NrgEdge Editor

Sharing content and articles for users
Last Updated: March 21, 2016
1 view
Business Trends
image

The industry is still reeling from the impact of the latest downturn. The current oil glut started late 2014, and the end is still nowhere in sight.

So why ask the question and the suggestion of another crash ahead? Well, our industry has not had the best track record of keeping up with the times, and those sure are changing.

Ten years ago, proponents of electric plug-in cars were laughing stock and their creators considered out of touch loonies who were day-dreaming. Today, electric cars are being mass produced by Tesla in the USA (albeit not yet profitably) and most carmakers are making progress in leaps and strides towards bringing their own models to the market.

In addition, dozens of other giant corporations are investing billions to produce electric vehicles with a range between 200 and 300 miles between recharges that will cost around $30,000 in today's money and they plan to be ready by 2020. Battery technology is evolving at breakneck speed producing lighter and higher capacity units to improve autonomy and reduce overall weight of the vehicles while getting cheaper all the time. Tesla is expanding their factory capacity from 50,000 cars to 500,000 cars a year and sales are still good. In fact 2015 was a record year for them, one year into cheap gas.

So what is the fuss about electric cars you might ask? Well, every electric car will not use about 50 Bbl of oil a year and instead use electricity generated from a variety of sources that are not all hydrocarbon dependent. Right now the reduction in gas consumption is still negligible, but as the momentum of the adoption of electric cars as an alternative to traditional combustion engine cars increases, so will be the amount of gas and thus oil not used to fuel vehicles. This is taken from a study conducted by Bloomberg New Energy Finance group and the article was penned by Tom Randall: "BNEF The Next Oil Crash".

What is worrying is the fact that the oil and gas industry is dismissing the threat posed by electric vehicle adoption in an almost unanimous way. One can see it in their comments about this topic:

  • Exxon Mobil estimates the electric vehicle adoption rate at no more than 1% of total market until 2050.
  • Ryan Lance, CEO of ConocoPhillips says electric vehicle adoption will not happen in a significant manner during his lifetime and it will take another 50 years.
  • OPEC estimates electric vehicles to be about 1% of total vehicles on the road by 2040.

This is sounding the same way as the almost militant rejection of the oil and gas industry of the effects of climate change on the energy markets, dismissing the concept due to “flawed science”. The point is not so much if the science is flawed or not, it is the public’s perception of climate change as a serious issue, and this has become an undisputed fact with the signature of the Paris Accord last year on CO2 emissions reduction efforts. We all tend to forget that Perception = Reality, regardless of the fact that perceptions can be false or un-founded.

Then there is the argument of where those 1,900 Tera-Watts/hour of extra electricity needed to power all those electric vehicles is going to come from. It is hard to tell what the proportion of fossil fueled electricity to nuclear to clean power ratios will be, but for sure, it won’t be all from oil and gas. So the impact on oil and gas consumption will inevitably be one of overall reduction of hydrocarbon consumption, but more importantly, a fall in gasoline consumption that will affect refineries and gas station businesses in a permanent manner.

The authors of the Bloomberg study predict a time window somewhere in the middle to the end of the next decade (the earliest by 2023, realistically somewhere between 2027 and 2030). This is just around the corner in oilfield time scales.

There are plenty of examples of entire industries that have disappeared over the last couple of decades because of a dismissal of the effects new technologies would have on them. Kodak is now just a distant memory in older people’s minds because it did not believe that digital photography would make the old film and print obsolete and was just “a passing fad”.

There are others that understood the existential threat to their businesses and reinvented themselves, such as Xerox recognizing that the photocopier was dead the minute the modern scanner appeared.

So what is the message that we all need to read, understand and then act upon?

There are tremendous changes going on in the 21st Century. Technology is advancing ever more rapidly and the oil and gas industry better embrace those changes and adapt with them, lest it becomes the next Kodak of the world because it is so much easier to be in denial than to face facts. Electric cars are just one of those changes, the other one is the rapid development of green energy, mostly wind, solar and geothermal.

There is another example of how technology overtook our industry by complete surprise: the economical exploitation of shale oil and gas.

