Looking ahead, the IMF’s global economic outlook indicates a slightly lower outlook for global economic growth. Additionally, according to the IEA, moderate oil price levels at the beginning of 2019 could create around 1.4 million b/d of additional demand growth in 2019. If OPEC members and co-operating non-OPEC resource holders, such as Russia, successfully implement the December 2018 agreement, then demand growth and production declines from existing operations would have to be balanced by production growth from non-OPEC countries, mostly from the USA. As a consequence, markets could tighten, and prices could rise if supply growth from the USA moderates. Postponements and cancellations of new supply projects over the last few years could lead to further market tightening in the next few years, given the long lead time of many of these projects. In such a scenario, we believe that the average Brent crude oil price could be 10% to 40% higher in 2022 than the 2018 average.

On the other hand, we believe that the price environment could weaken if OPEC and the non-OPEC resource holders abandon their production cuts, global economic growth slows, or if other non-OPEC producers, such as US shale producers, effectively deliver more and cheaper oil to the market. In such a scenario, we believe that the average Brent crude oil price could be 10% to 30% lower in 2022 than the 2018 average.

NATURAL GAS

We estimate global gas demand to have grown by about 3.2% in 2018, which is higher than the average annual growth rate of 2.4% since the beginning of the century. A combination of weather conditions, implementation of new policies such as the partial substitution of coal by gas-fired power generation in China, and global economic growth led to an increase in demand in most regions.

Global liquefied natural gas (LNG) imports grew by 28 million tonnes (9.6%) in 2018. LNG demand growth was supported by weather conditions, lower nuclear power generation and the start-up of new regasification capacity in Asia. China and India alone increased their regasification capacity by 19% and 33% from 2017 respectively, equal to 21 million tonnes per annum, in total. Supply growth was primarily driven by the start-up of new projects in Australia, the USA and Russia. The majority of additional LNG supply was absorbed by Asia, offsetting declines in the Middle East and North Africa.

Natural gas prices can vary from region to region.

In the USA, the natural gas price at the Henry Hub averaged $3.1 per million British thermal units (MMBtu) in 2018, 3% higher than in 2017, and traded in a range of $2.5-4.9/MMBtu. There was some downward pressure on prices due to strong gas supply growth, which averaged 11% higher than in 2017, helped by higher oil prices and new gas pipeline capacity. However, gas prices were also supported by a range of other factors, such as below-normal storage inventory levels, and demand growth due to colder than normal weather in the second half of 2018, the completion of LNG liquefaction projects, increased exports to Mexico by pipeline and US industrial demand.

In Europe, natural gas prices were higher than in 2017. The average price at the UK National Balancing Point (NBP) was 33% higher in 2018. At the main continental gas trading hubs – in the Netherlands, Belgium and Germany – prices were also stronger, as reflected by stronger Dutch Title Transfer Facility (TTF) prices. European gas prices were supported by record prices for carbon dioxide (CO2) allowances (EUAs) which averaged €16/tCO2 in 2018

compared to €6/tCO2 in 2017, resulting in higher preference for gas over coal in power generation. Gas prices were also supported by lower nuclear power output, particularly in Belgium and Spain, lower than normal temperatures early in the year, and competition from North-East Asian markets for LNG supplies for storage replenishment ahead of winter.

We also produce and sell natural gas in regions where supply, demand and regulatory circumstances differ markedly from those in the USA or Europe. Long-term contracted LNG prices in the Asia-Pacific region generally increased in 2018 as they are predominantly indexed to the price of Japan Customs-cleared Crude, which has increased in line with global oil prices. North Asia spot prices (reflected by the Japan Korea Marker) also increased due to relatively strong demand, particularly from China.

Looking ahead, we expect gas markets in North America, Europe and Asia Pacific to be well supplied over the next few years, despite our expectation of LNG demand growth in Asia. Price developments are very uncertain and dependent on many factors.

In the USA, Henry Hub gas prices may increase over the next few years due to increasing demand from LNG exports, exports to Mexico by pipeline, and US residential/industrial users. On the other hand, increasing availability of low-cost natural gas and oil, combined with technological improvements, could continue to place pressure on natural gas prices. Due to such uncertainty, we believe that average Henry Hub gas prices could be between 10% lower to 30% higher by 2022 than the 2018 average. In Europe, we believe gas prices will be increasingly influenced by the cost of LNG imports from the USA. We believe that the price at the UK NBP may average between 30% lower and 30% higher by 2022 than the 2018 average. In the Asia Pacific region, gas prices are expected to continue to be strongly influenced by oil prices, but also increasingly by Henry Hub gas prices. By 2022, we believe that the price of LNG delivered under contract to the Asia-Pacific market may average between 30% lower and 30% higher than the 2018 average.

