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Last Updated: June 16, 2016
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Professional services organisation, PricewaterhouseCoopers (PwC), published their latest report, 'A Sea Change - The future of the North Sea Oil & Gas', which seeks to define the state of the North Sea Oil and Gas industry and, through the contribution of some 30+ anonymous 'senior industry stakeholders', give some guidance on how the industry could change to secure a turnaround in fortunes within a 24-month window of opportunity. Whilst full of positive sentiment, I can't help but worry that fundamentally, the North Sea Oil and Gas industry is averse to change.

The strongest element of the report is the urgent need for disruptive thinking within an industry that has always cyclically repeated the past and now, in a lower for longer environment, expects and needs different results. It shouldn't take Einstein to see the insanity of that as a strategy.

In theory, three of the most innovative or potentially most impactful ideas mooted are: consortium funding; nationalisation of the supply infrastructure; and standardisation of technologies. However, in heeding lessons from other large scale industries that have been forced into significant change, these are sometimes not without their problems when it comes to practical implementation.

Consortium funding

The exit of many forms or scale of traditional funding from the industry has crippled exploration and development activities. Consortium funding, where those Operators (or Service companies) with deeper pockets club together to finance projects of mutual benefit could well go some way to replacing some of the more risk-averse sources that have withdrawn their support in recent times, scared off by unworkable reserves or performance covenant based lending. The worry is that whilst this may reduce the capital injection required, lenders will still take funding decisions or guarantees based on the weakest link in any partnership. Recovering after the 2008 financial crash, lending institutions of all sizes, despite having billions made available to inject back into the market, were more interested in rebuilding their own balance sheets before providing much-needed market stimulation. Perhaps, in the North Sea, those with the deepest pockets could provide more assurity than others, but then with shareholder pressure, Operators and Service companies may take the same approach in addressing their own needs first. 

Nationalised infrastructure

One of the biggest threats to the sustainability of supply in the North Sea is the integrity and long-term viability of the supply structure. Much of the efficiency savings achieved in the last decades that have driven the North Sea production cost to be amongst the most competitive in the world stem from collaborative use of the offshore pipeline and tie-back infrastructure. As fields face decommissioning or reduced investment in integrity, this advantage may literally erode. So, the industry suggests passing the maintenance of the infrastructure onto the Government. However, as an option, this has a familiar ring.

The nationalised National Rail inherited a poorly maintained infrastructure from the private Rail Track group of companies. Several catastrophic failures, mismanagement and massive losses led to this re-nationalisation where the bulk of the ongoing cost for the upkeep falls to the tax payer. A similar deal with the UK people, who perhaps would not hold the same fondness for bailing out the oil and gas industry, may struggle to find far-reaching support.


A key collaborative initiative that will only work if there is true commitment to co-operate from both Operators and Suppliers is standardisation. Macondo and other milestones have necessarily driven the performance standards demanded of oilfield equipment and operations higher and higher. However, raising the bar to a level where all equipment must meet the same stringent specifications whatever the working conditions is an expensive gold-plated option that led to spiralling industry costs in recent times. Likewise, the pursuit of competitive advantage by technology developers has baked in over-complexity and a lack of interoperability that similarly impacts on costs. Lessons can be learned from the automotive industry that introduced cross-manufacturer standardisation and many other technology and supply chain collaborations that greatly contributed to reduced manufacturing costs.

An industry averse to change

Change management experts identify several common traits in individuals and organisational cultures that lead to the lack of success or failure of change programmes. I believe that industries as a whole, including the Oil and Gas industry, can also be affected by these same factors leading to less than practical success when compared to the vision or goals such as this one.

Fear of the unknown

The precipitous decline of the oil price came as a surprise to most. However, like a blind-sided boxer left reeling from a stunning left hook, the industry has taken too long to gather its wits and come back fighting.

As an industry, Oil and Gas displays an astonishing lack of flexibility in its interpretation of and reaction to the information it has to hand. Just like the proverbial oil tanker, even with all the signs of oversupply, spiralling costs and reduced global demand, the industry failed to read the signs and change direction. And now, almost two years later, we are still lamenting how the industry should change rather than celebrating how it has changed.

