Natural Gas in Southern Africa, Part 2: Available gas resources and future development

Natural Gas in Southern Africa, Part 2: Available gas resources and future development

By Anton Putter

This is the second part of a 2-part series of articles covering the natural gas industry in southern Africa.   For these articles, we view southern Africa as comprising South Africa, Namibia, Botswana, Lesotho, Swaziland, Zimbabwe and Mozambique.  The two parts focus on different aspects of the natural gas market, as follows:

In this Part 2, the focus is on current and potential sources of natural gas in southern Africa and we describe a possible future scenario for natural gas.

Introduction

In the first article of this series, an overview was given of the history of the gas industry in southern Africa, a global perspective was given on gas prices and the growth in global gas demand, and the status of the current gas market and infrastructure in southern Africa was reviewed.  Currently, less than 4% of South Africa’s primary energy needs are sourced from natural gas or equivalent. This compares with 14.2% for South Korea, 28.4% for the USA, and 23.1% for Germany (BP Energy Review, 2018).

It was clearly illustrated that southern Africa is lagging the rest of the world in the use of natural gas, primarily due to limited gas supply and not as a result of high gas pricing. The lack of pipeline infrastructure is also a major inhibitor to further development of the gas industry in southern Africa, together with the slow development of local gas resources.

In this article, we discuss current and potential sources of natural gas and describe a possible future scenario for natural gas in southern Africa.  We believe that natural gas can easily exceed 14% of southern Africa’s primary energy needs.

Sources of natural gas in southern Africa

The current and imminent producers of natural gas in southern Africa were discussed in Part 1 of this series of articles (Putter, 2018).  Two current producers are PetroSA offshore gas and the Pande / Temane gas fields in Mozambique.  The Rovuma Venture is progressing their LNG project from the Mamba field offshore Mozambique with first production expected in 2024.

The lack of local gas resources is inhibiting the growth of the gas industry in South Africa.  Following are a few notes on some of the southern African gas resources that could change this:

  • Rovuma gas: This major gas resource in the north of Mozambique (and south of Tanzania) is one of the biggest gas fields in the world.  Unfortunately, the development of floating LNG plants (such as the Rovuma venture) will do nothing for natural gas consumption in southern Africa since all the LNG will be exported.  The only way for this massive natural gas resource to make a meaningful contribution to natural gas consumption in the region, would be for the gas to be brought ashore and transported to the major energy markets in the region, either via electricity generation and transmission, a major natural gas pipeline or possibly conversion to derivatives such as liquid fuels or fertilisers;
  • Offshore gas: Several exploration efforts are underway to find oil and gas off the southern African coast such as Sasol offshore Mozambique, Total and ENI offshore South Africa and Eco Atlantic offshore Namibia.  If the gas would be brought ashore from any of these potential developments, it could make a meaningful contribution to the gas economy in southern Africa;
  • Karoo shale gas: Since this gas would be well located for distribution of energy within the region, it could certainly play an important role in the growth of the gas economy in southern Africa.  Exploration, however, has now been held up for 10 years due to regulatory and environmental considerations, and it is still not clear when this will go ahead; and
  • Coal bed methane (CBM): Several CBM resources are in the region and some with substantial volumes of gas in place.  Amongst others, there are known CBM resources in Botswana, Waterberg and Mpumalanga in South Africa, the western side of Zimbabwe, and Tete in Mozambique.  At this stage it would seem like these CBM resources are the first of the larger resources mentioned here, that will be exploited on large scale within southern Africa.

The distribution of these gas resources is shown in Figure 1.

Figure 1:  Distribution of gas resources in southern Africa

There are also numerous smaller resources that have the potential to contribute to the southern African gas economy.  These include the biogenic gas of the northern Free State province in South Africa, biogas from waste dumps or digester gas from sewerage works or animal farms: 

  • Biogenic gas: Biogenic gas is unconventional gas produced at great depth by microorganisms during respiratory and fermentation processes. Biogenic gas is not generally contained in traps, but is continually being generated at depth and migrates to surface along natural fracture systems, faults and dykes;
  • Biogas: Biogas is a biofuel that is naturally produced from the decomposition of organic waste. When organic matter, such as food scraps and animal waste, break down in an anaerobic environment (an oxygen free environment) they release a blend of gases, primarily methane and carbon dioxide. Methane content is typically between 50 and 55%; and
  • Digester gas: Digester gas is a category of biogas, produced from organic wastes such as livestock manure, and food processing waste in a controlled environment such as a biogas plant. Organic waste such as livestock manure and various types of bacteria are put in an airtight container called a digester, so the process could occur. Depending on the waste feedstock and the system design, biogas is typically 55 to 75 % pure methane.

It is not anticipated that any of these smaller resources in isolation has the potential to contribute more than 2 million GJ/a.

Apart from the above-mentioned ‘normal’ sources of natural gas, there is the possibility to produce synthetic natural gas (SNG).  This used to be the basis of the gas industry in South Africa and even today, the gas going down the Lilly pipeline to KwaZulu-Natal is SNG, called methane rich gas (MRG) by the producer, Sasol.  Various sources of SNG could be considered such as from gasification of coal, biomass, petroleum coke or solid waste, and the conversion of this gasified gas to SNG.  Another possibility for SNG is a mixture of liquefied petroleum gas (LPG) and air, as is practiced on small scale in Port Elizabeth, South Africa.

Possible future scenario for natural gas in southern Africa

It is obvious that there is substantial scope for the growth of the gas industry in southern Africa.  This is also supported by the latest Integrated Resource Plan (IRP) proposed by the South African government which foresees a much larger role for gas in electricity generation than is currently the case (additional 8100 MW from gas by 2030).

OTC runs a gas forecasting model, predicting the gas demand over the longer term.  This model uses a wide range of assumptions and anticipates contributions from most of the potential sources of gas mentioned above.  Under a set of optimistic macro-economic and project-specific assumptions, this model predicts growth in gas consumption in southern Africa as shown in Figure 2, when gas prices remain at the current levels.

Figure 2:  Predicted growth in southern Africa gas consumption (from OTC model)

The following conclusions can be drawn from Figure 2:

  • Growth in gas demand over the next 20 years will be driven by power generation;
  • Gas consumption for derivative manufacture will become a much smaller proportion of the overall gas demand and more in line with global ratios;
  • Industrial offtake of gas will only grow at modest rates and is inhibited by the lack of gas pipeline infrastructure;
  • By 2035, gas-generated power production in the region will be roughly 13000 MW, which seems to be in line with the 11930 MW of installed gas-fired capacity in South Africa by 2030 as foreseen by the latest IRP (RSA DoE, 2018); and.
  • By 2035, gas will then contribute 14% to the total primary energy supply of southern Africa, a similar level to the current contributions of gas in South East Asia where expensive LNG is used, but still short of the 20% level in northern Europe with similar natural gas prices.

Gas competes with other primary sources of energy and as such growth in gas consumption will be very dependent on the price of the gas to the consumer.  Figure 3 shows what the model predicts for gas growth at three different gas prices.

