President Joe Biden’s energy chief extended an olive branch to the oil industry Tuesday, telling executives a crude export ban is not under consideration, while assuring them that the administration was “not a bogeyman.”
Energy Secretary Jennifer Granholm made the virtual remarks Tuesday to an outside advisory group with members including executives from such companies as Exxon Mobil Corp. and Royal Dutch Shell Plc. Her conciliatory tone comes as the administration’s policies on energy production, which included a temporary halt to oil leasing on federal lands and the termination of a permit for the Keystone XL pipeline, have drawn the ire of industry.
“I do not want to fight with any of you,” Granholm told the National Petroleum Council. “I do think it’s much more productive to work together on future facing solutions.”
The administration, Granholm said, is not considering reinstating a ban on the export of crude oil — a tool the Biden White House had previously been considering as it sought ways to address gasoline prices that hovered around a seven-year high, setting off political alarm bells.
Granholm’s comments represent the administration’s most definitive statement regarding the export ban, which had the potential to upend oil markets while discouraging domestic oil production.
“I heard you loud and clear and so has the White House,” Granholm said in her remarks. “We wanted to put that rumor to rest.”
Granholm’s address to the council follows finger pointing over the issue of high gasoline and oil prices. The industry was also angry with the administration’s decision to dramatically reduce access to oil and gas development, followed by complaints domestic producers weren’t ramping up production amid increasing energy demand as the worst of the pandemic ended.
The Biden administration has since sold oil and gas drilling rights in the Gulf of Mexico after a federal district judge in June ruled against the moratorium.
Granholm, in her comments, asked the industry to ramp up oil and gas production, while repeating previous complaints about unused permits and leases.
“While I understand you may disagree with some of our policies, it doesn’t mean the Biden administration is standing in the way of your efforts to help meet current demand,” Granholm said, while asking the industry to help partner in the administration’s battle against climate change. “I firmly believe those that embrace the change rather than fighting it will be rewarded on the other side.”
Market levels are expected to remain at current levels, with medium sour grades seeing support from the heightened pace of buying. Crude oil eased early in the week as traders weighed the potential near-term oil demand impacts of rising coronavirus cases around the world amid concerns about the effectiveness of vaccines against its omicron variant that weighed on market sentiment.
The World Health Organization said omicron poses a very high global risk. A strengthening in the US dollar also weighed on oil prices. Pfizer and BioNTech pharmaceutical companies said preliminary laboratory studies demonstrate that three doses of the Pfizer-BioNTech COVID-19 vaccine neutralize the omicron variant while two doses show indications of a significant increase in protection.
Crude oil prices averaged about 2 percent higher, despite persistent market volatility and an uncertain demand outlook amid concerns about omicron. Going forward, the market structure will depend heavily on the demand part of the equation, while a weaker oil market structure will probably weigh on market sentiment in the near term.
China’s announcement that it would cap overall emissions rather than restrict energy consumption to meet its climate goals could be a positive boost to the oil market.
However, oil prices came under further pressure after the International Energy Agency showed lower global oil demand growth forecasts for 2021 and 2022. Crude oil prices settled slightly higher, reversing earlier losses after the EIA’s weekly data showed the largest US crude draw last week since September, exceeding market expectation. Oil prices were supported with higher equity markets, as investors weighed the US Fed’s decision to tighten monetary policy to slow rising inflation.
While crude production growth outside of the OPEC+ remained just 90,000 barrels per day, industry reports suggest the figure to rise to 1.5 million bpd in 2022 and 0.9 million bpd in 2023. The reports said most growth will come from the US and its Strategic Petroleum Reserve release could add an additional 400,000 bpd to the global oil supply pool.
The IEA’s latest market outlook had a more bearish outlook for global oil balances in the first half of 2022. It now sees a surplus of 1.7 million bpd materializing in the first quarter of 2022 and a surplus of 2 million bpd in the second quarter of 2022.
December and January balances could tighten further as a major pipeline outage in Ecuador has forced crude production shut-ins which we estimate will take about 120,000 bpd of supply off the market on average in December and could potentially negatively impact January output too. Moreover, Russia’s crude and condensate production growth has slowed down recently because the country is running out of spare production capacity.
However, from January 2022, global crude balances are expected to be in surplus.
