The liquefied natural gas (LNG) market needs more than $200 billion more in investment by 2030, Royal Dutch Shell said in its 2018 LNG Market Report.
In 2017, LNG consumption increased 29 million tons and to reach 293 tons, surpassing all estimates and expectations. In the last year since Shell published its report, LNG imports grew 11%. According to company estimates, by 2030 the demand for LNG will increase to 500 million tons. Despite the rapid development of the LNG market, investment into new projects isn’t keeping up with demand.
Shell warns that underinvestment in the industry could lead to a shortage of the product by the mid 2020s. This is due to the ‘gap’ in energy investment that began in 2014 when energy prices fell and new capital investment in LNG came to a halt. But in today’s somewhat recovered price market, final investment decisions (FIDs) on new projects are still not going forward.
According to Shell, the so-called ‘gap’ between investment and demand is a function of how the frozen natural gas is negotiated between buyers and sellers. Buyers prefer short-term and more flexible contracts (similar to the oil market), whereas sellers want long-term contracts to supply steady income to begin paying off the massive debt of constructing the LNG terminal.
The energy giant has been ramping up its LNG holdings in recent years, with the most notable acquisition being the $30 billion purchase of BG Group, which brought several natural gas and LNG assets to Shell’s portfolio. It participates in projects along the entire value chain, from exploration and production, to liquefaction and transport, as well as regasification and distribution to customers. Now, the Anglo-Dutch firm is the world’s largest independent producer and trader of LNG, and accounts for more than one-fifth of the world’s LNG market. In 2017, Shell increased is LNG production by 8 percent to 33.24 million tons.
One of Shell’s biggest project to date is Prelude FLNG off the coast of western Australia, a floating liquefied natural gas facility which can liquefy gas from offshore fields on the vessel itself instead of building onshore facilities. Then, once production runs dry, the unit can move to another field for production. Prelude, which is innovative in both its size and technology, will produce 5.3 million tons per year once it is online. Shell faces several other energy majors in Australia and around the world who are building projects similar in scope. The successive announcement of these LNG projects (especially in Australia where labor is expensive and many of the projects are facing delays) caused fears of the LNG market becoming oversaturated. Prices have been depressed since a brief post-Fukushima spike in 2011.
Shell is also weighing large-scaled projects in the US and Canada, Shell’s head of integrated gas and new energies, Maarten Wetselaar, said.
The shale boom has put downward pressure on natural gas prices, making LNG attractive option for traders – buy at about $2.00-3.00 on the Henry Hub, then freeze and ship off to Japan where it fetches prices between $8.00-9.00. Conversely, in countries such as the US and Russia where natural gas is produced cheaply, there zero demand for more expensive LNG.
Japan remains the world’s largest importer of liquefied natural gas, while China is in a close second, followed by South Korea. China’s demand for LNG has reached 38 million tons as the country’s economy continues to suck up energy. The government’s policy on reducing carbon emissions has made LNG, which is cleaner than burning coal, a favorite. Across Asia, demand for LNG grew by 17 million tons.
The new Shell forecast for the LNG market looks at the future supply-demand ratio. Since the beginning of the twenty-first century, the number of countries importing liquefied natural gas has quadrupled, and producers have doubled, while world trade in LNG has tripled: from 100 million tons in 2000 to almost 300 million tons in 2017.
Jarand Rystad, CEO of Rystad Energy, an oil and gas research analysis firm, presented his company’s forecast for future oil prices based on an economic simulated model at the Primakov National Research Institute of World Economy and International Relations (IMEMO), Russian Academy of Sciences, in Moscow on December 14, 2017. In short, oil prices in 2025 could range anywhere from $20 to $140, but it largely depends if the oil market is oversupplied or undersupplied in 2021, 2022, and 2023.
The model takes into account both supply and demand factors, which ultimately are driven by current oil prices. Investments in new onshore and offshore projects are made when oil prices are high, and pulled back in a bearish market.
To make a simple analogy, Rystad told an anecdote about pork prices in Germany from the late 19th century into the early 20th century. An economist noticed that prices for the meat nearly always soared around Christmastime, and periods of high prices would last for about two years at a time, before going into a 2-year slump. This is due to the simple fact that once farmers saw their neighbors making windfall profits during times of plenty, they too decided to invest in a hog farm. However, in the two years it took to start producing at full capacity, a lot of other farmers had had the same idea, and then there was a massive oversupply in the market. At this point, farmers decided their venture wasn’t worth it, closed up shop, and eventually, this created higher demand.
Rystad explains that is one of the first recorded analysis of a boom-bust commodity cycle, and likens the general principle to oil prices and demand/supply. What they found is that it isn’t all that different and that a perfect linear relationship exists between the decision to drill a new oil well and current oil prices.
“Basically, oil managers are taking decisions based on the current oil price and average oil price over the last year,” Rystad asserted.
Future oil investments have a strong correlation to current oil prices. “If it has been high for 3 years, it will be low for 3 years. It’s quite symmetrical,” said Rystad, adding that of course shocks from demand (the financial crisis), supply (war in the Middle East, pipeline disruptions), or structural (disruption by mobile vehicles) complicate the dynamic oil price simulation that he and his colleagues at Rystad are working on.
When oil prices are at $140 per barrel, every producer is investing into the industry, but when prices fall below $40, for example, smaller players get squeezed out.
The Model – Supply, Demand, and Peak Oil
Predicting oil prices into today’s complex world has a lot more inputs than the simple days of raising hog some 100 years ago. Rystad’s model relied on something called the implicit stock build – the relationship between supply and demand. The strongest relationship between the current oil price (log) and accumulated stock draw painted a clearer picture of what to expect in the future.