Figure 3: Impact of gas price on southern Africa gas consumption (from OTC model)

These three gas prices were selected to represent extremes of USA type pricing at the one extreme and imported LNG pricing at the other extreme.  At least the following conclusions can be drawn from this analysis:

  • LNG type pricing (the $12/GJ line in Figure 3) will not lead to significant growth in the southern African gas industry unless some other significant event(s) happens such as environmental regulations drastically impacting the generation of power from coal, steep increases in the price of electricity for other reasons or regulatory intervention that promotes the use of LNG imports.
  • Low gas pricing (as represented by the $4/GJ line in Figure 3) can be a game-changer for the southern African economy. In the macro-economic assumptions underlying the model it is assumed that gas available in large quantities at such a low price would boost the GDP growth of the southern African economy by at least 1% per annum over this whole period.

Closing remarks

Gas is underutilised as an energy source in southern Africa.  There is significant potential to grow the gas consumption in this region.  Furthermore, if the gas price at which this growth occurs, is lower than the current gas prices, this development has the potential to have a noticeable positive impact on the economy of the region.

Over the past 10 to 15 years, several gas prospects have emerged in the region.  Each of the four potential sources mentioned earlier has the potential to more than double the current gas consumption in southern Africa.  If several of these sources are exploited in combination, it would change the energy landscape in southern Africa.

Infrastructure development, specifically pipeline networks, will remain a challenge in the region and could inhibit the growth of the gas industry.  Governments in the region and state-owned entities (SOE’s) can play a significant role in facilitating the development of infrastructure. 

References

BP Energy Review., 2018, BP Statistical Review of World Energy. Available from https://www.bp.com/content/dam/bp/en/corporate/pdf/energy-economics/statistical-review/bp-stats-review-2018-full-report.pdf  Accessed on 27 August 2018.

RSA DoE (Department of Energy), 2018, Integrated resource plan 2018, final draft for public input.  Available from http://www.energy.gov.za/IRP/irp-update-draft-report-2018.html.  Accessed on 2 December 2018.

Putter, A.H., 2018, Insight article 055: Natural Gas in Southern Africa, Part 1: current natural gas supply and demand.  Available from http://www.ownerteamconsult.com/natural-gas-in-southern-africa-part-1/ . Accessed on 10 November 2018.

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Natural Gas in Southern Africa, Part 1: Current supply and demand

Natural Gas in Southern Africa, Part 1: Current supply and demand

By Anton Putter

This is the first part of a 2-part series of articles covering the natural gas industry in southern Africa.   For these articles, we view southern Africa as comprising South Africa, Namibia, Botswana, Lesotho, Swaziland, Zimbabwe and Mozambique.  The two parts focus on different aspects of the natural gas industry, as follows:

·      Part 1:  Current natural gas supply and demand; and 

·      Part 2:  Available gas resources and future development.

Introduction

The gas industry in South Africa has a long history.  The first gas was produced by the Johannesburg Lighting Company in 1892.  Following the expansion of the gas network in Johannesburg by the Johannesburg Gas Works (the city utility that took over the Johannesburg Lighting Company), further development of the gas industry in South Africa was closely aligned to the development of the synthetic fuel industry in South Africa (Lauferts & Mavunganidze, 2009).  Sasol pioneered the synthetic fuel industry in Sasolburg in the 1950’s and in Secunda in 1980, while PetroSA (initially called Mossgas) introduced the first natural gas into South Africa in 1992. 

The most significant event in the gas industry in southern Africa up to now, was the development of the Pande and Temane natural gas fields in Mozambique and the construction of a pipeline, the ROMPCO pipeline, to transport that gas from Pande / Temane to Secunda where it linked into the existing gas pipeline network.  The gas flow through the ROMPCO pipeline commenced in 2004, and more than doubled the use of gas in southern Africa.

In this article we take a global perspective on natural gas, consider the current gas market and infrastructure in southern Africa, and discuss the natural gas sources currently exploited in southern Africa.

Global perspective on gas

Globally, gas consumption has grown strongly over the past 10 years and is predicted to surpass coal to become the second biggest source of primary energy within the next 5 to 10 years.  This growth is illustrated clearly in Figure 1, showing the primary energy development over the past 25 years.

Figure 1: Growth in Global Primary Energy Consumption (BP Energy Review, 2018)

The growth in natural gas has been specifically fast in the LNG segment, with growth rates approaching 5 to 10% per year over the past 2 years and LNG consumption now approximately 300 million tpa.  Even so, the LNG consumption still represents only slightly more than 10% of the global natural gas consumption.  Also noticeable from the LNG statistics over the past 27 years in Figure 2, is the fast growth in regasification capacity and the growth in the number of LNG importing countries.

Figure 2: Growth in LNG Trade (IGU, 2018)

Unlike most other commodities, there are significant differences in gas pricing around the world.  These differences are driven by the extremely high logistics cost of moving natural gas around, whether in the form of LNG, by pipeline or any other means, and these differences are expected to persist into the future.  Figure 3 shows a forecast of global natural gas prices from Cambridge Energy Research Associates (CERA, 2014), showing an expectation for these current price variances to persist into the future.

Figure 3: Forecast of natural gas pricing (IHS CERA, 2014)

Current gas market in southern Africa

There has been significant growth in the gas industry in southern Africa with the introduction of natural gas from Pande and Temane, but the consumption of gas in southern Africa still lags far behind the rest of the world as illustrated in Table 1.

Table 1: Natural gas contribution to total primary energy consumption in 2017 (BP Energy Review, 2018)

Region

Total primary energy in MTOE*

Natural gas in billion m³

Natural gas as % of primary energy

World

13511

3670

23.4%

USA

2235

739

28.4%

Germany

335

90

23.1%

South Korea

296

49

14.2%

Australia

139.4

42

25.9%

South Africa

120.6

4.5

3.2%

* MTOE:  Million tons oil equivalent

Even though the above numbers for South Africa does not reflect the methane-rich gas sent from Secunda to KwaZulu-Natal or the PetroSA internal consumption, less than 4% of South Africa’s primary energy needs are sourced from natural gas or equivalent.  This compares with 14.2% for South Korea, a country totally reliant on very expensive imported liquefied natural gas (LNG), 28.4% for the USA where the gas is of the cheapest in the world, and 23.1% for Germany which is mostly reliant on long-distance pipelines for its natural gas supply and with prices similar to South African prices.

In 2017, the gas consumption in southern Africa was approximately 220 million GJ.  The breakdown of this consumption is shown in Figure 4.

Figure 4: Gas demand in southern Africa (from OTC Gas Roadmap model)

The fraction of gas converted in southern Africa to derivatives (such as liquid fuels, wax, ammonia and methanol) is very high when compared to global ratios.  Conversely the use of gas in electricity generation and industrial uses is very low compared to the rest of the world.  This situation is a result of South Africa’s political history where the strategic need to produce synthetic liquid fuels (GTL) was very high.

The high consumption of natural gas into liquid fuels is demonstrated by Figure 5 showing the breakdown of the gas conversion uses in southern Africa in 2017.

Figure 5: Derivative gas demand in southern Africa (from OTC Gas Roadmap model)

Gas infrastructure in southern Africa

The lack of infrastructure is a major inhibitor to further development of the gas industry in southern Africa (together with the slow development of local gas sources).  The few major pipelines in the region is shown in Figure 6 and are concentrated in the east of the region with some branching off these pipelines.

