Highlights and outlook
R&M and Chemicals
Consolidated financial results 2
2016 dividend: €0.80 of which €0.40 already paid as interim dividend
Claudio Descalzi, Eni’s Chief Executive Officer, commented:
"The 2016 results mark the successful conclusion of a radical transformation process. Over the past three years, Eni has restructured to withstand one of the most complex environments in the history of the oil industry, while strengthening its growth prospects and preserving a robust balance sheet. Our future growth trajectory will leverage on the key achievements made in this period: a strong production in Q4 of 1.86 million boe/d, our record proved reserve replacement ratio, a well-stocked pipeline of new, high quality projects which will contribute to an expected production growth rate of 3% on average in the next four-year period, and the advanced restructuring of our middownstream businesses. The solidity of our balance sheet has been preserved by maintaining a sustainable level of gearing, while Eni has been the only Major to reduce its leverage during the 2014-2016 period. In light of these achievements, we intend to propose at the next Annual General Shareholders Meeting the distribution of a cash dividend of €0.8 per share in 2016. Looking to the future, we are able to reaffirm our progressive remuneration policy, in line with the expected improvement of commodity prices and our own financial performance."
In the fourth quarter of 2016, Eni reported an adjusted operating profit of €1.29 billion, up by 103% or €0.65 billion quarter-on-quarter, reversing the negative trend of the previous quarters, thanks to doubling in the E&P operating performance to €1.4 billion (up by €0.8 billion). The E&P improvement was driven mainly by efficiency and optimization measures (up by €0.7 billion) and by a marginal recovery in the oil scenario (the Brent benchmark was up by 13.2%), which has yet to be fully reflected in gas prices which were down due to the time lags in oil-linked price formulas. These increases were partly offset by lower non-recurring gains in the G&P segment.
On the minus side, the G&P segment reported an adjusted operating loss of €72 million, compared to a profit of €18 million in the fourth quarter of 2015, which was negatively affected by an unfavourable trading environment, particularly in the LNG business, as well as by lower non-recurring gains and higher operating charges. The Refining & Marketing and Chemical segment reported lower results (down by €59 million or 44%) due to competitive pressures, a less favourable refining and commodity environment y-o-y and the negative impact of the shutdown of the EST conversion plant following the accident occurred in December 2016. These negatives were partly counteracted by cost efficiencies and optimization gains.
After five quarters affected by the downturn in oil prices, the fourth quarter of 2016 saw the Group revert to a net profit of €0.46 billion, compared to a net loss of €0.3 billion in the fourth quarter of 2015. This recovery reflected an improved operating performance and a material reduction in the adjusted tax rate to 58% from about 168% in the fourth quarter of 2015.
For the FY2016, adjusted operating profit of €2.32 billion was down by €2.2 billion y-o-y, or 48%. A low commodity price environment accounted for a decline of €3.3 billion, while a four month and half shutdown of operations at Val d’Agri and lower non-recurring gains in G&P accounted for €0.6 billion. By contrast, efficiency gains and a reduced cost base, mainly in the E&P segment, improved the performance by €1.7 billion.
Adjusted net loss for the FY2016 amounted to €0.34 billion, lower by €1.14 billion from the adjusted net profit of 2015 (€0.8 billion). This was due to a lowered operating performance, declining results from equity-accounted entities reflecting a weaker oil price scenario and a higher tax rate (up by 38 percentage points). The latter point reflected the recording of a tax rate as high as 100% in the first nine months of the year due to the oil downturn, which determined a larger relative weight of taxable profit earned under PSA schemes, which are characterized by higher-than-average rates of taxes. Furthermore, the Group tax rate was negatively affected by the classification as special items of the reversals of certain deferred tax assets, which were written down in the previous reporting period.
