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It is over a year now since OPEC declared its market-share cold war against shale oil producers back in 2014, yet the cartel still can't declare "mission accomplished" and claim its victory. 

 

Following its decision not to cut oil production, OPEC expected oil prices to drop to $70 a barrel, which they thought would be enough to squeeze many shale oil producers out of the market.

 

The reality proved otherwise, shale oil producers were able to react quickly in order to reduce their costs through various cost-cutting measures to weather the storm of low oil prices. And many of them managed to survive at those prices. 

 

For OPEC, that meant only one thing; oil prices have to slump further, therefore OPEC's members pursued their market-share strategy and kept pumping. 

 

In January 2015, oil prices were down at levels around $45-$55. During that time, OPEC's Secretary-General was calling the bottom in oil prices. He offered a bullish statements during his speech in London on Jan. 26 by saying "Now the prices are around $45-$55, and I think maybe they have reached the bottom and we will see some rebound very soon." 

It was not too long after that, oil prices fell further making the remark of OPEC's Secretary-General another layer of noise. Things didn't go as OPEC expected and oil prices are still falling till today to levels not OPEC nor anyone else has expected at that time.  

 

Today, oil prices are slightly above $30 a barrel down from over $100 a barrel in 2014. U.S. average rig counts is 541, down 1068 from their recent peak of 1,609 on Oct. 10, 2014. More than 40 U.S. oil and gas companies have filed for bankruptcy protection, and other companies are aggressively reducing their budgets aimed surviving the current downturn. And yet, U.S. oil production is only inching downwards. 

 

Despite falling oil prices and rig counts declines, production cutbacks are relatively minor. According to EIA, in the U.S. alone, oil production has only declined 384,000 barrel a day from its peak in July 2015 of 9,598,000 barrel a day. In general, U.S. shale oil is showing a great resilience regardless of the current bearish sentiments. 

 

A point worth mentioning here is the fact that U.S. oil production dropped to its lowest point during this downturn which was 9,096,000 barrel a day on September 2015. This can be seen as a normal reaction for the crashing prices. However, the following months production started increasing till it reached 9,227,000 barrel a day last month.

Economically, low oil prices means an inevitable decline in supply and historically, low rig count leads to declining oil production. But the current downturn has proved that this is not always the case. Something changed, and a new shift in the oil industry is taking place.

 

Technological Advancement is Beating Rig Count

 

Rig count is considered as a direct measure of the health of oil industry and oil production. Falling rig count lead to a decline in oil production, but why this is not the case in this downturn? Why shale oil producers are able to maintain production?

 

The answer to the above question lays on advanced technology introduced as well as better and efficient ways of producing the oil. Many companies are now focusing on increasing efficiency and productivity of their wells. More cheaper and efficient well intervention and well completion technology, targeting richer sections of shale plays as in the case of the Permain Region -where production is in a continous increase- as well as increasing the well productivity by using more sand in each hydraulic fracturing job. All these have offset the direct effect of falling rig count on oil production. Did OPEC expected that? Highly unlikely. 

A Short-Term Lose Better Than Out

 

Another reason that explains the resilience of shale oil is the fact that many operators who are still losing despite all the cost cutting measures prefer to take a loss and wait, because they know the oil market is boom and bust by nature and they expect things to get better soon. According to a report by Wood Mackenzie, given the cost of restarting production especially in large projects, many operators prefer to continue producing oil at a loss in hope for a rebound in prices rather than to stop production. 

 

What OPEC's Members didn't Expect

 

It seems now that when the OPEC's members decided not to cut their oil output back in 2014, they didn't really expect the current resilience of U.S. shale oil. They didn’t expect the resilience of U.S. oil production despite the dramatic fall in rig count. 

 

They didn’t expect that technology will be able to offset the effect of low oil prices and rig count on oil production. And most of all, they didn't expect the oil prices to fall to its current levels. And this is not something new, they are not accurate at foreseeing the outcomes of their actions, if they were, they would have known that high oil prices will lead to the current shale oil boom in the first place.