“The functional relationship is that if you have a stock drop of 1 million barrels per day, in a half a year, oil price changes 30%. So, if the oil price is $50, and you have a stock drop of 1 million barrels per day in a half year. 30% of 50 is 15%, then the oil price will be $65 at the end of the year. This is pretty much what we’ve seen this fall, for example. There is a pretty clear historical correlation,” Rystad explained.
“If you have a very fast very responsive oil price, you will get a somewhat different pattern – a double peak in the oil market. If you have a very slow reaction – like 3% –you get a slower and longer cycle.”
The length of an investment cycle greatly varies depending on whether the product is onshore or offshore.
The offshore (long) cycle is longer, lasting 5-7 years after a final investment decision (FID) is taken. The ‘long’ cycle can add an extra 1-2.5 million barrels of oil to the global supply, and up to 3 million barrels in a peak year. Investment in offshore, unlike onshore, is mostly spent on the facilities (80%) compared to the wells (20%).
The onshore (short) cycle is much more streamlined and results can be seen anywhere from 1-2 years after an FID decision is taken. The impact of the short cycle is much more dynamic and can add 6.5 million new barrels of oil in as short of a time period as 7 months, which is the case for shale/tight oil. Infrastructure is already in place, and do not have to be built from scratch like offshore (nor are they as technically complicated) so about 60-70% of investments are well investments.
“One other relationship we need to look is whether investments follow current oil prices or are people thinking more strategically? An example of this is the new horizontal shale wells. There was a structural growth from 2010 to 2013 since they had to learn how to switch from vertical wells to horizontal wells, but after that, it has been an almost perfect, linear relationship between the drilling of new wells and the actual oil price,” Rystad said.
This is true with both Brent and WTI benchmarks, with an even stronger correlation between the number of new wells drilled and WTI price.
“It’s a very strong functional relationship, and it’s the same for infield wells. We see that it very much follows the current oil prices. And when you look at field development decisions, they are correlated to decisions made in the previous year. Basically, oil managers are making decisions based on the current oil price and average oil price over the last year,” explained Rystad.
OPEC Restrictions Only Benefit Shale Oil
The most common, though unpredictable, example of supply disruptions today comes from Vienna by way of OPEC: the organization’s decision to expand or limit production has a great impact on investment cycles worldwide.
In Rystad’s OPEC production cut model, they predict that the body of oil-producing countries wants to keep the price of oil propped above $60 per barrel, the range oil indices have been hovering at since OPEC decided to limit production in 2016 in order to prop up global oil prices (or to squeeze out American shale producers, whatever your view is).
Once OPEC decides to end its production hold, there will be a boom of new oil onto the market. “If the oil price goes below $60, OPEC will cut 1.5 million barrels for one year. This is a rigid allegory for OPEC. I don’t think they will have the discipline to do that,” said Rystad.
“Every time the oil price goes to $60, OPEC cuts, and the oil price will oscillate between $60 and $80, which is what we think now is the marginal cost of suppliers: $70 in these cases. The oil prices will not be allowed to have a downturn, but you also will not turn off the short cycle sufficiently to get a real off turn. In this decision, this is the scenario where shale will get the largest global market share. The one that will benefit the most from OPEC cutting is actually shale,” Rystad continued.
“Many people think that shale cannot go on growing as fast as today. Investors will say to stop, they aren’t getting sufficient reserves, etc. The exact reason isn’t important, but we can make a scenario when we put the restriction into the model,” he said.
In the case that OPEC ends its production freezes, the market will again be oversupplied and oil prices will dip below $40 and wipe out all short cycle (shale and infield drilling). This doesn’t have a major effect as long as it follows a relative strong long cycle of investment, such as the volumes investments made in 2011, 2012, and 2013 to develop new fields. The long investment cycle usually spills over 4-6 years in the future. If for example, there was a price collapse in 2019, this could lead to a huge undersupply in 2021, 2022, and 2023, and oil prices could jump to $140 and remain at these levels for 2-3 years.
Then, predictably, investors will go crazy and invest as much money as they can into oil. Once the money is poured into development, it will still take a couple years to get all the oil on the market, and only in 2025 would a super over supply occur and prices collapse as a result. Rystad explained that this scenario wouldn’t be a shock, because it is quite similar to the super oversupply that we witnessed at the end of the last cycle, and that in fact the pattern is just repeating.
Disruptions, Peak Oil, and the Power of Shale
Supply and demand are the most important inputs into the model, but there are also larger, structural shifts that Rystad had to account for. One of those was the rapid increase of crude tankers from the Middle East to China.
“The oil in the tankers grew from 930 million barrels to 1235 million barrels. So, what happened is that the total supply change expanded proportionally,” said Rystad.
In Asia, another major shift was that China began stashing away strategic reserves (similar to the US oil stockpile), so the analytical team had to incorporate these into the supply chain size in the model.
In Europe and America, a larger structural demand change is underway with the development of renewable energy sources (and government support for the initiatives) as well as electric cars. As these developments accelerate and become the new norm, the demand for oil will wane, and much of the world’s oil may forever be left untouched underground.
That said, we will still witness a peak oil demand in our lifetimes, whether it’s in 10, 20, or 30 years.
“Demand is flattening out because we have a peak oil demand in the model – it’s 2035. We are experimenting with three different peak oil scenarios – 2025, 2030, and 2035. The simulation shows you get longer down periods if you have an earlier peak demand. So, if we have peak demand in 2025, we will see 2-3 years upcycle, and 4-6 years down cycle. So, it, of course, has a negative impact on the oil market if we have an earlier peak demand, but we will still get price flare-ups,” Rystad said.
