17 January 2014, Sweetcrude, Port Harcourt –Dr. Chijioke Nwaozuzu is a former British Chevening Scholar and PTDF PhD Scholar. He was recently awarded an Honorary Doctor of Science (DSc) by the Victoria Global University (VGU), Island of Turks & Caicos (UK Territory).
He was recently appointed a Senior Lecturer at the Emerald Energy Institute (for Petroleum & Energy Economics & Policy), University of Port-Harcourt. He belongs to numerous professional organizations and networks. In this interview he speaks on a number of issues affecting the Nigerian oil and gas industry.
What is your assessment of the industry as at 2013, with regard to exploration and production, refineries, importation of petroleum products, etc. Did we fare well? Could we have fared better?
First and foremost, the Nigerian Petroleum Industry is still evolving and the time I ripe to transform it. The passage of the Petroleum Industry Bill (PIB) by the National Assembly holds the key to further restructuring of the industry. Presently, Nigeria is the largest producer of oil in Africa; the 11th largest producer of oil in the world; and the 8th largest exporter of crude oil. Nigeria’s oil is mainly classified as ‘sweet crude’ or ‘light crude’ and has very low sulphur content. Nigeria is also the largest producer of ‘sweet crude’ among OPEC (Organization of Petroleum Exporting Countries) countries.
Nigeria’s oil production hovers between 1.9 million barrels per day (bpd) and 2.5 million bpd. Pipeline vandalism and crude theft currently are responsible for marring production, which could have been increased to 4 million bpd by 2010 in the absence of such constraints. There were 37.2 billion barrels of proved oil reserves as of 2011. Nearly 43% of Nigeria’s exports go to the US, and this volume is threatened as the US is investing heavily in the production of shale oil, solar and wind energies as well as hybrid and electric vehicles.
With a speedy passage of the Petroleum Industry Bill (PIB), NNPC along with her joint-venture partners can possibly achieve the goal of improving known crude reserves from the current 36 billion barrels as at 2013 to 40 billion by 2015. The national target is to achieve 40 billion barrels of oil reserves and a daily production of 4 million barrels of oil (bpd), including condensates, as envisioned in the Vision 20: 2020. To ensure that other prospective basins are reasonably explored, the Ministry of Petroleum Resources has ramped up exploration activities in the entire inland basins of Chad, Anambra, Benue, and the Bida / Sokoto / Dahomey basin. There are increased exploration activities in the offshore, onshore and inland basins leading to the drilling of a total of 19 exploration wells in 2012. Within the period 2011-13, 93 development wells under joint-venture (JV), 38 under PSC, and 33 workover wells were drilled.
Consequently, crude oil production has been maintained currently at an average of 2.3 million bpd despite massive crude oil theft, illegal oil bunkering, and pipeline vandalism. Production lost to crude theft alone is about 400,000 bpd. We should recall that in the aftermath of the FGN Amnesty Programme, crude oil production rose from 1.9 mbpd in 2009 to a peak of 2.62 mbpd in 2010. Sustained production at this level has been marred due to the above factors. Government has put plans in place to stem this menace through effective law enforcement and application of the Crude Oil Fingerprinting Initiative (COFPI).
The industry has achieved significant oil reserve additions since the inception of this current administration. As at 2012 year ending, a total of 600 million barrels of reserves were added which translates to 70% reserve replacement. Crude oil reserve base dropped by 0.06% to 36.8 billion barrels compared to year ending 2011 figures. In addition, Nigerian Petroleum Development Company (NPDC) production capacity has been boosted through strategic divestment and thus has grown their reserve base to 1.7 billion barrels. Given the current rate of reserve additions and the intensified exploratory work going on, it is possible for the current administration to achieve the target of 40 billion barrels of crude reserves by 2015. The Petroleum Ministry is currently developing a comprehensive framework to increase crude oil production from an average of 2.3 mbpd to 4 mbpd within its life-span.
Nigeria’s gas reserves is estimated at 187 trillion standard cubic feet of gas (scf), with current production estimated at 8.24 billion standard cubic feet of gas per day (scfd) as of 2012. The current gas supply is enough to support about 5 giga watts (GW) of power generating capacity. Bulk of this gas is associated gas (AG) which is produced in the course of crude oil extraction. Nigeria’s gas reserves are about three times the value of her crude oil reserves.
