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Solving the World’s Energy Challenges: The Critical Role of the Private Sector

 By Samuel Bodman

 It’s A PLEASURE TO BE BACK INCAIRO. I would like to thank Omar (Mohanna President of American Chamber of Commerce In Cairo) for that kind introduction. I’m also honoured that my counterparts — Ministers Fahmy and Younes — have joined me at today’s lunch.

Let me get right to the point: the world needs safe, reliable, clean, affordable, and diverse energy supplies — and in considerably greater numbers than we now have. This is a global challenge, perhaps one of the most significant of our time — and one that you all understand acutely.

The International Energy Agency’s most recent World Energy Outlook, estimates that the world’s primary energy needs will grow by 55% by 2030.

Addressing this challenge in a timely way will require literally billions of dollars annually over many years. The IEA estimates that $22 trillion of investment will be needed between now and 2030 to meet expected demand.

We also know that this investment must occur around the world — in developed and developing nations alike — and at all stages of the energy cycle.

At the same time, we all must recognize the realities of global climate change and look for ways to develop cleaner sources of energy that at the very least do not worsen — and hopefully can improve — the health of our earth’s environment.

So the energy scenario we must confront is this: if we are to encourage economic growth around the world, if we are to raise living standards for all people of all nations, if we are to improve our environmental health, the world needs clean, affordable, diverse energy supplies, as well as new suppliers and supply routes. And achieving that demands responsible action both from consuming nations and producing nations.

I don’t want to sound too alarmist, but in some ways, what we are really talking about is reducing the world’s energy insecurity.

So what do we do about it? That answer is complex, of course, and the solution is multifaceted. But, it can be summarized this way: we must grow the pie of what’s available.

For conventional fuels, the principal challenges facing us are: Will the necessary investments be made to bring sufficient hydrocarbons to market? Is the investment climate in producing countries conducive to inviting such capital flows? Are large consuming nations having the right type of discussions and collaborations with producing nations? If not, why not? And, are we adequately investing in ways to produce fossil energy more cleanly and efficiently?

Beyond hydrocarbons, the world absolutely requires new energy options in the form of alternative fuels and advanced energy technologies: the development of commercially competitive cellulosic ethanol; advanced hybrid vehicle technologies — with a focus on developing better batteries; hydrogen fuel cells; solar energy, including an acceleration of the development of solar photovoltaics; high- efficiency wind power; and carbon sequestration and clean-coal technologies.

Besides, any global energy strategy must include efforts to expand access to emissions- free nuclear power in a way that responsibly manages waste and dramatically reduces proliferation risks. The Egyptian government shares this belief. It is a topic that I’ve been discussing with officials during my visit to Cairo, including this morning in my meeting with President Mubarak.

To advance this global effort, nearly two years ago President Bush introduced the Global Nuclear Energy Partnership, which aims to facilitate the worldwide expansion of nuclear energy for peaceful purposes in a safe and secure manner. Among other things, GNEP establishes the common goal of creating reliable fuel services that will provide a viable and economic alternative to the spread of sensitive nuclear technologies.

The partnership seeks to take advantage of the best available fuel cycle approaches to recycle spent nuclear fuel to reduce the amount of waste and tap its unused energy.

In all these areas — from traditional hydrocarbon development to alternative energy to nuclear power — governments certainly have a tremendously important role to play. But the public sector cannot do this job alone. Even our research priorities — the research and development agenda itself— must be developed with substantial input from corporations, utilities, and universities. And, research needs to be conducted in a coordinated way. As we ramp up research and development investment, I believe we also must find innovative approaches to get beneficial technologies out into the marketplace quickly and to share the risk that the capital markets and private sector are not yet ready to take on. In the United States we are doing this through a range of collaborative models, including cost-sharing partnerships and loan guarantees.

At the Energy Department, we are also establishing an Entrepreneur in Residence programme, which aims to bring venture capital- sponsored entrepreneurs into three of our National Laboratories to help commercialize new technologies. And we are developing a new Technology Commercialization and Deployment Fund. This fund will allow our laboratories to move clean energy technologies toward commercial viability though prototype development, demonstration projects, market research, and other deployment activities.

In general, our strategy recognizes that many of the transformative breakthroughs are likely to happen in and in conjunction with — the private sector. . . and that the government must take an active role in encouraging that activity. Personally, I believe that we are already seeing results.