Net borrowings and cash flow
As of December 31, 2016, net borrowings5 were €14.78 billion, €2.09 billion lower than December 31, 2015. The reduction reflected an increase in cash flow from operating activities (€7.67 billion), the closing of the Saipem transaction with net proceeds of €5.2 billion and other asset divestments for €0.6 billion, which comprised the available-for-sale shareholding in Snam due to the exercise of the conversion right from bondholders and marketing activities of fuels in Eastern Europe. These inflows funded capital expenditure of the year (€9.2 billion) and the payment of the final dividend 2015 and the 2016 interim dividend to Eni’s shareholders (for a total amount of €2.88 billion). The reduction in net borrowings was also due to other inflows relating to investing activities (€0.3 billion) and the fact that the financial assets (€0.57 billion) held by the Group insurance company are no longer committed to funding the loss provisions and therefore have been netted against finance debt in determining the Group’s net borrowings. These positives were offset by negative change in fair value of securities held for trading (down €0.3 billion) which are netted against net borrowings. A normalized measure of the cash flow from operating activities was €8.3 billion, calculated by excluding the negative effect of the Val d’Agri shutdown (€0.2 billion), a reclassification of certain receivables for investing activities to trading receivables (€0.3 billion), while including changes in working capital due to the sale of a 40% interest in Zohr (€0.1 billion). This normalized cash flow funded approximatly 95% of the capex of the year, which reduced from €9.2 billion to €8.7 billion when deducting the expected reimbursement of past capex related to the divestment of a 40% interest in the Zohr project (€0.5 billion).
Cash flow from operations was also influenced by a larger amount of receivables due beyond the end of the reporting period, being transferred to financing institutions compared to the amount sold at the end of the previous reporting period (approximately €1 billion).
Compared to September 30, 2016, net borrowings decreased by €1.23 billion due to the robust cash generation of the fourth quarter of €3.25 billion, which funded capital expenditure of the period (€2.25 billion) generating a surplus. A larger amount of receivables due beyond the end of the reporting period were sold to financing institutions compared to the amount sold at the end of the previous reporting period by approximately €700 million.
As of December 31, 2016, the ratio of net borrowings to shareholders’ equity including non-controlling interest – leverage6 – decreased to 0.28, compared to 0.29 as of December 31, 2015. This change was due to lower net borrowings which offset a €4 billion reduction in total equity, driven by the negative result of the period, the derecognition of the Saipem non-controlling interest and dividend distributions to Eni shareholders.
It is worth mentioning the recovery in Group leverage to 0.28 from 0.32 on September 30, 2016, due to the robust cash generation of the fourth quarter 2016 and the increase in total equity driven by the positive result of the period and positive foreign currency translation differences (approximately €2.3 billion).
The Board of Directors intends to submit a proposal for distributing a dividend of €0.80 per share7 (€0.80 in 2015) at the Annual Shareholders’ Meeting convened for April 13, 2017. Included in this annual payment is €0.40 per share paid as interim dividend in September 2016. The balance of €0.40 per share is payable to shareholders on April 26, 2017, the ex-dividend date being April 24, 2017.
Eni signed two agreements with Bp and Rosneft for the disposal of a 40% interest in the giant discovery Zohr, located in the operated block of Shoruk (Eni 100%) off Egypt. These transactions confirm the effectiveness of Eni’s “dual exploration model”, which simultaneously targets the fast-track development of discovered resources, while reducing stakes retained in exploration leases in order to monetize in advance part of the discovered volumes and reduce expenditures in development process.
These agreements have economic efficacy from January 1, 2016 and contemplate the reimbursement to Eni of capex incurred until the closing date. The new partners have the option to acquire a further 5% stake at the same terms defined in the agreements.
The first transaction closed on February 2017 following approval by the Egyptian authorities; the second one is expected to close by the first half of 2017. The total consideration of the deal amounts to approximately €2 billion as of January 1, 2017, including the reimbursement of costs incurred by Eni in 2016.
Eni reported positive performances when comparing to the corresponding period of 2015:
As part of its strategy designed to evolve the Company’s business model towards a low-carbon environment, Eni intends to develop renewable energy projects in its countries of operations. In 2016, Eni selected and launched a number of industrial initiatives on a large scale in Italy and abroad.
- The “Italy project” plans to build facilities, mainly in the solar photovoltaic business, in owned industrial areas, which are ready to use and currently lack any industrial value. Fifteen projects have been identified with an overall capacity of approximately 220 MW to be installed by 2022. The first phase of the project foresees the installation of five units: Assemini and Porto Torres in Sardinia (obtained the Final Investment Decision for both projects, while the approval is ongoing from the relevant authorities), Manfredonia in Puglia and Priolo in Sicily (FID obtained) and finally Augusta in Sicily.
- Outside Italy the company has identified a number of projects to be deployed in countries of operations considered strategic for the Company (mainly Africa and Asia) to increase Eni’s energy efficiency, the sustainability of our consumptions, as well as to improve the access to energy of local communities through a more sustainable energy mix. In December 2016 Eni obtained the FID for a development project in the upstream field BRN in Algeria.