On the other hand, global prices of liquefied natural gas are trading at record highs. Prices will only fall from spring if Nord Stream 2 is commissioned but the world must get ready for another bumpy year ahead.
France’s TotalEnergies (TTEF.PA), Royal Dutch Shell (RDSa.L), Malaysia’s Petronas and Qatar Energy on Friday scooped up big offshore fields in Brazil together with state-owned Petrobras, paying nearly $2 billion to its cash-strapped government.
While TotalEnergies (28%), Qatar Energy (21%) and Petronas (21%) made the top offer for Sepia field, Petrobras, formally Petroleo Brasileiro SA (PETR4.SA), later entered the consortium by exercising preference rights to take a 30% stake.
Petrobras (52.5%), Shell (25%) and Total (22.5%) secured the nearby Atapu field.
Officials, who had been keen to attract major foreign players, deemed the auction a success, and analysts said the offers agreed to were relatively rich.
The selloff was widely seen as a test of Brazil’s investment climate and of large oil producers’ willingness to keep spending big on traditional oil assets, despite increasing pressure over climate change and toward energy transition.
TotalEnergies, which snapped up a stake in both blocks, said the investment will bring output with “costs well below $20 per barrel of oil equivalent” and with carbon emissions rates below industry levels.
“These are unique opportunities to access giant low-cost and low emissions oil reserves,” CEO Patrick Pouyanné said in a statement.
Signing bonuses were fixed in reais at the equivalent of $1.3 billion for Sepia and $740,000 for Atapu. Companies bid for a percentage of the production they were willing to share with the government, winning the highest: 37.43% for Sepia and 31.68% for Atapu.
Petrobras, TotalEergies and Shell shares fell on Friday, following a 2.60% decrease in Brent prices.
Brazil attempted to auction both fields in 2019, but neither received offers, even from Petrobras. At the time, complex legal issues and rich signing bonuses kept oil majors away.
This time, the bidding terms were considered more attractive, several industry sources told Reuters, largely due to big cuts in both signing bonuses and minimum profit oil.
Government moves to streamline rules and lower fees “drew bids well above the minimums for both assets,” said Andre Fangundes, vice president of consultancy Welligence.
“Companies were more aggressive than we expected,” said Marcelo de Assis, head of Latin America upstream research at Wood Mackenzie.
Eleven companies signed up for the chance to bid on Friday. Exxon Mobil Corp (XOM.N)made final arrangements to bid together with Petrobras and a subsidiary of Portugal’s Galp Energia SGPS SA (GALP.LS), people close to the negotiations said, but never presented a final offer.
Oil majors will be able to add production to their portfolios in the short term. Petrobras is ramping up production at Sepia to 180,000 bpd and has reached the 160,000 bpd maximum capacity at Atapu. A second platform is planned for each field.
Cementing Brazil’s status as Latin Americas biggest oil producer, the two fields could boost the country’s production by 12% over the next six years, adding 700,000 bpd, and bringing in almost $40 billion in investment, its energy ministry said after the auction. Petrobras is set to receive $6.2 billion for past investments in the two fields.
Oil supermajor Shell is facing some big changes in its future as stakeholders approve the long-talked-about move from the Netherlands to the U.K. This follows months of controversy over its scheduled North Sea Cambo oilfield project, resulting in Shell’s withdrawal from the development, and its huge drive to invest in renewables over the next decade. These are just a few of the major shifts in Shell’s energy strategy that suggest the company will undergo a substantial transition in the coming years.
Last week, 99.8 percent of Royal Dutch Shell stakeholders approved the company’s move to London, which it hopes will help simplify its dual tax structure and make it more competitive. This could lead to a transformation like that seen by Total’s name change to TotalEnergies earlier this year, as Shell drops the ‘Royal Dutch’ to become Shell PLC.
The move is likely linked to a legal case loss earlier in 2021 when a Dutch court ruled that Shell must decrease its carbon emissions by 45 percent by 2030, in line with national aims to decarbonize the economy. Shell has already announced a net-zero carbon emissions target for 2050 and aims to reduce its emissions by 45 percent by 2035, five years behind the ruling.