CRUDE OIL AND NATURAL GAS PRICE ASSUMPTIONS

Our ability to deliver competitive returns and pursue commercial opportunities ultimately depends on the accuracy of our price assumptions (see “Risk factors” on page 15). The range of possible future crude oil and natural gas prices used in project and portfolio evaluations is determined after a rigorous assessment of short, medium and long-term market drivers. Historical analyses, trends and statistical volatility are considered in this assessment, as are analyses of market fundamentals such as possible future economic conditions, geopolitics, actions by OPEC and other major resource holders, production costs and the balance of supply and demand. Sensitivity analyses are used to test the impact of low-price drivers, such as economic weakness, and high-price drivers, such as strong economic growth and low investment in new production capacity. Short-term events, such as relatively warm winters or cool summers, affect demand. Supply disruptions, due to weather or political instability, contribute to price volatility. See also Note 8 to the “Consolidated Financial Statements” on page 188.

REFINING MARGINS

Industry gross refining margins were lower on average in 2018 than in 2017 in each of the key refining hubs of Europe, Singapore and the USA. Oil products demand growth has slowed in line with global economic growth. Periods of high crude prices led to reductions in oil products demand. Refinery capacity additions, especially in the Middle East and Asia, combined with tempered demand growth have led to generally lower refinery utilisations. Refinery activity continued to be low in Latin America.

Looking forward, we believe refinery margins may be impacted by the introduction of the new International Maritime Organization shipping fuel specification in 2020.

PETROCHEMICAL MARGINS

Cracker industry margins fell in all three main regions in 2018. Asian naphtha cracker margins fell sharply in the fourth quarter, amid continuing concerns over the potential impact of US tariffs, while US ethane cracker margins came under pressure from new cracker unit start-ups. Supported by healthy European demand, European naphtha cracker margins decreased the least during 2018.

The outlook for petrochemical margins in 2019 and beyond depends on supply and demand balances and feedstock costs. Demand for petrochemicals is closely linked to economic growth. Product prices reflect prices of raw materials, which are closely linked to crude oil and natural gas prices. The balance of these factors will drive margins.

The statements in this “Market overview” section, including those related to our price forecasts, are forward-looking statements based on management’s current expectations and certain material assumptions and, accordingly, involve risks and uncertainties that could cause actual results, performance or events to differ materially from those expressed or implied herein. See “About this Report” on pages 05-06 and “Risk factors” on pages 15-20.

EARNINGS 2018-2017

Income for the period was $23,906 million in 2018, compared with $13,435 million in 2017. After current cost of supplies adjustment, total segment earnings were $24,364 million in 2018, compared with $12,471 million in 2017.

Earnings on a current cost of supplies basis (CCS earnings) exclude the effect of changes in the oil price on inventory carrying amounts, after making allowance for the tax effect. The purchase price of volumes sold in the period is based on the current cost of supplies during the same period, rather than on the historic cost calculated on a first-in, first-out (FIFO) basis. Therefore, when oil prices are decreasing, CCS earnings are likely to be higher than earnings calculated on a FIFO basis and, when prices are increasing, CCS earnings are likely to be lower than earnings calculated on a FIFO basis.

Integrated Gas earnings in 2018 were $11,444 million, compared with $5,078 million in 2017. The increase was mainly driven by higher realised oil, gas, and liquefied natural gas (LNG) prices, higher gains on divestments, increased contributions from LNG trading, the impact of fair value accounting of commodity derivatives, and higher production. These effects were partly offset by the absence of a gain from the strengthening Australian dollar on a deferred tax position in 2017 and by higher operating expenses. See “Integrated Gas” on pages 29-30.

Upstream earnings in 2018 were $6,798 million, compared with $1,551 million in 2017. The increase was mainly driven by higher realised oil and gas prices, lower impairment charges, the absence of a charge as a result of US tax reform legislation in 2017, and lower well write-offs. This was partly offset by the movements in deferred tax positions, lower gains on divestments, lower production, and a charge related to the impact of the weakening Brazilian real on a deferred tax position. See “Upstream” on pages 36-37.

Downstream earnings in 2018 were $7,601 million, compared with $8,258 million in 2017. The decrease was mainly driven by higher operating expenses, unfavourable exchange rate effects, and lower realised base chemicals and refining margins. This was partly offset by higher realised marketing margins, lower charges related to provisions, the impact of fair value accounting of commodity derivatives and higher gains on divestments. There was also a charge in 2017 as a result of US tax reform legislation. See “Downstream” on pages 53-54.