Peak oil demand aside, Rystad is still bullish on investment into shale resources, especially in the US.
“The world is totally dependent on shale. Even if you make a scenario with a flat shale production, the world would run into an energy crisis – we wouldn’t have enough energy. We need shale to grow going forward.”
1:05 –1927 pork prices in Germany – the original boom-bust cycle
5:15 – In the last decade, 89% of oil industry investments have been in offshore
5:24 – On peak years, investment cycles can spur an additional 3 million barrels in production in offshore
8:59 – Shale and tight oil short cycle is only 7 months from price signal to decision to drill to completion
9:44 – Typical well level decline is 8 million barrels, new wells declining faster
10:15 – Short cycle providing new 6.5 million barrels of oil, long cycle up to 3 million barrels
A year ago in Vienna, as the Organization of the Petroleum Exporting Countries met for its November meeting on whether or not to maintain, cut, or increase oil production for member countries, there was a new face on the sidelines. Alexander Novak, Russia’s Energy Minister. Leading up to the negotiations, and the final announcement of an OPEC cut, Novak had a busy couple months jet-setting to Qatar and China to meet with Saudi oil ministers to clinch the deal to cap oil production and cooperate with OPEC to stabilize the oil markets.
Russia’s participation, in terms of sheer volume, gave the production freeze a larger market impact. Prices rose 10% after the decision was initially announced last November. It was the first time Russia joined OPEC members in a collective action since 2001. Tomorrow, on November 30, Russia is expected to join the 9-month extension of the current agreement. By capping production, OPEC and Russia have more or less achieved its goal of stabilizing oil prices, which have been hovering at a near $60 per barrel level, in both US and European markets.
Last November, Russia and Saudi Arabia – OPEC’s biggest producer – were in a similar predicament Both governments faced massive budget deficits and oil revenue shortages due to historically low oil prices that earlier in 2016 had fluttered below $30 per barrel.
Russia’s incentive in 2016 to agree to a production cut was motivated by increasing oil revenues in the short term, but more importantly, the idea was to boost oil prices before selling off shares in Rosneft, Russia’s largest and state-owned oil company. The Russian government, therefore, had a direct financial interest in boosting oil prices to fetch a higher valuation for Rosneft before putting it up for sale.
This year, the Russian government has a much more concrete goal in mind: keep oil prices high through the elections in March of 2018. Rosneft no longer has an interest in prolonging the production cuts, because now that the sale is complete, the company wants to secure its market position – i.e. keep prices high enough to make a profit, but low enough to continue to box out US shale producers.
In 2018, Saudi and Russian interests may not align. Saudi Arabia is gearing up to list its energy giant Saudi Aramco 2018, and wants to see oil prices continue to climb before the billion, if not trillion dollar, IPO. The higher the oil prices, the higher the company can list its initial shares. Russia doesn’t necessarily want to sabotage the IPO, but would certainly benefit from it fetching the lowest price possible.
While OPEC is happy to leave the exit strategy vague, Russia is not. Russia’s oil companies such as Rosneft and Lukoil seem to be placated by prices above $60 a barrel and don’t necessarily support extending the deal any longer.
Of course, Saudi and Russia are not the only voices at tomorrow’s meeting. The 14 member countries of OPEC all have various needs. Nigeria and Libya, which were exempt from the production cap cut last year due to low production and civil unrest, may be forced to comply this year. In Venezuela, the crisis has significantly cut oil production, and major debts at state-owned PDVSA risk further damaging output and refinery potential.
Saxo Bank’s Chief Economist Steen Jakobsen is bearish on a recovery in oil prices. The Danish banker sees the growing trend in electrification, especially in transport, as a direct threat to the fossil fuel market. Jakobsen shared this prediction, along with other forecasts on global energy shifts, at a presentation for financial professionals and journalists in Moscow.
According to Jakobsen, electrification is the “single biggest industry paradigm shift we have seen in the history of my time,” adding that electrification will not only revolutionize the car industry, but “will change the economic structure as we know it.”
“Based on electrification, and the massive amount of potential in the Middle East which is being kept in check right now because of the Saudi Aramco IPO, I think oil could easily see $25 in WTI and $30 in Brent in the next 12 months, and certainly in the next couple of years,” Jakobsen said.
“The number of electric cars will go from 2% this year to 10% next year, and then 25% the following year,” said Jakobsen, who believes this will spell the end of oil. As seen in the chart below, 56% percent of oil demand comes from transport.
The rationale behind the significant jump will be supported by government tax incentives encouraging citizens to buy electric instead of petrol engines. China has emerged a pioneer in using government incentives to clean up its polluted cities. In fact, China has announced that by 2030, no cars in the country will run on petrol. If production and export-based economies such as Germany don’t follow the lead in electrification, they will have major economic gaps to fill once battery-powered engines take over the traditional combustion model. Companies like Mercedes Benz, Porsche, and Audi will have to adapt to the normal of electric vehicles, and reevaluate their business models.
The current streak in oil prices can be explained by supply and demand: “The inventory of oil stock in the world is going down, pushing prices up.” In the near future, when the Middle East is unable to unlock their hydrocarbon potential, this will offset the current price structure, and likely cause a glut in the market.
“We started the year with oil prices being up 25 to 50%, and now year over year, we are flat. There is no new inflation coming, unless of course we go much higher in oil prices.”
Jakobsen’s bearish outlook on oil prices follows the theme for his other predications in the global economy, from blockchain to technology to credit availability.