But Shell insists that the move will merely simplify its complicated dual-class share system, currently incorporated in the U.K. but with Dutch tax residence. Nick Stansbury, head of climate solutions at Legal and General Investment Management, a major Shell shareholder, explains, “We think this is actually a relatively routine bit of corporate simplification, a kind of corporate tidying up exercise to deal with a complex bit of historical legacy that is simply no longer needed in the world that Shell now lives and operates in.”
Shell stocks have dropped slightly since the announcement, from $44.14 on Friday 10th December to $42.83 the following Wednesday. However, uncertainty around the latest wave of Covid-19 infections and the worldwide implementation of greater restrictions have hit several oil and gas stocks hard in recent weeks. Shell believes the move will ultimately be positive for its stakeholders, as well as for its planned projects in both fossil fuels and renewables.
Shell’s Chair, Sir Andrew Mackenzie stated of the proposal last month, “The simplification will normalize our share structure under the tax and legal jurisdictions of a single country and make us more competitive. As a result, Shell will be better positioned to seize opportunities and play a leading role in the energy transition.”
The company has already promised major changes to its portfolio following the dip in oil and gas demand during the pandemic, as well as in response to international pressure to decarbonize operations. Much like other oil majors, Shell is doubling down on its investments in renewables, earmarking between $5 and $6 billion a year for green energy. Representatives have previously stated that oil production most likely peaked in 2019 and now is the time to get ahead of the game when it comes to alternative energy development.
Its objective is to sell around 560 terawatt-hours annually by 2030, twice its current electricity sales. Building upon its current hydrogen operations, Shell hopes to develop integrated hydrogen hubs to serve both industry and heavy-duty transportation, expecting to achieve a double-digit share of the world’s clean energy sales.
In the mid-term, Shell announced a $565 million investment for renewable energy projects in Brazil through 2025, earlier this year. Developments include largescale solar fields and a natural gas-fired thermal plant, which could start generating energy as early as 2022.
However, the oil major was repeatedly criticized this year for its ongoing interest in the development of the Cambo oilfield in the North Sea, particularly following the COP26 climate summit that took place in Glasgow this November. Until this December, Shell was pursuing the further exploration and development of Cambo, seemingly contradicting its pledge to move away from fossil fuels and decarbonize operations. But following mounting public pressure, Shell ultimately withdrew from the Cambo oilfield development last week, forcing Siccar Point Energy to put the project on hold.
Siccar Point’s CEO, Jonathan Roger, expressed disappointment in Shell’s decision to exit the project. He still believes that “Cambo is a robust project that can play an important part of the UK’s energy security, providing homegrown energy supply and reducing carbon-intensive imports, whilst supporting a just transition.”
So, the jury is out on how dedicated Shell is to reducing its carbon emissions by 45 percent by 2030, as ruled in the Netherlands earlier this year, especially following its recent decision to move to the U.K. However, its recent withdrawal from Cambo, as well as a significant increase in its renewable energy investments over the last year, suggest that Shell is open to diversifying its portfolio, as it aims to get ahead of the competition in several green energy areas.
Brent prices and particularly calendar spreads are being hammered by the rising number of confirmed coronavirus cases around the world, which is threatening tougher international travel restrictions and renewed domestic lockdowns.
Brent spreads have slumped since the start of November, roughly two weeks after the seven-day average new case count started rising in the middle of October, according to global statistics compiled by Our World in Data.
There has been an inverse correlation between the two since the start of the year, as the ebb and flow of infections produces a relaxation and tightening of quarantines and other restrictions impacting oil consumption.
Brent’s calendar spread between futures contracts for February and March 2022 has slumped to a backwardation of just over 20 cents per barrel, down from a peak of more than $1.20 at the start of November.
The seven-day average number of new confirmed cases around the world has climbed to almost 620,000 per day from just 400,000 in the middle of October.
The new wave of infections is likely being driven by a combination of seasonal factors (respiratory diseases spread more rapidly in the northern hemisphere winter) and the emergence of the more transmissible Omicron variant.
The seasonal increase was widely anticipated by policymakers and traders, but the scale and suddenness was not, prompting an abrupt tightening of quarantines and social-distancing controls.
TIDE OF ANXIETY
Previous waves of new coronavirus infections in February-April and June-August also produced a softening of Brent calendar spreads.
But the most recent wave has coincided with growing concerns about rising inflation, the health of the global economy and the outlook for oil consumption in 2022.