The oil and gas industry has known for generations the existence of these vast shale deposits saturated with oil and gas, but since the time we first encountered them, we deemed them uneconomical to produce. But then there came the time when the biggest oil consumer in the world (USA) ran out of conventional hydrocarbon reservoirs, all had been drilled. Well, some non-conformists and very dogged entrepreneurs started to experiment with shale to make it yield its riches in commercial quantities.

At the beginning it was almost a quimera, as it was too costly and the ideas to squeeze the oil or gas from shale rock had not matured. Then came the decade of 100$ oil and suddenly shale started to make economic sense, so much so, that it achieved two unintended consequences:

  1. The advent of the current oil glut.
  2. The demise of deep water.

Shale became the victim of its own success by oversupplying the world crude market, not with shale oil exports, but with crude that the USA did no longer need to buy. The established IOCs and NOCs dismissed shale in the beginning and only at the very end, just a couple of years before the glut arrived did the majors start to take shale seriously, once it was a proven concept.

But there is more. At the mid-30$ range, some shale oil seems to be still commercially viable, and all shale producers have not stopped to drill and much less have they stopped to flow their wells, so here is the second blow: new Deep Water projects are now hopelessly uneconomical, and unless they find a way to drastically reduce the cost of production, it will accompany Kodak and all those that could not adapt to change in the dust of the history books.

Hundreds of billions of dollars invested in all these complex and immensely expensive offshore developments are doomed if we as an industry can’t find the answer to significantly lower its costs.

All we have to do is look at the shale accumulation map of the world to see that we have the potential of producing oil onshore from shale for a very long time. Even if many countries ban hydraulic fracturing, there are still huge quantities of relatively easy and simple ways to produce shale oil and gas that will keep the price of oil low for a long time. Argentina and the UK are working hard towards exploiting their shale potential even in this depressed market scenario.

There may be a few geopolitical blips affecting the crude market, but it won’t be for decades. Even something as unthinkable that for example Saudi Arabia or Russia become failed states like Libya or Yemen and we lose 10 million barrels of oil production, the effect will not last for long. There are too many “pinch hitters” that will come and save the day, shale being one of them.

Let’s not forget there are millions of barrels of production currently not on the market due to conflict (Libya, Yemen, Iraq), sanctions and incompetence (Iran, Venezuela) to name just a few.

So what should the industry do about all of this?

We should all be focusing on the impact all these changes are bringing to our industry and look for ways to change so that we can benefit instead of being run over by change.

The oil and gas industry should collectively be researching effective carbon capture and sequestration technologies to reduce significantly the impact of CO and CO2 coming from hydrocarbon combustion.

Another idea would be to partner with leading combustion engine manufacturers to develop cleaner combustion engines, again to reduce or eliminate the pollution effects of hydrocarbon fuel combustion.

Last but not least, the oil and gas industry should be leading the charge into developing green energy, to eliminate fossil fuel combustion and save hydrocarbons for generations to come to produce all the other goods we take for granted in our lives that are all manufactured from oil and gas: fertilizers, synthetic fibers, resins, composite materials, lubricants, polymers, and the list goes on and on. There will be billions more humans on the planet, all wanting to benefit from these products and others not even invented yet.

I for one will keep trying to delay the time when I will become part of the dust of history. I will do this by keeping an open mind and embracing change instead of rejecting it.

3
1 0

Something interesting to share?
Join NrgEdge and create your own NrgBuzz today

Latest NrgBuzz

Your Weekly Update: 11 - 15 February 2019

Market Watch

Headline crude prices for the week beginning 11 February 2019 – Brent: US$61/b; WTI: US$52/b