The major pipelines are as follows:

  • ROMPCO pipeline: This 865 km pipeline from Temane in Mozambique to Secunda in South Africa is jointly owned by Sasol, the Mozambique government and the South African government.
  • Lilly pipeline: Transnet owns this 600 km pipeline from Secunda to Durban;
  • Sasol pipelines: Sasol owns several gas pipelines originating in Secunda and reaching destinations such as Johannesburg, Ekurhuleni, Pretoria, Sasolburg and Emalahleni.

Even though South Africa is amongst the top 30 economies in the world, it is not one of those 36 countries (see Figure 2) with LNG import facilities.  Over the past couple of years there has been efforts by the Department of Energy in South Africa to facilitate such a facility.  At this stage, it does not appear that anything will be in place within the next couple of years.

Figure 6: Main gas pipelines within southern Africa

Sources of natural gas in southern Africa

There are currently two producers of natural gas in southern Africa with another project in development, namely:

  • PetroSA gas production: The offshore shallow gas fields supplying the gas-to liquids facility of PetroSA has been producing since 1991 and the gas production has been in strong decline over the past number of years;
  • Pande and Temane gas fields: These onshore Sasol gas fields has been producing since 2004.  Gas production has been steadily increasing, but the latest drilling results reported by Sasol does not sound promising; and
  • Mamba gas field, Mozambique: The Mozambique Rovuma Venture (joint development by ENI, Exxon and CNPC) is progressing their Rovuma LNG project from the Mamba field offshore Mozambique.  The plans entail two floating LNG production trains of 7.6 million tpa each, with first production expected in 2024.

As already alluded to, the lack of local gas resources is inhibiting the growth of the gas industry in South Africa. 

Concluding remarks

It is clearly illustrated in this article that southern Africa is lagging the rest of the world in the use of natural gas.  This is primarily due to limited supply and not because of high gas pricing.  Growth in the natural gas industry in southern Africa will most probably be driven by the exploitation of additional gas resources and substantial development of the local infrastructure.

In Part 2 of this series of articles, we will explore other potential sources of natural gas in southern Africa and possible future growth scenarios.

References

BP Energy Review., 2018, BP Statistical Review of World Energy. Available from https://www.bp.com/content/dam/bp/en/corporate/pdf/energy-economics/statistical-review/bp-stats-review-2018-full-report.pdf  Accessed on 27 August 2018.

IGU (International Gas Union), 2018, World LNG Report.  Available from https://www.lngglobal.com/international-gas-union-2018-world-lng-report  Accessed 28 August 2018.

IHS CERA, 2014, Fueling the Future with Natural Gas.   Available from https://www.fuelingthefuture.org/assets/content/AGF-Fueling-the-Future-Study.pdf  Accessed on 28 August 2018.

Lauferts, M. & Mavunganidze, J., 2009, Ruins of the Past: Industrial Heritage in Johannesburg. Available from https://www.witpress.com/Secure/elibrary/papers/STR09/STR09047FU1.pdf  Accessed on 20 August 2018.

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An Introduction to Product Logistics

An Introduction to Product Logistics

By Anton Putter

Introduction

In a general business sense, product logistics can be described as the management of the flow of things between the point of origin and the point of consumption in order to meet the product requirements of customers.

Product logistics is a critical factor in the overall success of any project.  It is inconceivable for a project to be classified as successful if the plant resulting from such a project cannot operate at planned capacity due to the following:

  • Limitations on feedstock supply or feedstock quality deviations;
  • Business cannot sell the product to the final customer, due to product contamination prior to reaching the customer;
  • The final product cannot reach the customer according to the contracted plan due to constraints in the outgoing logistics chain; or
  • The packaging of the product does not meet the customer’s requirements.

All the above are examples of product logistics shortcomings that can handicap a project, even if such a capital project was completed within budget and on schedule.

Scope of this Article

By its nature, a short article like this can only touch on the surface of a complex concept such as product logistics.  To limit the scope of the article, only the following aspects of product logistics will be dealt with:

  • Important factors during the conceptualisation, project implementation and business commissioning of capital projects, rather than the later phases of the overall project life-cycle;
  • Factors pertaining specifically to the petrochemical industry;
  • Product logistics, rather than the wider topic of product supply chain (see previous Insight Article 037 on Project Logistics (Steyn & Lourens, 2017) for an explanation of the difference between logistics and supply chain); and
  • Incoming logistics of feedstocks and outgoing logistics of products are considered, but not internal logistics of moving the materials through the petrochemical plant or the logistics of consumables (such as process chemicals, catalysts, gaskets, safety equipment, etc.), spare parts, shutdown or turnaround materials and project equipment (for the latter topic, please refer to the previous Insight Article).

How does product logistics fit into a petrochemical project?

Product logistics forms an integral part of the project planning and execution of any petrochemical project.  Like any other operational aspect of a project, such as production or maintenance, the product logistics for the ultimate operations of this petrochemical plant, must be considered throughout project development.

Figure 1 shows some of the elements of inbound and outbound logistics which must be considered; in this case for an LNG (liquefied natural gas) export project, with the inbound logistics shown as pipeline (and sometimes underground storage as well) while the outbound logistics includes LNG storage, export port, LNG ships, import port and pipeline distribution.

Fig1Logistics

Figure 1:  LNG inbound and outbound logistics chains (“K” Line, 2017)

The stage-gate model approach to project management soundly deals with the product logistics requirements of a project.  At every stage of the project, it is necessary to confirm that the product logistics development is on par with the overall project’s stage of development, and that the product logistics planning is fully integrated with all the other streams of the stage-gate model.

Product logistics planning commences at the early stages of a project and forms an integral part of the conceptual and prefeasibility studies.  Examples of such early phase product logistics considerations are:

  • Facility and logistics infrastructure siting: Siting and the access to transport infrastructure such as railway lines and suitable ports;
  • Feedstock sources and quality: Feedstock source(s), quality of feedstock and possible pretreatment before incurring logistics costs;
  • Customer quality requirements: Final product customer base and quality, and the ability to deliver the desired quality all the way to the customer; and
  • Multi-purpose logistics infrastructure: Interface between project logistics (Steyn & Lourens, 2017) and product logistics, and possibility of creating logistics infrastructure to be used for both purposes.

Typically, the capital cost for investment in logistics facilities is a relatively small portion of the overall capital investment in a petrochemical project (normally anywhere from 2 -10%), but product logistics is crucial to the ultimate project or business success of the investment.  Therefore, product logistics must be an integral part of every framing meeting as well as other stage-gate meetings of the project.

Conversely, the logistics costs of an operating petrochemical facility is typically a substantial portion of the overall operating costs (normally anywhere from 5 – 25%), and therefore logistics cost optimisation is essential to overall business success.  Like the other operating costs incurred during plant operations, the logistics costs are largely determined during the design phase of the facility and must receive adequate attention to ensure the desired optimisation.