And the earlier oil price rise between August and October has triggered a belated release of emergency reserves, led by the United States, adding to supply in the next few months.
The result has been a huge swing in spreads, accelerated and amplified by liquidation of a large number of hedge fund positions, most of them concentrated in nearby futures contracts.
If coronavirus behaves like other respiratory infections, the number of new cases is likely to continue rising for at least another month, though social distancing, health regulations and vaccinations may blunt the increase.
While new cases are accelerating, pressure for greater restrictions on the number of social contacts and cross-border movements will continue to weigh on forecasts for oil consumption.
Brent prices and calendar spreads are therefore likely to remain under pressure until there are clearer signs the new wave is being brought under control by some combination of controls, the arrival of spring weather, or growing acquired immunity in the first quarter of next year.
Independently-held oil product stocks in the Amsterdam-Rotterdam-Antwerp (ARA) hub fell during the week to 15 December, reaching their lowest since December 2014.
Data from consultancy Insights Global show total inventories fell during the week to 15 December, as a rise in Rhine water levels prompted a sharp increase in barge flows to destinations inland.
This effect was most pronounced on gasoil inventories, which fell to their lowest since May 2014 as low tanker inflows to the ARA area combined with the highest upriver flow of gasoil barges since mid-2020. Rhine water levels have been chronically low during the fourth quarter, but a temporary increase this week has eased loading restrictions and prompted market participants to move as much cargo in land as they can before loading restrictions are reimposed.
Loading restrictions on the Rhine force traders to use more barges, increasing costs. Seagoing tankers arrived from Oman, Russia and Qatar and departed for France, Portugal and the UK.
Gasoline inventories were also affected by changes in the regional barge market. Congestion at various terminals around the ARA area caused the return of loading delays, which had been easing since the discovery of the Omicron variant of Covid-19.
Tankers arrived from Portugal, Spain, Sweden and the UK, and departed for Angola, the Caribbean, the US and west Africa. Inventory levels fell back, having reached five-month highs the previous week.
Naphtha stocks fell for the second consecutive week, reaching their lowest since July 2021. Imports fell, with only Algeria and Russia sending cargoes. Barge flows from storage tanks to destinations along the Rhine rose on the week, as petrochemical producers sought to bring in feedstocks while there are no loading restrictions on the river.
ARA jet fuel stocks fell on the week, with Rhine flows well supported and a rare cargo departing for Norway, in addition to the usual flows to the UK and Ireland. Regional airports are likely to be stocking up ahead of the seasonal rise in transport fuel demand. Tankers arrived in the ARA area from India, Saudi Arabia and the UAE.
Fuel oil stocks fell, with at least one Suezmax departing for Singapore. Tankers arrived from France, Georgia, Poland, Russia, Spain and the UK. Demand for fuel oil from bunker suppliers was firm, probably supported by the uptick in the use of barges.
Recovering economies this year have resulted in a robust rebound in oil demand, disproving some projections from the onset of the pandemic in 2020 that the world had already seen peak oil demand.
Despite scares of new variants, such as Delta and lately, Omicron, global oil demand is on track to reach pre-pandemic levels within months and to further rise in coming years. Peak oil demand is not in the cards in the near future, analysts say.
Oil investors surveyed by Bloomberg Intelligence in November have also significantly recalibrated their expectations of peak oil demand over the past two years.
Two and a half years ago, a fifth of oil investor clients polled by Bloomberg Intelligence said that oil demand would peak by February 2021, BloombergNEF’s Chief Content Officer Nathaniel Bullard notes. In June 2019, another one-third of oil investors thought we would see global oil demand peak by 2025. In previous surveys, most investors expected peak oil demand by 2030.
But the latest survey from last month showed a stark difference in the general timeline to peak oil demand compared to the previous four polls.
Currently, just 2 percent of oil investors believe peak oil demand will occur by 2025, and fewer than 40 percent see that peak before 2030. One-third of investors expect oil demand to peak between 2025 and 2030, but another one-third think that peak would be after 2030, at some point between 2030 and 2035.
Mid-2030s is currently OPEC’s timeline for peak oil demand. Global oil demand is expected to continue to grow into the mid-2030s to 108 million barrels per day (bpd), after which it is set to plateau until 2045, OPEC said in its 2021 World Oil Outlook (WOO) earlier this year. OPEC sees oil demand growing “strongly” in the short- and medium-term before demand plateaus in the long term.
