Easwaran Kanason

Co - founder of NrgEdge
Last Updated: March 21, 2018
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Business Trends
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Last week, OPEC sounded an alarm. Previously hopeful that the global crude markets would be balanced by June, which would allow it to walk back on the supply freeze that propped prices up at the cost of OPEC market share, the OPEC monthly report raised its expectations for non-OPEC supply for a fourth consecutive month. OPEC now expects global oil demand to grow by 1.6 mmb/d this year, which is more than previously expected. However, non-OPEC oil supplies will grow by 1.66 mmb/d, more than covering demand. The culprit, as always, is the US, where output is expected to grow by 12%. And this is not even the most optimistic forecast; the IEA expects non-OPEC supplies to grow by 1.8 mmb/d this year.

While this has near term implications – Saudi Arabia has already signalled that the OPEC supply curbs may have to extend into 2019 – the more important question is, how far can shale go? American oil production can consistently surpassed expectations over the past year, as the recovery in oil prices triggered a return rush to shale drilling. This will help US oil production reach 11 mmb/d by Q418; it could be even earlier, based on current production trends. By 2030, BP expects US shale oil to grow to 10 mmb/d, almost double its current level.

Despite the base case for shale production being constantly revised upwards – requiring lower long-term oil prices to clear – it is worth asking how realistic it is. There are suggestions that American shale production could hitting the wall; not because the of finite reserves in the Permian, but because of technology limitations. The application of new technology does not in itself create new energy, it only improves the recovery of hydrocarbons and at a faster rate. As reported in CNBC, "Mark Papa, a pioneer in the U.S. shale oil revolution, is warning that forecasts for booming U.S. production growth will leave industry watchers disappointed in the coming years as drillers burn through their best wells and tighten their purse strings. The impression of U.S. shale as the big bad wolf is perhaps a bit overstated, Papa told an audience at this year's CERAWeek by IHS Markit in Houston this year. Papa's comments were a stark contrast to the tone of cautious optimism at the conference, where many executives claimed that data analytics and technology, like machine learning, will improve efficiency in the oil patch and fuel further gains." Most people are focused on additions to the US rig count, productivity rates in shale wells are actually declining, while costs per well are rising. Major players seem to be mitigating this by creating larger fields by connecting wells, but there is also a looming logistical and manpower crunch. The WSJ reports that "Oil infrastructure is the most glaring constraint to limitless growth in U.S. shale output, said analysts for Energy Aspects in a recent note. The Permian basin had 10 oil takeaway pipelines with a combined capacity of 2.92 million barrels a day as of February 2018, said analysts. There will be a shortage of takeaway capacity in the Permian by August, which will only get worse into year-end, noted experts." This suggests that while shale production is still on the steep part of its growth curve, that could soon plateau out and that long-term forecasts are overstated. That would be good news for oil prices in the long run.

However, there are signs that the opposite could be true. Investment into shale players is increasing, giving them more funds to play with. With money, come more interest – solving, or at least, mitigating most of the upcoming bottlenecks. It seems that either more debt through borrowings or the capital markets is driving this production surge, particularly in the USA. However it is worth noting that the USA is not the only place the shale revolution is taking place. By the end of this month, Saudi Arabia will have produced its first shale gas from the North Arabia basin. The giant South Ghawar and Jafurah basins – which reportedly rival Eagle Ford in size – are also underway. Promising finds are improving moods in China and Argentina shale as well, while the UK drilled its first shale well last year. Even if the American shale revolution hits the brakes, the movement could continue elsewhere, which would mean that current non-US share oil production forecasts maybe understated? There is little data out there about the profitability or economics of non-US shale fields. 

Both the low and high scenarios make compelling cases. Both, however are closely tied to current developments in US oil production. Ultimately the base case for shale will depend on economics but more importantly the demand for hydrocarbons in the medium to long term. If oil demand keeps growing, so will the need for more oil, but any large surge would only dampen prices all over again, effectively killing shale production. So can shale go far, technically possible, as there are proven reserves all around the world that are still untapped. But like with everything else, it's the economics and geopolitical factors that will define its days ahead. 