Futhermore, a number of agreements for collaboration have been settled with Ghana, Algeria and Tunisia, to strengthen Eni’s presence in these countries and to enlarge the scope of activities.
Finally, in 2016 Eni signed strategic framework agreements with:
In 2016 Eni’s activities continued in line with the commitments foreseen in the Memorandum of Understanding, signed in 2014, with the Ministery for the Economic development and Local Authorities.
In April following the fulfilment of certain conditions, Eni began the construction activities at the Green Refinery project, being one of the pillar of the agreement. The refinery will have a capacity of 750 ktonnes/y. The conversion will leverage on the application of ecofining proprietary technology, developed and patented by Eni, to convert unconventional and second-generation raw materials into green diesel. Gela reconversion represents the first integrated and cross businesses’ project which Eni is developing in Italy to combine the needs of the business and those of the communities living in the area. The agreement foresees also: i) the launch of new hydrocarbon exploration and production activities in the Region of Sicily and the offshore area; ii) the realization of a modern hub for shipping locally produced crude oil and green fuel produced on the site; a feasibility study, to identify LNG and CNG storage and transport infrastructure in Gela, as well as the realization of a project for the production of natural latex from natural products with the relative development of the agricultural supply chain; iii) the set-up of a competence centre focused on safety issues; iv) environmental remediation activities at plants and areas that will gradually lose their industrial destination.
The Group financial outlook, its business prospects and the key industrial and profitability targets in the short and medium term are disclosed in the press release “Eni’s strategic plan 2017-2020”, which will be issued later today, available on the Company’s website eni.com and publicly disseminated as required by applicable listing standards.
This press release on the results of the full year and the fourth quarter 2016 has been prepared on a voluntary basis according to article 82-ter, Regulations on issuers (Consob Regulation No. 11971 of May 14, 1999 and subsequent amendments and inclusions). The disclosure of results and business trends on a quarterly basis is consistent with Eni’s policy to provide the market and investors with regular information about the Company’s financial and industrial performances and business prospects considering the reporting policy followed by oil&gas peers who are communicating results each quarter. Instead, the discussion about the full year results and performance of the Group complies with the listing standards set by the Italian Exchange (“Borsa Italiana”) with regard to the minimum set of disclosures of press release about the approval of statutory financial statements by listed companies’ boards.
Results and cash flow are presented for the fourth and the third quarter of 2016 and the full year of 2016, for the fourth quarter and the full year of 2015. Information on the Company’s financial position relates to end of the periods as of December 31, 2016, September 30, 2016 and December 31, 2015. Accounts set forth herein have been prepared in accordance with the evaluation and recognition criteria set by the International Financial Reporting Standards (IFRS) issued by the International Accounting Standards Board (IASB) and adopted by the European Commission according to the procedure set forth in Article 6 of the European Regulation (CE) No. 1606/2002 of the European Parliament and European Council of July 19, 2002. These criteria are unchanged from the Interim Consolidated Financial Report as of June 30, 2016, which investors are urged to read.
Continuing and discontinued operations in Eni’s financial statements 2016
Effective January 1, 2016, Eni Group is no more engaged in the Engineering & Construction segment (“E&C”), following the closing of the sale of a 12.503% stake in Saipem SpA to CDP Equity SpA on January 22, 2016. Concurrently, a shareholder agreement between Eni and CDP Equity SpA entered into force, which established the joint control of the two parties over the target entity. Those transactions triggered loss of control of Eni over Saipem. The retained interest of 30.55% in the former subsidiary has been recognized as an investment in an equity-accounted joint venture with an initial carrying amount aligned to the share price at the closing date of the transaction (€4.2 per share, equal to €564 million) recognizing a loss through profit of €441 million. Considering the pro-quota share capital increase of Saipem subscribed by Eni, the initial carrying amount of the investment amounted to €1,614 million. At the end of February 2016, Saipem reimbursed intercompany loans owed to Eni (€5,818 million as of December 31, 2015) by using the proceeds from the share capital increase and new credit facilities from third-party financing institutions.
