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Shell Transforms To A Gas Producing Company

Shell’s equity gas production all over the world will surpass its net oil output by the end of 2012. It is official. “Globally, Shell is focusing more on gas”, says Ubaka Emelumadu, Vice President Gas, Sub-Saharan Africa Shell Upstream International.
Shell is increasing its gas output in places as far flung from one another as Qatar, The Netherlands, Australia, Russia and Nigeria.

Shell Transforms To A Gas Producing Company

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Gas Policy Delays Tanzanian Bid Round

Tanzania has shifted its 4th offshore licensing round further by a few months to allow its parliament enough time to ratify the Natural Gas Policy and Gas Utilization Master Plan. The sale of nine blocks was to have been launched in the first week of September 2012, but the Tanzanian Ministry of Energy & Minerals has called for the delay until the parliamentary session in October 2012, when the government will be presented with the instruments.

The move will allow the policy to be ratified before the start of the new roadshow schedule, which is anticipated to start again soon after the Parliamentary ratification. The gas policy and gas utilization master plan have to be backed up by a Gas Act.

18 companies are working in Tanzania with 26 gas exploration licenses, exploring gas in the country as well as off the country’s coast.

ION GeoVentures, the consultant to the Tanzanian government on the bid round, says  that the bid round data package will be available for review and purchase by September-end.

“Investors will get more time period to evaluate the technical data and assess the prospects of the nine blocks on offer”, the company explains.


South Africa Warms Up To Gas

First it was the National Planning Commission report. Then came the Cabinet’s lifting of moratorium.

Overnight, the mainstream thinking of the South African political and business elite has changed from “gas-is-not-on-the cards” to “its -okay-to-include-gas-in-the mix”.

The South African National Planning Commission’s revised plan, released in August 2012, repeated its cautionary note on the cost of nuclear power, the country’s preferred alternative to fossil fuels, and suggested a diverse mix of energy sources. The Commission said: “If gas reserves are proven, and environmental concerns alleviated, then development of these resources and gas-to-power projects should be fast-tracked.”

Several days after the Planning Commission’s report was aired all over the media, the government lifted a year- long moratorium on Shale Gas Exploration.

And then, the South African media went agog with discussions about the imperative of gas in the country’s energy mix.

South Africa’s energy policy has not always viewed natural gas, the world’s least polluting fossil fuel, as an important resource for its planned, massive increase in electricity supply capacity.

The Integrated Resource Plan (IRP) for the country, published as a government gazette in May 2011, envisages an addition of 42, 600MW of new build electricity generation capacity between 2010 and 2030, to all existing and committed power plants. The plan assumes a nuclear fleet of 9,600MW; 6,300MW of coal; 17,800 MW of renewable;  and 8,900 MW of other generation sources, which includes only 2, 400MW of close cycle gas turbine generated power.

The installed open cycle gas turbines currently generate 1,316MW, or a mere 4% of the country’s nameplate capacity. Two of these four gas plants-the 588MW Ankerlig plant and the 438MW Gourikwa plant- were commissioned only in the last six years. Before they were built, the country was generating just 342MW (171MW each) from two plants: Acacia and Port Rex. South Africa’s power utility Eskom currently supplies 45% of Africa’s power and 95% of its own country’s electricity, mostly from coal-fired plants. There’s limited space for more private sector generation in the medium to the long term.

We have argued, in this magazine, that even the 2,400MW of gas fired electricity in the IRP, a 20 year resource plan envisaging a build of  42, 600MW, is a mere after thought. The national conversation around energy issues in South Africa has involved every conceivable energy source but natural gas. The roll out for installation of renewable energy plants has kicked in; there’s a vibrant discussion of the possibility of scaling up nuclear power generation in the country, even if there are more skeptics than optimists; and the place of coal in the country’s energy future is assured.

But no one was, really, discussing gas until recently. The IRP had extensive input from a wide range of stakeholders in the energy industry.

A key reason for the aversion to gas utilization in S.A’s energy mix is that while the country doesn’t have much gas reserves, it considers the cost of imported gas as rather too high.  Take this liner in the plan:  “The import coal and hydro options are preferred to local options, but imported gas is not preferred to local gas options”. So, even while South Africa has the opportunity to benefit from the recent natural gas finds offshore Mozambique, one of the  most significant hydrocarbon discoveries  on the planet in the last 10 years.

The current upbeat mood about gas in the South African national conversation is driven largely by the optimism that Shale gas exploration would unlock trillions of cubic feet of shale gas in the Karoo.

The discussion still has not accommodated nuanced reviews of the opportunities afforded by gas pools in neighbouring countries.


The African Gas Grid On Hold

The notion of a system of pipelines delivering methane from “rich” countries to “poorer” neighbours is passé.