Various production forecasts for American shale tight oil production 

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Your Weekly Update: 11 - 15 November 2019

Market Watch  

Headline crude prices for the week beginning 11 November 2019 – Brent: US$62/b; WTI: US$56/b

  • The trade war between the US and China – and its implications on the rest of the global economy – continue to weigh down on crude oil prices, as varying indications from American and Chinese authorities paint a sketchy picture of how, or when, the trade dispute could be resolved
  • Mild improvement in US and China manufacturing and job offered hope for a respite, but the broader picture is still negative, particularly in India where a worsening economy is tampering fuel demand growth and triggering a diesel glut
  • With OPEC and the OPEC+ club preparing to meet in Vienna in three weeks, words from within the group are that the largest and most influential producers are not pushing for deeper cuts but will instead emphasise greater adherence to the current supply deal that is set to expire in March 2020
  • This comes as OPEC predicts that US shale will continue to steal its market share through 2023, making the prospect of further cuts unpalatable to members who are loathed to further sacrifice volumes amid weak prices
  • In Venezuela – where tumbling output has thus far made the OPEC task of curbing output easier – production and exports seem to have steadied, with international shipments exceeding 800,000 b/d for the second month in a row in October; most volumes going to China and Rosneft under barter deals
  • In the Persian Gulf, where the Iran situation is another potential flashpoint, a US-led multinational coalition has begun patrolling the vital shipping lane to prevent attacks and threats in the critical seabourne oil distribution pathway
  • Signs that US crude output is heading for a period of tempered growth after explosive growth seem to be confirmed by the chronic deterioration in the active US rig count; 7 oil rigs stopped operation, bringing the total count to 817 – the lowest number in 31 months
  • Until there is more clarity on the US-China trade situation or the outcome of the December OPEC meeting in Vienna, crude oil prices are likely to stay rangebound at US$60-63/b for Brent and US$56-59/b for WTI – not high enough to please producers, but not low enough to prompt decisive action


Headlines of the week

Upstream

  • Adnoc is aiming to start trading of its new Murban crude futures contract on the Abu Dhabi exchange in Q2 or Q3 2020, aiming to create a new price benchmark for Middle Eastern crudes while lifting destination restrictions on the grade
  • Hungary’s MOL Group has bought out Chevron’s interests in Azerbaijan for US$1.57 billion, acquiring a 9.57% stake in the Azeri-Chirag-Gunashli (ACG) field and an 8.9% stake in the Baku-Tbilisi-Ceyhan (BTC) pipeline
  • Equinor – along with partners ExxonMobil, Idemitsu and Neptune – have announced a new oil find in the North Sea at the Echino South well in the Fram field, with recoverable resources estimated at 38-100 million boe
  • The Ivory Coast has launched a new licensing round, covering five offshore blocks located near existing discoveries and infrastructure
  • The Canadian province of Alberta is loosening its crude oil production limits once again after a severe lack of pipeline capacity strained production last year by exempting new conventional wells from current output caps; Alberta currently allows producers to exceed their limits if shipping the excess by rail
  • Kosmos Energy has announced a new offshore oil discovery in Equatorial Guinea at the S-5 well of the Santonian reservoir in the Rio Muni Basin
  • Equinor is exiting Eagle Ford, selling its 63% interest and operatorship of its onshore shale plays in the area to Spain’s Repsol for US$325 million
  • As Total’s offshore Brulpadda discovery in South Africa moves ahead, the challenging geography of the Paddavissie play may require a fixed platform

Midstream/Downstream

  • South Africa’s Central Energy Fund and Saudi Aramco are collaborating on a new 300 kb/d refinery at Richards Bay that is expected to come onstream by 2028 as the largest oil refinery in the southern Africa region
  • The Chevron-SPC Singapore Refining Co joint venture delivered its first cargo of very low sulfur fuel oil in October in Asia’s key bunkering hub, ahead of the IMO deadline for marine fuel oil sulfur content kicking in in January
  • The refurbishment of the idled St Croix refinery in the US Virgin Islands is on track for completion in early 2020, reducing capacity by a third to 210 kb/d but increasing capacity for cleaner fuels, particular for marine usage
  • Husky Energy has completed the sale of its 12 kb/d Prince George refinery in Canada’s British Columbia to Tidewater for US$215 million