Eni’s Chemical business, managed by the wholly-owned subsidiary Versalis, has been reclassified as continuing operations, with retroactive effects as of December 31, 2015. In accordance with IFRS 5, Versalis has ceased to be classified as discontinued operations due to termination of the negotiations with US-based SK hedge fund, who had shown an interest in acquiring a majority stake in Versalis. Eni’s Annual Report 2015 was prepared accounting this business as discontinued operations. Consequently, Eni’s management reinstated the criteria of the continuing use to evaluate Versalis by aligning its book value to the recoverable amount, given by the higher of fair value less cost to sell and value-in-use. Conversely, under IFRS 5 Versalis was measured at the lower of its carrying amount and fair value less cost to sell. This amendment in Versalis evaluation marginally affected the opening balance of Eni’s consolidated net assets (an increase of €294 million) and was neutral on the Group’s net financial position. For more information about the criteria of the continuing use to evaluate Versalis in Eni consolidated accounts 2016, see Eni Interim Consolidated Report as of June 30, 2016 (the section Basis of preparation in Notes to the Consolidated Interim Financial Statements). The results of Versalis have been aggregated with those of R&M, in the reportable segment “R&M and Chemicals” because the two segments exhibit similar economic characteristics.
Successful effort method (SEM)
Effective January 1, 2016, management modified on voluntary basis, the criterion to recognize exploration expenses adopting the accounting of the successful-effort-method (SEM). The successful-effort method is largely adopted by oil&gas companies, to which Eni is increasingly comparable given the recent re-focalization of the Group activities on its core upstream business.
Under the SEM, geological and geophysical exploration costs are recognized as an expense as incurred. Costs directly associated with an exploration well are initially capitalized as an unproved tangible asset until the drilling of the well is complete and the results have been evaluated. If potentially commercial quantities of hydrocarbons are not found, the exploration well costs are written off. If hydrocarbons are found and, subject to further appraisal activity, are likely to be capable of commercial development, the costs continue to be carried as an unproved asset. If it is determined that development will not occur then the costs are expensed. Costs directly associated with appraisal activity undertaken to determine the size, characteristics and commercial potential of a reservoir following the initial discovery of hydrocarbons are initially capitalized as an unproved tangible asset. When proved reserves of oil and natural gas are determined and development is approved by management, the relevant expenditure is transferred to proved property.
In accordance to IAS 8 “Accounting policies, Changes in accounting estimates and Errors”, the SEM application is a voluntary change in accounting policy explained by the alignment with an accounting standard largely adopted by oil&gas companies and as such it has been applied retrospectively.
The retrospective application of the SEM has required adjustment of the opening balance of the retained earnings and other comparative amounts as of January 1, 2014. Specifically, the opening balance of the carrying amount of property, plant and equipment was increased by €3,524 million, intangible assets by €860 million and the retained earnings by €3,001 million. Other adjustments related to deferred tax liabilities and other minor line items. More details are available on the “Basis of presentation” in the “Notes to the Consolidated Financial Statements” of Eni’s Interim Consolidated Report as of June 30, 2016.
The table below sets forth the amounts of the comparative periods 2015 which have been restated following the adoption of the SEM and the accounting of Versalis as part of the continuing operations.
Non-GAAP financial measures and other alternative performance indicators disclosed throughout this press release are accompanied by explanatory notes and tables in line with guidance provided by ESMA guidelines on alternative performance measures (ESMA/2015/1415), published on October 5, 2015. For further information see the section “Alternative performance measures (Non-GAAP measures)” of this press release.
Eni’s Chief Financial Officer, Massimo Mondazzi, in his position as manager responsible for the preparation of the Company’s financial reports, certifies that data and information disclosed in this press release correspond to the Company’s evidence and accounting books and records, pursuant to rule 154-bis paragraph 2 of Legislative Decree No. 58/1998.
1 Adjusted Earnings before interest and taxes.
2 In this press release, adjusted results from continuing operations of the comparative periods 2015 are reported on a standalone basis, thus excluding the results of Saipem. An equivalent performance measure has been provided for net cash provided by operating activities. Adjusted results and standalone results are Non-GAAP measures; for further information see page 25.
3 Net cash provided by operating activities. For an explanation of the items of the cash flow normalization see page 15 in the section “Summarized Group Cash Flow Statement”.
4 Net of the Zohr reimbursement; see page 15.
5 Details on net borrowings are furnished on page 33.
6 Non-GAAP financial measures and other alternative performance indicators disclosed throughout this press release are accompanied by explanatory notes and tables in line with guidance provided by ESMA guidelines on alternative performance measures (ESMA/2015/1415), published on October 5, 2015. For further information see the section “Non-GAAP measures” of this press release. See pages 25 and subsequent.