Multitude of decisions

The project phase of product logistics entails a multitude of decisions that must be taken.  Many of these decisions are dependent on decisions that must firstly be taken by other business functions such as marketing, production, business management, etc., or decisions that are taken in consultation with those business functions.  There is often the need for logistics input into decisions by other functions or disciplines.  Examples of these multiple decisions are:

  • Mode of transport: Mode of transport to be used at various stages of supply or distribution.  Options in the petrochemical industry are normally road transport, rail transport, pipeline, barging, shipping, or conveyor belt;
  • Storage capacity: The required storage capacity must be decided upfront during the feasibility phase of the project since this impacts the site lay-out, the basic design and the capital costs.  The total storage capacity of feedstocks and products are determined by a variety of aspects such as turnaround periods (at suppliers in the case of feedstocks), required security of customer supply, strategic stockholding levels, and seasonality of feedstocks supply and product offtake. Decisions must be taken on how much of the storage capacity will be provided on-site as well as off-site (possibly closer to large customers to ensure security of supply).  The capital cost of specialised storage such as refrigerated or pressurised storage vessels can become a major consideration.
  • Product packaging: Packaging to be provided, normally mostly for outbound logistics.  This could be bulk, isotainers, drums, bulk bags, normal bags, etc., or a combination of these as determined by marketing.
  • Quality control measures: For the outbound logistics chain, this will include third-party quality assurance and possibly blending facilities, third-party inbound product logistics and upgrading facilities close to the customers.  For the inbound logistics, this could include blending facilities and third-party quality assurance;
  • Security of customer supply: In conjunction with the marketing function, the security of supply to customers is determined.  This will accordingly affect the decisions on aspects such as strategic stockholding for feedstocks and products, duplication of inbound and outbound logistics channels, contingency plans on product supply, etc.
  • Product safety: In the petrochemical industry, the products handled during both inbound and outbound logistics could be flammable, explosive and/or toxic.  Suitable measures must be put in place to ensure safe handling of these products during the logistical operations; and
  • Logistics infrastructure: Product logistics is normally not core business for the owner or investor involved. Therefore, the default position should be for third parties to construct, own and operate the product logistics function.  There are, however, many strategic considerations that could lead to alternative decisions.  For instance, third parties may be hesitant to make large investments in infrastructure in some cases.  This could then lead to investment and ownership of the product logistics assets by the project owner, but operations thereof by third party operators.  Secondly, inbound and outbound logistics chains, or elements thereof, may be so strategically important to the overall business success, that ownership and control thereof must be retained by the project owner.  Thirdly, the remote location of a petrochemical facility may force the developer to supply infrastructure, at least up to the point where it links to existing infrastructure.  Lastly, there may be a strategic necessity to have two logistic channels and/or two or more logistics suppliers.

It is essential that all these decisions and risk management activities are coordinated within the overall project development and in close consultation with all the other functions.  A structured process, such as the stage-gate model, is ideal for this purpose.

Third parties and contracts aplenty

The logistics activities are characterised by interfaces with third parties.  These interfaces are typically regulated by contracts.  A single sales contract with a customer can easily be backed up by ten contracts with logistics third parties. For an overseas customer supplied on a CIF (cost, insurance and freight) basis there could, for example, be a need for contracts with overland transporters, a port storage provider, an affreightment provider, a third-party quality assurer, insurers, freight forwarding agents, packaging materials or equipment providers, packagers, and logistic coordinators.

A substantial portion of the products from a petrochemical plant is typically exported, normally to a variety of countries and usually requiring deep-sea logistics.  This has, amongst others, the following consequences:

  • The outgoing logistic chains are long, requiring careful planning and stock control;
  • The logistics contracts must be concluded in various legal jurisdictions; and
  • The deep-sea logistics will be governed by maritime law; a distinct and specialised body of law.

For a logistics chain that includes international shipping, the COAs (contracts of affreightment) are critical.  These contracts with ship-owners may have to be concluded years in advance of any product being shipped to allow the ship-owner the opportunity to create additional shipping capacity and/or rearrange its shipping routes.  This would especially be the case when there are large volumes of product shipped, when the product shipped would necessitate new shipping routes and/or when the product requires specialised shipping (for example, pressurised, specific materials of construction, or refrigeration).

The sales contracts are concluded under certain commercial terms which determines the point(s) where the buyer takes over the costs, risk and documentation of the product logistics.  These commercial terms are extremely important from a logistics perspective since it determines the services and infrastructure to be provided by the owner of the petrochemical plant.  These commercial terms are widely known as Incoterms® and a whole range of possibilities exist, as shown in Figure 2.

It is essential that the logistics system design is audited by a third party during the project implementation phase.  This audit is primarily aimed at the operability of the logistics design, rather than the cost-effectiveness of the logistics system.  The timing of this audit is important: it must be late enough during project development so that the bulk of the system is ready for audit (especially the documentation and information systems), but not so close to commissioning that there is no time to implement changes.

Fig2Logistics

Figure 2:  Incoterms® 2010 as defined by the International Chamber of Commerce (Emadtrans, 2013)

Summary

The crucial aspects of product logistics as discussed above, are:

  • Product logistics is managed as part of the stage-gate approach to project implementation and commences at the earliest phase of project development;
  • Logistics capital costs is normally a small portion of the overall project capital, but the success of the logistics system determines the overall project success;
  • Logistics operating costs is normally a substantial portion of the overall costs and needs due optimisation during the project development phases;
  • In the project phase, product logistics is characterised by a multitude of decisions to be taken on factors such as mode of transport, storage capacity, packaging, risk management, and third party versus own assets and operations;
  • Numerous third parties are typically involved in the inbound and outbound logistics activities and the contracts governing these relationships must be concluded during the project phase of the development, sometimes years in advance of plant commissioning; and
  • A logistics system audit must be performed by a third party during project development to ensure that the logistics will commence with limited disruptions.

References

Emadtrans (Emadtrans Logistics, Inc.), 2013, Incoterms. Available from http://www.emadtrans.us/incoterms.html  Accessed on 30 May 2017.

“K” Line (Kawasaki Kisen Keisha, Ltd.), 2017, LNG carrier business model. Available from https://www.kline.co.jp/en/service/lng/index.html  Accessed 30 May 2017.

Steyn, J.W. & Lourens, D., 2017, Insight Article 037: An introduction to project logistics management.  Available from www.ownerteamconsult.com/published-insight-articles/   Accessed on 28 May 2017.

 

XTL Projects and the Oil price

XTL Projects and the Oil price

This is a full reprint of a three part series of papers on the impact of the oil price on coal-to-liquids (CTL) and gas-to-liquids (GTL) projects by Anton Putter and Charl Buys.

Part 1 – Background on oil market and oil price
Part 2 – Current status of the oil industry
Part 3 – Unconventional oil and impact of oil price on XTL decision-making

Part 1 – Background on oil market and oil price

Introduction

The international oil price fell precipitously during the latter half of 2014. In the case of Brent oil, the price declined from $115/bbl on 19 June 2014 to $47/bbl on 13 January 2015, a decline of 59% within a period of 7 months.

Volatility in the oil price is not something new, as illustrated in Figure 1 below showing the oil price from 1861 to 2013.

Such extreme volatility in the oil price does, however, beg the question as to how decision-makers on projects in the oil industry should react. Some of the unconventional oil projects are highly capital intensive and project execution typically takes 5 years or longer. Decision-makers on these projects are expected to commit large amounts of money (typically at the end of front-end loading) while there is a high level of uncertainty on the oil price 5 years down the line when the first revenue will be generated to yield a return on this large investment.

Part 1 focuses on conventional oil. A brief overview is provided on the historical development of the oil price and a listing of the major factors impacting the oil market. More information is provided on OPEC and on the Hubbert production model.