  • Oil prices remains entrenched in their trading ranges, with OPEC’s attempt to control global crude supplies mitigated by increasing concerns over the health of the global economy
  • Warnings, including from The Bank of England, point to a global economic slowdown that could be ‘worse and longer-lasting than first thought’; one of the main variables in this forecast are the trade tensions between the US and China, which show no sign of being solved with President Trump saying he is open to delaying the current deadline of March 1 for trade talks
  • This poorer forecast for global oil demand has offset supply issues flaring up within OPEC, with Libya reporting ongoing fighting at the country’s largest oilfield while the current political crisis in Venezuela could see its crude output drop to 700,000 b/d by 2020
  • The looming new American sanctions on Venezuelan crude has already had concrete results, with US refiner Marathon Petroleum moving to replace Venezuelan crude with similar grades from the Middle East and Latin America
  • While Nicolas Maduro holds on to power, Venezuela’s opposition leader Juan Guaido has promised to scrap requirements that PDVSA keep a controlling stake in domestic oil joint ventures and boost oil production through an open economy when his government-in-power takes over
  • Despite OPEC’s attempts to stabilise crude prices, the US House has advanced the so-called NOPEC bill – which could subject the cartel to antitrust action – to a vote, with a similar bill currently being debated in the US Senate
  • The see-saw pattern in the US active rig count continues; after a net loss of 14 rigs last week, the Baker Hughes rig survey reported a gain of 7 new oil rigs and a loss of 3 gas rigs for a net gain of 4 rigs
  • While demand is a concern, global crude supply remains delicate enough to edge prices up, especially with Saudi Arabia going for deeper-than-expected cuts; this should push Brent up towards US$64/b and WTI towards US$55/b in trading this week


Headlines of the week

Upstream

  • Egypt is looking to introduce a new type of oil and gas contract to attract greater upstream investment into the country, aiming to be ‘less bureaucratic and more efficient’ with faster cost-recovery, ahead of a planned Red Sea bid round encompassing over a dozen concession sites
  • Lukoil has commenced on a new phase at the West Qurna-2 field in Iraq, with 57 production wells planned at the Mishrif and Yamama formation that could boost output by 80,000 boe/d to 480,000 boe/d in 2020
  • Aker BP has hit oil and natural gas flows at well 24/9-14 in the Froskelår Main prospect in the Alvheim area of the Norwergian Continental Shelf
  • Things continue to be rocky for crude producers in Canada’s Alberta province; production limits were increased last week after being previously slashed to curb a growing glut on news that crude storage levels dropped, but now face trouble being transported south as pipelines remain at capacity and crude-by-rail shipments face challenging economics

Midstream & Downstream

  • The Caribbean island of Curacao is now speaking with two new candidates to operate the 335 kb/d Isla refinery after its preferred bidder – said to be Saudi Aramco’s American arm Motiva Enterprises – withdrew from consideration to replace the current operatorship under PDVSA
  • America’s Delta Air Lines is now reportedly looking to sell its oil refinery in Pennsylvania outright, after attempts to sell a partial stake in the 185 kb/d plant failed to attract interest, largely due to its limited geographical position

Natural Gas/LNG

  • Total reports that it has made a new ‘significant’ gas condensate discovery offshore South Africa at the Brulpadda prospect in Block 11B/12B in the Outeniqua Basin, with the Brulpadda-deep well also reporting ‘successful’ flows of natural gas condensate
  • Italy’s Eni and Saudi Arabia’s SABIC have signed a new Joint Development Agreement to collaborate on developing technologies for gas-to-liquids and gas-to-chemicals applications
  • The Rovuma LNG project in Mozambique is charging ahead with development, with Eni looking to contract out subsea operations for the Mamba gas project by mid-March and ExxonMobil choosing its contractor for building the complex’s LNG trains by April
February, 15 2019
SHORT-TERM ENERGY OUTLOOK

Forecast Highlights

Global liquid fuels

  • Brent crude oil spot prices averaged $59 per barrel (b) in January, up $2/b from December 2018 but $10/b lower than the average in January of last year. EIA forecasts Brent spot prices will average $61/b in 2019 and $62/b in 2020, compared with an average of $71/b in 2018. EIA expects that West Texas Intermediate (WTI) crude oil prices will average $8/b lower than Brent prices in the first quarter of 2019 before the discount gradually falls to $4/b in the fourth quarter of 2019 and through 2020.
  • EIA estimates that U.S. crude oil production averaged 12.0 million barrels per day (b/d) in January, up 90,000 b/d from December. EIA forecasts U.S. crude oil production to average 12.4 million b/d in 2019 and 13.2 million b/d in 2020, with most of the growth coming from the Permian region of Texas and New Mexico.
  • Global liquid fuels inventories grew by an estimated 0.5 million b/d in 2018, and EIA expects they will grow by 0.4 million b/d in 2019 and by 0.6 million b/d in 2020.
  • U.S. crude oil and petroleum product net imports are estimated to have fallen from an average of 3.8 million b/d in 2017 to an average of 2.4 million b/d in 2018. EIA forecasts that net imports will continue to fall to an average of 0.9 million b/d in 2019 and to an average net export level of 0.3 million b/d in 2020. In the fourth quarter of 2020, EIA forecasts the United States will be a net exporter of crude oil and petroleum products by about 1.1 million b/d.