A decade ago, there was much heady talk of a Pan African Gas Grid. The notion was of a series of gas lines, feeding off main lines, to deliver gas from hydrocarbon rich parts of the continent to hydrocarbon starved towns and villages.

There were conference deliberations of a system of cross-border gas lines diverted and integrated into national gas grids, giving access to several gas sources and allowing market security and flexibility to develop through storage and swaps of volumes between nations.

The idea started to gel as the 895km Mozambique-South African gas pipeline moved into commissioning phase in 2002 a year before the West African Gas Pipeline Implementation Agreement was signed at a ground breaking ceremony in Sekondi, Ghana. The 672km line running from Nigeria through Benin, to Togo and terminating in Ghana, was to deliver Nigerian gas to the “energy-starved” countries along the route. Around the same time, the earliest conversations about a 4,000km trans Saharan gas pipeline, taking Nigerian gas across the desert through Niger to Algeria, were being tabled.

So much promise.  Nigeria and Cameroon agreed to export more than 800million standard cubic feet per day of gas to Equatorial Guinean through pipelines from either country (although this was less for domestic purposes than for boosting EquatoGuinean plans for a second LNG project).  In Namibia, south west of the continent, arrangements were being made to pipe gas from the 1.5Tcf the Kudu gas field to South Africa, where it would feed thermoelectric plants meant to power both Cape Town in South Africa and power-starved Namibia.

The Moz-SA line  having been commissioned and the WAGP already under construction, commentators were touting these two as representing  the building blocks of a continental grid that could assure availability of gas to resource poor countries and lift the industrial capacity of those who inhabit the continent.

The promoters of WAGP painted it ever so brightly.  A Dames & Moore study, commissioned by Chevron suggested that between 10,000 and 2,000 primary sector jobs will be created as the new power suppliers stimulate the growth of new industry. This industrial growth, they touted, would create up to three times that number of secondary jobs due to the multiplier effect. A pre-investment study of the WAGP identified about $1.8 billion in total capital investment for the region as a result of pipeline project. “That includes the $ 400 million for the power plants, and $ 800 million in new industry, which include minerals processing.”

Whereas most of WAGP’s 140MMscf/d gas is destined for power plants in Ghana, Benin and Togo, replacing other fuels and reducing costs and emissions, the fact of its availability would open doors to other investment possibilities, we heard.

Investors actually sat down and took notice. Anglogold Ashanti, the huge gold miner, hinted of replacing fuel for its plants with gas from WAGP. Gaslink, the Nigerian independent gas supplier, said it wanted to tap from WAGP gas and deliver, through spur lines, to companies and industries in Ghana, Benin and Togo.

Much of that conversation has been scuttled. Today, with epileptic supply of gas from WAGP, ranking Ghanaian officials are openly wondering why they bought into the project in the first place. Togo and Benin, where the demand is weaker, have remained silenced with the disappointment. Nigeria, the source of the gas, is battling internal challenges of gas supply to its own growing domestic power capability and Shell, a major supplier of the gas for the pipeline, hasn’t lived up to its billing as a supplier of good quality pipeline gas. The power plants to be built in Ghana, as far as the Ghanaian Gas Masterplan is concerned, are looking more to gas supplies from the Jubilee field, a resource that was discovered four years after the WAGP Implementation agreement was signed. And as for thousands of jobs that were meant to be created in the event of the take off of the pipeline, what you have are angry Ghanaian commentators demanding accountability for what has gone wrong with the WAGP.

Since July 2009, when Petroleum and energy ministers Rilwan Lukman of Nigeria, Chakib Khelil of Algeria and Mohammed Abdullahi of Niger signed the agreement in Abuja, there has been a significant reduction in public discussion on the project which was proposed to have a capacity of 30 billion cubic metres per annum.

“Nobody talks of Trans Saharan Gas Pipeline anymore” says a ranking official at the Nigerian state hydrocarbon company, the NNPC. “The project has been put on hold”. The Algerians, who seemed the keener partners in the first place, have gone rather quiet, and the Nigerians talk about it in terms of, “when we are able to get some interested parties who will foot the bill”.

In the south west, Eskom’s enthusiasm for Namibian gas and/or of the power to be generated from the planned 800MW combined cycle plant at Oranjemund in Southern Namibia , that would be fueled by gas from the Kudu gas field, has waned.   Discussions between Tullow Oil, the British operator of the Kudu field and Eskom didn’t get anywhere. “The Kudu Gas to Power Project in Namibia was not concluded due to the economics of the project”, Eskom said in a statement.  “Electricity would have been produced at a cost well in excess of Eskom’s own options.  In addition certain risk allocations (such as fuel price currency and indexation) could not be agreed between the fuel supplier, the project developer and Eskom”.