“Everything that goes on in the world is deflationary,” Jakobsen explained, saying that innovations such as blockchain and automatic will mean that the economy simply needs “less of everything” – fewer bankers, factory workers, and in the case of energy – less oil. This trend can be seen in the strengthening dollar: as the USD grows stronger (and thus US-held debt becomes more expensive to pay off), as a result emerging markets, commodities, and inflation all go down.
Predictions for next 30 years:
Peak oil demand?
Health care cost mean revision (max % of GDP)
Regulation – Basel III + IV – credit limitation
Higher policy rates (tax on credit)
Automation and robotics
Blockchain – cheaper, faster, and “less everything”
Monopolistic break-up of IT giants: FB, Google, Amazon, Apple
In creating their economic outlooks, Saxo Bank heavily favors “credit impulse” data points, a good predictor of what the real economy will look like in nine months. The tool measures the change of new credit issued as a percentage of GDP.
The recent drop we are seeing in the global credit impulse is the second largest in the history of this chart (which dates back to 1998). The largest decline was in 2007-2008. When faced with an equity slump in the first quarter of 2016, central banks responded with a massive amount of credit expansion, which came to fruition in the beginning of 2017.
“In my opinion, there is a 66% chance probability of a recession in the early parts of 2018 in the US unless something else happens – in terms of taxes, wars, etc.,” the Saxo Bank economist said. Jakobsen noted that the drying up of capital is happening while most central bankers and politicians believe their economies are getting back on track.
“The US interest rate is going to zero. There is no way the world can live with high US interest rates. It’s not only an issue for the US, but for the whole world, because 50% of all net-debt in the world is financed in dollars”.
“The economic reality is that if you have zero growth – or close to zero growth – you have no productivity, no disposable income – you will ultimately see all these things transmit into the banking sector.”
“In China, the amount of credit is still expanding, but the speed of which this credit is expanding is decreasing,” Jakobsen explained.
“In Russia today you have a credit impulse contraction just as big as we see in China. If you have no lending demand, you have a low velocity of money, and low inflation.” A lack of credit in the banking sector will of course have adverse spillover effects on the economy. Under US sanctions, Russia is currently cut-off from long-term loans from US and European institutions, but has attracted credit from Chinese banks to fill the gap. However, in the long term, if Russia’s banking landscape wants to be competitive, it has to be open to foreign banks and capital.
According to Jakobsen, the biggest risk to Russia right now is the US expanding sanctions to include the Russian derivative and bond markets. “It would hurt more than all the sanctions together, because you are taking away all the credit input.” If such sanctions are passed (which Jakobsen sees as likely, as Trump will want to appear tough against the Russians), the ruble could jump back up to 65 or 70 rubles per USD, and the bond spread up by 200 basis points.
The acquisition of the Indian oil refining company Essar Oil by Rosneft and partners will be the largest ever foreign direct investment in India. The $13 billion dollar deal is also Russia’s largest investment abroad.
The prized asset that Rosneft consortium gets out of the deal is the Vadinar refinery in the western region of Gujarat that can process 400,000 barrels of crude oil per day. Control over the second largest refinery in India will give the world’s largest listed oil producer a solid foothold in the fast-growing Indian market, as well as an outlet to energy-hungry South Asia. Other assets that are part of the deal include 2,700 petrol stations, a deep-water port at Vadinar, and power plant that provides electricity for the Vadinar refinery.
The Vadinar refinery was initially planned to open in 1996, but a variety of delays pushed back the open until 2008. The plant itself is modern and has the capacity to refine heavy and extra heavy crude oils. About 40-50% of finished products will be diesel fuels, 15% gasoline, and another 9-10% petroleum coke, a coal-like and carbon-intensive energy source.
The oil flowing into the plant mostly comes from abroad (The Middle East and Latin America), and only about 15-20% is domestically sourced from India. Under the new deal, Rosneft will supply 200,000 barrels of oil per day, or about half of the raw material, over a 10-year period. Rosneft will supply the refinery with pre-paid oil from Venezuela: in August, the Russian oil company lent Venezuelan state oil company PDVSA $6 billion, and the indebted company will pay it back with oil.
Crippling debt is also what led to Essar Oil to seek a buyer. Last year, the company was struggling to pay interest loans on time. In 2016, Essar Oil paid off $600 million in interest, which was about half of the company’s EBITDA (profit before depreciation, interest, taxes, and amortization). No dividends were paid out in the last fiscal year.
Rosneft itself acquired 49% of the Indian company, and another 49% was acquired by a consortium which includes oil trader Trafigura Group and United Capital Partners (UCP).
There is an observation that the consortium companies play a purely ceremonial role, and were included to avoid international sanctions or interference by the US. Had Rosneft bought all the shares outright, then Essar Oil would become a subsidiary company and would be sanctioned.
According to a report by The Indian Express, Amsterdam-based Trafigura financed its share of the purchase with a loan from Russian state bank VTB. There is an alleged agreement in which Trafigura will transfer its stake to Rosneft in the future. The Moscow-based United Capital Partners has long been suspected of having special ties with Rosneft management. Head of United Capital Partners Ilya Shcherbovich considered it necessary to public refute these rumors.
The total transition amount was officially stated as $12.9 billion, of which $10.9 billion was for the Vadinar refinery asset itself, and another $2 billion for the remaining assets. Rosneft only paid $3.5 billion in cash, and the consortium paid the same amount. VTB will issue Essar a $3.9 billion loan in order to restructure its debt. In total, $10.9 billion was paid to Essar Oil.