Natural gas

  • The Henry Hub natural gas spot price averaged $3.13/million British thermal units (MMBtu) in January, down 91 cents/MMBtu from December. Despite a cold snap in late January, average temperatures for the month were milder than normal in much of the country, which contributed to lower prices. EIA expects strong growth in U.S. natural gas production to put downward pressure on prices in 2019. EIA expects Henry Hub natural gas spot prices to average $2.83/MMBtu in 2019, down 32 cents/MMBtu from the 2018 average. NYMEX futures and options contract values for May 2019 delivery traded during the five-day period ending February 7, 2019, suggest a range of $2.15/MMBtu to $3.30/MMBtu encompasses the market expectation for May 2019 Henry Hub natural gas prices at the 95% confidence level.
  • EIA forecasts that dry natural gas production will average 90.2 billion cubic feet per day (Bcf/d) in 2019, up 6.9 Bcf/d from 2018. EIA expects natural gas production will continue to rise in 2020 to an average of 92.1 Bcf/d.

Electricity, coal, renewables, and emissions

  • EIA expects the share of U.S. total utility-scale electricity generation from natural gas-fired power plants to rise from 35% in 2018 to 36% in 2019 and to 37% in 2020. EIA forecasts that the electricity generation share from coal will average 26% in 2019 and 24% in 2020, down from 28% in 2018. The nuclear share of generation was 19% in 2018 and EIA forecasts that it will stay near that level in 2019 and in 2020. The generation share of hydropower is forecast to average slightly less than 7% of total generation in 2019 and 2020, similar to last year. Wind, solar, and other nonhydropower renewables together provided about 10% of electricity generation in 2018. EIA expects them to provide 11% in 2019 and 13% in 2020.
  • EIA expects average U.S. solar generation will rise from 265,000 megawatthours per day (MWh/d) in 2018 to 301,000 MWh/d in 2019 (an increase of 14%) and to 358,000 MWh/d in 2020 (an increase of 19%). These forecasts of solar generation include large-scale facilities as well as small-scale distributed solar generators, primarily on residential and commercial buildings.
  • In 2019, EIA expects wind’s annual share of generation will exceed hydropower’s share for the first time. EIA forecasts that wind generation will rise from 756 MWh/d in 2018 to 859 MWh/d in 2019 (a share of 8%). Wind generation is further projected to rise to 964 MWh/d (a share of 9%) by 2020.
  • EIA estimates that U.S. coal production declined by 21 million short tons (MMst) (3%) in 2018, totaling 754 MMst. EIA expects further declines in coal production of 4% in 2019 and 6% in 2020 because of falling power sector consumption and declines in coal exports. Coal consumed for electricity generation declined by an estimated 4% (27 MMst) in 2018. EIA expects that lower electricity demand, lower natural gas prices, and further retirements of coal-fired capacity will reduce coal consumed for electricity generation by 8% in 2019 and by a further 6% in 2020. Coal exports, which increased by 20% (19 MMst) in 2018, decline by 13% and 8% in 2019 and 2020, respectively, in the forecast.
  • After rising by 2.8% in 2018, EIA forecasts that U.S. energy-related carbon dioxide (CO2) emissions will decline by 1.3% in 2019 and by 0.5% in 2020. The 2018 increase largely reflects increased weather-related natural gas consumption because of additional heating needs during a colder winter and for additional electric generation to support more cooling during a warmer summer than in 2017. EIA expects emissions to decline in 2019 and 2020 because of forecasted temperatures that will return to near normal. Energy-related CO2 emissions are sensitive to changes in weather, economic growth, energy prices, and fuel mix.