Despite expected plateauing demand in the long run, oil will continue to be the fuel with the single largest share of the global energy mix by 2045, meeting 28 percent of energy demand then, OPEC Secretary General Mohammad Barkindo said last month, stressing the need for investments in oil supply to meet consumption.
Demand is set to grow, as the world still runs on fossil fuels which account for around 85 percent of total global energy demand.
The most meaningful dent to oil demand is likely to come from electric vehicles (EVs), which, in some countries, have started to eat away at oil demand for road transportation.
Nevertheless, it will take years to see road fuel demand globally severely impacted by electrification in transportation.
According to BloombergNEF’s Electric Vehicle Outlook 2021, EVs of all types are already displacing well over 1 million barrels of oil demand per day. In its Economic Transition Scenario, BloombergNEF sees oil demand from road transport overall peaking in 2027 and then declines steadily from there.
EVs have the potential to displace some oil demand, but the world as a whole is not there yet, other analysts say.
“When the impact of the pandemic on world oil markets was at its height, there was talk that we had already passed the point of “peak demand”, and consumption would never again be higher than it was in 2019. Wood Mackenzie analysts did not believe it at the time, and their scepticism is being vindicated,” Ed Crooks, Vice-Chair, Americas at Wood Mackenzie, wrote in October.
“Peak demand will come only through long-term structural changes, most immediately in light road transport, and those take time. There are signs that the surge in EV sales in Europe may be starting to chip away at road fuel demand there, but most of the world is not there yet. As the impact of the pandemic continues to fade, that is likely to become increasingly apparent,” Crooks noted.
Independently-held oil product stocks in the Amsterdam-Rotterdam-Antwerp (ARA) hub rose during the week to 8 December, reaching their highest since mid-September.
Data from consultancy Insights Global show total inventories rose during the week to 8 December, continuing the upward trend recorded since stocks hit seven-year lows in late November.
The discovery of the Omicron variant of Covid-19 in the second half of November contributed to a dimming of the demand outlook for gasoline.
This brought the forward curve into a brief contango, having been steeply backwardated since the summer. Gasoline inventories consequently rose to five-month highs, recording their highest week-on-week percentage rise since June 2019.
Gasoline market participants took advantage of a temporary rise in Rhine water levels to bring in blending components from refineries inland, and tankers also arrived with blending components or finished-grade material from Latvia, Russia, Estonia, France, Germany, Spain and the UK. Outflows to the US and west Africa were steady at a low level, and tankers also departed for Brazil, the Caribbean, the Mediterranean and Mexico.
Gasoil stocks also rose. The volume of middle distillates heading inland on barges rose on the week in response to the temporary rise in Rhine water levels. Market participants inland sought to build stocks of diesel and heating oil ahead of peak winter demand season for the latter. Tankers arrived in the ARA area from Russia and Qatar, and departed for France and the Mediterranean.
Naphtha stocks fell, supported by firm demand from northwest European gasoline blenders and petrochemical end-users during the week to 8 December. Cargoes arrived from Algeria, Russia, Spain and the UK.
ARA jet fuel stocks rose on the week, as the volume departing for the UK dwindled relative to the levels seen in recent weeks. The tightening of Covid restrictions in the UK may be affecting the outlook for jet fuel consumption, while at least one cargo of jet fuel arrived in the area from the UAE.
Fuel oil stocks fell. Tankers arrived from the Black Sea, Russia and the UK and departed for the Mediterranean and west Africa.
The tank terminal market is very fragmented with more than a thousand terminal operators operating five thousand terminals worldwide (1). The global market leader Vopak owns just 5 percent of all tank terminals worldwide. Many smaller players are operating in and across niches. With increasing spot activity, vessel owners call many terminals that they are not familiar with. Each tank terminal now handles more vessels of different types and sizes than ever before (3). Buying and selling opportunities abound, but properly valuing a tank terminal has become a daunting task. So how do you determine the value of your tank terminal? In this article, we share 5 key indicators that will help you understand how much your tank terminal is worth.