Investment in Essar Oil (billions of USD)
Trafigura and UCP (via VTB loans)
VTB loan to Essar Oil
Essar Oil shareholders received a total of $7 billion. According to the agreement, these shareholders will have to transfer about half of this sum back to Essar Oil to pay back the company’s outstanding accounts payable, including a $2.5 billion debt for Iranian oil deliveries.
Another $2 billion will be spent on the acquisition of the Essar Oil Vadinar oil terminal, an asset which was not previously owned by the company. The new buyers will receive the asset shares once the debts of the terminal (which are on Essar Oil’s balance sheet) are offset.
According to Indian analysts, the $10.9 valuation estimate was based on a 12.5 multiple of EBITDA. This estimate doesn’t look at the market capitalization of the company because the share value of a highly indebted company would be massively undervalued. Instead, the method gives a value to the enterprise as a whole without taking into account the debt load.
For Rosneft and the consortium of buyers, this means that the total return on invested capital was a ratio of 1:12.5, or 8%, and this is before depreciation and taxes. This estimate is approximately twice as large compared to other similar companies to Essar Oil. For example, India’s biggest oil refining company Reliance was estimated to have an EBITDA multiple of 7 at the time of sale.
Perhaps this is because there is potential to expand the capacity of the expensive equipment? Unlikely, as at the time of sale, the refinery was (and still is) operating at about 100% capacity. According to data from Essar Oil, only $5.3 billion in the capital was spent on construction. So, for the amount that Rosneft and its partners paid, it would have been possible to build two such refineries from scratch?
The price tag is linked to currency volatility. Before Rosneft agreed to buy Essar Oil, it was a condition that the company delist from the Indian stock exchange at the end of 2015. Before that, in June 2015, the company stock was worth about 100 Indian rupees per share. In mid-June 2015, after the announcement of a deal with Rosneft, the stock price jumped to 146 rupees per share. By December 2015, Essar Oil was forced to offer minor shareholders a buyout price of 262.8 rupees per share. The Indian government stipulated that Essar Oil had to offer minority shareholders the same share buyout prices it was planning to sell to Rosneft. The all ubiquitous VTB happened to provide money to Essar to buy out minority shareholders. Therefore, Rosneft paid about 2.6 times more than market value before the acquisition was announced. How much is this in monetary terms?
The market capitalization of Essar Oil (the cost of shares, ie the company’s value minus debts) in June 2015 prior to the announcement of the Rosneft deal was about 140 billion rupees, or about $2.2 billion. And Rosneft paid $7 billion for company shares. That leaves a $4.8 billion gap in transaction price and market capitalization.
Even if Rosneft was willing to overpay for access and control, certainly the company cannot justify such a massive discrepancy in value. Some news outlets reported that Saudi and Iranian oil companies initially showed interest in purchasing Essar Oil. This is doubtful – neither Saudi Aramco nor NIOC have ever made major investments abroad, nor do they have the cash.
Let us not forget that this deal carries significant political weight. It was signed at a meeting between Russian President Putin and Indian Prime Minister Modi at the BRICS summit.
Leading up to the Deal
One would think that before completing an acquisition, it would be worthwhile to carefully study what you are getting into. However, Essar Oil released its latest report for the 2016/2017 year on August 19, 2017, that is, almost the same day that the deal with Rosneft was finally sealed.
Apparently, the Russians were in a hurry and did not want to examine the company’s financial position in detail. It is possible Rosneft conducted its due diligence in conjunction with the audit before the company closed its books, although this would be a highly unusual practice.
Before completing the acquisition, one would think it would be worthwhile to study in detail what exactly you are getting. But, apparently, the Russians were in a hurry and did not want to examine in detail the financial position of the company before finally acquiring it. Perhaps, however, that they conducted due diligence simultaneously with the audit, before the closure of the company’s books – although this would be rather unusual. Another oddity is that the final report was produced according to Indian Accounting Standards, unlike previous years, when reports were done according to International Financial Reporting Standards. This is in no way illegal, but it is rather unusual and suspicious conduct right before a sale.
Essar Oil took made another extremely unorthodox move during this period and switched external auditors from Deloitte to an unknown Indian auditor to certify the financial statements. The last audit carried out by Deloitte was published with “qualification”, which doesn’t fully confirm the reliability of the company’s financial statement.
In the two years between the announcement of the sale and the final acquisition, Essar Oil showed significant improvement in its financial performance. For the 2014-2015 fiscal year, EBITDA totaled $900 million, and the next year it reached $1.1 billion, and in 2016-2017, it was already $1.7 billion. In two years’ time, the company’s profitability doubled, yet there were no significant developments in capacity or utilization.
Ahead of a sale, companies engage in “window dressing”, improving the appearance of a company before putting the enterprise up for sale. An example of such a number trick is an increase of activity in an affiliated company, Essar Energy Overseas Limited, which in 2016 shipped about $2.5 billion worth of products. Deloitte declined to recognize the debts as high-quality. We don’t know for sure if Essar Oil engaged in such methods, but if they did and it slipped under Rosneft’s radar, that’s another issue.
Who Exactly is the Seller?
Essar Oil is part of the Essar Group conglomerate, which is owned by the famous Ruia family in India. Originally from rural western India, the family began their business in construction and built a large business empire over the past few decades. In addition to oil, the family has interests in telecoms, banking, and metals.
In 1999, Essar Steel became the first company in the history of India to default on its international debt. More recently, the telecoms arm of the conglomerate has come under legal scrutiny over charges of fraud and bribery to government members to secure 2G services. The slump in commodities caused significant problems in their metals enterprises, and Essar Group debts reached 1.4 trillion rupees, or about $22 billion. Selling Essar Oil was the only way for the Ruia family to manage this heavy debt burden.