Having spent a good chunk of my career in the financial sector, I can honestly say that for the first time in my life we are seeing the venture capital community put sizeable amounts of money into entrepreneurial companies in the alternative energy business.

In the first three quarters of 2007, investments in the so-called “clean tech” sector (which includes alternative energy and conservation technologies, among other things) by U.S. venture capital firms totaled $2.6 billion — the highest annual dollar volume ever (even with just 3 quarters worth of data) — according to a recent industry report. Of those investments, solar energy was the biggest sub-sector funded, with 35 solar-related deals totaling $664.6 million. And, I interpret this as a clear sign that the clean-energy market is viable — indeed, thriving.

All this illustrates the coalescence of forces that we’re seeing in the energy arena in the United States — and indeed, throughout the world. Governments around the world recognize that there is an urgent need to accelerate the development of these technologies and to bring them to market. And, at the same time, the private sector recognizes that there’s a big opportunity here: one that can favourably impact their balance sheets as well as the world’s energy security and environmental health.

The challenges that we face are too large and too important for a “business as usual” approach. We must bet on technology and we must take some risks.

One final point, which I make with particular emphasis: we must promote increased energy efficiency across the global economy. The truth is the biggest source of immediately available “new” energy is the energy that we waste every day. I believe that improvements in energy efficiency can be achieved — in relatively short order — on a global scale in our industrial and power-generating sectors, our government agencies, our homes, our offices, and our transportation sector.

Collectively, these measures will not only take some pressure off of demand, but also improve the health of our shared environment.

Together, with the right leadership and funding commitments from governments around the globe, with the talent of our world’s scientists and engineers, and with (he capital, commitment and innovative power of our commercial sectors — which you all represent — we will solve this problem . .we will achieve a cleaner, affordable, and secure energy future for all people of the world.

The Honourable Samuel W Bodman, United States Secretary of Energy at lunch with the American Chamber of Commerce in Cairo, January 2008..


Telecom Egypt buys out Algeria’s only private telephone operator

TELECOM EGYPT HAS ACQUIRED THE entire capital of Lacom, the only private fixed telecommunications operator in Algeria. Telecom Egypt and another Egyptian company, Orascom, had each previously owned 50% of Lacom’s capital. Algerie Telecom, the largest provider of fixed, mobile and internet services is slated for privatisation in the first half of 2008(story above).


Shell Nigeria Gas Connects New Customers

SHELL NIGERIA GAS LIMITED, THE GAS transmission/distribution arm of Shell in Nigeria, has added two more companies to its gas distribution network. Shell said that May&Baker, the drug manufacturer, and Nigerian Foundries Limited, both based in Ota, in the far west of Lagos, were recently connected to the company’s network. Nigerian Foundries Limited is the West African sub-region’s biggest foundry, while May&Baker Nigeria Plc. is one of Nigeria’s largest pharmaceutical companies, with increasing interests in the packaged foods market. Bayo Opadere SNG’s Managing Director, said the tying of the two companies “into our distribution network reflects Shell’s commitment to Nigeria’s industrial development”.


Winfield Resources to Build Oil Refinery in Mauritania

CANADIAN FIRM WINFIELD Resources Limited on Thursday said that Mauritania had granted it a licence to build an oil refinery with a capacity of300,000 barrels per day as part of a multi-billion dollar scheme.

“Our company has received this licence and is preparing the different stages of preparation in terms of investment, training Mauritian technical staff and the other required arrangements,” Winfield’s representative in Mauritania, Bouna Ould Hassen, told AFP.

The refinery proposal, with the start of construction due in six months, is part of a broader seven billion dollar (47 billion euro) investment programme that will also include a seawater desalination plant and an electric power plant for the oil installation.

“The surplus water and electricity will be sold locally and to countries in the region that express a need for them,” Ould Hassen said.

The licence to refine oil in the west African mainly desert nation, the latest producer on the continent, was only announced by Winfield Resources, which published a press release on its web site dated February 15, stating that the refinery was due to be built at the port of Nouakchott.

The Mauritanian government recently dismissed two senior civil servants — the director of legislation and the president of the national hydrocarbon fuels commission — for “non-respect of the law” in the case.