Federal Government’s target is to achieve over 7 Giga Watts (GW) of electricity before the end of the year by injecting about 3.5 GW of electricity into the national grid through the NIPP projects. However, power generation of this magnitude has a direct correlation to aggressive natural gas production, and the oil & gas industry has a lead role to play in natural gas production. This should not be a difficult target to realize, considering that the Nigerian Jurisdiction is regarded as ‘a natural gas province with traces of oil in it’. Therefore, we need to examine what the oil and gas sector is doing to boost natural gas production in Nigeria.
Previous government’s policy of producing natural gas mainly for export is gradually being replaced with one that also accommodates gas production for domestic use (i.e. for cooking and for power generation and manufacturing sectors). There have been notable achievements in gas production so far. Total average gas production increased from 7.7 billion standard cubic feet of gas per day (scfd) in 2011 to 8.24 scfd in 2012, which translates to a 7% increase. There is also a decrease in gas flare to about 10% compared to 30% in 2010.
The Petroleum Minister’s Emergency Gas Supply Plan (2012) has contributed over 230 million scfd for power generation and thus increased national power generating capacity by 30% (4.2 GW of power). The planned addition of 450 million scfd of gas supply for power generation will boost generating capacity by an additional 40% (i.e. to 6 GW of power). Domestic gas supply has peaked at 1.5 billion scfd currently, and a significant proportion is being channeled to the power sector. The current gas supply should support about 5 GW of power generating capacity. Based on realistic projections this is expected to increase to 10 GW by 2015 / 16. Nigerian Petroleum Development Company (NPDC) is being positioned as a dominant gas supplier to the domestic market. NPDC has a producibility of 450 million scfd in the Western Niger Delta. In 2012, the Oredo Integrated Gas Handling Facility contributed 65 mscfd to the gas network.
Domestic gas supply to household and manufacturing sector almost doubled from 185 million scfd to 357 million scfd, and thus has provided feedstock for growth in the nation’s cement sector and over 200 manufacturing companies. This figure continues to grow as the Nigerian Gas Company (NGC) constructs additional pipeline infrastructure. Consequently, gas sales have risen to about 4 billion scfd in 2012 (an increase of about 70%).
A contract has been awarded for the construction of a 120km East-West Gas Pipeline crossing the Niger River, and is expected to be completed by 2015. This pipeline creates a major linkage between the huge gas reserves in the Eastern Niger Delta and other parts of the country. On completion this critical gas pipeline could mitigate the shortfalls in gas supply to the power sector in the Western Region.
The largest natural gas initiative in Nigeria is the Nigerian Liquefied Natural Gas project which is operated by several foreign oil companies and the Nigerian National Petroleum Corporation (NNPC). Another major natural gas project is the West African Gas Pipeline which has encountered several bottle-necks. However, when completed the pipeline would transport natural gas from Nigeria to Ghana, Togo, Benin Republic and Cote d’Ivoire. Bulk of the AG is flared off and Nigeria loses an estimated $18.2 million daily from the loss of revenue from flared gas. In recent years, the volume of gas flared has been significantly reduced and plans have been initiated to put an end to gas flaring in the coming years.
The Nigerian petroleum industry has recorded significant progress in its upstream petroleum and gas developments, but the same cannot be said of the downstream sector. Much still needs to be done in terms of repairing and privatizing existing refineries with a combined name-plate capacity of 445,000 barrels of oil per day; construction of new small, medium and large refineries, petrochemical plants, fertilizer and ammonia plants, Gas to Liquid (GTL) plants; and development of renewable sources of energy. These industries will help the country withstand shocks from projected lesser demand for fossil fuels in the future.
What can Nigeria do better in 2014?
There are two major threats to our continued dependence on oil resources: global warming attributed in part to the use of fossil fuels for transportation, and the development of shale oil in the US. In 2014, we must begin to think about how to construct plants that will convert our oil and gas resources to secondary and tertiary products. These plants will act as the bulwark against expected future reduced demand for crude oil. It was not raining when Noah built the Ark!
The focus for 2014 would be to sustain the momentum in upstream petroleum and gas development, enforce security of petroleum operations in the Niger Delta, and lunch a full-scale attack on crude oil theft and pipeline vandalism. Apart from the use of natural gas for domestic, power, and manufacturing purposes government should also consider putting policies and incentives in place to encourage the construction of plants that utilize natural gas as feedstock, e.g. gas to liquid plants, fertilizer and ammonia plants, etc.
