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.
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finance projects of mutual benefit could well go some way to replacing some of the more risk-averse sources that have withdrawn their support in recent times, scared off by unworkable reserves or performance covenant based lending.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.
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.
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.
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
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Headline crude prices for the week beginning 12 August 2019 – Brent: US$58/b; WTI: US$54/b
Headlines of the week
The momentum for crude prices abated in the second quarter of 2019, providing less cushion for the financial results of the world’s oil companies. But while still profitable, the less-than-ideal crude prices led to mixed results across the boards – exposing gaps and pressure points for individual firms masked by stronger prices in Q119.
In a preview of general performance in the industry, Total – traditionally the first of the supermajors to release its earnings – announced results that fell short of expectations. Net profits for the French firm fell to US$2.89 billion from US$3.55 billion, below analyst predictions. This was despite a 9% increase in oil and gas production – in particularly increases in LNG sales – and a softer 2.5% drop in revenue. Total also announced that it would be selling off US$5 billion in assets through 2020 to keep a lid on debt after agreeing to purchase Anadarko Petroleum’s African assets for US$8.8 billion through Occidental.
As with Total, weaker crude prices were the common factor in Q219 results in the industry, though the exact extent differed. Russia’s Gazprom posted higher revenue and higher net profits, while Norway’s Equinor reported falls in both revenue and net profits – leading it to slash investment plans for the year. American producer ConocoPhillips’ quarterly profits and revenue were flat year-on-year, while Italy’s Eni – which has seen major success in Africa – reported flat revenue but lower profits.
After several quarters of disappointing analysts, ExxonMobil managed to beat expectations in Q219 – recording better-than-expected net profits of US$3.1 billion. In comparison, Shell – which has outperformed ExxonMobil over the past few reporting periods – disappointed the market with net profits halving to US$3 billion from US$6 billion in Q218. The weak performance was attributed (once again) to lower crude prices, as well as lower refining margins. BP, however, managed to beat expectations with net profits of US$2.8 billion, on par with its performance in Q218. But the supermajor king of the quarter was Chevron, with net profits of US$4.3 billion from gains in Permian production, as well as the termination fee from Anadarko after the latter walked away from a buyout deal in favour of Occidental.
And then, there was a surprise. In a rare move, Saudi Aramco – long reputed to be the world’s largest and most profitable energy firm – published its earnings report for 1H19, which is its first ever. The results confirmed what the industry had long accepted as fact: net profit was US$46.9 billion. If split evenly, Aramco’s net profits would be more than the five supermajors combined in Q219. Interestingly, Aramco also divulged that it had paid out US$46.4 billion in dividends, or 99% of its net profit. US$20 billion of that dividend was paid to its principle shareholder – the government of Saudi Arabia – up from US$6 billion in 1H18, which makes for interesting reading to potential investors as Aramco makes a second push for an IPO. With Saudi Aramco CFO Khalid al-Dabbagh announcing that the company was ‘ready for the IPO’ during its first ever earnings call, this reporting paves the way to the behemoth opening up its shares to the public. But all the deep reservoirs in the world did not shield Aramco from market forces. As it led the way in adhering to the OPEC+ club’s current supply restrictions, weaker crude prices saw net profit fall by 11.5% from US$53 billion a year earlier.
So, it’s been a mixed bunch of results this quarter – which perhaps showcases the differences in operational strategies of the world’s oil and gas companies. There is no danger of financials heading into the red any time soon, but without a rising tide of crude prices, Q219 simply shows that though the challenges facing the industry are the same, their approaches to the solutions still differ.
Supermajor Financials: Q2 2019
Source: U.S. Energy Information Administration, CEDIGAZ, Global Trade Tracker
Australia is on track to surpass Qatar as the world’s largest liquefied natural gas (LNG) exporter, according to Australia’s Department of Industry, Innovation, and Science (DIIS). Australia already surpasses Qatar in LNG export capacity and exported more LNG than Qatar in November 2018 and April 2019. Within the next year, as Australia’s newly commissioned projects ramp up and operate at full capacity, EIA expects Australia to consistently export more LNG than Qatar.
Australia’s LNG export capacity increased from 2.6 billion cubic feet per day (Bcf/d) in 2011 to more than 11.4 Bcf/d in 2019. Australia’s DIIS forecasts that Australian LNG exports will grow to 10.8 Bcf/d by 2020–21 once the recently commissioned Wheatstone, Ichthys, and Prelude floating LNG (FLNG) projects ramp up to full production. Prelude FLNG, a barge located offshore in northwestern Australia, was the last of the eight new LNG export projects that came online in Australia in 2012 through 2018 as part of a major LNG capacity buildout.
Source: U.S. Energy Information Administration, based on International Group of Liquefied Natural Gas Importers (GIIGNL), trade press
Note: Project’s online date reflects shipment of the first LNG cargo. North West Shelf Trains 1–2 have been in operation since 1989, Train 3 since 1992, Train 4 since 2004, and Train 5 since 2008.
Starting in 2012, five LNG export projects were developed in northwestern Australia: onshore projects Pluto, Gorgon, Wheatstone, and Ichthys, and the offshore Prelude FLNG. The total LNG export capacity in northwestern Australia is now 8.1 Bcf/d. In eastern Australia, three LNG export projects were completed in 2015 and 2016 on Curtis Island in Queensland—Queensland Curtis, Gladstone, and Australia Pacific—with a combined nameplate capacity of 3.4 Bcf/d. All three projects in eastern Australia use natural gas from coalbed methane as a feedstock to produce LNG.
Source: U.S. Energy Information Administration
Most of Australia’s LNG is exported under long-term contracts to three countries: Japan, China, and South Korea. An increasing share of Australia’s LNG exports in recent years has been sent to China to serve its growing natural gas demand. The remaining volumes were almost entirely exported to other countries in Asia, with occasional small volumes exported to destinations outside of Asia.
Source: U.S. Energy Information Administration, based on International Group of Liquefied Natural Gas Importers (GIIGNL)
For several years, Australia’s natural gas markets in eastern states have been experiencing natural gas shortages and increasing prices because coal-bed methane production at some LNG export facilities in Queensland has not been meeting LNG export commitments. During these shortfalls, project developers have been supplementing their own production with natural gas purchased from the domestic market. The Australian government implemented several initiatives to address domestic natural gas production shortages in eastern states.
Several private companies proposed to develop LNG import terminals in southeastern Australia. Of the five proposed LNG import projects, Port Kembla LNG (proposed import capacity of 0.3 Bcf/d) is in the most advanced stage, having secured the necessary siting permits and an offtake contract with Australian customers. If built, the Port Kembla project will use the floating storage and regasification unit (FSRU) Höegh Galleon starting in January 2021.