In the meantime, however, some of the countries that were being describes as “energy-starved”, are turning round to be hydrocarbon rich. Ghana, for one, which is building a gas processing facility that will feed power plants and supply industrial parks. Just the other day, Apache encountered 52metres of net gas sand in a well in offshore Kenya. Companies have struck oil in Liberia and Sierra Leone.

The dynamics are changing.


A Firmer Grip On Domestic Gas

Quantity of Natural Gas Vehicles Sold in Egypt

Investments are flowing into pipelines, gas processing facilities and gas-for-factories all over the continent

The headline news favour big ticket projects; Five million metric tonnes  per year LNG trains aimed at the Chinese market. Long trans-border gas pipelines lain under the Mediterranean Sea, ferrying North African gas to Europe.

But the projects that will kickstart Africa’s industrialization are less likely to feature humongous sized vessels transporting super-cooled natural gas from offshore  Mozambique to China, than several, intra country pipelines taking methane from hydrocarbon rich villages to power plants, factories and homes in the continent’s rapidly growing cities.

These projects are starting off all over the continent, more readily than they used to. After Ghana insisted to World Bank officials that it would not export its gas to pay its loans, the country took a couple of years to get a grip on developing the fuel for home use. Now the project is going forward.
The concept: A 36km shallow water, dense phase gas pipeline will take one hundred and twenty million standard cubic feet of gas per day (120MMscf/d) of gas from the Jubilee Field production facility to a new, 150MMscf/d central processing facility at Atuabo (in Ghana’s Western region) to produce lean gas, propane, butane LPG and condensate. From here, a 120km onshore gas line will deliver the lean gas to a 550MW thermal power station at Aboadze, near Takoradi, while another 75km onshore line will transport more gas to the mining centre of Prestea. The plant at Atuabo is planned to be Ghana’s first gas hub, as gas from other discoveries, including those at Sankofa, Dzata, Tweneboa, North and South Tano fields, will be piped to Atuabo for processing. The cost is $850MM. Opportunities will open up to secondary distributors of gas, as well as industries that can take advantage of the fuel.

Tanzania: State sponsors a big infrastructure leap.
In July 2012, Tanzania signed a contract with three Chinese companies -China Petroleum Technology Development Corporation, Petroleum Pipeline Engineering Bureau and China Petroleum Pipeline Engineering Corporation to construct an 898 kilometre pipeline from Mtwara to Dar es Salaam and then round the  bay(offshore). The project will cost $1.2 billion (or 1.86 trillion shillings). Anticipated project completion date is early to mid- 2014. The onshore segment involves a 36-inch line for 487 kilometres and a 24-inch line for 24 kilometres, connecting the mainland to the gas source on Somanga Fungu, a small island in the Indian Ocean. Officials say that the infrastructure will drastically reduce the cost of electricity generation from $0.42 (663 shillings) per to $0.02, almost 32 shillings.

Mozambique, Big and small:
While everyone focuses on Anadarko’s proposed two train LNG project off the coast of Mozambique, a number of gas projects are taking off in this South east African country. ENH, the state hydrocarbon company, has initialed an agreement with South African synfuels giant Sasol, that will lead to having natural gas piped to homes in Maputo city and the neighbouring district of Marracuene.
Since 2004, Sasol has commissioned and operated both a gas processing facility located in Temane in southern Mozambique, and a pipeline that takes the gas from the Pande and Temane fields to Sasol’s chemical plants in the South African city of Secunda. A branch of the pipeline goes to Matola where it supplies gas to several Mozambican industries, including the Mozal aluminium smelter. With the April 2012 agreement, Mozambican homes and smaller enterprises will begin to benefit.

Some 100 institutions, including hospitals, hotels and restaurants will be the first beneficiaries of the pipeline. The programme is expected to capture all of Maputo and Marracuene within ten years.

Sasol promises to make available to ENH, for domestic consumption, some 5.5Billion cubic feet of gas a year for a period of 20 years in an initial phase. The gas pipeline will run from Matola to Marracuene over a distance of 30 kilometres. It’s not clear how much each residence connected to the line will pay, but ENH says the $40MM project, funded by South Korea, will be implemented on the basis of social funding and subsidized, so that takers will be connected at a much lower price than the cost reflective price of $1,200.00.

Cameroon: small is beautiful.
One project to watch is the Victoria Oil and Gas(VOG) operated Logbagba project in Douala, the main commercial city of Cameroon. It’s a very small project, with the initial phase completed in November 2011, delivering 0.7MMscf/d of gas to factories in the city. The project is on course to raise capacity to 8MMscf/d. The delivery helps companies to substitute heavy fuel oil and waste oil used in raising heat with natural gas, helps in power generation at customer sites and is used in centralized near site power generation with local distribution, in compliance with current electricity legislation and regulations, on industrial estates and at the Douala port. Essentially, what VOG is doing is a minuscule version of what Oando is doing in Lagos; delivering gas to factories, but Cameroon is a much smaller economy than Lagos and the fact that this is happening at all is key.