7 Dividends are not entitled to tax credit and, depending on the receiver, are subject to a withholding tax on distribution or are partially cumulated to the receiver’s taxable income.
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This press release, in particular the statements under the section “Outlook”, contains certain forward-looking statements particularly those regarding capital expenditure, development and management of oil and gas resources, dividends, allocation of future cash flow from operations, future operating performance, gearing, targets of production and sales growth, new markets and the progress and timing of projects. By their nature, forward-looking statements involve risks and uncertainties because they relate to events and depend on circumstances that will or may occur in the future. Actual results may differ from those expressed in such statements, depending on a variety of factors, including the timing of bringing new fields on stream; management’s ability in carrying out industrial plans and in succeeding in commercial transactions; future levels of industry product supply; demand and pricing; operational issues; general economic conditions; political stability and economic growth in relevant areas of the world; changes in laws and governmental regulations; development and use of new technology; changes in public expectations and other changes in business conditions; the actions of competitors and other factors discussed elsewhere in this document. Due to the seasonality in demand for natural gas and certain refined products and the changes in a number of external factors affecting Eni’s operations, such as prices and margins of hydrocarbons and refined products, Eni’s results from operations and changes in net borrowings for the fourth quarter of the year cannot be extrapolated on an annual basis.
The all sources reserve replacement ratio disclosed elsewhere in this press release is calculated as ratio of changes in proved reserves for the year resulting from revisions of previously reported reserves, improved recovery, extensions, discoveries and sales or purchases of minerals in place, to production for the year. A ratio higher than 100% indicates that more proved reserves were added than produced in a year. The Reserve Replacement Ratio is a measure used by management to indicate the extent to which production is replaced by proved oil and gas reserves. The Reserve Replacement Ratio is not an indicator of future production because the ultimate development and production of reserves is subject to a number of risks and uncertainties. These include the risks associated with the successful completion of large-scale projects, including addressing ongoing regulatory issues and completion of infrastructure, as well as changes in oil and gas prices, political risks and geological and other environmental risks.
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Throughout much of its history, the United States has imported more petroleum (which includes crude oil, refined petroleum products, and other liquids) than it has exported. That status changed in 2020. The U.S. Energy Information Administration’s (EIA) February 2021 Short-Term Energy Outlook (STEO) estimates that 2020 marked the first year that the United States exported more petroleum than it imported on an annual basis. However, largely because of declines in domestic crude oil production and corresponding increases in crude oil imports, EIA expects the United States to return to being a net petroleum importer on an annual basis in both 2021 and 2022.
EIA expects that increasing crude oil imports will drive the growth in net petroleum imports in 2021 and 2022 and more than offset changes in refined product net trade. EIA forecasts that net imports of crude oil will increase from its 2020 average of 2.7 million barrels per day (b/d) to 3.7 million b/d in 2021 and 4.4 million b/d in 2022.
Compared with crude oil trade, net exports of refined petroleum products did not change as much during 2020. On an annual average basis, U.S. net petroleum product exports—distillate fuel oil, hydrocarbon gas liquids, and motor gasoline, among others—averaged 3.2 million b/d in 2019 and 3.4 million b/d in 2020. EIA forecasts that net petroleum product exports will average 3.5 million b/d in 2021 and 3.9 million b/d in 2022 as global demand for petroleum products continues to increase from its recent low point in the first half of 2020.
Source: U.S. Energy Information Administration, Short-Term Energy Outlook (STEO), February 2021
EIA expects that the United States will import more crude oil to fill the widening gap between refinery inputs of crude oil and domestic crude oil production in 2021 and 2022. U.S. crude oil production declined by an estimated 0.9 million b/d (8%) to 11.3 million b/d in 2020 because of well curtailment and a drop in drilling activity related to low crude oil prices.
EIA expects the rising price of crude oil, which started in the fourth quarter of 2020, will contribute to more U.S. crude oil production later this year. EIA forecasts monthly domestic crude oil production will reach 11.3 million b/d by the end of 2021 and 11.9 million b/d by the end of 2022. These values are increases from the most recent monthly average of 11.1 million b/d in November 2020 (based on data in EIA’s Petroleum Supply Monthly) but still lower than the previous peak of 12.9 million b/d in November 2019.