The deal was a relief for both the Ruia family and many of Essar Oil’s creditors. Standard Chartered Bank, according to estimates, was able to recover $2.5 of the $5.5 billion that it provided to Essar Group.
How the Purchase Affects Rosneft’s Balance Sheet
Rosneft officially only bought 49% of the shares, which means that Indian company’s activities will not be added to its balance sheet. This means that Essar Oil’s debt will not be added to Rosneft’s already heavy corporate debt situation.
At the end of the second quarter, Rosneft’s had a lot of cash on hand, $12.4 billion to be exact. This cash flow is pre-payments from the Chinese for oil supplies, in a deal struck several years ago.
Rosneft paid $3.5 billion in cash for its stake in Essar Oil. Given its cash reserves, this is of course more than feasible, but the indicators of net debt (debt minus cash) will increase by the same amount.
India is a very promising market with an ever-growing population and increasing purchasing power among the middle class. India is the third biggest oil buyer worldwide, after the US and China, and produces oil that covers 20% of its total oil demand.
Perhaps Rosneft made the right decision to invest in India and secure a foothold in the market, which will become one of the most significant in the world. At the same time, working in India presents its own set of challenge. Indians are tough business partners, and it is extremely important to understand local conditions and markets, especially in downstream products. The dynamic and sales-oriented approach is much more unique than developing upstream fields abroad.
How does the acquisition of an Indian oil refinery fit into the development Rosneft’s strategy? Is this a purely financial investment aimed at dividends, or should this new acquisition help the Russian company achieve some strategic goals?
Many believe the transaction was not of commercial interest but was a geopolitical move to build strong economic ties with India. In 2016, Rosneft offered India’s state Oil and Natural Gas Corporation will increase its stake in Rosneft’s Vankor project to 26 percent, and a group of Indian companies (Oil India, Bharat Petroresources, and Indian Oil) to increase their stake in the Siberian field Vankor to 49.9% for about $3.1 billion. However, it is rather useless to link these transactions: besides the fact they both contain the word “Indian”, they have nothing in common.
Another motivation for the deal could be Rosneft’s scheme to move 200,000 barrels of Venezuelan oil to India per day. Of course one of the main risks is that everything in Venezuela is hanging by a thread – if the Madura government falls, Rosneft could lose its source of oil for the refinery. Between the purchase of the refinery and the prepayments to Venezuela, Rosneft has spent about $17 billion. That is a very expensive risk.
In any case, it’s hard not to agree that the purchase of Essar Oil was truly a landmark deal. But only time will tell if this acquisition turns out to be profitable.
On Friday, August 25, Hurricane Harvey, one of the worst tropical storms to hit the US in twelve years, touched down on land. By then, it had gathered the strength of a category 4 hurricane on a 5 point scale.
The oil refinery industry was inadequately prepared. According to data from the International Energy Agency (IEA), daily oil production from US companies in the Gulf of Mexico decreased by 21.64%, down from 1.75 million to 1.31 million barrels per day.
The supply decrease hasn’t led to an increase in oil prices, as basic economics would lead us to believe. In its path, Harvey has destroyed crucial infrastructure centers that normally order and buy crude oil from Gulf Coast refineries. As long as bad weather conditions continue, most businesses (and their demand for energy) will stay closed. The millions of resident’s in greater Houston have been advised to stay off the roads, a factor which also cuts the demand for refined oil products such as gasoline. Goldman Sachs estimates that demand for oil will be reduced by 2 million barrels per day.
Harvey’s effect on oil prices is less obvious.
First, the storm has caused a larger spread between WTI oil prices (trading at roughly $46 per barrel) and Brent (at about $50 per barrel). On Monday, the spread between the US-based benchmark and the European grew to more than $5 per barrel. Brent prices have not taken a hit from the storm.
The primary reason Harvey isn’t destroying WTI prices is due to the recent diversification of the US oil industry into shale, or tight oil.
The US offshore hydrocarbon fields in the Gulf of Mexico produce only about 17% of the country’s total oil output, whereas 48% of the nation’s crude production came from shale reserves. When Hurricane Katrina hit in 2005, it wasn’t the same story, and energy prices, especially for natural gas and gasoline, soared.
CNN reported that Hurricane Harvey has forced 10 oil refineries along the Gulf Coast to shut down. About half of US petroleum and natural capacity is located along the gulf coast in the states of Texas, Louisiana, Mississippi, Alabama, and Florida.
Oil and gas companies began evacuating platforms and rigs before the storm hit. Personnel were evacuated from 98 production platforms (there are a total of 737 in the Gulf of Mexico, both in US and Mexican waters).
Harvey passed through the second largest refinery (600,000 bpd capacity) in Port Arthur, which is owned by Saudi Arabian Oil. Several other companies, such as Shell, confirmed they have closed down their refineries in areas that are in the hurricane’s path. ExxonMobil has closed their Baytown refinery (560,000 bpd capacity), which supplies fuel and petroleum products to the southern and eastern states.
Some refineries continued to operate, but have reduced output. As a result, on Monday, gasoline prices in the US rose by 5% to $1.76 per gallon (before tax). For comparison, gasoline increased by more than 40% following Hurricane Katrina in 2005.
According to investment bank notes from Bank of America and Goldman Sachs, the closure of refineries will lead to a collapse in demand. Goldman Sachs noted that the closure of refineries will translate into 3 million barrels of oil per day not being refined into gasoline and other petroleum products, or about 16% of US refining capacity.
Novatek, the pioneer of Russian LNG in the Arctic, has started commissioning activities on the first liquefaction unit, and the company announced the train will be put into production by December 2017, when the first carrier is scheduled to be delivered to international markets.