Tougher Times in Deepwater Nigeria

 By Stewart Williams and Alison Dines, Wood Macenzie

THE GENERAL PERCEPTION ACROSS West Africa’s oil industry is that the high cost inflation seen over the last few years is slowing, particularly with respect to rig rates. Absolute costs, however, are still increasing and 2008/9 will see deepwater drilling rates surpass the $500,000 per day mark for the first time. The specific rig in question is the West Capelle, a new-build driliship, which is due to begin drilling for TOTAL in Nigeria in the third quarter of 2008. Its sister ship, the West Polaris, is also due to start operations in the Gulf of Mexico. After completing its programme with ExxonMobil, the West Polaris will move to West Africa to drill exploration wells in the Nigeria, Sao Tome et Principe (NSTP) JDZ, Equatorial Guinea and Gabon.

With exploration in the region set to increase again and prospects being located in ever- increasing water depths, Wood Mackenzie has examined the effect of cost escalation in the deepwater Niger Delta. While the US Gulf of Mexico, with its very attractive fiscal terms, can support such day rates and subsequent development costs, West Africa has tougher fiscal terms and Nigeria is an increasingly expensive development area. This insight examines the reserves threshold for commercial oil development in Nigeria and the Nigeria-Sao Tome and Principe JDZ under the existing range of fiscal terms in this deepwater region using typical development cost scenarios.

Methodology

We have created four model fields containing between 100 and 600 million barrels to analyse commercial reserves thresholds in the deepwater Niger Delta. Cost estimates for the model fields are based on our knowledge of current exploration costs and future development cost expectations of the major oil companies.  The table shows the range of capex for the individual model fields.

High day rates for drilling have accompanied increases in costs for facilities and subsea equipment too. In fact, it is subsea that is the strongest growth area in terms of costs. At the start of the decade, unit capital costs for West African deepwater projects sanctioned for development were around $4 per barrel (nominal). For projects awaiting sanction today, these costs have tripled to at least $12 per barrel, but in many cases more than this.

We assume that these model fields are in water depths greater than 1,000 metres -water depth affects royalty rates -and also has a bearing on exploration and development

costs. We have used Wood Mackenzie’s latest price assumption that assumes a flat long-term real oil price of $50 per barrel (2008 terms).

We have modeled full-cycle returns. The model fields have a 2008 discovery date and first produce in 2015, following first development expenditure in 2011. Although 2015 may seem pessimistic, seven-to eight-year lead times are typical of Nigerian deepwater projects. Satellite developments have been performed much more quickly than this, but our scenarios assume a standalone new field development. All cases assume subsea wells tied back to a new-build floating, production, storage and offloading (FPSO) vessel.

Results and Discussion

The following chart shows the range of full cycle IRRs under four PSC systems that currently apply in deepwater Nigeria and the NSTP JDZ.

The chart demonstrates the evolution and general toughening of fiscal terms in Nigeria from the first deepwater round in 1993, when lenient terms were offered to encourage high risk drilling, to the tougher terms in the latest bid rounds, which have also been accompanied by high bonuses.

Under the latest Nigerian fiscal terms and cost estimates, around 400 million barrels has to be discovered to achieve a 15% full-cycle return. Discoveries over the last five years, however, have been getting smaller, typically less than 300 million barrels. Most major operators agree that the largest fields have already been found and that it will be difficult to develop new discoveries, even in a high oil price environment. In the early 2000s, the reserve thresholds were much lower, mainly because costs were substantially below the levels seen today.

We have not included signature bonuses in this chart but with a bonus of $50 million (the minimum set for the 2005, 2006 and 2007 bid round deepwater blocks) a 15% will be difficult to achieve, even with a 600 million-barrel discovery.

Why are costs particularly high in Nigeria?

Nigerian projects do attract a risk premium but it is difficult to put a figure on this — the contracts here are more expensive for a number of reasons. Security concerns in Nigeria mean that oil companies have to increase pay to encourage both their own staff and contractors to work there. A history of contract award delays, project design changes and significant re-tendering for contracts also add a premium when contractors are bidding for work in the country.