Much needs to be done to move the downstream sub-sector ‘northwards’. The planned privatization of existing refineries will open up this sub-sector. Post-privatization, we will be faced with an oligopoly. The worst threat we can possibly face in the downstream sub-sector is for this privatization exercise to translate to a movement from public sector monopoly (as represented by NNPC’s ownership of all existing refineries) to a private – sector monopoly (as may be represented by four colluding MD’s of the privatized refineries). In the immediate term, post-privatization, price regulation must be enforced by the Petroleum Products Pricing Regulatory Agency (PPPRA). However, for price regulation to be effective the regulatory agency should be ‘relatively independent’ and the regulator has to have solid character and integrity to avoid ‘regulatory capture’.
It expected that the government will start to implement its plans to construct three new refineries (Lagos, Bayelsa, Lokoja, etc), and to create incentives for the construction of new private refineries. Considering the high capital intensity of constructing large refineries (150,000 bpd to 1 million bpd), government is expected to take the lead in such projects in concert with multinational oil companies or international independent oil firms. Of course, the multinational oil companies will act as the operators (i.e. adopting the NLNG model of shareholdings and operatorship). On full construction, government can off-load bulk of its shareholding to local oil companies (upstream and downstream players included). My former boss, Dr Kalu Idika Kalu tells me that there is a category of ultra low-interest loans within the World Bank called ‘Resource Development Loan Facility’. Government can access these cheap loans for investments in large-scale refineries and petrochemical complexes. The construction of new refineries and the expansion of existing ones will ensure that we overcome the problem of fuel importation, and provide employment not only for the technicians and engineers that will be retrenched in the course of privatization of existing refineries but also create employment for new-comers.
I also expect that in 2014, government will start to take the threat presented by shale oil development in the US seriously and begin to invest in renewable sources of energy (biofuels, solar, wind, tidal forms of energy). President Barrack Obama made these a part of his presidential campaign promises and he has never looked back since then.
It is also expected that the National Assembly will pass the PIB early on in 2014. There are a few international developments in the petroleum sector than may ginger the National Assembly into an early passage of the PIB. The US and Western Europe account for bulk of Nigeria’s oil exports. Due to the ‘global warming phenomenon’ and the resulting environmental directives (Kyoto Protocol), these countries have since commenced measures to reduce their dependence on fossil fuels. Future fuels would be mainly natural gas; shale oil, and biofuels. Vehicles that run on CNG, biofuels, fuel cells are currently being tested and perfected in Western countries. Hybrid vehicles are already in use in some parts of the US. Pilot tests are being carried out on vehicle that runs on hydrogen. Wind and solar forms of energy are being harnessed in increasing frequency. The fuel mix dynamics is set to change and a new paradigm will soon emerge. It is relevant to note that the world did not switch from biomass energy to coal because there was no more firewood to burn. Similarly, the world switched from coal to fossil fuels not because coal resources were depleted. In the same breath, the ‘global warming phenomenon’ has dictated a switch from fossil fuel to something else. As a nation, these developments will impact us and we need to adapt in time. Therefore, all well-meaning citizens of this country should put pressure on the National Assembly to speedily pass the PIB as well as Gas Master Plan in their current forms. Amendments could be made as and when necessary along the implementation route.
As regards the upstream, for how long can we survive the lack of investment, as the IOCs have not been investing in last few years?
This question takes us back to the PIB. The IOCs are not investing much because of uncertainty, which the passage of the PIB is supposed to clear up. There is fundamental interdependence between Host Countries and the Multinational Oil Companies in the development of natural resources, but the interests of these two parties differ much but only converge on resource production- sharing. Two other major stake holders are the National Oil Companies and the Host Communities. The fact that oil and gas resources are vested in the Federal Government of Nigeria does not exclude the Host Communities as major stakeholders. These communities bear the brunt of environmental degradation (acid rain, oil spillage, foul air and water) that usually attends resource extraction and refining processes. Speaking of, the need for environmental remediation in Host Communities and environmental justice for those that bear the brunt!