Until some ten years ago tank terminal investments were exclusively the territory of industry players and private equity. Now increasingly pension and infrastructure funds are entering the market. With the yield on bonds approaching zero percent pension funds and insurance companies shift more of their capital allocations to riskier higher-yielding investment opportunities. And since typical core infrastructure investments like airports, ports, gas pipelines and toll roads are very competitive, tank terminals stand out as an interesting alternative (2) with a low-risk profile and stable revenue streams.
Countering this trend private equity firms are also becoming more creative to realize better returns on tank terminals. Some hire management teams from the storage industry to acquire and develop storage terminals for them, thereby turning a formerly distant investor into an active role of storage operators. Some have bought into existing storage companies with the same goal: turning hands-on experience and know-how into higher yields (2).
As an owner of a tank terminal one can profit from these trends because there are more buyers around plus investors looking for partnerships and acquiring strategic shares. This applies mostly to the independent operators, who have yet to position themselves in a nice market. Semi-captive players need to constantly reevaluate their proposition and be open to better partnerships. Fully captive sites are already vertically integrated in a branch of the industry so they will only be open to selling or investment when that industry is restructuring.
How to approach the valuation of your tank terminal
Before we look at the five factors
determining the value of your tank terminal, let’s describe three approaches
for valuation (4):
Income
approach
The income or discounted cash flow approach requires inputs on prospective financial information, single- or multi-period cash flows, rates of return and long-term growth, and exit multiples and terminal values. Potential challenges with this approach include the availability of projections, unobservable industry growth/risk benchmarks, and a high level of subjectivity. Potential benefits of this method include capturing the asset-specific growth trajectory and risk/reward profile and sidestepping the lack of comparability across peer groups. Limitations include input parameters that can be difficult to estimate and the possibility of yielding negative values for early-stage projects.
Market
approach
An alternative approach is looking at the general market of tank terminals and identifying similar transactions. Here we have for instance the so-called “cost of a comparable transaction” with the same reasoning as when a prospective home buyer checks out recent sales in a neighborhood. An alternative is the Guideline Public Company Method, which also looks for similarity but in this case of trading multiples of publicly traded companies that are similar to the subject company. However, pre-revenue companies lack a basis to apply meaningful multiples, and in general, there is a lack of comparability across peers due to differences in margin and cost structure, location, and the competitive landscape.
Cost
approach
These methods provide the estimated
replacement cost of an asset based on the current replacement cost minus the
cost of depreciation, including deductions for physical deterioration and all
relevant forms of obsolescence. Or they restate the individual assets and
liabilities on the balance sheet to fair value. This method is easy to understand,
but it fails to capture intangible assets like contracts, location, future
growth and goodwill value.
The 5 key factors that influence the value of your tank terminal
From the limitations of these technical valuation techniques, follows that we need a complementary, more intuitive, birds-eye view to get at a decent valuation. So let’s bring in five key factors that singly influence the value of your tank terminal.
1. Location
The most important factor determining the value of your tank terminal is its location on the map. In most cases the surrounding industries, position within transport and distribution networks, and regional supply and demand dynamics determine the demand for tank space. A tank terminal on a bad spot is like a hotel in a disaster zone. An example: after the collapse of the Soviet Union in a few years’ time many tank terminals sprang up in booming industry and trade zones in the Baltics. Since then, the new strong Russian government has been consolidating elsewhere, especially around St. Petersburg. The Baltic tanks became partly redundant and crashed in value of course.
2. Infrastructure
A second related factor is the infrastructure
of the tank terminal. A good location at the sea side is worthless without good
maritime infrastructure. Are there good rail connections? What kind of
pipelines are available or could be built? Do installations have security
valves? Are there adequate fire extinguishers? Is the terminal maintained well
enough and what’s the state of the equipment?
3. Business model
As outlined above, ever more diverse players are entering the market of tank terminals with varying business models for generating revenue. The employed or planned business model is the third factor determining the value of the tank terminal. We can discern four types of business models:
1/ An industrial terminal has low margins but a very stable business; In this setup, a tank terminal is located next to an industrial site. It is basically an outsourcing solution for the chemical site next door. All storage and logistical services are handled by the industrial terminal and the players on the chemical site pay a fee for that;
2/ A trade hub is a highly flexible set-up, mostly on prime locations and with bigger margins. Traders use the terminal to facilitate their arbitrage strategies. As such the terminal needs to be very flexible and responsive so that the trader can capture market opportunities. However, customers come and go and tanks quite often go empty for a while;
3/ an import or export terminal focuses on specific products entering and given clearance in a geographical area. Players in those regions need the terminal to either import products for consumption or to make bulk for exporting excess products;
4/ strategic storage is related to the security of supply issues and is mainly applicable to OECD countries.