Natural Gas/LNG

  • The Port Kembla LNG import terminal in Australia’s New South Wales is facing delays, as Australian Industrial Energy and Japan’s JERA struggle to lock in customers to make the project commercially viable
  • Having taken over Anadarko’s interest in the Mozambique LNG project, Total is now looking to expand the export terminal with two additional trains, which could double capacity from a current planned 12.9 million tpa
  • The OMV/ETAP Nawara gas field in Tunisia is on track to produce first natural gas by end-2019, with capacity of 2.7 mcm/d boosting the country’s gas output by 50% and slashing gas imports by some 30%
  • After years of delays, the site for Indonesia and Inpex’s 9.5 million tpa Abadi LNG project has been decided as Yamdena island in the Arafura Sea

Corporate

  • Total will be exiting a key American industrial lobby group, following in the footsteps of Shell as it claims a divergent outlook on climate change issues
November, 15 2019
Brazil Needs a “Makeover” For Future Oil Bids

The year’s final upstream auctions were touted as a potential bonanza for Brazil, with pre-auction estimates suggesting that up to US$50 billion could be raised for some deliciously-promising blocks. The Financial Times expected it to be the ‘largest oil bidding round in history’. The previous auction – held in October – was a success, attracting attention from supermajors and new entrants, including Malaysia’s Petronas. Instead, the final two auctions in November were a complete flop, with only three of the nine major blocks awarded.

What happened? What happened to the appetite displayed by international players such as ExxonMobil, Shell, Chevron, Total and BP in October? The fields on offer are certainly tempting, located in the prolific pre-salt basin and including prized assets such as the Buzios, Itapu, Sepia and Atapu fields. Collectively, the fields could contain as much as 15 billion barrels of crude oil. Time-to-market is also shorter; much of the heavy work has already been done by Petrobras during the period where it was the only firm allowed to develop Brazil’s domestic pre-salt fields. But a series of corruption scandals and a new government has necessitated a widening of that ambition, by bringing in foreign expertise and, more crucially, foreign money. But the fields won’t come cheap. In addition to signing bonuses to be paid to the Brazilian state ranging from US$331 million to US$17 billion by field, compensation will need to be paid to Petrobras. The auction isn’t a traditional one,  but a Transfer of Rights sale covering existing in-development and producing fields.

And therein lies the problem. The massive upfront cost of entry comes at a time when crude oil prices are moderating and the future outlook of the market is uncertain, with risks of trade wars, economic downturns and a move towards clean energy. The fact that the compensation to be paid to Petrobras would be negotiated post-auction was another blow, as was the fact that the auction revolved around competing on the level of profit oil offered to the Brazilian government. Prior to the auction itself, this arrangement was criticised as overtly complicated and ‘awful’, with Petrobras still retaining the right of first refusal to operate any pre-salt fields A simple concession model was suggested as a better alternative, and the stunning rebuke by international oil firms at the auction is testament to that. The message is clear. If Brazil wants to open up for business, it needs to leave behind its legacy of nationalisation and protectionism centring around Petrobras. In an ironic twist, the only fields that were awarded went to Petrobras-led consortiums – essentially keeping it in the family.

There were signs that it was going to end up this way. ExxonMobil – so enthusiastic in the October auction – pulled out of partnering with Petrobras for Buzios, balking at the high price tag despite the field currently producing at 400,000 b/d. But the full-scale of the reticence revealed flaws in Brazil’s plans, with state officials admitting to being ‘stunned’ by the lack of participation. Comments seem to suggest that Brazil will now re-assess how it will offer the fields when they go up for sale again next year, promising to take into account the reasons that scared international majors off in the first place. Some US$17 billion was raised through the two days of auction – not an insignificant amount but a far cry from the US$50 billion expected. The oil is there. Enough oil to vault Brazil’s production from 3 mmb/d to 7 mmb/d by 2030. All Brazil needs to do now is create a better offer to tempt the interested parties.