Greater emphasis needs to be placed on reading the signs of the cycle and not adding too much complexity on what is still essentially a supply and demand driven market.


Much hope is placed on the UK Government's fiscal mechanisms to create a more favourable market environment. Whilst the PwC report cites praise for some of the changes that have been made, they make little difference currently in a market without revenue. UK Energy Secretary, Amber Rudd, on a trip to open the new Total Shetland gas plant, made no apologies for her lack of a visit to Aberdeen fully a year after taking up the appointment that oversees the UK's energy policies - including North Sea Oil and Gas. That is clearly not something that inspires trust within the industry that the Westminster government has a clear plan. One could argue that they do not even have a vested interest in the industry with the tax take moving into negative figures for the first time in 2015-16, falling from over £2 billion the previous year and down from £10 billion contribution just five years ago.

Loss of control

The perception that change will take away control has a crippling effect. The often quoted story of the howling dog not moving from the nail it is sitting on because the pain is not yet bad enough, exemplifies how the fear of what is on the other side of change outweighs the imperative for action. But surely, the industry has endured a deep enough pain that even the most thick-skinned or stubborn cannot ignore.

Bad timing

The longer the industry waits to make significant changes the less chance they will be made. As the oil price appears to stabilise around $50, the industry is already showing signs of drawing its breath in preparation to releasing a collective sigh of relief. However, $50 as the new bottom is tenuous and there is still a long way to go before significant spending returns. There will be many more companies and individuals who do not retain their positions to see the benefits of a market recovery.

PwC's report suggests a 24-month window of opportunity. I would ask why more was not done a year ago when the window was open even wider.

Predisposition toward change

Finally, a person's attitude to change plays a large part in how actively they engage with it. We all know and understand that the Oil and Gas industry operates on a cycle of boom and bust. If so, then as an industry why change at all? Let's just wait for the next upcycle to swing by.

Even if there is sufficient oil under the North Sea for another 20+ years, there is the clear and present danger that without decisive change, the UK's ability to extract it profitably will be severely damaged. Lack of investment in exploration and production, the supply infrastructure or retaining the skilled workforce within the North Sea basin will all impact negatively and, again, drive costs up and competitiveness down.

Leading change

It is likely that seeking salvation from outside the industry at a Government level will not bear much fruit. Instead, change should be led from the inside out. Our industry leaders, therefore, bring the greatest chance of change within the Oil and Gas industry.

Organisations that want to have a long-term future in the North Sea, need to embed change within their organisations from the top down. Executive teams need to consider change at the forefront of their strategy and decision making, ensuring that it is a core competency of management and a key skill throughout the organisation.

Through championing change, great leaders create an environment that nurtures the most innovative and creative thinking from their people. Openness, transparency and availability of information for improved decision-making build the integrity and trust needed to drive difficult changes throughout the workforce and the whole industry. Developing a wider sense of trust will also bring greater collaboration between industry players.

By David Wilson from Refining Business

United Kingdom West Europe Aberdeen Decommissioning
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Venezuelan crude oil production falls to lowest level since January 2003

monthly venezueal crude oil production

Source: U.S. Energy Information Administration, Short-Term Energy Outlook

In April 2019, Venezuela's crude oil production averaged 830,000 barrels per day (b/d), down from 1.2 million b/d at the beginning of the year, according to EIA’s May 2019 Short-Term Energy Outlook. This average is the lowest level since January 2003, when a nationwide strike and civil unrest largely brought the operations of Venezuela's state oil company, Petróleos de Venezuela, S.A. (PdVSA), to a halt. Widespread power outages, mismanagement of the country's oil industry, and U.S. sanctions directed at Venezuela's energy sector and PdVSA have all contributed to the recent declines.

monthly venezuela crude oil rig count

Source: U.S. Energy Information Administration, based on Baker Hughes

Venezuela’s oil production has decreased significantly over the last three years. Production declines accelerated in 2018, decreasing by an average of 33,000 b/d each month in 2018, and the rate of decline increased to an average of over 135,000 b/d per month in the first quarter of 2019. The number of active oil rigs—an indicator of future oil production—also fell from nearly 70 rigs in the first quarter of 2016 to 24 rigs in the first quarter of 2019. The declines in Venezuelan crude oil production will have limited effects on the United States, as U.S. imports of Venezuelan crude oil have decreased over the last several years. EIA estimates that U.S. crude oil imports from Venezuela in 2018 averaged 505,000 b/d and were the lowest since 1989.

