, co

mpl

aine

d of

th

e re

venu

e pr

ofile

of

th

e re

cent

ly

priv

atize

d po

wer

co

mpa

nies

, say

ing

it is

not

mee

ting

the

expe

ctat

ion

of in

vest

ors.

CH

IGBO

AN

ICH

EBE

Head

, Pub

lic C

omm

unica

tions

M

ay 2

2, 2

014


Infrastructure


Page 196

Important Risk Warnings and Disclaimers

CSL STOCKBROKERS LIMITED (“CSL Stockbrokers”) is regulated by the Securities and Exchange Commission, Nigeria.

FCMB (UK) LIMITED (“FCMB UK”), trading in the name of ‘CSL Stockbrokers’, is authorised by the Prudential Regulation Authority (PRA)

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authorisation can be viewed at the Financial Services Register at http://www.fsa.gov.uk/register/home.do by entering the Firm Reference

Number 502704. FCMB UK is registered in England and Wales No. 6621225.

Both CSL Stockbrokers and FCMB UK are members of the FCMB Group (“the Group”) of Nigeria, a group of companies which also

includes First City Monument Bank Ltd.

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Infrastructure


Page 197