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The Strait of Hormuz and Oil Prices

The UK has just designated the Persian Gulf as a level 3 risk for its ships – the highest level possible threat for British vessel traffic – as the confrontation between Iran with the US and its allies escalated. The strategically-important bit of water - and in particular the narrow Strait of Hormuz – is boiling over, and it seems as if full-blown military confrontation is inevitable.

The risk assessment comes as the British warship HMS Montrose had to escort the BP oil tanker British Heritage out of the Persian Gulf into the Indian Ocean from being blocked by Iranian vessels. The risk is particularly acute as Iran is spoiling for a fight after the Royal Marines seized the Iranian crude supertanker Grace-1 in Gibraltar on suspicions that it was violating sanctions by sending crude to war-torn Syria. Tensions over the Gibraltar seizure kept the British Heritage tanker in ‘safe’ Saudi Arabian waters for almost a week after making a U-turn from the Basrah oil terminal in Iraq on fears of Iranian reprisals, until the HMW Montrose came to its rescue. Iran’s Revolutionary Guard Corps have warned of further ‘reciprocation’ even as it denied the British Heritage incident ever occurred.

This is just the latest in a series of events around Iran that is rattling the oil world. Since the waivers on exports of Iranian crude by the USA expired in early May, there were four sabotage attacks on oil tankers in the region and two additional attacks in June, all near the major bunkering hub of Fujairah. Increased US military presence resulted in Iran downing an American drone, which almost led to a full-blown conflict were it not for a last-minute U-turn by President Donald Trump. Reports suggest that Iran’s Revolutionary Guard Corps have moved military equipment to its southern coast surrounding the narrow Strait of Hormuz, which is 39km at its narrowest. Up to a third of all seaborne petroleum trade passes through this chokepoint and while Iran would most likely overrun by US-led forces eventually if war breaks out, it could cause a major amount of damage in a little amount of time.

The risk has already driven up oil prices. While a risk premium has already been applied to current oil prices, some analysts are suggesting that further major spikes in crude oil prices could be incoming if Iran manages to close the Strait of Hormuz for an extended period of time. While international crude oil stocks will buffer any short-term impediment, if the Strait is closed for more than two weeks, crude oil prices could jump above US$100/b. If the Strait is closed for an extended period of time – and if the world has run down on its spare crude capacity – then prices could jump as high as US$325/b, according to a study conducted by the King Abdullah Petroleum Studies and Research Centre in Riyadh. This hasn’t happened yet, but the impact is already being felt beyond crude prices: insurance premiums for ships sailing to and fro the Persian Gulf rose tenfold in June, while the insurance-advice group Joint War Committee has designated the waters as a ‘Listed Area’, the highest risk classification on the scale. VLCC rates for trips in the Persian Gulf have also slipped, with traders cagey about sending ships into the potential conflict zone.

This will continue, as there is no end-game in sight for the Iranian issue. With the USA vague on what its eventual goals are and Iran in an aggressive mood at perceived injustice, the situation could explode in war or stay on steady heat for a longer while. Either way, this will have a major impact on the global crude markets. The boiling point has not been reached yet, but the waters of the Strait of Hormuz are certainly simmering.

The Strait of Hormuz:

  • Connects the Persian Gulf to the Gulf of Oman/Indian Ocean
  • Length: 167km
  • Width: 96km (widest) to 39km (narrowest)
  • Controlled by Iran, the UAE and Musandam (Oman)
  • The conduit for 33% of all LNG trade and 20% of total crude oil demand
July, 16 2019
Your Weekly Update: 8 - 12 July 2019

Market Watch 

Headline crude prices for the week beginning 8 July 2019 – Brent: US$64/b; WTI: US$57/b