Another key issue facing operators is the local content requirement. Although Nigeria has been producing oil for over 50 years, it is only in the last few years that local participation has been pushed by the government. The haste in which this has been introduced means that there has been little time for Nigeria to build capacity in the local service and construction sectors that is required if all new deepwater projects are to meet the 70% built-in-country requirements. While the regulation is still not passed into law yet, the Nigerian National Petroleum Corporation’s (NNPC) Nigerian Content Division is trying to enforce it and this is becoming a barrier to project sanction.

Further costs are incurred in Nigeria through the addition of indirect taxes, which include VAT, import and custom duties, the Niger Delta Development Commission levy and education tax.

Company Outlook

The high cost issue is impacting the corporate view of the region. Already in 2007, we have seen several mid-sized to large lOCs either pull out or farm down their Niger Delta deepwater positions. Devon Energy and Pioneer have left the region completely, Chevron is farming down its share of the Nsiko deepwater discovery and ExxonMobil sold its share of the NSTP JDZ Block 1 (Obo discovery) to Addax in September 2007. Press reports suggest that Occidental, who only returned to Nigeria in 2005, has sold its deepwater position, which includes a stake in the Uge oil discovery.

Although many players are diluting their deepwater positions, others are still building theirs despite the high cost environment. Addax, a very successful Nigerian-shelf player, now has a significant deepwater portfolio in Nigeria and the JDZ. The company’s acreage in Nigeria, OPL 291, is one of the more prospective blocks and has the potential for a large discovery. In the NSTP JDZ, Addax now has an interest in four adjacent blocks, which could lead to cluster developments. This would probably lower each field’s individual reserves threshold required for commerciality. This is not the case with other, smaller Nigerian finds which are generally far apart from each other. BG too is developing a deepwater position and acquired a stake in OPL 323 in August 2007. This was, by far, the most sought-after block in the 2005 round due to its perceived prospectivity.

Conclusions

With commercial reserves thresholds increasing and discovery sizes falling, we expect to see a general slowdown in Nigerian deepwater development. Although the terms have become tougher (through a combination of legislation changes and competitive bidding), it is increasing development costs that are driving the increase in reserves needed for commerciality. Even existing fields with good terms and large volumes, such as Usan, Bosi and Bonga SW, have seen development schedules slip due to rising costs.

Satellite developments will become more attractive, as will infill drilling on the existing large developments that have attractive fiscal terms. However, if deepwater momentum is to continue in the region, then new development concepts have to be considered and NNPC may be able to help by considering some flexibility on the local content directives.

For new discoveries, reducing the time between discovery and first oil would improve the economics. Short lead times have been difficult to achieve for a number of reasons. OPEC constraints exist in Nigeria and the government has staggered deepwater development approvals to balance supply with the output from higher tax areas on the onshore and shelf. This problem should not be a concern in the Nigeria-Sao Tome Principe JDZ as production from this area is understood to be outside of Nigeria’s OPEC quota. The recently announced NNPC restructuring, however, does not bode well for the short-to mid-term as it may be difficult to get NNPC’s approval for project sanction.


… Nigerian Foreign reserves rise to $58.3 billion

NIGERIA’ RESERVES rose to 58.3 Billion dollars (37.4 billion euros) in February 2008 from 54.79 billion dollars the previous month, the Central Bank of Nigeria (CBN) has said. The bank said the reserves had grown steadily in the last three years, driven by high crude oil prices in the international market. Oil prices simmered down in February 2008 after hitting a record 111 dollars per barrel overnight, but analysts said prices remain on the boil due to a sharp fall in the value of the US dollar.

New York’s main oil futures contract, light sweet crude for delivery in April, was at 109.78 dollars per barrel in Asian trade, down 55 cents from its all-time closing high of 110.33 dollars in New York. The CBN said the reserves level, which hit 45 billion dollars in 2005, dropped to 32 billion dollars after Nigeria paid 12.4 billion dollars in debt owed to governments in the Paris Club of creditors. It said reserves began to build from April 2006, when the total came to 37 billion dollars. The total then went to 41.95 billion in December 2006 and to 42.65 billion in the first weeks of 2007. The Paris Club in 2005 cancelled 18 billion dollars of Nigeria’s debt, leaving a total of 12.4 billion dollars, including arrears and interest. Nigeria, Africa’s biggest oil producer with a daily output of 2.6 million barrels at peak production level, derives around 95 percent of its foreign earnings from the oil sector.