In the past week, crude oil prices have surged to levels last seen over a year ago. The global Brent benchmark hit US$63/b, while its American counterpart WTI crested over the US$60/b mark. The more optimistic in the market see these gains as a start of a commodity supercycle stemming from market forces pent-up over the long Covid-19 pandemic. The more cynical see it as a short-term spike from a perfect winter storm and constrained supply. So, which is it?
To get to that point, let’s examine how crude oil prices have evolved since the start of the year. On the consumption side, the market is vacillating between hopeful recovery and jittery reactions as Covid-19 outbreaks and vaccinations lent a start-stop rhythm to consumption trends. Yes, vaccination programmes were developed at lightning speed; and even plenty of bureaucratic hiccoughs have not hampered a steady rollout across the globe. In the UK, more than 20% of adults have received at least one dose of the vaccines, with the USA not too far behind. Israel has vaccinated more than 75% of its population, and most countries should be well into their own programmes by the end of March. That acceleration of vaccinations has underpinned expectations of higher oil demand, with hopes that people will begin to drive again, fly again and buy again. But those hopes have been occasionally interrupted by new Covid-19 clusters detected and, more worryingly, new mutations of the virus.
Against this hopeful demand picture, supply has been managed. Squabbling among the OPEC+ club has prevented a more aggressive approach to managing supply than kingpin Saudi Arabia would like, but OPEC+ has still managed to hold itself together to placate the market that crude spigots will remain restrained. And while the UAE has successfully shifted OPEC+ quota plan for 2021 from quarterly adjustments to monthly, Saudi Arabia stepped into the vacuum to stamp its authority with a voluntary 1 million barrels per day cut. The market was impressed.
That combination of events over January was enough to move Brent prices from the low US$50/b level to the upper US$50/b range. However, US$60/b remained seemingly out of reach. It took a heavy dusting of snow across Texas to achieve that.
Winter weather across the northern hemisphere seemed harsher than usual this year. Europe was hit by two large continent-wide storms, while the American Northeast and Pacific Northwest were buffeted with quite a few snowstorms. Temperatures in East Asia were fairly cold too, which led to strong prices for natural gas and LNG to keep the population warm. But it was a major snowstorm that swept through the southern United States – including Texas – that had the largest effect on prices. Some areas of Texas saw temperatures as low as -18 degrees Celsius, while electricity demand surged to the point where grids failed, leaving 4.3 million people without power. A national emergency was declared, with over 150 million Americans under winter storm warning conditions.
For the global oil complex, the effects of the storm were also direct. Some of the largest oil refineries in the world were forced to shut down due to the Arctic conditions, further disrupting power and fuel supplies. All in all, over 3 mmb/d of oil processing capacity had to be idled in the wake of the storm, including Motiva’s Port Arthur, ExxonMobil’s Baytown and Marathon’s Galveston Bay refineries. And even if the sites were still running, they would have to contend to upstream disruptions: estimates suggest that crude oil production in the prolific Permian Basin dropped by over a million barrels per day due to power outages, while several key pipelines connecting Cushing, Oklahoma to the Texas Gulf Coast were also forced to shutter.
That perfect storm was enough to send crude prices above the US$60/b level. But will it last? The damage from the Texan snowstorm has already begun to abate, and even then crude prices did not seem to have the appetite to push higher than US$63/b for Brent and US$60/b for WTI.
Instead, the key development that should determine the future range for crude prices going into the second quarter of 2021 will be in early March, when the OPEC+ club meets once again to decide the level of its supply quotas for April and perhaps beyond. The conundrum facing the various factions within the club is this: at US$60/b, crude oil prices are not low enough to scare all members in voting for unanimous stricter quotas and also not high enough to rescind controlled supply. Instead, prices are at a fragile level where arguments can be made both ways. Russia is already claiming that global oil markets are ‘balanced’, while Saudi Arabia is emphasising the need for caution in public messaging ahead of the meeting. Saudi Arabia’s voluntary supply cut will also expire in March, setting up the stage for yet another fractious meeting. If a snow overrun Texans was a perfect storm to push crude prices to a 13-month high, then the upcoming OPEC+ meeting faces another perfect storm that could negate confidence. Which will it be? The answer lies on the other side of the storm.
Much like the year itself, the final quarter of 2020 proved to be full of shocks and surprises… at least in terms of financial results from oil and gas giants. With crude oil prices recovering on the back of a concerted effort by OPEC+ to keep a lid on supply, even at the detriment of their market share, the fourth quarter of 2020 was supposed to be smooth sailing. The tailwind of stronger crude and commodity prices, alongside gradual demand recovery, was expected to have smoothen out the revenue and profit curves for the supermajors.