Corporate earnings in 2018 were a loss of $1,479 million, compared with a loss of $2,416 million in 2017. The lower loss was mainly driven by lower net foreign exchange losses and net interest expense, partially offset by higher costs. There was also a charge in 2017 as a result of US tax reform legislation. See “Corporate” on page 61.

EARNINGS 2017-2016

Income for the period was $13,435 million in 2017, compared with $4,777 million in 2016. After current cost of supplies adjustment, total segment earnings were $12,471 million in 2017, compared with $3,692 million in 2016. BG Group plc (BG) was consolidated within Shell’s results with effect from February 2016 following its acquisition.

Integrated Gas earnings in 2017 were $5,078 million, compared with $2,529 million in 2016. The increase was mainly driven by higher realised oil, gas, and LNG prices, as well as the impact of the strengthening Australian dollar on a deferred tax position, and lower impairment charges. These effects were partly offset by the impacts in 2017 of a charge for fair value accounting of commodity derivatives, a charge as a result of US tax reform legislation, and by lower liquids production partially offset by higher LNG liquefaction volumes.

Upstream earnings in 2017 were $1,551 million, compared with a loss of $3,674 million in 2016. The improvement was mainly driven by higher realised oil and gas prices. Higher gains on divestments and lower depreciation charges were partly offset by higher impairment charges. Overall, there were higher taxation charges. Beneficial movements in deferred tax positions were more than offset by a charge in 2017 as a result of US tax reform legislation and the absence of a gain related to the impact of a strengthening Brazilian real on a deferred tax position in 2016.

Downstream earnings in 2017 were $8,258 million, compared with $6,588 million in 2016. The increase was mainly driven by improved refining and chemicals industry conditions, the impact of fair value accounting of commodity derivatives, and lower taxation, redundancy and impairment charges. This was partly offset by lower gains on divestments and higher depreciation charges.  

Corporate earnings in 2017 were a loss of $2,416 million, compared with a loss of $1,751 million in 2016. The higher loss was mainly driven by higher interest expense and net foreign exchange losses, partly offset by lower operating expenses. There was also a charge in 2017 as a result of US tax reform legislation.

production available for sale

Oil and gas production available for sale in 2018 was 1,338 million barrels of oil equivalent (boe), or 3,666 thousand boe per day (boe/d), compared with 1,338 million boe, or 3,664 thousand boe/d, in 2017. In 2018, increased production from new field start-ups and ramp-ups, as well as lower maintenance activity was offset by the impact of divestments and field declines.

[A] See “Oil and gas information” on pages 49-50.
[B] Natural gas volumes are converted into oil equivalent using a factor of 5,800 scf per barrel.

PROVED RESERVES

The proved oil and gas reserves of Shell subsidiaries and the Shell share of the proved oil and gas reserves of joint ventures and associates are summarised in “Oil and gas information” on pages 44-46 and set out in more detail in “Supplementary information – oil and gas (unaudited)” on pages 215-226.

Before taking production into account, our proved reserves increased by 733 million boe in 2018. This comprised increases of 1,337 million boe from Shell subsidiaries and decreases of 604 million boe from the Shell share of joint ventures and associates, mainly related to the Groningen field. The increase from Shell subsidiaries included 997 million boe from revisions and reclassifications, 474 million boe from extensions and discoveries, and 42 million boe from improved recovery, partly offset by net sales of minerals in place of 175 million boe.

In 2018, total oil and gas production was 1,388 million boe, of which 1,338 million boe was available for sale and 50 million boe was consumed in operations. Production available for sale from subsidiaries was 1,179 million boe and 43 million boe was consumed in operations. The Shell share of the production available for sale of joint ventures and associates was 159 million boe and 7 million boe was consumed in operations.

Accordingly, after taking production into account, our proved reserves decreased by 655 million boe in 2018, to 11,578 million boe at December 31, 2018, with an increase of 117 million boe from subsidiaries and a decrease of 771 million boe from the Shell share of joint ventures and associates.

CAPITAL INVESTMENT AND OTHER INFORMATION

Capital investment was $24.8 billion in 2018, compared with $24.0 billion in 2017.

Divestments were $7.1 billion in 2018, compared with $17.3 billion in 2017. Operating expenses increased by $1.2 billion in 2018, to $39.3 billion.

Our return on average capital employed (ROACE) increased to 9.4%, compared with 5.8% in 2017, mainly driven by a higher income in 2018.

Gearing was 20.3% at the end of 2018, compared with 25.0% at the end of 2017, driven by debt repayments and an increased cash balance in 2018. With effect from 2018, the net debt calculation has been amended and the prior period comparative has been revised. See Note 14 to the “Consolidated Financial Statements” on page 191.