South Africa Petrol Price Rises to $1.2 Per Litre

THE RETAIL PRICE OF A CERTAIN GRADE OF petrol, in some part of South Africa, rose to $1.2 per litre in February 2008, a whopping 15% increase after moving up by 4% in January.

The wholesale price of diesel and 0,005 per cent sulphur increased by 10%. In the last one year, the price of diesel has jumped 55% to $1.1 25 per litre. The wholesale price of illuminating paraffin also increased by 10%, while the single maximum national retail price for illuminating paraffin increased by 12 percent. The prices are priced per litres The retail price of a litre of 95 octane unleaded petrol in Gauteng increased to $1.2 per litre and to $1.1 per litre at the coast – new highs. During the period under review, the average international product prices of petrol, diesel and illuminating paraffin increased.


Transnet Gets The Nod For Durban To Gauteng Oil Pipeline

NATIONAL ENERGY REGULATOR OF South Africa (NERSA) has awarded a licence to Transnet Pipelines to build the new multi products pipeline Durban – Gauteng. The project cost is estimated at $400million by the company for the design, construction and commissioning. The on-line date is scheduled for the third quarter of 2010 by which time the existing pipeline will be short of capacity and will need to be supplemented by rail and road transportation. iPayipi consortium also applied for this project but its application was declined. Transnet owns, operates, manages and maintains a network of 3,000km of high pressure oil and gas pipelines in South Africa. The network traverses five provinces from Kwazulu—Natal to Gauteng.


BG Achieves First Gas From West Delta Deep Marine Concession Phase IV

UK OPERATOR, BG HAS MADE THE FIRST delivery of gas from the West Delta Deep Marine concession Phase IV project (WDDM IV) into Egypt’s domestic natural gas market. WDDM IV was sanctioned by the Egyptian government and partners on the project in May 2006 to deliver gas from seven additional deepwater wells in the Scarab/Saffron and Simian subsea fields. BG says that the delivery date was one month ahead of schedule, the project was delivered under budget and with a successful safety record, achieving 2.5 million man hours with no lost time injuries. The project also marks the first time that all subsea structures were fabricated entirely in Egypt by Petrojet, an affiliate of the Egyptian General Petroleum Corporation (EGPC). Ian Hewitt, President of BG Egypt, said, among other things: “This is a great example of sustainable development where BG Egypt, as well as delivering on local content obligations, has also worked to improve the capability of the local contractor.”


Nigeria’s National Domestic Gas Supply And Pricing Policy

INTRODUCTION – Policy Aspirations GIVEN THE ABUN DANCE OF NIGERIA’S gas resources, Government has identified the accelerated development of the domestic gas sector as a focal strategy for achieving the national aspiration of aggressive GDP growth (10% increase per annum). Domestic gas is defined as gas utilized locally within the shores of Nigeria either for home, industrial and/or electric power use. Specifically for industrial use, gas used in value adding industries such as methanol, fertilizer etc. is considered domestic gas, regardless of whether the end product (i.e. fertilizer, methanol) is consumed locally or exported.

Gas export (LNG and pipeline) provide high returns to government through tax receipts and dividends for equity stake. However, it is recognized that beyond economic rent, there are broader strategic benefits to the economy that may be attained from the domestic utilization and value addition to natural gas. In essence, in addition to exporting of natural gas, Nigeria must develop strategies to ensure increased domestic utilization.

Rising gas prices in key international markets however continues to create a preferential pull for exports. Consequently, there is a disproportionate focus by gas suppliers in the country for LNG projects. This is creating an anomaly in Nigeria where there is now a significant shortfall in the availability of gas for domestic utilization. The continued shortfall directly threatens the economic aspirations of the nation which if unchecked may result in Nigeria supporting the development of the economies of the industrialized nations at the expense of its own economy.

The energy requirement to sustain an aggressive GDP growth is enormous. Currently, total demand (export and domestic) for natural gas far outstrips supply. The demand is driven by growth in the Power sector and other gas based industries such as Fertilizer, Methanol, LNG etc.  Gas demand is forecast to grow from the current level of 4bcf/d to about 20bcf/d by 2010. In the short term, the growth in the domestic sector is particularly most aggressive, growing from less than 1 bcf/d in 2006 to about 7 bcf/d by 2010.  This demand growth is underpinned largely by the power sector and by an increasing requirement by large industries such as fertilizer and methanol that require gas in high quantities. These industries which are unable to compete in high gas cost locations have expressed strong interest in relocating to Nigeria.