A successful negotiation of the PIB will take into account of these interests, which I will briefly narrate here. Let us commence with the Host Country’s interests. Nigeria is characterized by high population growth, excessive unemployment, low per capital income, a low level of economic development (reflected in a lack of social services and resources), a low quality of education, and short life expectancies). Given this setting, the critical concern of government should be economic growth. As a major oil exporter, oil E & P activities should secure a reasonable tax base for the government, revenue from the world oil market, capital for economic expansion, and employment and income for individual workers. There are other economic, social, and political factors of interest to the Host Country. These include acquisition of technology and expertise from foreign oil companies, increasing local content in supplies and other forms of contracting, access to foreign markets, infrastructure development in the course of E & P activities, such as roads, communications, port facilities, etc. Few developing countries have the capital, technology and trained personnel necessary to develop oil reserves, and so must rely to varying degrees on foreign investment by the MNOCs. The FDI offered by the MNOCs provide the Host Country with technology, managerial and technical expertise, and a reduced vulnerability to downturns in the world’s economy, and with capital. FDI also provides the opportunity to shift the responsibility of building and maintaining the requisite support services and infrastructure facilities to the MNOCs. Therefore, it is in the interest of Host Countries to maintain this historical interdependence with the MNOCs.
The MNOCs interests are principally driven by the characteristics of petroleum E & P operations. There is a considerable lag between an investment in a petroleum prospect and the realization of any profit from the enterprise. E & P operations is capital – intensive and frequently entails the creation of a robust infrastructure before actual extraction can take place. These operations are also high- risk in nature (the existence, extent and quality of oil reserves; production costs; and world crude oil prices are all difficult to determine well in advance). Therefore profitability is never assured. Generally, most MNOCs tend to improve their profitability by improving the crude oil which accounts for why they get involved in the entire value chain of the industry. Also hydrocarbon reserves are finite, so MNOCs must continually acquire new reserves which again are capital – intensive. The fiscal incentives available in different oil producing countries tend to determine where the MNOCs sink their oil rigs.
MNOCs are compelled to be far more concerned about government policies and regulations than most other businesses. These companies have to deal directly with the government (through their agencies) being the custodian of national oil reserves, but also must deal with the political and legal hazards associated with extracting the reserves that in most cases is the Host Country’s major source of revenue. The primary interest of the MNOCs as with any other business are maximization of profits and minimization of risks or at least ensuring that unavoidable risk are factored into the potential ‘upside’ of the enterprise. For the MNOCs the principal risks are geological, economic, and political. Political risks include a sudden increase in taxes, unfavorable alteration of the production- sharing ratio, government instability, agency – in-fighting, outright confiscation of production, and nationalization of foreign oil assets. These interests and risks have to be factored into the PIB debate and negotiations to ensure the MNOCs are not discouraged from making further investments in the Host Country. Else, they would be encouraged to move away and invest in other countries with more stable and better fiscal regimes.
NOCs (e.g. NNPC) are created to develop petroleum resources within the home (Host) country and in most cases are typically multi – layered in structure, and organized into subsidiaries in accordance with function, such as E & P, refining, marketing, petrochemicals, retail etc. The corporate forms of NOCs mimics that of the MNOCs, but the overall objectives of NOCs are less clear than the purely –for- profit MNOCs. NOCs are basically government agencies, and as such are responsive to government pressures and policies. Examples are: capping prices to domestic purchasers, purchasing from local suppliers (i.e. increasing local content) whose materials may be inferior and costlier, paying high wages that are not co-related to profitability, adopting in efficient labor- intensive production methods to increase employment, making uneconomic investments to promote political goals, etc. The NOCs can afford to carry-on in this manner, confident in the belief that when and where necessary, the government is likely to grant the company better tax treatment than private companies. Additional State Aid or bail – out measures may come in the forms of providing access to capital on favorable terms, including low-cost government loans, government loan guarantees, and direct capital infusions from the government coffers. In a situation where the NOC is economically threatened, the government will most likely step in as ‘savior of last resort’ and take remedial steps to prevent the NOC from collapse, or from defaulting on its obligations.
The widespread dissatisfaction with the efficiency levels of NOCs has led many oil- producing countries to move towards privatization. This trend is more evident in South America than in the Middle East, Asia and Africa. For example Argentina began to privatize its NOC, YPF (Yacimientos Petroliferos Fiscales) as early as 1989, and most other South American countries have at least partially privatized their NOCs. Some of these NOCs have broadened their role into international downstream activities, which includes building transnational pipelines to transport petroleum and natural gas to the marketplace, acquisition of refineries in the US & Western Europe, and also retailing directly to consumers in these foreign countries. For example, Petroleos de Venezuela S.A (PDVSA) owns CITGO Petroleum Corporation through which the NOC carries out extensive refining, marketing and transportation operations in the US.