EIA expects Venezuela's crude oil production to continue decreasing in 2019, and declines may accelerate as sanctions-related deadlines pass. These deadlines include provisions that third-party entities using the U.S. financial system stop transactions with PdVSA by April 28 and that U.S. companies, including oil service companies, involved in the oil sector must cease operations in Venezuela by July 27. Venezuela's chronic shortage of workers across the industry and the departure of U.S. oilfield service companies, among other factors, will contribute to a further decrease in production.

Additionally, U.S. sanctions, as outlined in the January 25, 2019 Executive Order 13857, immediately banned U.S. exports of petroleum products—including unfinished oils that are blended with Venezuela's heavy crude oil for processing—to Venezuela. The Executive Order also required payments for PdVSA-owned petroleum and petroleum products to be placed into an escrow account inaccessible by the company. Preliminary weekly estimates indicate a significant decline in U.S. crude oil imports from Venezuela in February and March, as without direct access to cash payments, PdVSA had little reason to export crude oil to the United States.

India, China, and some European countries continued to receive Venezuela's crude oil, according to data published by ClipperData Inc. Venezuela is likely keeping some crude oil cargoes intended for exports in floating storageuntil it finds buyers for the cargoes.

monthly venezuela crude oil exports by destinatoin

Source: U.S. Energy Information Administration, Short-Term Energy Outlook, and Clipper Data Inc.

A series of ongoing nationwide power outages in Venezuela that began on March 7 cut electricity to the country's oil-producing areas, likely damaging the reservoirs and associated infrastructure. In the Orinoco Oil Belt area, Venezuela produces extra-heavy crude oil that requires dilution with condensate or other light oils before the oil is sent by pipeline to domestic refineries or export terminals. Venezuela’s upgraders, complex processing units that upgrade the extra-heavy crude oil to help facilitate transport, were shut down in March during the power outages.

If Venezuelan crude or upgraded oil cannot flow as a result of a lack of power to the pumping infrastructure, heavier molecules sink and form a tar-like layer in the pipelines that can hinder the flow from resuming even after the power outages are resolved. However, according to tanker tracking data, Venezuela's main export terminal at Puerto José was apparently able to load crude oil onto vessels between power outages, possibly indicating that the loaded crude oil was taken from onshore storage. For this reason, EIA estimates that Venezuela's production fell at a faster rate than its exports.

EIA forecasts that Venezuela's crude oil production will continue to fall through at least the end of 2020, reflecting further declines in crude oil production capacity. Although EIA does not publish forecasts for individual OPEC countries, it does publish total OPEC crude oil and other liquids production. Further disruptions to Venezuela's production beyond what EIA currently assumes would change this forecast.

May, 21 2019
Your Weekly Update: 13 - 17 May 2019

Market Watch

Headline crude prices for the week beginning 13 May 2019 – Brent: US$70/b; WTI: US$61/b