Results of Brazil’s November upstream auctions:

  • 6 November: Four blocks on offer, two awarded (Buzios, 90% Petrobras 5% CNOOC 5% CNODC ; Itapu, 100% Petrobras)
  • 7 November: Five blocks on offer, one awarded (Aram, 80% Petrobras 20% CNOOC)
November, 14 2019
Short-Term Energy Outlook

Highlights  

Global liquid fuels

  • Brent crude oil spot prices averaged $60 per barrel (b) in October, down $3/b from September and down $21/b from October 2018. EIA forecasts Brent spot prices will average $60/b in 2020, down from a 2019 average of $64/b. EIA forecasts that West Texas Intermediate (WTI) prices will average $5.50/b less than Brent prices in 2020. EIA expects crude oil prices will be lower on average in 2020 than in 2019 because of forecast rising global oil inventories, particularly in the first half of next year.
  • Based on preliminary data and model estimates, EIA estimates that the United States exported 140,000 b/d more total crude oil and petroleum products in September than it imported; total exports exceeded imports by 550,000 b/d in October. If confirmed in survey-collected monthly data, it would be the first time the United States exported more petroleum than it imported since EIA records began in 1949. EIA expects total crude oil and petroleum net exports to average 750,000 b/d in 2020 compared with average net imports of 520,000 b/d in 2019.
  • Distillate fuel inventories (a category that includes home heating oil) in the U.S. East Coast—Petroleum Administration for Defense District (PADD 1)—totaled 36.6 million barrels at the end of October, which was 30% lower than the five-year (2014–18) average for the end of October. The declining inventories largely reflect low U.S. refinery runs during October and low distillate fuel imports to the East Coast. EIA does not forecast regional distillate prices, but low inventories could put upward pressure on East Coast distillate fuel prices, including home heating oil, in the coming weeks.
  • U.S. regular gasoline retail prices averaged $2.63 per gallon (gal) in October, up 3 cents/gal from September and 11 cents/gal higher than forecast in last month’s STEO. Average U.S. regular gasoline retail prices were higher than expected, in large part, because of ongoing issues from refinery outages in California. EIA forecasts that regular gasoline prices on the West Coast (PADD 5), a region that includes California, will fall as the issues begin to resolve. EIA expects that prices in the region will average $3.44/gal in November and $3.12/gal in December. For the U.S. national average, EIA expects regular gasoline retail prices to average $2.65/gal in November and fall to $2.50/gal in December. EIA forecasts that the annual average price in 2020 will be $2.62/gal.
  • Despite low distillate fuel inventories, EIA expects that average household expenditures for home heating oil will decrease this winter. This forecast largely reflects warmer temperatures than last winter for the entire October–March period, and retail heating oil prices are expected to be unchanged compared with last winter. For households that heat with propane, EIA forecasts that expenditures will fall by 15% from last winter because of milder temperatures and lower propane prices.