Nigeria needs to demonstrate availability and affordability of gas or else risk losing these industries to competing nations like Egypt, Trinidad etc. The scale of demand growth relative to supply growth creates an immediate availability challenge. In addition, is the challenge of price affordability and hence gas pricing. The domestic demand sectors such as electric power, fertilizer, methanol etc. have varying capacity to bear gas prices (Fig. 1). For example, the Nigerian Power sector has a lower gas price threshold than a Methanol industry. Government is however keen to stimulate the growth of all these sectors. Timely availability, affordability and commerciality of supply of natural gas is a critical pre-condition for realizing the government’s aspiration for the domestic economy.

In recognition of the urgent need for domestic gas availability and a pricing framework to drive and sustain a major gas based industrialization in Nigeria, this policy document seeks to:

l. provide solutions to the issue of gas pricing;

2. address domestic gas supply availability in a manner that delicately balances the need for domestic economic growth and revenue generation from exports; and

3. provide an implementation approach for the gas pricing that enables the full participation of all gas suppliers in the country in a manner that ensures sustained gas supply to the domestic market.

B) GROUPING OF NIGERIA’S DOMESTIC DEMAND SECTORS

The need for a pricing strategy that recognises the diversity in the ability of the various industrial sub-sectors to bear gas price cannot be overstated. Such strategy will not only enable and sustain diversity of the demand sectors, thereby enabling Nigeria to benefit from the industrialisation potential that is inherent in gas, it will also enable the selective maximization of net revenues for Nigerian gas from sectors that are most able to deliver that direct economic benefit.

From a gas pricing strategy perspective, Government has grouped the entire domestic demand into three broad groupings. This grouping is in recognition of the fact that the different demand sectors have different strategic benefits to the country and different pricing considerations. Fig. 2.1 below presents the three categories. Any demand sector will fall into one of these categories and where there is a lack of clarity, the Minister for Energy will determine the classification of such sector. Fig 2.1: Grouping of Gas Demand Sector

The groupings are:

Strategic Domestic Sector — This refers to a very limited set of sectors that have a significant direct multiplier effect on the economy namely the Power Sector (residential and light commercial users) or other sector that the Honourable Minister for Energy may from time to time consider applicable. The strategic intent in gas pricing is to facilitate and ensure low cost gas access to these sectors in order to spur rapid economic growth.

Strategic Industrial Sector  – This refers to industries that utilise gas as feedstock in the production of value added products that are primarily destined for export or in some cases, consumed locally. Strategically, these sectors ensure that value is added to Nigerian gas before it is exported. The process of value addition ensures industrialisation, job creation etc. Typical projects in this group are Methanol, GTL and Fertilizer. For this sector, the strategic intent in pricing is to ensure that feedgas price is affordable and predictable in order to ensure competitiveness of the products in international markets in the face of competition from other gas producing countries such as Qatar, Trinidad etc. that provide gas at very low prices to buyers.

Commercial Sectors — This refers to sectors that use gas as fuel as opposed to feedstock. Unlike the two previous classifications, projects in this category are a potential major direct revenue earner for Nigerian gas in view of their capacity to bear high gas prices as the competing alternative fuel is LPFO. Typical sectors in this category include cement and domestic manufacturing industries, industrial Power etc.

(C) GAS PRICING REFORM – LIQUIDS BASED PRICINGAPPROACH

A widely known characteristic of Nigerian gas is its relative richness in liquids i.e. NGLs. NGLs continue to attract a high price in international markets (similar trend in crude oil pricing). As a result of the potential high revenue that comes from NGLs produced in conjunction with residue dry gas, it is possible for a gas supply project to accommodate a relatively lower price for the residue dry gas and still be a profitable supply project. Residue dry gas is used mostly in the domestic market.

This gas pricing policy aims to exploit this intrinsic value of NGLs in deriving a relatively low gas price for the strategic domestic sector – Power. It is recognized that not all gas resources in the country are rich in NGLs, consequently, it is intended that this philosophy be applied selectively — especially in the short term as the Power sector is currently unable to pay higher price for gas (in view of the low end user power tarrif that currently obtains in Nigeria).  It is however the expectation that in the medium term, power tariff will be more commercial and a higher gas price will be achievable.