Nigeria’s is the most ambitious.
For all the debate about the pace, the efficiency, and the operating environment, the Nigerian state-led infrastructure programme for domestic gas is the most ambitious on the continent. True, the cost is not comparable with the outlays that Egypt and South Africa, the biggest economies in the neighbourhood, have invested over several years on keeping the lights on. But among the smaller economies, Nigeria is a local champion of sorts. Spending $2Billion at a go on a number of gas pipelines(See map) to connect gas wells to power plants, while a number of power plants are being built all over the Niger Delta basin, is noteworthy.

Egypt keeps the lead.
Egypt has powered its economy with natural gas, providing the impetus for the near doubling of consumption over the last decade, to reach 1.6 Trillion cubic feet (Tcf) in 2010. Electricity consumption increased by an average of 7 percent per annum in the past 10 years, surging from nearly 61 billion kWh in 2000 to 116 billion kWh in 2009. In terms of electricity generation, conventional thermal electricity, which derives from traditional fossil fuels, accounts for nearly 90 percent of Egypt’s electricity generation, with the remainder mainly from hydroelectricity. The increased use of compressed natural gas as a fuel for motor vehicles and the conversion of some thermal power plant feedstock to gas have, to an extent, helped to ease the consumption of petroleum products.


Afren to Develop Gas Assets with EDF, Gasol..

Afren, the AIM listed, Africa focused operator, has signed a Memorandum of Understanding (MoU)  with Electricite de France (“EDF”) and Gasol plc to examine  a gas aggregation joint venture to identify and develop stranded gas assets in certain identified West African countries.

The proposed joint venture will develop gas to proven status, construct requisite collection networks to aggregate, and deliver the gas to a central gas processing hub for domestic use and/or export to global markets as Liquefied Natural Gas (‘LNG”). It is envisaged that Afren and EDF will share participation in developing the exploration and production gas assets to proven status, and that EDF and Gasol will share participation in the collection of the gas, and its processing, liquefaction and monetization.

Afren already has a co-operation agreement with E.ON Ruhrgas AG and Gasol, to investigate the availability and accessibility of gas in Nigeria, with a focus on the Anambra Basin and south east Niger Delta, announced in January 2008.


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.


Construction on Medgaz pipeline begins

CONSTRUCTION BEGAN ON THE FIRST stage of the Medgaz pipeline from Algeria to Spain on March 9, 2008. The Medgaz consortium includes Algeria’s state-owned Sonatrach with a 36% stake, Cepsa and Iberdrola SA with 20% each and Endesa SA and Gas de France with 12% each. Despite a number of disputes in the second half of 2007, Algeria and Spain eventually agreed on the amount of gas Sonatrach may sell through the Medgaz pipeline. Spain agreed to allow Sonatrach to sell more than 1 billion cubic metres of natural gas through the pipeline and dropped five of the seven conditions for Sonatrach to increase its stake in the Medgaz project from 20% to 36%. The pipeline is expected to transport at least eight ( 8) billion cubic metres of gas per year to Europe beginning in 2009.


Kikwete Endorses 300MW Power and CNG Export Project In Tanzania

TANZANIAN PRESIDENT JAKAYA Kikwete has endorsed a domestic gas to wire project as alternative commercialization options for monetizing the natural gas resource of Mnazi Bay Concession. He has also endorsed a marine compressed natural gas export project, aiming to use the same feed stock. A joint analysis of Pre-Feasibility study, undertaken for the proposed 300 MW power generation and transmission

interconnection project, collectively termed the VLPP, was presented to the president by management of Artumas, operator of the Mnazi Bay and officials of the relevant Tanzanian government in January 2008. The study recommended the VLPP and marine CNG export projects as the priority developments for natural gas utilization. Mr Kikwete advised ‘Artumas to move forward with both initiatives, targeting 2010 for start up

of commercial operations. Phase 2 analysis is underway, further examining capital and operating costs for the generation assets, assessing the economics and routing challenges for the Mtwara-Dar es Salaam transmission interconnection, and examining the environmental aspects of the overall development through an Environmental Impact Scoping Assessment. The Phase 2 Pre-Feasibility results were targeted for end-February 2008, and expected to be input to final decision regarding project sanction and financing. The VLPP has been incorporated within the TANESCO Tanzania Electricity Master Plan update, which is to be released in first-half 2008. Artumas is maintaining its focus on the marine compressed natural gas (CNG) export project, moving natural gas from Mtwara to Mombasa. Ongoing monitoring and geopolitical assessment of the political turmoil in Kenya suggests that the recent unrest should not impact the timing of the CNG export development, according to the release.

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