Insight Article 011- XTL project and the oil price - 1-3

 

Figure 1: Oil price from 1861 to 2013 in constant 2013 US dollars. (www.zero-hedge.com)

Historical development of the oil price

Considering the fluctuations in the oil price over the past 150 years as presented in Figure 1, several conclusions can be drawn. The most relevant conclusions are discussed below.

The oil price has, over the past 50 years, been extremely volatile, varying from $15/bbl to $120/bbl in comparable dollars. Although extremely volatile, the oil price mostly does not display the typical cyclical behaviour of investment-dependent commodities. Such cyclical commodities like petrochemicals and metals would typically display price cycling over 6 – 10 years, based on the investment period for new capacity and the time the market takes to absorb this new capacity. Some typical cycling can be seen in the oil chart before 1930, but very little after that.

Since the 1950s, the oil price is not so much affected by economic and market factors as it is affected by political events/decisions and conflicts. Some of the most prominent events influencing the oil price during the last 50 years were the formation and rise of OPEC, the Yom Kippur War, the Iranian Revolution, the Iran/Iraq war, the invasion of Kuwait, the events of 9/11 and the subsequent invasion of Iraq, and the Arab Spring. The only factors of an economic nature that impacted the oil price significantly during this period were the peak of conventional oil production in the USA in 1970 and the global financial crisis in 2008.

Following a 70-year period of relative stability until 1971, the oil price then entered a period of extreme volatility and increasing price levels. The average price of oil from 1900 – 1970 was just below $20/bbl and the average price from 1970 to 2014 was $54/bbl (both in 2013 dollars). From 1970 the 10-year moving average oil price has steadily increased from $16/bbl in 1971 to over $90/bbl currently.

Factors impacting the oil market

A range of factors play a role in the oil market. Some of these are discussed below. The Organisation of Oil Exporting Countries (OPEC) and the Hubbert Curve are discussed in the following two sections.

Oil is an important driver of the world economy. It is the by far the highest value single commodity in the world and in 2014 represented over 4% of the world GDP. There is a strong relationship between world GDP growth and oil consumption as illustrated by Figure 2.

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Figure 2: World growth in GDP, energy and oil (ourfiniteworld.com)

Oil is such a significant portion of the world economy that it is often contended that it is not only changes in world GDP that leads to changes in oil demand and price (decline in world GDP would lower oil demand and price such as occurred following the global financial crisis in 2008), but that it is also sometimes changes in oil prices that lead to changes in world GDP (reference the two oil price shocks in the 1970s and the resultant negative impact it had on world GDP).

Oil is a highly traded commodity with oil trade representing over 60% of the global oil consumption in 2013. This results in many countries being highly dependent on oil imports, whereas the export of oil is concentrated in the hands of a few countries.

The oil price is relatively uniform on a global basis due to the strong traded market and the low cost of logistics involved. This is unlike natural gas where the prices differ significantly on a global basis due to high logistical barriers, lack of infrastructure and a small traded market (most of the traded market is based on long-term contracts).

Over the past 40 years oil prices have had little relation to the cost of conventional oil production. This is mostly due to the role played by OPEC which strives to put upwards pressure on prices. See the section below on OPEC.

The biggest impacts on the oil supply/demand balance and prices are due to unpredictable world events. This has been the case over the last 150 years and can be expected to still be the case in the foreseeable future.

Oil remains the largest primary energy source supplying 33% of the world’s energy in 2013, closely followed by coal (30%) and natural gas (24%). Over the past 40 years the proportion of energy from oil has declined from 48% to 33%. This 15% decline has mostly been made up by growth in market share from natural gas (6%), nuclear energy (4%) and renewables (3%). In spite of this decline in energy market share, there has been a steady growth in oil consumption as illustrated in Figure 3.

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Figure 3: Global oil consumption growth (BP, Review of World Energy 2013)

The rate of oil flow from a conventional oil field reaches a plateau soon after first production takes place. Depending on the management of an oil field this plateau can last for many years, easily in the range of 20 – 30 years in the case of well-managed fields. However, once this middle-age stable phase of an oil field ends, the production from such a field enters an inexorable decline phase. The rate of decline varies from field to field, but is generally in the range of 3 – 9 % per year.

The discovery of conventional oil peaked in the 1960s and since then progressively fewer barrels of conventional oil were found each year. There are up to 50 000 oil fields spread around the world. Of these just over 500 are considered giant oil fields (i.e. with recoverable reserves in excess of 500 million bbls). Just 100 of these giant oil fields produce over 50% of the world’s conventional oil and almost all 100 of these giant fields are in their mature and declining phase.

The threat of peak oil has been hanging over conventional oil production for many years. Estimates for when the world will reach peak oil production of conventional oil has ranged from the year 2000, extending to the year 2025. See also the section on the Hubbert Curve below.

The Organisation of Petroleum Exporting Countries (OPEC)

The Organisation of Petroleum Exporting Countries (OPEC) has played a significant role in the oil market and the oil price since the 1970s in the aftermath of the Yom Kippur war. OPEC was founded by Iraq,  Kuwait, Iran, Saudi Arabia and Venezuela in 1960. The initial mandate of OPEC was to “coordinate and unify the petroleum policies” (source: OPEC website – Brief History) of its members and to “ensure the stabilisation of oil markets in order to secure an efficient, economic and regular supply of petroleum to consumers, a steady income to producers, and a fair return on capital for those investing in the petroleum industry”.

Over the years, various members joined OPEC whilst others left the organisation (Gabon and Indonesia). The current 12 members of OPEC are the countries listed in Table 1 below. In the middle 1970s, OPEC added to its initial goals the purpose of “selling of oil for socio-economic growth of the poorer member nations” which formed the basis of OPEC’s attempts of achieving higher oil prices over the next 40 years. The current production level and potential of the different OPEC members are:

Production and potential of the OPEC members

OPEC rarely produces close to the potential capacities due to a variety of reasons such as conflict (as currently experienced in Libya), infrastructure constraints (Nigeria regularly experiences problems), political sanction (such as currently imposed on Iran) and production cut-backs to balance world oil supply and demand (Saudi Arabia is normally responsible for the bulk of these cutbacks). The actual OPEC production is currently over 30 million barrels per day (million bbl/day).

The Hubbert Curve

Peak oil is the point of maximum production in a specified conventional oil area. This peak oil theory was developed by M King Hubbert, a geoscientist from the USA. Based on this theory, Hubbert predicted in 1956 that the oil production in the USA would peak in 1970 at just below 10 million bbl/day. This prediction proved quite accurate as demonstrated by the curve in Figure 4.

The original prediction by Hubbert on USA oil production held quite well until the mid-1990s. The reason why actual oil production in the USA started exceeding Hubbert’s prediction at that stage was the emergence of oil production from unconventional oil sources. Firstly, it was the success of deep-water oil production (water deeper than 150 meters) in the Gulf of Mexico that added to USA oil production from the late 1990s. Secondly, the spectacular rise of shale oil production since 2008 is leading to a strong increase in unconventional oil production in the USA.

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Figure 4: USA crude oil production vs Hubbert Curve (en.wikipedia.org)

Closing Remarks

In Part 1 of this series of articles we’ve focused on conventional oil. A brief overview was provided on the historical development of the oil price and the major factors impacting the oil market was discussed.