  • Bolstered by the renewed OPEC+ supply pact but rattled by increasing tensions between Iran and the US, oil prices started the week steady after gaining over the previous week
  • With the OPEC+ supply deal extended to March 2020, focus will now shift to adherence and in particular, Russian commitments to the agreement that previously wavered over 1H19
  • More critical to the market is the escalating standoff between the US and Iran around the Straits of Hormuz and even beyond; British forces seized an oil tanker off Gibraltar that was suspected to carrying Iranian crude to Syria, drawing share criticism from Iran
  • Iran itself confirmed that it was raising its level of nuclear enrichment above levels agreed to in the 2015 deal that ended sanctions, and accused European signatories to the deal of ‘not doing enough’
  • Iranian forces also confronted a British tanker escorted by a warship in the Persian Gulf, with the narrow channel now a flashpoint for action
  • As a recipient of Middle Eastern crude, China has also raised security levels for its vessel passing through the Straits of Malacca after doing the same for the Straits of Hormuz, raising some eyebrows
  • While the confrontation – or lack of – between the US and Iran will be the main driver behind oil prices movement in the second half of 2019, the trade policies of the Trump administration that may now hit secondary Asian manufacturing nations such as Vietnam is also leaving the global economy increasingly fragile
  • Against this backdrop, the US active oil and gas rig count fell again, dropping five oil sites and gaining one gas site for a net loss of four rigs
  • As the Iranian situation deteriorates, the market will be pricing more risk premiums into traded prices, which should inch up towards the US$65-67/b range for Brent and US$59-61/b for WTI

Headlines of the week

Upstream

  • Marathon Oil has completed the sale of its UK businesses to RockRose Energy, handing over the Brae and Foinaven area fields for US$345 million
  • Despite pulling out from the UK North Sea, ConocoPhillips is still active in Norway, recently submitting a new plan to re-develop the Tor field in Great Ekofisk, which was shut down in 2015 despite only 20% of resources extracted
  • In a bit to boost national production, Nigerian independent Aiteo Eastern E&P has announced plans to spend up to US$15 billion over the next five years to drill new wells and re-visit existing assets
  • Eni and Vitol have been awarded rights to Block WB03 in the offshore Tano basin in Ghana, with Eni holding 70% and expanding its presence in the country
  • Total has approved Phase 3 development at the onshore Dunga field in Kazakhstan that will increase capacity by 10% to some 20,000 b/d by 2022
  • Eni has launched production from the Mizton field in Mexico’s Bay of Campeche Area 1 – the first new offshore new field development by an international firm since reforms in 2008
  • Halliburton and Kuwait Oil have signed an agreement to explore for oil offshore Kuwait which makes Kuwait’s first foray in offshore upstream services
  • Energean Oil & Gas has purchased Electricite de France’s Italian unit for US$850 million, gaining assets in Egypt, Italy, Algeria, Croatia and the North Sea to complement its existing fields in Israel and Greece

Midstream/Downstream

  • China will be launching a new low-sulfur bunker fuel oil contract on the Shanghai Futures Exchange by the end of 2019, just as new IMO regulations on marine fuel oil sulfur content caps kick into effect in 2020
  • Just as American crude production hits new highs, American refining capacity has also reached a new record high of 18.8 million b/d
  • China has issued a new round of crude oil import quotas for private oil refiners, allowing them to bring in an additional 56.85 million tonnes (~1 mmb/d) over the remainder of 2019
  • In the fallout over the contaminated crude scandal at the Druzhba pipeline, Russian pipeline operator Transneft has capped volumes of Rosneft crude that can be transported to Germany and Poland on the pipeline
  • The US Environmental Protection Agency (EPA) has proposed an increased biodiesel mandate to 20.04 billion gallons in 2020 up from 19.92 billion gallons in 2019, but may not extend the hardship waiver program which drew criticism
  • Iraq and Oman have signed a new MoU to cooperate in the oil and gas sector which includes plans for a shared Omani refinery processing Iraqi crude