The first train (there are a total of three trains at Yamal LNG) will have a capacity of 5.5 million tons of liquefied natural gas, once in full production. The second train is scheduled to start up in 2018, and the third in 2019. When all three trains are active by 2019, the operation will have a capacity of 16.5 million tons of LNG.
The three-train Yamal LNG plant sources natural gas from the South Tambey field on the Yamal Peninsula in Russia’s West Siberia, and the liquefies the gas, and ships it off by boat.
In the short term by 2025, once Novatek’s projects Yamal LNG (16.5 million tons) and Arctic LNG 2 (16.5 million tons) reach full capacity, the company predicts Russia will be the world’s 5th largest producer of LNG. The Arctic LNG 2 project, located on Russia’s Gydan Peninsula, is slated to be completed by 2023. Through auctions and licencing awards, Novatek has amassed a significant amount of bloc holdings in the Russian arctic, which will enable the company to start and complete several more projects like Yamal and Arctic 2.
In the long term, Novatek has ambitions to topple Qatar as the largest LNG producer worldwide (Novatek has said it plans to be producing 100 million tons of LNG in the near future).
Novatek’s plans are not limited to the Arctic. Just recently the company closed a deal to acquire 51% of Gazprombank’s shares in the Cryogas-Vysotsk project in the Baltic Sea. The project includes the construction of an LNG plant with 660,000 tons of capacity per year, as well as an export terminal in the Vysotsk area on the border of Russia and Finland. This project will help Novatek break into LNG marine fuel market. On July 14, a subsidiary of Novatek Gas and Power joined the Society for Gas as a Marine Fuel (SGMF) and SEA \ LNG, an industry coalition that lobbies for LNG as a marine fuel. According to SGMF, already 45 ports worldwide are set up for LNG refueling.
NOVATEK’s subsidiary company Arctic LNG-1 won an auction for the right to explore and produce hydrocarbons in the subsoil area of the Gydan Peninsula of the coast of the Kara Sea in northern Siberia. The acquisition will help NOVATEK secure its foothold in the Russian LNG market, as the Gydan Peninsula license will boost the resource base for large-scale LNG projects in the Yamal region.
The company bought the rights in an auction for $38 million (2.262 billion rubles) for a 27-year lease.
The Gydan site is located in close proximity to the Utrenno field, which is the resource base of Novatek’s Arctic LNG-2 project. The area is estimated to have a total resource potential of 4.74 billion barrels of oil equivalent. Together, the Gydan and Yamal peninsulas are comparable to LNG production in Qatar, NOVATEK has said.
The Arctic LNG 2 project will nearly match Yamal’s production capacity of 16.5 million tons (21 billion cubic meters) per year once it begins operating in 2022-2023. The plant will draw from a resource base of 1.2 trillion cubic meters of proven gas reserves in addition to 50.5 million tons of liquid hydrocarbons.
The addition of Arctic LNG 2 to the Yamal LNG project will significantly reduce the cost of producing LNG in Russia’s Arctic seas, and a liquefaction hub will be set up in Murmansk. Arctic LNG 2 is planned to cost $10 billion and produce 16.5 million tons (21 billion cubic meters) per year once it is in operation starting in 2022 or 2023.
NOVATEK CEO Leonid Mikhelson has said that Russia will soon occupy a quarter of the global LNG market, since the country’s share in world gas reserves is 22-24%. According to Mikhelson, Russia’s vast reserves give the country and obvious competitive advantage in the emerging LNG market.
By the end of this year, NOVATEK’s Yamal LNG project will be commissioned, and eventually production will reach 16.5 million tons per year.
According to NOVATEK, the company already has a significant raw material base on the Gydan Peninsula, including the Utrennoye, Geophysical and Ladderoyskoye fields, as well as the Trekhbogorny, Niavayakhsky, Zapadno-Solpatinsky, Tanamsky, and Severo-Tanamsky fields.
Tehran has announced that gas production at South Pars, the country’s and world’s largest gas field, has doubled in the last four years, and the launch of five new gas platforms has put Iran in reach of surpassing neighboring Qatar’s gas production capacity level.
Iranian President Hassan Rohani, who is up for re-election next month, delivered the good news in April.
According to a statement by the National Iranian Gas Company (NIGC), with the start-up of the five gas platforms has put Iran’s gas production capacity level on par with neighboring Qatar.
The inauguration of South Pars phases 17 through 21 completes the country’s biggest investment, amounting to around $20 billion over the past ten years.
South Pars, which is the world’s largest gas field, has some 230 billion barrel of oil equivalent recoverable hydrocarbons. Two-thirds of the field is located in Qatar, and the other third in Iran. At present, Qatar produces more than 590 million cubic meters of natural gas per day from the field and has plans to boost production by 2022. Iran is trying to catch up in production. Iranian authorities have said that by 2018, gas production from the South Pars field (3,700 sq. km) will exceed that of Qatar’s in the North Field (6,000 sq. km), which is the geological continuation of South Pars.
In total, Iran’s gas production has reached 540 million cubic meters, up from just 240 million when Rohani was elected in 2013, according to Iran’s Ministry of Energy.
Production was curbed by sanctions against Iran, which made it impossible for foreign companies to invest in infrastructure to bring the product to market. As a result, most of Iranian gas produced is used for domestic consumption.
Most of the gas produced is used for domestic consumption, and exports are focused on delivering natural gas via already-existing pipelines to Oman, Pakistan, Iraq, and Kuwait. Tehran relies on oil, not natural gas, for main export revenues.