U.S. residential electricity price

  • West Texas Intermediate (WTI) crude oil price
  • World liquid fuels production and consumption balance
  • U.S. natural gas prices
  • U.S. residential electricity price
  • West Texas Intermediate (WTI) crude oil price
February, 13 2019
The State of the Industry: A Brightened 2018

2018 was a year that started with crude prices at US$62/b and ended at US$46/b. In between those two points, prices had gently risen up to peak of US$80/b as the oil world worried about the impact of new American sanctions on Iran in September before crashing down in the last two months on a rising tide of American production. What did that mean for the financial health of the industry over the last quarter and last year?

Nothing negative, it appears. With the last of the financial results from supermajors released, the world’s largest oil firms reported strong profits for Q418 and blockbuster profits for the full year 2018. Despite the blip in prices, the efforts of the supermajors – along with the rest of the industry – to keep costs in check after being burnt by the 2015 crash has paid off.

ExxonMobil, for example, may have missed analyst expectations for 4Q18 revenue at US$71.9 billion, but reported a better-than-expected net profit of US$6 billion. The latter was down 28% y-o-y, but the Q417 figure included a one-off benefit related to then-implemented US tax reform. Full year net profit was even better – up 5.7% to US$20.8 billion as upstream production rose to 4.01 mmboe/d – allowing ExxonMobil to come close to reclaiming its title of the world’s most profitable oil company.

But for now, that title is still held by Shell, which managed to eclipse ExxonMobil with full year net profits of US$21.4 billion. That’s the best annual results for the Anglo-Dutch firm since 2014; product of the deep and painful cost-cutting measures implemented after. Shell’s gamble in purchasing the BG Group for US$53 billion – which sparked a spat of asset sales to pare down debt – has paid off, with contributions from LNG trading named as a strong contributor to financial performance. Shell’s upstream output for 2018 came in at 3.78 mmb/d and the company is also looking to follow in the footsteps of ExxonMobil, Chevron and BP in the Permian, where it admits its footprint is currently ‘a bit small’.

Shell’s fellow British firm BP also reported its highest profits since 2014, doubling its net profits for the full year 2018 on a 65% jump in 4Q18 profits. It completes a long recovery for the firm, which has struggled since the Deepwater Horizon disaster in 2010, allowing it to focus on the future – specifically US shale through the recent US$10.5 billion purchase of BHP’s Permian assets. Chevron, too, is focusing on onshore shale, as surging Permian output drove full year net profit up by 60.8% and 4Q18 net profit up by 19.9%. Chevron is also increasingly focusing on vertical integration again – to capture the full value of surging Texas crude by expanding its refining facilities in Texas, just as ExxonMobil is doing in Beaumont. French major Total’s figures may have been less impressive in percentage terms – but that it is coming from a higher 2017 base, when it outperformed its bigger supermajor cousins.

So, despite the year ending with crude prices in the doldrums, 2018 seems to be proof of Big Oil’s ability to better weather price downturns after years of discipline. Some of the control is loosening – major upstream investments have either been sanctioned or planned since 2018 – but there is still enough restraint left over to keep the oil industry in the black when trends turn sour.

Supermajor Net  Profits for 4Q18 and 2018

1. ExxonMobil:

- 4Q18 – Net profit US$6 billion (-28%);

- 2018 – Net profit US$20.8 (+5.7%)

2. Shell:

- 4Q18 – Net profit US$5.69 billion (+32.3%);

- 2018 – Net profit US$21.4 billion (+36%)

3. Chevron:

- 4Q18 – Net profit US$3.73 billion (+19.9%);

- 2018 – Net profit US$14.8 billion (+60.8%)

4. BP:

- 4Q18 – Net profit US$3.48 billion (+65%);

- 2018 - Net profit US$12.7 billion (+105%)

5. Total: 

- 4Q18 – Net profit US$3.88 billion (+16%);

- 2018 - Net profit US$13.6 billion (+28%)

February, 12 2019