Conversely, countries like Kuwait, Saudi Arabia, Libya, Nigeria, Angola, etc. have made no significant efforts toward privatizing their NOCs which still enjoy monopoly control. However, countries like México, Kuwait, Saudi Arabia have reorganized and restructured their NOCs and introduced diverse cost –cutting measures and audit controls to make them operate more efficiently and competitively in the global marketplace. To arrive at this minimal point in part of what the PIB seeks to achieve. The suggested restructuring of NNPC in the PIB would ensure that the Nigerian petroleum industry at the least operates efficiently and eventual privatization of NNPC assets would ensure competitiveness in the global marketplace.
Host Communities are often disregarded but together they constitute a powerful interest and pressure group. It is a recognized fact that economic gains from petroleum reserves development outweigh the attendant social costs brought about by both upstream and downstream operations. The social costs include population displacement, cultural changes, and environmental effects. The environment effects are not limited to the immediate impact on land, water, and air around the host communities but include effects on traditional economic activities that are dependent on water, natural wildlife, and vegetation. Claims by, and on behalf of, indigenous host communities to participate in decisions on whether to incur such social and environmental costs, and if so, how to allocate them are advancing with increasing frequency. Where such claims are suppressed, it has often led to emergence of militant groups with full intent on impeding or crippling oil operations and engaging in hostage takings as a way of raising funds for arms. In a mono-product economy such as Nigeria, successful militancy activities in oil- producing locations spells disaster in terms of government revenues. Crude oil/fuel theft and pipeline vandalism are becoming regular features of the Nigerian petroleum sector. This is partly attributable to militancy activities, and nefarious criminals who ride on the back of such confusion to achieve personal economic gains.
The FGN has over a period of time made some concessions to the Host Communities who bear the social costs associated with oil production and refining, e.g. by setting up the Niger Delta Ministry, Niger Delta Development Commission (NDDC), the Amnesty Deal, extra- budgetary allocations to oil producing State Governments. There have been some contributions from the MNOC’s under corporate social responsibilities. Regardless of these palliatives, a visit to the Niger Delta Region still reveals insignificant human and infrastructural developments at the moment. Besides, who can tell how much of these benefits end up in individual possessions, and the proportion that in actually channeled towards real infrastructural development e.g. quality schools, markets, clean water plants, road and bridges, port facilities, etc. Nevertheless, more still needs to be done to ameliorate the social and environmental costs in host communities in Nigeria. The PIB should make additional concessions to Host Communities in the interest of environment equity and justice. Furthermore, the PIB should more importantly incorporate strategies into the Bill that ensure that the benefits incorporated in the Bill accrue in real terms to all peoples of the host communities.
The government said it would conduct a bid round of the marginal fields. Will it bring the succor that the government is seeking?
Giving details of the licensing round, Mrs. Alison-Madueke stated that a total of 31 fields are on offer with sixteen (16) of them located onshore, while the remaining fifteen (15) are located in the continental shelf. It is vital that potential investors understand the relationship between recoverable oil (in million standard barrels, mmstb) and the terrain of the oil field. Marginal oil fields in Nigeria can be categorized into five based on surface terrain and the typical range of minimal recoverable reserves required for profitable production as follows: onshore land (2-5 mmstb); onshore swamp (7-20 mmstb); coastal offshore (12-25 mmstb); continental shelf offshore (20-45 mmstb); and deep offshore (>40 mmstb). This indicates that the deeper into water the higher the minimal recoverable reserves.
In providing an update on the last marginal fields bid round which held in 2001, the Minister disclosed that of the 24 fields that were allocated to 31 indigenous oil companies in that exercise, 8 were already producing while the others are at various stages of development. Mrs Diezani Alison-Madueke noted that the marginal field operators (who currently account for about 1% of the nation’s production) have also recorded huge discoveries in excess of 100 million barrels to the nation’s reserve base, adding that of the eight assets that have so far been divested by the International Oil Companies (IOCs), at least four are held by active marginal field operators, who have continued to demonstrate remarkable technical ability in operating significantly larger assets.