Part 2, available in April 2015, will provide insight on what could be expected of the oil price in the short- term and Part 3, available in May 2015, will provide insight on the unconventional oil industry and the oil price in the long-term. The important question remains: Should developers put their XTL projects on hold until there is more clarity on the future of the oil price, or should they go ahead regardless?


 

Part 2 – Current status of the oil industry

Introduction

As an introduction, we repeat the pertinent points from part 1 of the article:

  • The oil price has fallen precipitously during the latter half of 2014;
  • Since 1861 the oil price has been characterised by extreme volatility;
  • Until 1970 the average oil price was stable at around $20/bbl, but subsequently increased steadily to a current 10-year moving average of over $90/bbl;
  • A variety of factors impact on the oil market;
  • OPEC has played a leading role in the world oil market and oil price since 1971;
  • The arrival of maximum conventional oil production as predicted by the Hubbert’s peak oil theory is imminent, and;
  • Historically, the biggest changes in the oil price were brought about by unexpected events, mostly of a political nature.

In this part, we discuss the recent decline in the oil price, the influence that a low oil price has on OPEC, oil supply and demand and specifically consider the oil price in the short-term.

The recent decline in the oil price

The world market for oil is currently dominated by oversupply and the recent decline in oil prices. The current excess production of oil is estimated at 1.0 – 1.5 million bbl/day which is sufficient to fill up all world storage before the end of 2015. As a result, the Brent oil price fell from $115/bbl in mid-June 2014 to $47/bbl in mid-January 2015, a decline of 57%. The factors which contributed to this strong decline are discussed below.

The strong growth in USA shale oil production: The production of shale oil in the USA has grown spectacularly from 500000 bbl/day in 2008 to 4 million bbl/day in January 2015. This growth and the bigger fields are shown in Figure 1.

 

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Figure 1: USA/Canada shale oil growth (USA Energy Information Administration)

 

A change in OPEC philosophy: For the past 40 years OPEC balanced the world oil supply/demand by reducing production in periods of excess and vice versa. In November 2014 OPEC deviated from this when they decided to maintain existing production rates despite the oil oversupply. Saudi Arabia is the main driver with the intention of suppressing new additional capacity, especially shale oil production. Figure 2, below, on non-OPEC oil production growth clearly illustrates that the main threat to OPEC market share is from the USA.

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Figure 2: Non-OPEC growth (USA Energy Information Administration)

Slowdown in growth rate of China: Over the past 20 years China’s growth in annual oil imports exceeded that of all other countries. Figure 3, below, demonstrates this dramatic growth in China’s oil consumption.

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Figure 3: China oil supply/demand (USA Energy Information Administration)

Should this trend continue, it is predicted that China will surpass the USA as the world’s major oil importer within five years, taking cognisance of the growth in USA oil production. Over the past year the GDP growth rate in China has slowed down, which has created some concern on the future oil demand of China.

Rise in Iraqi oil production: Following the invasion of Iraq in 2003 by a USA/UK led force and the overthrow of the Saddam Hussein government, OPEC excused Iraq from any quotas to enable Iraq to rebuild its economy. For the first eight years following the war, the Iraqi oil production remained reasonably close to 2 million bbl/day, but since 2012, this production has grown rapidly. In December 2014 Iraq produced 4 million bbl/day, the first time this has ever happened in Iraq.

Influence of low oil price on OPEC

Over the past 20 years, OPEC has produced oil in the range of 27 – 31 million bbl/day. Currently the OPEC production is at the higher end of the range at 30.5 million bbl/day. Although the OPEC contribution to global oil production has decreased from around 40% in the middle 1990’s to about 35% today, OPEC remains one of the major determinants of the oil price. The economies of all the OPEC members are dependent on oil income and as such the economy and political stability of these countries are closely tied to the oil price. The dependence of each country’s economy on oil revenue (excluding Angola), is illustrated in Figure 4, below.

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Figure 4: Effect of low oil price on OPEC country budgets (Deutsche Bank and IMF)

The various OPEC members are exposed to the current oil price levels in varying degrees. Saudi Arabia needs an oil price of close to $100/bbl to balance its budget. On the other hand, Saudi Arabia has foreign exchange reserves of over $700 billion which will enable it to absorb this decrease in income for a considerable period. The same holds true for the other Gulf producers such as Qatar, UAE and Kuwait.

The other producers in the Middle East, Iran and Iraq, have much smaller foreign exchange reserves, both in the range of $70 billion. These producers will not be able to absorb low oil prices for an extended period without having to take some drastic action.

Outside the Middle East, Nigeria (with reserves of $35 billion) and Venezuela (with reserves of $21 billion) have the highest economic exposure and would have to react before the end of 2015 if the oil price persists. Angola (with reserves of $38 billion) is in a slightly better position, but also exposed. Libya has the highest reserves outside of the Middle East ($120 billion), but is faced with political turmoil, which is disrupting oil flow.

Although Russia is not part of OPEC, its situation also deserves mentioning. Russia will lose about $2bn for each $1 fall in the oil price. The World Bank has warned that Russia’s economy could shrink by at least 0.7% in 2015. Similarly UBS is forecasting that Venezuela’s economy will shrink by 7% this year.

Oil supply and demand

The global oil consumption has been steadily growing over the past 40 years, in spite of oil price increases (in part due to OPEC’s successful management of the market) and oil’s declining share of world energy supply:

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Figure 9: Growth in global oil consumption (BP Review of World Energy 2013)

This growth in oil consumption is expected to continue into the future. Predictions on global oil consumption in 2030 vary between 100 and 120 million bbl/day. The majority of the growth in demand will come from the developing world, especially Asia Pacific.

Additionally the current lower oil price will boost the world economy in the short term. The world’s biggest economies are importers of oil and will benefit from lower costs. Countries which will benefit substantially are China, Japan, the EU, India as well as the USA. For example, it is estimated that a 10% drop in oil price will boost the EU economic output by 0.1%. This resultant improvement in world economy will boost oil consumption and contribute to a recovery in oil price.

Almost 80 years later, and the Hubbert’s peak oil theory today still holds true and needs to be considered in any conventional oil forecasts. A recent article by MarketLine (September 2014) states that the world conventional oil production is on the top flat part of the Hubbert bell curve and declines could be imminent. In support of this contention, they point out the decline in exploration for conventional oil by the major oil companies. Additional growth in world demand will have to be satisfied by unconventional oil production. This will be covered in more detail in the Part 3 of this article.

According to the Baker Hughes rig count, the number of rigs in oil service in the USA peaked at 1609 in October 2014. This has dropped to 825 rigs in the week ending 20 March 2015 – a decline of 48% within five months. This reduced rig count will start having an impact on shale oil production within six months to one year due to the high depletion rates of shale oil wells. Shale oil wells typically lose 60% of their capacity in the first year of production and another 40% in the second year of production.