Iran has not yet been able to replicate Qatar’s successful LNG model, due to a lack of investment as a result of sanctions, and now, an over-supplied market. Qatar is currently the world’s LNG exporter, and ships natural gas to both Europe and Asia, where the product fetches higher market prices.
Iran has signed memorandums of understanding agreements with Gazprom Neft, Lukoil, Tatneft, and Zarubezhneft to jointly develop and operate oil fields.
Thierry Bros, a senior research fellow of The Oxford Institute for Energy Studies sat down with Neftianka to discuss Russia’s future prospects in the LNG market.
Neftianka: You’ve been an analyst on both Russia and LNG markets for decades. You tell us, is LNG Russia’s top energy priority right now?
Bros: The government wants to be a decent player in the LNG world, and again, if you are the government, you have to address the question if you want to be a major LNG player, and ten years later you are a small player, but nowhere near where you wanted to be. It is difficult and risky for companies, therefore we need to partner one way or another.
Today we are in a world where there is too much LNG, other sources are drastically changing merit order system. The Russian government needs to answer one very simple question, is LNG strategic or not? It will need to adapt model to produce. If it decides that the project isn’t strategic, then the market can do it.
We are seeing a relaxed LNG world. I think companies have to think that its still a capitalist world, so you have to think about what type of strategy you want. If you have depletion of historical fields, then you need to find new fields.
You’ve been in the analyst trenches for quite some time now. What do you think about the current slump in LNG prices? Will Russia be able to influence LNG pricing the same way they were able to play with European gas pricing?
I think the Russian state will never be able to control the LNG price, it will be like Brent for oil. The question is, “Do we have sufficient market power LNG to understand the mechanics?” And right now the answer is no. The way to better understand the mechanics is to do more projects.
In order to better understand the LNG market, this means more Russian players and better reporting to the government. In a world where pipeline gas is going to be connected with LNG, Russia has an interest in understanding, but not necessarily controlling, the mechanics of LNG.
There is a very simple question if you are Russia is pipeline gas at discount to LNG, and if so, how can I price this?
The LNG “success” story that everyone is talking about these days is Yamal, an LNG plant with16.5 mtpa that looks like it can break even at $30/barrel prices, even though the area is remote and the technology advanced.
Novatek succeeded in understanding, thanks to Total [partner in Yamal LNG] that costs and CAPEX can’t go through the roof. They understood making it profitable from day one. We can’t twist the spreadsheet, the only way for this to go ahead is for the Russian government to take control, to provide tax holidays, port infrastructure, etc. Novatek and the Russian government definitely came out with a win/win situation.
Yamal has strong state support, provide LNG on time and on budget, a new thing in the LNG world these days. Russian LNG provided by different actors. Remember no monopoly in LNG world. Not enough to put Russia on the LNG map. Still second class player when it comes to LNG. Policy makers would like LNG to become more relevant in Russia.
Conversely, the Shtokman LNG project was thought to be risky, and was postponed. You cant say on your spread sheet you’ll add it up later, it has to be adapted from day one.
Gazprom’s Sakhalin, Russia’s first LNG project, had problems in term of CAPEX during the building phase, but now it operates perfectly fine.
We’ve seen LNG projects on maps for many years, but so far there are only two in Russia [Sakhalin and Yamal].
And what about Gazprom’s Vladivostok LNG project that has been officially shelved since late 2015?
If you are Gazprom, it makes sense to expanding Sakhalin because its cheaper.
Gazprom has never built an LNG liquefaction plant [their partner on the project, Shell, was the operator up until 2009].
Gazprom is extremely good at pipes and conventional upstream. LNG is challenging for them. I think Vladivostok LNG was on the map back many years ago because it was a hedge to Power of Siberia, but with Power of Siberia going ahead, they don’t need
Vladivostok LNG would in theory involve an undersea pipeline from Sakhalin to Vladivostok. Is it really profitable to use pipelines in an LNG project?
Gazprom is used to doing pipelines. They can do the profitability analysis and decide yes or no.
How do energy companies become more vertically integrated? What’s Gazprom’s future in an LNG world?
These big companies have the challenge to adapt – Exxon has the same problem with oil: Their mantra will be “oil, oil, oil” for how long? Gazprom has an advantage as a gas company, its one step ahead in the energy transition. This is why Rosneft is so pushy in breaking into the gas market. Gazprom understands there is a huge risk of unbundling, and for it to try and avoid it, in needs to be profitable day in and day out.
If you are Gazprom, you have to make your case stronger, and that means delivering what the state is expecting.
Gazprom will have a duty to do LNG projects in Russia. If your shareholders ask you do to something that isn’t profitable, you can come back and negotiate.
Of course it is easier to do in Europe, because Gazprom has a long history there, and Asians are tough bargainers. And when we compare this move to what’s going on in Europe, we see it’s a good for Gazprom. They are going to have a tendency to move towards Asia due to financing, sanctions, etc.
Will the Russian government support future LNG projects? How does this change with the 2013 law to “liberalize” the market, letting in new players Novatek and Rosneft to export abroad?
My understanding is that the Russia is creating competition between two national companies, Rosneft and Gazprom, and now Novatek.
It could be a good start. If you want liberalization of markets, this may be a good tool to use later on to move away from regulatory price. If you want to have a price of Russia that is reflective of the market.
Interestingly enough, the Russian government has opened the market to all the companies, and since this law, only one project. Did I pass a law for only one project, or am I going to tell the other companies that its time to deliver?
OK, last question. Do you think that St. Petersburg has the potential to be an LNG pricing hub?
Right now it is for a few players, but you have to start somewhere. You can use a hub as a pricing tool.