The government in awarding these marginal fields to indigenous operators hoped to increase oil production by about 1 billion barrels. Some progress has been made in marginal fields’ development as 8 out of the 24 operators have taken their fields to first oil. However, more still needs to be done, and six factors have constrained the activities of marginal field operators. The main factors relate to the lack of funding and the marginality of the fields. Other factors are: inadequate technical expertise, government policies on royalties and petroleum taxes, board / partnership wrangling in some cases, and in other cases the presence of significant anti-entrepreneurial mentality among the operators.
Funding constraints is the main reason cited by the growing number of Nigerian E & P companies for inability to progress on projects, as well as the necessity to invite foreign technical partners. The need to invite foreign partners has become inevitable given that most local banks have not co-operated with marginal field operators in putting these fields into production. However, such invitations run contrary to the core moral concept and principles of the marginal fields’ licensing exercise.
The original principle behind this exercise whereby the government took undeveloped discoveries, which has proven oil, from the oil majors and awarded these to local companies, was to encourage indigenous capacity building in the upstream petroleum sector. The indigenous marginal field operators were expected to employ Nigerian geologists and petroleum engineers, acquire workstations for their use, utilize other local skills in field development (in the office and on operational site), put local talent on site to supervise well drilling and produce the oil, and in the event, increase the pool of technically capable oilfield personnel who can replicate the same exercise elsewhere in Nigeria and abroad. Therefore, to invite technical partners would mean that the country still has not ‘indigenized’ the development of these marginal oil assets.
Undoubtedly, there exists abundance of local technical expertise, which has developed over a long period of time. This is so, considering that Nigeria has produced oil in commercial quantities since 1970 to date. However, most of them may not be available to work for marginal operators if they can earn more pay with established E & P companies. It should also be acceptable to highlight the relative differential in quality between local technical expertise and the technical expertise available in Western countries. Consequently, the government is not averse to joint-ventures between marginal field operators and foreign technical partners, provided that the Local Content Act applies to board appointments, local employees, and inclusion of local contractors in the provision of goods / services needed for field development and production.
Government policy as regards royalties and taxes can facilitate the development and production of these marginal fields. New fiscal regimes have been proposed in the Petroleum Industry Bill (PIB). If the PIB is passed in its current form, operators will observe a significant reduction in applicable royalties and taxes. A reduction of about 30% in applicable royalties and petroleum taxes has been proposed, which makes it commercially attractive for small operators to develop these marginal fields very profitably.
The PIB also introduces a modern acreage management system with strict relinquishment guidelines, which provides for oil companies operating in this country to relinquish acreages from existing oil prospecting licenses (OPLs) and oil mining leases (OMLs), except acreages that will be developed in the near future, or those that are currently in production. This policy is meant to discourage operators from sitting on acreages that otherwise will be available to other credible investors.
All factors considered, the future of marginal fields’ development still looks very promising despite these hurdles. However, going forward, there are a number of financial, technical initiatives and government policies that will aid the process of marginal fields’ development. The most important of these is the passage of the PIB. On the technical side, operators will have to develop more effective reservoir management systems and synergistic facilities utilization in order to boost mutual profitability. Energy & Petroleum Academic Centers in the country should be strengthened through funding by local industry players. This should enhance human capacity development needed in the industry and reduce the strong dependence on expensive expatriate personnel and skills.
Presently, investment in marginal fields comes from JV, Debt and Equity financing, or a combination of these. There should be more effective mutual integration between operators and the local financial sector. Operators can form Special Purpose Vehicles (SPV’s) and tap into the international investment market as well. They can also attract more capital expenditure (CAPEX) investment by aggregating or co-mingling proximal fields’ reserves in order to achieve critical volumes.
Government has a crucial role to play in enhancing the profitability of these ventures. Government can revise the fiscal terms and make them more investor- friendly; suspend royalty payment for at least three years from commencement of production to eliminate front-loading of royalty payments and thereafter apply the sliding- scale method to royalty payments based on levels of production; and provide tax holiday of 3 years by suspending VAT, import fees, education tax, etc. The CBN can support the local banks in reviewing monetary terms for energy projects, and government can also establish Energy Bank, as separate from Bank of Industry, to enable local energy companies gain access to funds at globally competitive rates.
PIB: What best approach do you think the government should take to see to its passage?