The business model is often determined by historic choices with regard to clients, business development, and infrastructure development. Especially today it is important to be able to pivot towards more lucrative business models, and as outlined above this can be enabled by smart joint ventures between operators and investors.
4. Customer portfolio
The fourth factor determining the value of a tank terminal is the customer portfolio. Tanks have a lifetime of about 30 years and have long-term lease contracts for the soil they stand on. During this lifetime a terminal will develop a certain customer portfolio and when a terminal is sold the new owner, of course, continues with much of the existing customers. Having a client portfolio that consists of solid companies that have the potential and expressed their will to grow their business at your terminal is definitely very valuable.
5. Product specialization
Finally, the fifth factor for tank terminal value determination is which products specific tanks may store and what product markets the terminal is specialized in. For gasoline, there are other requirements than for, for example, chemicals. Many kinds of safety and sustainability regulations have to be complied with. Furthermore, specialization in certain products has benefits for clients as a terminal can act as a hub for such a product, generating economies of scale and operational efficiencies.
All in all, it’s quite a complex field for
business developers and investors to make their moves. Technical tools like
discounted cash flow or EBITDA multiples can never have the last say. Tank
terminals offer a vast global playing field where sometimes inexperienced newcomers
make very bad decisions. A good team of experienced operators and well-informed
investors however can make tank terminal investments profitable. With the
abovementioned 5 factors in mind, it becomes easier to geographically and
economically zoom in to spot the best opportunities for buyers and
sellers.
Are you struggling to understand the value your terminal provides to your clients?
Request a 4-week free trial for the Tank Terminal Weekly Market Report.
Independently-held oil product stocks in the Amsterdam-Rotterdam-Antwerp (ARA) hub rose during the week to 1 December, having reached their lowest since December 2014 the previous week.
Data from consultancy Insights Global show total inventories rose in the week to 2 December. The overall rise was led by a increase in fuel oil stocks, supported by the arrival of cargoes from Estonia, France, Russia, Sweden and the UK. The arbitrage route from northwest Europe to Asia-Pacific for very low sulphur fuel oil is open, and the Suezmax Front Silkeborg departed the ARA area for Asia-Pacific.
Another Suezmax is scheduled to load, and at least one VLCC has also been provisionally booked on the route. Smaller tankers departed the ARA area for the Mediterranean and the US.
Gasoil was the only surveyed product to record a week on week fall in stock levels. Barge flows of middle distillates into the European hinterland fell on the week, with very low water levels on the river Rhine, but seagoing inflows from Russia, Sweden and the US comprised mostly part cargoes and MR tankers, and tanker outflows to the UK and France rose on the week.
Covid-related restrictions on freedom of movement are relatively relaxed in the UK and France compared with some other northwest European markets, which may be supporting end-user demand for diesel in the two countries.
Stocks of all other surveyed products rose. Gasoline inventories increased, supported by the arrival of cargoes from the Baltics, Finland, France and the UK. Outflows to the US fell on the week, while tankers also departed for Brazil, China, Mexico and west Africa.
Gasoline blending activity has reduced in the ARA area since the discovery of the Omicron coronavirus variant in late November, which in turn helped clear the congestion that had plagued the region throughout the fourth quarter.
Naphtha stocks rose, supported by the arrival of cargoes from Algeria, Russia, the UK and the US. Demand from petrochemical end-users along the river Rhine ticked down on the week, weighed down by the low liquidity caused by the sharp day on day moves in outright naphtha prices following the discovery of the Omicron Covid variant. Demand from gasoline blenders fell even more sharply, as the outlook for gasoline consumption suddenly darkened.
ARA jet fuel stocks were essentially unchanged on the week. The volume of jet fuel moving inland on barges fell on the week, following a period of stockbuilding at regional airports.
No tankers arrived in the ARA area while several departed for the UK and Ireland.
Reporter: Thomas Warner
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