Oil price in the short term

Although it is notoriously difficult to predict the oil price in the short-term (one to two years), it should be clear that the following could impact the oil price over the next couple of years:

  • It is the first time that the modern shale oil industry is experiencing a significant oil price decline, making it difficult to predict the industry’s response. Already evident is the reduction of oil rigs in shale oil service. This will lead to a short-term reduction in shale oil production, which will put upward pressure on oil prices.
  • The low oil price will put significant financial pressure on the governments of some of the OPEC members. In return, these members will put pressure on OPEC to revert to their previous policy of balancing the oil market by means of production quotas. Although deviations from these quotas are commonplace in OPEC, it has historically put upward pressure on oil prices.
  • A persistently low oil price will force OPEC member countries (and Russia) to reduce expenditure and social programmes. This will increase the risk of political and social upheaval in these countries and possibly interrupt oil supply from such a country. Venezuela is currently a prime candidate for such upheaval. However, unrest or change of government does not necessarily lead to a reduction in oil output.
  • The low oil prices will have a positive impact on the world economy. Such economic recovery will boost oil demand and put upward pressure on oil prices.
    Traditionally the biggest movements in the oil price resulted from unexpected world events. Should such a “black swan” event occur within the next two years, it is bound to put upward pressure on the oil price rather than the other way around, due to the current price levels of oil.

Closing remarks

On balance, it can be stated with a fair amount of certainty that the oil price will rise to a level of at least $70-$80/bbl within the next 2 years, but this could go hand in hand with substantial volatility. At this stage, however, the oil price is still under significant downward pressure and it could easily surpass its recent low point of $40/bbl.

Part 3, available in May 2015, will provide insight into the long-term oil price and the unconventional oil industry. Is the current oil price a threat to XTL projects?


 

Part 3 – Unconventional oil and impact of oil price on XTL decision-making

Introduction

As an introduction, we repeat some of the pertinent points from parts 1 and 2 of the article. From part 1 we have seen that:

  • The oil price has fallen precipitously during the latter half of 2014;
  • Until 1970 the average oil price was stable at around $20/bbl, but subsequently increased steadily to a current 10-year moving average of over $90/bbl;
  • OPEC has played a leading role in the world oil market and oil price since 1971, and;
  • Peak oil has been overhanging conventional oil production since 1970.

Some of the pertinent points from part 2 of the article are:

  • The recent fall in the oil price was caused by a change in OPEC’s approach, growth in Iraqi oil and USA shale oil production, and a slowdown in China’s growth rate;
  • The lower oil price is putting pressure on the economic and political stability of most OPEC members;
  • Every year global oil demand continues to grow at roughly 1 – 1.5 million bbl/day, and;
    In the short-term (within two years) the oil price is expected to increase to at least $70 to $80/bbl.

In this final part 3, we discuss unconventional oil and specifically focus on the impact of the current low oil price on decision-making regarding XTL projects.

Unconventional oil

Wikipedia defines unconventional oil as petroleum produced or extracted using techniques other than the conventional (oil well) methods. This definition is open for interpretation. For purposes of this article, the oil price required to yield an acceptable economic return on unconventional oil development was also taken into account. An oil price of approximately $50/bbl was used for this purpose. If a development requires an oil price in excess of $50/bbl to be economically justified, this is regarded as unconventional oil.

The following sources of oil/liquid fuels are thus regarded as unconventional oil:

  • Deepwater oil;
  • Shale oil, also referred to as tight oil; Heavy oil;
  • Biofuels, and;
  • XTL.

Over the past 15 years the unconventional oil production has grown strongly at the expense of conventional oil as illustrated in Figure 1, below. The graph does not include biofuels. From an oil market share of 3.0% in 2000, the market share of unconventional oil has grown to 11.8% in 2013.

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Figure 1: Growth in unconventional oil over recent years

Deepwater oil

Traditionally, deepwater oil was considered as everything produced in water deeper than 150 meters. With developing technology the water depth has become less of a stumbling block and today deepwater oil is generally considered as oil produced in water deeper than 500 meters. Currently oil is already produced in water as deep as 3 000 meters.

These improvements in technology are well illustrated by the North Sea oil fields. Initially the exploration and production of these oil fields in the 1970’s and 1980’s posed challenges and led to a number of major safety incidents. By the 1990’s the North Sea oil was found, produced and distributed easily and at a very competitive cost to conventional land-based oil. Most of the North Sea oil was produced in water not exceeding 200 meters in depth. Furthermore the North Sea oil demonstrated the typical peak oil behaviour of conventional land-based oil. The peak of 6 million bbl/day was reached at the turn of the century, and today the North Sea produces less than 2 million bbl/day.

Deepwater developments are megaprojects. The latest project which started up in February 2015 was Chevron’s Jack/St Malo platform in the Gulf of Mexico at a water depth of 2 250 meters (with the actual oil reserve another 6 000 meters below the sea-bed). This project cost an estimated $8 billion and will produce 94 000 bbl/day of oil. At an oil price of $80/bbl this project would yield a simple payback of approximately 4 to 4.5 years (taking cognisance of production costs and gas credits).

Since 2000 the production of deepwater oil has risen strongly from 1.4 million bbl/day to 5.5 million bbl/day in 2013. The growth in deepwater oil production was interrupted by the BP Deepwater Horizon incident in the Gulf of Mexico in 2010, but has now resumed its upward path.

Shale oil

The emergence of shale oil, or tight oil, has already been referred to in the earlier parts of this series of articles. In 2014 the global shale oil production exceeded 3 million bbl/day, compared to only 100 000 bbl/day a decade earlier. This spectacular growth was caused by two technological developments namely horizontal drilling and shale fracturing, or fracking.

The estimates on economics of shale oil recovery vary widely. For new projects to be justifiable, estimates of oil prices required range between $50 and $100/bbl. Figure 2, below, shows the required oil price of about $70/bbl for Bakken oil in North Dakota and about $80/bbl for Permian basin oil in Texas. These are currently the two largest production fields.

Another form of shale oil production in operation for many years in the world, is the mining of the oil shale (sometimes called torbanite) which is then flash pyrolysed to a synthetic crude oil. This is currently practiced in Estonia, Russia and China. The production from this process is included under tight oil in Figure 1, above.

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Figure 2: Crude oil cost curve for Canada and United States (Scotiabank Equity Research and Scotiabank Economics)

 

Heavy oil

There are two major sources of heavy oil in the world, ie Canada’s tar sands and Venezuela’s Orinoco heavy oil reserves. Each of these sources contain more technically recoverable oil than the whole of Saudi Arabia.

Tar sands in Canada (mostly Alberta) have been exploited commercially via surface mining and extraction since the late 1960’s as a source of heavy crude (also called bitumen). A variety of other techniques have since been commercialised, mostly in-situ processes targeting the bulk of the tar sands resources not accessible via surface mining. The most successful of these new processes is steam assisted gravity drainage (SAGD) and almost half of the total tar sands oil production of 2 million bbl/day in 2013 originated from SAGD.

A number of Canadian tar sands projects are under development and predictions are that production will reach 3 million bbl/day by 2020. Up to now, none of the projects under development has been discontinued as a result of the recent decline in oil prices. The oil price required to justify new projects is estimated by the Bank of Nova Scotia at about $65/bbl for SAGD projects and at about $100/bbl for mining/upgrading projects as shown in Figure 2, above.

Not much development has occurred in the Orinoco heavy oil fields over the past 15 years and production has remained relatively flat at roughly 500 000 bbl/day. This has been limited mainly by upgrader and logistics constraints. Recently, additional production licenses were awarded to consortiums, including international oil companies, which could lead to increased production ahead.