That didn’t happen.
Instead, losses were declared where they were not expected. And where profits were to be had, they were meagre in volume. And crucially, a deeper dive into the financial results revealed worrying trends in the cash flow of several supermajors, calling into question the ability of these giants to continue on their capital expenditure and dividend plans, and the risks of resorting to debt financing in order to appease investors and yet also continue expanding.
Let’s start with the least surprising result of all. For months, ExxonMobil had been signalling that it would be taking a massive writedown on its upstream assets in Q4 2020, which could lead to a net loss for the quarter and the year. Unlike its peers, ExxonMobil had resisted making writedowns on the value of its crude-producing assets earlier in 2020. At the time, it stated that it had already built caution in the value assessments of those assets, reflecting ‘fair value’; not so long after that bold statement, ExxonMobil has been forced to backtrack and make a US$20.2 billion downward adjustment. Unusually, that meant that non-cash impairments aside, ExxonMobil actually eked out a tiny profit of US$110 million for the quarter on the strength of margins in the chemicals segment, but a full year loss of US$22.4 billion: the first ever annual loss since Exxon and Mobil merged in 1998. This was better than expected by Wall Street analysts, who would also be cheering the formation of ExxonMobil Low Carbon Solutions, in which the group would pump some US$3 billion through 2025 to reduce its greenhouse gas emissions by 20% from 2016 levels. That acknowledgement of a carbon neutral future is still far less ambitious than its European counterparts, but is a clear sign that ExxonMobil is starting to take the climate change element of its business more seriously.
If ExxonMobil managed to surprise in a good way, then its closest American rival did the opposite. Chevron had been outperforming ExxonMobil in quarterly results for a while now, but in Q4 2020 retreated with a net loss of US$665 million. That was narrower than the US$6.6 billion loss declared in Q4 2019, but still a shock since analysts were expecting a narrow profit. Calling 2020 ‘a year like no other’, the headwinds facing Chevron in Q4 2020 were the same facing all majors and supermajors, despite gains in crude prices, refining margins and fuel sales were still soft. Chevron’s cash flow was also a concern – as was ExxonMobil’s – which prompted chatter that the two direct descendants of JD Rockefeller’s Standard Oil were considering a merger. If so, then there is at least alignment on the climate topic: Chevron is also following the trail blazed by European supermajors in embracing a carbon neutral future, with CEO Michael Wirth conceding that Chevron may ‘not be an oil-first company in 2040’.
On the European side of the pond, that same theme of lowered downstream performance dragging down overall performance continued. But unlike the US supermajors, the likes of Shell, BP and Total were somewhat insulated from the Covid-19 blows at the peak of the pandemic as their opportunistic trading divisions capitalised on the wild swings in crude and fuel prices. That factor is now absent, with crude prices taking on a steady upward curve. That’s good for the rest of their businesses, but bad for trading, which thrives on uncertainty and volatility. And so BP reported a Q4 net profit of US$115 million, Shell followed with a Q4 net profit of US$393 million and Total closed out the earning season with industry-beating Q4 net profit of US$1.3 billion, above market expectations.
The softness of the financials hasn’t stopped dividend payouts, but has also been used by Europe’s Big Oil to set the tone for the next few decades of their existence. Total and BP paid a hefty premium to secure rights to build the next generation of UK wind farms; Total joined the Maersk-McKinney Moller Center for Zero Carbon Shipping to develop carbon neutral shipping solutions and splashed out on acquiring 2.2 GW of solar power projects in Texas; BP signed a strategic collaboration agreement with Russia’s Rosneft to develop new low carbon solutions; and aircraft carrier KLM took off with the first flight powered by synthetic kerosene that was developed by Shell through carbon dioxide, water and renewables. That’s a lot of a groundwork laid for the future where these giants can be carbon neutral by 2050.
The message from Q4 seems clear. Big Oil has barely begun its recovery from the Covid-19 maelstrom, and the road to a new normal remains long and painful. But this is also an opportunity to pivot; to set a new destination that is no longer business-as-usual, but embraces zero carbon ambitions. Even the American supermajors are slowly coming around, while the European continues to lead. Will majors in Asia, Latin America and Africa/Middle East follow? Let’s see what that attitude will bring over this new decade.
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