I have previously identified the four major stakeholders in petroleum development in our country, and indeed in any other oil producing country. These are the Host Country, the Foreign Oil Companies, the National Oil Corporation, and Host Communities. These interest groups have different motivations and a reconciliation of these interests will bring about a speedy passage of the PIB. In Nigeria, as previously stated, the ownership rights to oil and gas are vested in the Federal Government of Nigeria. However, it would be a mistake in the course of negotiations to subsume the interests of Host Communities under those of the Host Country just because the latter holds the ownership rights. The social costs of oil extraction and processing are not equally felt across the country. The concept of environmental justice is applicable here. My best advice is for the National Assembly to pass the bill in its current form. Modifications can be made along the implementation route, as common sense would dictate that such changes may be necessary in the interest of all stakeholders.
The local content initiative is about 3 years old now. So far has it achieved the objective for which it was established?
The fundamental objectives of the Local Content Initiative are to increase indigenous participation in our oil and gas supply chain (goods, services, and manufacturing activities), to encourage local manufacturing of basic tools and equipment used in the oil industry, and to ensure that foreign oil companies partner with indigenous players in all aspects of the oil industry, and that local people are equitably represented in senior management placements and board appointments.
Under the effective leadership of the first Executive Secretary of the Local Content Agency, Engr Ernest Nwapa, a strong foundation has been laid in regard to these objectives. I listened to his presentation on the achievements of the Agency at the meeting of the Society of Engineers in Abuja, and was impressed at the highlights of the significant achievements already made by this agency. I have requested him to send to me a copy of his PowerPoint presentation, and I hope to do an article to articulate those achievements. Watch this space!
The refineries would be sold next year. Do you think the sale would encourage the private sector to invest in Greenfield refineries?
Privatization of the refineries is the right call because the existing refineries are aged, were mismanaged, and the business model they operate is faulty. However, my professional opinion is against outright sale of the refineries, and here is why. A transition from a government monopoly to private-sector monopoly or oligopoly (competition among a few players) in regard to the refining business has huge national security implications. The probability that the four owners of the privatized existing refineries might collude in price-fixing (an anti-competitive practice) is high. After all, we still practice crude capitalism in this country. Some might argue that the oligopolistic market structure may not have led to such price-fixing in the telecoms industry, but if you analyze the charges carefully you will see evidence of parallel pricing and charging. However, telecommunications and petroleum products are different goods. A telecoms charge does not have a short-run impact on the price of other consumer goods.
Petroleum products like education or training etc are classified as ‘special products’ or ‘impure public goods’ because their supply has multiplier effects on the socio-economic and political life of a community. However, unlike education the prices of petrol, diesel, and aviation kerosene, and lubricants affect the prices of all transported goods, and by extension all other services. Although such goods and services do not have the basic characteristics of public goods (e.g. roads, national defense, policing, power transmission, etc) they do however contain some public good dimensions. ‘Impure public goods’ can be freely traded in the market but require periodic regulatory interventions because they may be subject to some degree of market failure, with disastrous consequences for society.
As source of fuel, petroleum products have high energy content compared to gas and coal. Their fluidity creates economies of scale during storage. Currently, there are no adequate substitutes for petroleum fuels in transportation, and virtually none in the field of lubrication. These qualities have combined to make petroleum products the fuels of choice in modern transportation. Therefore, any disruption in fuel retailing activities within a given location will likely result in socially undesirable outcomes.
The economics of the petroleum retail trade presents an equally unique situation. The demand for petroleum products is not price elastic, i.e. an increase in price does not produces a corresponding decrease in demand or volume consumed. Similarly, a decrease in price does not produce a corresponding increase in demand or volume consumed. Petroleum products are similar to tobacco and alcoholic drinks (due to their addictive nature) in the sense that an increase in price does not produce a corresponding decrease in demand or quantity consumed. Hence, most Western Governments tend to derive significant revenues from imposing high taxes on tobacco products, wines, beers and spirits. Government’s usual justification is that for health care reasons, they are compelled to impose these high taxes to discourage the abuse of these products.
However, these governments can afford to levy high taxes on tobacco, wines and spirits, because their prices do not affect the prices of other consumer goods. However, petroleum products are dissimilar to tobacco, wine, beers, and spirits in the sense that a decrease in the prices of these products can produce a corresponding increase in demand or quantities consumed. This unique economics of petroleum products has been a source of potential abuse by non- discerning governments (either through hike in pump prices, or high fuel taxes) and by fuel retailers (through high pump prices) where the prices are unregulated.