Natural Gas/LNG

  • Kosmos Energy has struck new gas at the Greater Tortue Ahmeyim-1 well in the Albian reservoir offshore Mauritania and Senegal, which will support the Greater Tortue Ahmeyim LNG project that is on track for a 2022 start
  • Kenya and Tanzania have entered into talks to explore cross-border natural gas trading, aimed at delivering Tanzanian natural gas to Kenya to bypass requiring and building facilities for LNG imports
  • Energean Oil & Gas is reportedly looking to sell its stake in the major Glengorn gas discovery in the UK once its acquisition of Edison E&P is completed
  • Saudi Aramco has started work on the Jafurah gas terminal that will take unconventional gas from the Ghawar oil field to the coast for processing
July, 12 2019
TODAY IN ENERGY: U.S. utility-scale battery storage power capacity to grow substantially by 2023

Utility-scale battery storage units (units of one megawatt (MW) or greater power capacity) are a newer electric power resource, and their use has been growing in recent years. Operating utility-scale battery storage power capacity has more than quadrupled from the end of 2014 (214 MW) through March 2019 (899 MW). Assuming currently planned additions are completed and no current operating capacity is retired, utility-scale battery storage power capacity could exceed 2,500 MW by 2023.

U.S. utility-scale battery storage capacity

Source: U.S. Energy Information Administration, Annual Electric Generator Report and the Preliminary Monthly Electric Generator Inventory

EIA's Annual Electric Generator Report (Form EIA-860) collects data on the status of existing utility-scale battery storage units in the United States, along with proposed utility-scale battery storage projects scheduled for initial commercial operation within the next five years. The monthly version of this survey, the Preliminary Monthly Electric Generator Inventory (Form EIA-860M), collects the updated status of any projects scheduled to come online within the next 12 months.

Growth in utility-scale battery installations is the result of supportive state-level energy storage policies and the Federal Energy Regulatory Commission’s Order 841 that directs power system operators to allow utility-scale battery systems to engage in their wholesale energy, capacity, and ancillary services markets. In addition, pairing utility-scale battery storage with intermittent renewable resources, such as wind and solar, has become increasingly competitive compared with traditional generation options.

The two largest operating utility-scale battery storage sites in the United States as of March 2019 provide 40 MW of power capacity each: the Golden Valley Electric Association’s battery energy storage system in Alaska and the Vista Energy storage system in California. In the United States, 16 operating battery storage sites have an installed power capacity of 20 MW or greater. Of the 899 MW of installed operating battery storage reported by states as of March 2019, California, Illinois, and Texas account for a little less than half of that storage capacity.

U.S. operating utlity-scale battery storage by state

Source: U.S. Energy Information Administration, Annual Electric Generator Report and the Preliminary Monthly Electric Generator Inventory

In the first quarter of 2019, 60 MW of utility-scale battery storage power capacity came online, and an additional 108 MW of installed capacity will likely become operational by the end of the year. Of these planned 2019 installations, the largest is the Top Gun Energy Storage facility in California with 30 MW of installed capacity.

As of March 2019, the total utility-scale battery storage power capacity planned to come online through 2023 is 1,623 MW. If these planned facilities come online as scheduled, total U.S. utility-scale battery storage power capacity would nearly triple by the end of 2023. Additional capacity beyond what has already been reported may also be added as future operational dates approach.

Of all planned battery storage projects reported on Form EIA-860M, the largest two sites account for 725 MW and are planned to start commercial operation in 2021. The largest of these planned sites is the Manatee Solar Energy Center in Parrish, Florida. With a capacity of 409 MW, this project will be the largest solar-powered battery system in the world and will store energy from a nearby Florida Power and Light solar plant in Manatee County.

The second-largest planned utility-scale battery storage facility is the Helix Ravenswood facility located in Queens, New York. The site is planned to be developed in three stages and will have a total capacity of 316 MW.

July, 11 2019