Natural gas

  • Natural gas storage injections in the United States outpaced the previous five-year (2014–18) average during the 2019 injection season as a result of rising natural gas production. At the beginning of April, when the injection season started, working inventories were 28% lower than the five-year average for the same period. By October 31, U.S. total working gas inventories reached 3,762 billion cubic feet (Bcf), which was 1% higher than the five-year average and 16% higher than a year ago.
  • EIA expects natural gas storage withdrawals to total 1.9 trillion cubic feet (Tcf) between the end of October and the end of March, which is less than the previous five-year average winter withdrawal. Withdrawal of this amount would leave end-of-March inventories at almost 1.9 Tcf, 9% higher than the five-year average.
  • The Henry Hub natural gas spot price averaged $2.33 per million British thermal units (MMBtu) in October, down 23 cents/MMBtu from September. The decline largely reflected strong inventory injections. However, forecast cold temperatures across much of the country caused prices to rise in early November, and EIA forecasts Henry Hub prices to average $2.73/MMBtu for the final two months of 2019. EIA forecasts Henry Hub spot prices to average $2.48/MMBtu in 2020, down 13 cents/MMBtu from the 2019 average. Lower forecast prices in 2020 reflect a decline in U.S. natural gas demand and slowing U.S. natural gas export growth, allowing inventories to remain higher than the five-year average during the year even as natural gas production growth is forecast to slow.
  • EIA forecasts that annual U.S. dry natural gas production will average 92.1 billion cubic feet per day (Bcf/d) in 2019, up 10% from 2018. EIA expects that natural gas production will grow much less in 2020 because of the lag between changes in price and changes in future drilling activity, with low prices in the third quarter of 2019 reducing natural gas-directed drilling in the first half of 2020. EIA forecasts natural gas production in 2020 will average 94.9 Bcf/d.
  • EIA expects U.S. liquefied natural gas (LNG) exports to average 4.7 Bcf/d in 2019 and 6.4 Bcf/d in 2020 as three new liquefaction projects come online. In 2019, three new liquefaction facilities—Cameron LNG, Freeport LNG, and Elba Island LNG—commissioned their first trains. Natural gas deliveries to LNG projects set a new record in July, averaging 6.0 Bcf/d, and increased further to 6.6 Bcf/d in October, when new trains at Cameron and Freeport began ramping up. Cameron LNG exported its first cargo in May, Corpus Christi LNG’s newly commissioned Train 2 in July, and Freeport in September. Elba Island plans to ship its first export cargo by the end of this year. In 2020, Cameron, Freeport, and Elba Island expect to place their remaining trains in service, bringing the total U.S. LNG export capacity to 8.9 Bcf/d by the end of the year.


Electricity, coal, renewables, and emissions

  • EIA expects the share of U.S. total utility-scale electricity generation from natural gas-fired power plants will rise from 34% in 2018 to 37% in 2019 and to 38% in 2020. EIA forecasts the share of U.S. electric generation from coal to average 25% in 2019 and 22% in 2020, down from 28% in 2018. EIA’s forecast nuclear share of U.S. generation remains at about 20% in 2019 and in 2020. Hydropower averages a 7% share of total U.S. generation in the forecast for 2019 and 2020, down from almost 8% in 2018. Wind, solar, and other nonhydropower renewables provided 9% of U.S. total utility-scale generation in 2018. EIA expects they will provide 10% in 2019 and 12% in 2020.
  • EIA expects total U.S. coal production in 2019 to total 698 million short tons (MMst), an 8% decrease from the 2018 level of 756 MMst. The decline reflects lower demand for coal in the U.S. electric power sector and reduced competitiveness of U.S. exports in the global market. EIA expects U.S. steam coal exports to face increasing competition from Eastern European sources, and that Russia will fill a growing share of steam coal trade, causing U.S. coal exports to fall in 2020. EIA forecasts that coal production in 2020 will total 607 MMst.
  • EIA expects U.S. electric power sector generation from renewables other than hydropower—principally wind and solar—to grow from 408 billion kilowatthours (kWh) in 2019 to 466 billion kWh in 2020. In EIA’s forecast, Texas accounts for 19% of the U.S. nonhydropower renewables generation in 2019 and 22% in 2020. California’s forecast share of nonhydropower renewables generation falls from 15% in 2019 to 14% in 2020. EIA expects that the Midwest and Central power regions will see shares in the 16% to 18% range for 2019 and 2020.
  • EIA forecasts that, after rising by 2.7% in 2018, U.S. energy-related carbon dioxide (CO2) emissions will decline by 1.7% in 2019 and by 2.0% in 2020, partially as a result of lower forecast energy consumption. In 2019, EIA forecasts less demand for space cooling because of cooler summer months; an expected 5% decline in cooling degree days from 2018, when it was significantly higher than the previous 10-year (2008–17) average. In addition, EIA also expects U.S. CO2 emissions in 2019 to decline because the forecast share of electricity generated from natural gas and renewables will increase, and the share generated from coal, which is a more carbon-intensive energy source, will decrease.
November, 14 2019