  • Crude oil prices are holding their ground, despite the markets showing nervousness over the escalating trade dispute between the USA and China, as well as brewing tensions in the Middle East over the Iranian situation
  • China retaliated against President Trump’s decision to raise tariffs from 10% to 25% on US$200 billion worth of Chinese imports by raising its own tariffs; crucially, China has also slapped taxes on US LNG imports at a time when American export LNG projects banking on Chinese demand are coming online
  • In the Middle East, Saudi Arabia reported that two of its oil tankers were attacked in the Persian Gulf, with the ‘sabotage attack’ near the UAE speculated to be related to Iran; with the US increasing its military presence in the area, the risk of military action has escalated
  • The non-extension of US waiver on Iranian crude is biting hard on Iran, with its leaders calling it ‘unprecedented pressure’, setting the stage for a contentious OPEC meeting in Vienna
  • In a move that is sure to be opposed by Iran, Saudi Arabia has said it is willing to meet ‘all orders’ from former Iranian buyers through June at least; Saudi Aramco is also responding to requests by Asian buyers to provide extra oil
  • The see-saw trend in US drilling activity continues; after a huge gain two weeks ago, the active US rig count declined for a second consecutive rig, with the loss of two oil rigs bringing the total site count to 988, below the equivalent number of 1,045 last year
  • There is considerably more upside to crude prices at the moment, with jitters over the health of the global economy and a delicate situation in the Middle East likely to keep Brent higher at US$71-73/b and WTI at US$62-64/b

Headlines of the week


  • Occidental Petroleum and Warren Buffet have triumphed, as Chevron bowed out of a bidding war for Anadarko Petroleum; Occidental will now acquire Anadarko for US$57 billion, up significantly from Chevron’s US$33 billion bid
  • The deal means that Occidental’s agreement to sell Anadarko’s African assets to Total for US$8.8 billion will also go through, covering the Hassi Berkine, Ourhoud and El Merk fields in Algeria, the Jubilee and TEN fields in Ghana, the Area 1 LNG project in Mozambiuqe and E&P licences in South Africa
  • BP has sanctioned the Thunder Horse South Expansion Phase 2 deepwater project in the US Gulf of Mexico, which is expected to add 50,000 boe/d of production at the Thunder Horse platform beginning 2021
  • Africa is proving to be very fruitful for Eni, as it announced a new gas and condensate discovery offshore Ghana; the CTP-Block 4 in the Akoma prospect is estimated to hold some 550-650 bcf of gas and 18-20 mmbl of condensate
  • In an atypical development, South Africa has signed a deal for the B2 oil block in South Sudan, as part of efforts to boost output there to 350,000 b/d
  • Shell expects to drill its first deepwater well in Mexico by December 2019 after walking away with nine Mexican deepwater blocks last year

Midstream & Downstream

  • China’s domestic crude imports surged to a record 10.64 mmb/d in April, as refiners stocked up on an Iranian crude bonanza due to uncertainty over US policy, which has been confirmed as crude waivers were not renewed
  • Having had to close the Druzhba pipeline and Ust-Luga port for contaminated crude, Russia says it will fully restore compliant crude by end May shipments, including cargoes to Poland and the Czech Republic
  • Mexico’s attempt to open up its refining sector has seemingly failed, with Pemex taking over the new 340 kb/d refinery as private players balked at the US$8 billion price tag and 3-year construction deadline
  • Ahead of India’s move to Euro VI fuels in April 2020, CPCL is partially shutting down its 210 kb/d Manali refinery for a desulfurisation revamp
  • China’s Hengli Petrochemical is reportedly now stocking up on Saudi Arabian crude imports as it prepares to ramp up production at its new 400 kb/d Dalian refinery alongside its 175 kb/d site in Brunei
  • South Korea’s Lotte Chemical Corp expects its ethane cracker in Louisiana to start up by end May, adding 1 mtpa of ethylene capacity to its portfolio
  • Due to water shortage, India’s MRPL will be operating its 300 kb/d refinery in Katipalla at 50% as drought causes a severe water shortage in the area

Natural Gas/LNG

  • Partners in the US$30 billion Rovuma LNG project in Mozambique now expect to sanction FID by July, even after a recent devastating cyclone
  • Also in Mozambioque, Anadarko is set to announce FID on its Mozambique LNG project on June 18, calling it a ‘historic day’
  • After talks of a joint LNG export complex to develop gas resources in Tanzania, Shell and Equinor now appear to be planning separate projects
  • Gazprom has abandoned plans to build an LNG plant in West Siberia to compete with Novatek, focusing instead on an LNG complex is Ust-Luga
  • First LNG has begun to flow at Sempra Energy’s 13.5 mtpa Cameron LNG project in Louisiana, with exports expected to begin by Q319
May, 17 2019
Shell Eclipses ExxonMobil Once Again

The world’s largest oil & gas companies have generally reported a mixed set of results in Q1 2019. Industry turmoil over new US sanctions on Venezuela, production woes in Canada and the ebb-and-flow between OPEC+’s supply deal and rising American production have created a shaky environment at the start of the year, with more ongoing as the oil world grapples with the removal of waivers on Iranian crude and Iran’s retaliation.