Based on an assumption of $40/bbl long run NGL price, it has been established that across the Niger Delta, there is a limited volume of gas reserves for which the marginal cost of development and supply can be met profitably with a dry gas price of $0. l/mcf. This assumes that the supplier receives $0.1 /mcf for the residue dry gas in addition to other NGL revenues at $40/bbl. It is the intent of this policy that this category of gas reserves be deployed for use in the strategic domestic sectors. $0.1 0/mmbtu is therefore established as the floor price for the strategic domestic sector. This low price is in line with the strategic intent of ensuring a low cost gas supply to those critical sectors of the economy.

In addition, based on existing transmission infrastructure costs in Nigeria and international benchmarks, a transmission tarrif (on postage stamp basis) of $0.30/mmbtu is proposed. The Honourable Minister for Energy may revisit this tariff from time to time as appropriate.

D) THE GAS PRICING FRAMEWORK

The gas pricing framework proposed in this policy is a transitional pricing arrangement. The Honourable Minister of Energy (Gas) will monitor the environment and determine when the domestic market is fully developed and an alternative pricing approach is required.

It is important to establish that the pricing framework does not fix prices. It barely sets out a transparent structure for determining  the floor price for dry gas for 3 categories of demand sectors presented in section B. The floor price is the lowest price that gas can be supplied to a particular category of demand sector. The actual price paid is based on an indexation formula jointly determined during negotiation between the buyer and seller. In essence, the market actually determines the price by establishing the indexation mechanism.

Figure 3.1 below presents a schematic of the pricing framework. Three distinct price regimes are evident in the framework, corresponding to three different approaches for determining the floor price. The three approaches include

1. Cost of supply basis (regulated pricing regime)

2. Product netback price basis and (pseudo- regulated pricing regime)

3. Alternative fuels basis. (market led regime)

The Regulated Pricing Regime (cost of supply basis): This pricing approach applies specifically to the strategic domestic sectors of Power. As discussed in section C, the floor price for this category is determined primarily by establishing the lowest cost of supply that allows a 15% rate of return to the supplier. This has been established as $0. l/mmbtu for a limited volume of gas reserves. These reserves will therefore be assumed dedicated to the strategic domestic sector.

The Pseudo-Regulated Pricing Regime (Product Netback basis): The second floor price determination approach applies strictly to strategic industrial sectors i.e. sectors that use the gas as feedstock. For this group, the floor price is not based on the cost of supply of the gas, but on the netback of the product price. The product price used in determining the floor price is the assumed long run price of the product. With this approach, the pricing of gas will better reflect the ability of the sector to pay given the price of its product. However, since the intention of this policy is not to support sectors that are unviable i.e. sectors whose netback price translates to a gas floor price lower than the cost of supply of gas, the consideration of affordability will not be at the expense of sustainability of gas supply.

The Market Led Regime (Alternative Fuels Basis): The third floor price determination approach applies to all other sectors that use gas as fuel or wholesale buyers buying gas for subsequent resale. For this category, the price of gas is indexed to the price of alternative fuel such as LPFO. The indexation will be established during negotiation.

The foregoing structure provides the basis for the pricing framework illustrated below. Three segments can be identified in the framework consistent with the three demand sector groupings, starting with the lowest priced sector, the strategic domestic sector to the highest priced sector — the commercial sectors. It is assumed that pricing for each demand sector will transition to the next higher pricing band once a saturation level has been attained. For example, for the strategic domestic sector, once the domestic requirement has been met (domestic saturation point) and Power is now being exported, the framework proposes that export Power benefits from a relatively higher price, determined by the netbacking philosophy applied to strategic industrial sectors such as methanol. Similarly, once the capacity of a strategic industrial sector exceeds an export saturation limit (i.e. once Nigeria’s export capacity for that sector e.g. fertilizer is assumed to have reached an acceptable limit), any incremental capacity will attract a much higher price consistent with that of commercial sector buyers. Through this transitional mechanism, pricing can be aligned with required capacities within the economy.