Therefore, post-privatization, the most important aspect that the regulatory agencies have to keep under close watch is the pricing of petrol, diesel and kerosene (i.e. reregulation). Parallel pricing or price leadership are regular features of petroleum products retail market. Theoretically, these pricing mechanisms are characteristics of markets where goods and services produced and sold by each company are close substitutes (i.e. little product differentiation) and where companies are subjects to the same demand and supply conditions. As a result, no competitor can afford to lose market share by refusing to match price reductions by the others. Similarly, no market player can afford to miss out on profits when other competitors increase their prices. These pricing features are also present at the refining and wholesaling levels of the downstream petroleum industry, which are characterized by oligopolistic market structures.
All relevant factors considered, the preferred model of privatization for Nigerian refineries will be a kind of joint venture between NNPC and a ‘core’ foreign investor (NOC or Independent) and other private investors. NNPC should have the minority shareholding (between 40-49%). The core investor should have the role of operator, and should have considerable financial and technical capability and strong operational experience in refinery management. Other private investors will include other refiners, major petroleum products marketers, independent petroleum products marketers, depot owners, and the investing public.
From the get-go, it should be expected that refinery workers and associated staff unions would be restive as soon as the privatization announcement was made. The refinery labor force is an important stakeholder in the business of crude oil refining. In technical terms, refinery technical workers are treated as part of the fixed costs of refinery operations because it takes a considerable length of time, and expenditure to train a competent technical refinery staff. They are part and parcel of refinery operations, difficult to replace when retrenched, and almost impossible to operate a refinery when they go on strike. Therefore, it is imperative to design and execute a model of privatization that secures the buy-in of top refinery management (the change agents) and which earns the acceptance of refinery workers as well. Successful negotiations with the industry labor unions will entail provision of safeguards for engineers and technician, and also with due regard to staff disengagement matters (e.g. staff pensions, gratuities, and other incentives). However, technical refinery staff will only be temporarily retrenched should the government decide to embark on the construction of major refineries in partnership with IOCs or Independents.
McKinsey report (2012) emphasized that even if Nigeria “pulls out all the stops” on existing refineries and achieves an unlikely capacity utilization of 90%, the country will not be self-sufficient in petroleum products availability. The table below clarifies this position. Therefore, if existing refineries are privatized and rehabilitated, the demand for products will still outstrip the supply if new refineries are not constructed. This has critical implications for continued products importation, fuel pricing, and overall competitiveness of the refining business and marketing of products. Therefore, there is a role for smaller private refinery projects (particularly those that operate the modular model of refining which is neither labor nor capital intensive). The Dr Kalu Idika Kalu led National Refineries Special Task Force evaluated the potentials of applicants for, and licensees of, private refineries in Nigeria. There were 35 companies under these categories. Four of these (Total Support Energy, Orient Petroleum, Antonio Oil, and NSP refineries) were considered to have relatively higher potential for successful project completion. The reasons for the failure of majority of these companies to demonstrate seriousness in their projects were attributed to funding challenges, inability to obtain crude supply agreement, and inadequate operational and technical capabilities. Therefore, in addition to spear-heading the privatization of existing refineries and the construction of new large refineries, government should design incentives to encourage the four identified private refinery projects as well as encourage even more private refinery proposals.
Crude oil theft assumed an alarming rate in 2013. How best do you think it could be minimized in 2014?
You mean the reported 400,000 barrels of oil per day loss to thieves? This loss translates to a crude oil cargo of 1 million barrels every two and a half days (i.e. $100 million every two and a half days, assuming a price of $100 per barrel). It is befuddling to hear that such volumes can go missing on a daily basis. The question is: are these numbers real, or imagined? If it’s really true, I cannot begin to imagine the collaboration and networks required to ‘pull off this Houdini’. You are talking here about very powerful interests, with ‘brass-balls’ and serious ‘cohunes’!
Let us yet believe that we are talking about much smaller volumes (like 10,000 bpd), in which case the Petroleum Minister has introduced a Crude Oil Fingerprinting Initiative and there is a Joint Task Force (JTF) of the armed forces operating within the Niger Delta area. In my opinion, the JTF should include representatives of all arms of the national security organizations, including well-paid local and foreign spies. Call in the ‘ISREALI MOSSAD AGENCY’ if necessary! It is unacceptable.