The results were particularly disappointing for ExxonMobil and Chevron, the two US supermajors. Both firms cited weak downstream performance as a drag on their financial performance, with ExxonMobil posting its first loss in its refining business since 2009. Chevron, too, reported a 65% drop in the refining and chemicals profit. Weak refining margins, particularly on gasoline, were blamed for the underperformance, exacerbating a set of weaker upstream numbers impaired by lower crude pricing even though production climbed. ExxonMobil was hit particularly hard, as its net profit fell below Chevron’s for the first time in nine years. Both supermajors did highlight growing output in the American Permian Basin as a future highlight, with ExxonMobil saying it was on track to produce 1 million barrels per day in the Permian by 2024. The Permian is also the focus of Chevron, which agreed to a US$33 billion takeover of Anadarko Petroleum (and its Permian Basin assets), only for the deal to be derailed by a rival bid from Occidental Petroleum with the backing of billionaire investor guru Warren Buffet. Chevron has now decided to opt out of the deal – a development that would put paid to Chevron’s ambitions to match or exceed ExxonMobil in shale.

Performance was better across the pond. Much better, in fact, for Royal Dutch Shell, which provided a positive end to a variable earnings season. Net profit for the Anglo-Dutch firm may have been down 2% y-o-y to US$5.3 billion, but that was still well ahead of even the highest analyst estimates of US$4.52 billion. Weaker refining margins and lower crude prices were cited as a slight drag on performance, but Shell’s acquisition of BG Group is paying dividends as strong natural gas performance contributed to the strong profits. Unlike ExxonMobil and Chevron, Shell has only dipped its toes in the Permian, preferring to maintain a strong global portfolio mixed between oil, gas and shale assets.

For the other European supermajors, BP and Total largely matched earning estimates. BP’s net profits of US$2.36 billion hit the target of analyst estimates. The addition of BHP Group’s US shale oil assets contributed to increased performance, while BP’s downstream performance was surprisingly resilient as its in-house supply and trading arm showed a strong performance – a business division that ExxonMobil lacks. France’s Total also hit the mark of expectations, with US$2.8 billion in net profit as lower crude prices offset the group’s record oil and gas output. Total’s upstream performance has been particularly notable – with start-ups in Angola, Brazil, the UK and Norway – with growth expected at 9% for the year.

All in all, the volatile environment over the first quarter of 2019 has seen some shift among the supermajors. Shell has eclipsed ExxonMobil once again – in both revenue and earnings – while Chevron’s failed bid for Anadarko won’t vault it up the rankings. Almost ten years after the Deepwater Horizon oil spill, BP is now reclaiming its place after being overtaken by Total over the past few years. With Q219 looking to be quite volatile as well, brace yourselves for an interesting earnings season.

Supermajor Financials: Q1 2019

  • ExxonMobil – Revenue (US$63.6 million, down 6.7% y-o-y), Net profit (US$2.35 billion, down 49.5% y-o-y)
  • Shell - Revenue (US$85.66 billion, down 5.9% y-o-y), Net profit (US$5.3 billion, down 2% y-o-y)
  • Chevron – Revenue (US$35.19 billion, down 5% y-o-y), Net profit (US$2.65 billion, down 27.2% y-o-y)
  • BP - Revenue (US$67.4 billion, down 2.51% y-o-y), Net profit (US$2.36 billion, down 9.2% y-o-y)
  • Total - Revenue (US$51.2billion, up 3.2% y-o-y), Net profit (US$2.8 billion, down 4.0% y-o-y)
May, 15 2019