Indexation

It is important to reiterate that the entire gas pricing framework simply specifies the floor price. Actual prices will include an escalation for inflation and an indexation to real time product price (which may be higher than the long run price used in the determination of the floor price) and/or any other indices considered appropriate by both buyer and seller of the gas. The indexation will be determined through a process of negotiation.

(E) IMPLFMINTATION

(i)The Downstream Gas Act

To underpin the proposed pricing framework, Government will establish a Gas Regulatory Agency, the Gas Regulatory Commission, through the proposed Downstream Gas Act. Amongst other functions, the Commission will have the power, where necessary, to regulate the price of gas supplied and utilized in the downstream gas sector and the power to promote reliable and efficient use of gas throughout Nigeria. It will also have the power to monitor and impose pricing restrictions on licensees. Pending the establishment of this GRC however, an interim agency will be set up by the Minister as a department within the Ministry of Energy (Gas).

Consistent with the pricing principles established by the Act, the Commission will have the power to regulate the prices charged by licensees where competition has not developed to such an extent as to protect the interest of consumers. The relevant pricing principles in this regard are cost reflectivity, price disaggregation and the earning of a reasonable return on investment by licensees.

A Transitional Pricing Plan setting out temporary or transitional pricing arrangements allowing for a gradual transition towards pricing arrangements that are consistent with the pricing principles above is required to be introduced by the Downstream Gas Regulatory Agency. The gas pricing framework presented in this policy document is designed to achieve this objective.

(ii) Domestic Gas Reserves and Production Obligation

In implementing this pricing policy, it is essential that there is sufficient gas available for the various demand sectors. To facilitate this, a domestic gas supply and reserves obligation will be imposed on all operators in the country. In essence, all gas (AG and NAG) asset holders will be required to dedicate a specific proportion of their gas reserves and production for supply to the domestic market. This is the “Domestic Reserves Obligation”.

The reserve obligation will be broken down annually to a production obligation for the same period. The sum total of all obligations will equal the planned domestic requirement for the stated period. Periodical reviews to the domestic obligation will take place to reflect the changing demographics of the demand and supply landscape i.e. new demand will be allocated accordingly as new suppliers come on stream. The Minister for Energy will periodically stipulate the reserves and production obligation of the various operators. The allocation of the obligation across operators will be based on the principles of equity to be determined by the Minister.

(iii) The Aggregate Gas Price and the Strategic Gas Aggregator

The gas pricing framework stipulates a pricing regime for various demand sectors ranging from a floor price of about $0.l/mcf for the strategic domestic sectors to over $2/mcf for the commercial sectors. The Aggregate Domestic Gas Price is the forecast average domestic price based on the projected total domestic demand portfolio using the relevant prices proposed by this framework.

All suppliers of gas in the country will be paid the aggregate domestic gas price. A target aggregate price will be set by the Gas Regulator based on the known portfolio of domestic demand. The portfolio will be balanced continually to ensure that the aggregate price does not fall below the threshold. In essence, the suppliers have a fixed price whilst the buyers will pay the sector price proposed in the framework. The aggregate pricing will ensure that regardless of their geographical location all suppliers are able to benefit from the high priced customers as well as from the low priced buyers. The aggregate price will ensure that the suppliers receive an acceptable return for their domestic obligation.

A Strategic Aggregator (under the auspice of the Department of Gas or the GRC) will manage the implementation of the domestic reserves and production obligation and the aggregate price. It will ensure a balanced growth of the domestic portfolio such that the target minimum aggregate price is achieved whilst not compromising the nation’s primary objective for economic growth by ensuring the availability of adequate volumes of gas to the strategic domestic sectors.

Conceptually, the Strategic Aggregator acts as a one stop intermediary point between the suppliers and the diverse demand sectors and will ensure that gas is supplied at the aggregated price. Through a Gas Management Model, the Strategic Aggregator plays the role of portfolio manager on behalf of all suppliers the primary objective being to preserve a minimum aggregate price portfolio. When the aggregate price is higher than the minimum threshold, an agreed portion will be paid out to the suppliers whilst the balance will be retained as cushion in the event that the portfolio mix for unavoidable reasons falls below the target minimum threshold.

Conclusion

The National Domestic Gas Supply and Pricing Policy therefore aims to fully align the gas sector with the economic growth aspiration of the nation. This policy will be applied in conjunction with the Gas Pricing regulations and modifications thereto.

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