Biofuels

The biofuels industry has grown strongly over the past 15 years from a total output of 18 million m3 in 2000 to 116 million m3 in 2013. The latter is equivalent to approximately 2 million bbl/day of oil. The growth is illustrated in Figure 3, below.

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Figure 3: Biofuels growth from 2000 (Renewables 2014 Global Status Report)

As can be seen, the bulk of the biofuel production consists of bio-ethanol. Almost 60% of this large volume of ethanol is produced in the USA and about 30% in Brazil. The production of biodiesel is spread more evenly around the world. Almost all biofuels depend on government support in one way or another, either in the form of subsidies or as mandatory percentages in the final fuel blends.

XTL

XTL is defined as Coal to Liquids (CTL), Gas to Liquids (GTL) and Biomass to Liquids (BTL) projects. The liquid products include synfuels from Fischer-Tropsch, Methanol to Gasoline (MTG) and Methanol to Olefins (MTO) processes. Currently the total global synthetic fuel production capacity approaches 400 000 bbl/day and is expected to grow rapidly in coming years, with multiple new plants currently under construction in China.

Owner Team Consultation (OTC) agrees with the following statement from the Journal of Natural Gas Science and Engineering (2012:9, p196-208): “For a capital cost of $110 000/bbl/day of liquid fuels the project will require a $50/bbl average oil price to break even. For a 15% IRR the average oil price will have to be in the order of $75/bbl. GTL projects will thus be viable in specific locations with a low gas price, a logistical advantage to a specific market and a 60 to 80 $/bbl long-term low oil price forecast.” The primary drivers for a GTL project are the cost of capital and the gas price.

CTL projects, on the other hand, depend primarily on capital, operations and maintenance cost, future CO2 tax regimes and the coal source and price. Capital can be in the 130 000 to 140 000 $/bbl/day

range, but could under some circumstances increase to 200 000 $/bbl/day. With operating cost between 30 to 40 $/bbl, CTL projects will then require a sustainable minimum oil price between 60 to 80 $/bbl and an average oil price in the 80 to 100 $/bbl range to become justifiable.

As stated in Fuel (2013:103, p805 – 813): “CTL projects should thus be seen as profitable strategic projects focusing on:

  • import replacement and balance of payment advantages, especially for land locked countries with abundant coal resources;
  • job creation, and;
  • utilising low grade coal and adding value to a natural resource.”

Both CTL and GTL projects are megaprojects and are dependent on specialised technologies. OTC can add considerable value to owner organisations in managing these (and other) aspects of the project development on behalf of the owner organisation.

Oil price in the long-term

It is somewhat easier to put a value on the long-term oil price (over the next 20 years) than it is to predict near-term movements in the oil price. The floor in the oil price will be set by the operating cash cost of the highest cost producers, while the average price should be sufficient to attract investment in new capacity. Bearing this in mind, the following comments can be made on the long-term oil price:

Conventional oil production in the world has stabilised at 80 million bbl/day over the past 10 years. This is in line with the Hubbert curve. Although short-term increases above this production level might occur, the next big change will occur when conventional oil production starts its downward slide along the Hubbert curve. Therefore any growth in oil consumption worldwide as well as declines in conventional oil production will have to be supplied from unconventional oil sources.

Global oil consumption in 2030 is estimated at approximately 110 million bbl/day. This is almost 20 million bbl/ day higher than the oil consumption in 2013 (and 17 million bbl/day higher than the oil consumption currently). Even if there is no decline in conventional oil production until 2030 which is highly unlikely, this would still require a growth in unconventional oil production of 87% (from 10.7 million bbl/day in 2013 to 20 million bbl/day in 2030). Not only will this need significant capital investment in unconventional oil, but it will also require oil prices anywhere between $60/bbl and $100/bbl for justification of these projects.

The 10-year moving average oil price (in constant 2013 dollars and for WTI) surpassed $90/bbl for the first time in 2013 and reached almost $95/bbl in 2014. An average oil price of just above $50/bbl will be required for 2015 and 2016 to bring the 10-year moving average to below $90/bbl again. This is unlikely to happen and it is therefore reasonably safe to assume that the 10-year moving average oil price will remain above $90/bbl.

The oil price will fluctuate around this long-term average as all commodity prices do. The floor for these fluctuations in the oil price will be set by the avoidable operating cash cost of the highest cost producers. Figure 4, below, shows the operating cost for both conventional oil producers (the first 80 million barrels of production) and for the unconventional oil producers (the last 10 million barrels of production). This indicates that the oil price should not drop below $40/bbl for a sustainable period. This was also the floor reached in the recent oil price plunge at the end of 2014 / early 2015. Also please note that this figure was developed in 2012 and some of these costs might now be slightly higher.

 

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Figure 4: Cash cost of global oil production (Morgan Stanley)

In the longer-term the oil price will still be subject to geo-political events which will cause the biggest short-term movements in the oil price. If such an event is sustained it could impact the oil price for a period of up to five years (until long lead-time alternatives are put in place).

There is a reasonably good chance that oil pricing will revert to typical commodity-type price cycling as capital-intensive non-conventional oil grows as a proportion of total world supply,. More projects will be developed (final investment decisions made) during periods of high oil prices and contrary to that, fewer projects during periods of low oil pricing.

Oil price and decision-making on XTL projects

All of the above leaves decision-makers with a variety of guidelines and factors to consider when dealing with XTL projects:

  • Decision-makers should take a longer-term view of oil pricing and not react to short-term movements in the oil price;
    The final investment decision on an XTL project (normally after the completion of feasibility study or basic engineering, but before final engineering and construction) is typically taken 4 to 6 years before the first oil or fuel is produced and sold. Therefore the actual oil price at the time of the final investment decision is of little consequence in the outcome of the investment decision;
  • The actual oil price at the time of first production from an XTL project would have had some impact historically, but has not been crucial for the financial success of a project. A hypothetical CTL project (where all assumptions are the same except the actual oil price over the 20 year life of the project) starting up in 1980 (and enjoying high oil prices for the first five years would have yielded the same 20-year IRR as an identical project starting up in 1990 (which would have been subject to low oil prices for the first seven years of its life);
  • There is a reasonable chance that oil pricing will revert to commodity-type pricing cycles. Under these circumstances there would be some benefit in counter-cyclical investment, i.e. planning the start-up of the project such that it coincides with the upward slope in the price cycle;
    A reasonably conservative average oil price that can be considered for megaproject justification range between $80/bbl and $100/bbl;
  • More important for the decision-makers is to ensure that the project can withstand oil price volatility, specifically a low oil price of approximately $50/bbl for a period of up to two years during operations. In this regard the structuring of the financing is extremely important;
    An asset of strategic importance to a country or region will be more robust during times of low oil prices. Therefore constructive engagement with the host government and its various bodies as early as possible in the project development is essential, and;
  • During the operating phase of an XTL project, it is important to employ a considered hedging strategy on the sale of products. This will, amongst others, ensure a more stable cash flow and make it easier to cover loan commitments and capital project requirements.

Closing remarks

In conclusion, it can be said that XTL projects now face a brighter future than ever in the past. As part of the unconventional oil industry, XTL projects will contribute in replacing the growing shortfall in conventional oil production. Such XTL projects will be megaprojects and probably of strategic significance to the host country. The successful XTL projects will be differentiated by skillful and diligent management of the megaproject execution and the technologies involved.