SIGNIFICANT ACCOUNTING ESTIMATES AND JUDGEMENTS

See Note 2 to the “Consolidated Financial Statements” on pages 172-181.

LEGAL PROCEEDINGS

See Note 25 to the “Consolidated Financial Statements” on pages 211-213.

These indicators enable management to evaluate Shell’s performance against its strategy and operating plans. Those which are used in the determination of Executive Directors’ remuneration are asterisked below and on the following page. See “Directors’ Remuneration Report” on pages 119-147.

FINANCIAL PERFORMANCE INDICATORS

Total shareholder return (TSR) is the difference between the share price at the beginning of the year and the share price at the end of the year (each averaged over 90 days), plus gross dividends delivered during the calendar year (reinvested quarterly), expressed as a percentage of the share price at the beginning of the year (averaged over 90 days). The data used are a weighted average in dollars for A and B shares. The TSRs of major publicly-traded oil and gas companies can be compared directly, providing a way to determine how we are performing in relation to our industry peers.

Cash flow from operating activities is the total of all cash receipts and payments associated with our sales of oil, gas, chemicals and other products. The components that provide a reconciliation from income for the period are listed in the “Consolidated Statement of Cash Flows”. This indicator reflects our ability to generate cash to service and reduce our debt and for distributions to shareholders and investments. See “Liquidity and capital resources” on page 63.   

Free cash flow is the sum of “Cash flow from operating activities” and “Cash flow from investing activities”, which are listed in the “Consolidated Statement of Cash Flows”. This indicator is used to evaluate cash available for financing activities, including dividend payments, after investment in maintaining and growing our business. See “Non-GAAP measures reconciliations” on page 264.

Return on average capital employed (ROACE) is defined as income for the period, adjusted for after-tax interest expense, as a percentage of average capital employed during the year. Capital employed is the sum of total equity and total debt. ROACE measures the efficiency of our utilisation of the capital that we employ and is a common measure of business performance. See “Summary of results” on page 24 and “Non-GAAP measures reconciliations” on page 264.

Earnings on a current cost of supplies basis (CCS earnings) is the income for the period, adjusted for the after-tax effect of oil-price changes on inventory. Segment earnings presented on a current cost of supplies basis is the earnings measure used by the Chief Executive Officer for the purposes of making decisions about allocating resources and assessing performance. See “Summary of results” on page 24 and “Non-GAAP measures reconciliations” on page 263.

CCS earnings per share, which is on a diluted basis above, is calculated by dividing CCS earnings attributable to shareholders (see “Non-GAAP measures reconciliations” on page 263) by the average number of shares outstanding over the year, increased by the average number of dilutive shares related to share-based compensation plans.

Capital investment is defined as capital expenditure and investments in joint ventures and associates, as reported in the “Consolidated Statement of Cash Flows”, plus exploration expense, excluding exploration wells written off, new finance leases and investments in Integrated Gas, Upstream and Downstream equity securities, adjusted to an accruals basis. Capital investment is a measure used to make decisions about allocating resources and assessing performance. See “Liquidity and capital resources” on page 63 and “Non-GAAP measures reconciliations” on page 263.

Gearing is defined as net debt (total debt less cash and cash equivalents) as a percentage of total capital (net debt plus total equity) at December 31. With effect from 2018, the net debt calculation includes the fair value of derivative financial instruments used to hedge foreign exchange and interest rate risks relating to debt, and associated collateral balances. The inclusion of these debt-related derivative balances reduces the volatility of net debt caused by fluctuations in foreign exchange and interest rates, and eliminates the potential impact of related collateral payments or receipts. The prior period comparative has been revised to reflect the change in net debt calculation. Gearing is a measure of the degree to which our operations are financed by debt. See “Liquidity and capital resources” on page 62.

OTHER PERFORMANCE INDICATORS

Production is the sum of all average daily volumes of unrefined oil and natural gas produced for sale by Shell subsidiaries and Shell’s share of those produced for sale by joint ventures and associates. The unrefined oil comprises crude oil, natural gas liquids, synthetic crude oil and bitumen. The gas volume is converted into equivalent barrels of oil to make the summation possible.  See “Summary of results” on page 25.

Liquefied natural gas (LNG) liquefaction volumes is a measure of the operational performance of our Integrated Gas business and LNG market demand. See “Integrated Gas” on page 29.

Refinery and chemical plant availability is the weighted average of the actual uptime of plants as a percentage of their maximum possible uptime. The weighting is based on the capital employed, adjusted for cash and non-current liabilities. This indicator is a measure of the operational excellence of our Downstream manufacturing facilities. See “Downstream” on page 53.

Project delivery reflects our capability to complete major projects on time and within budget on the basis of targets set in our annual Business Plan. Project delivery on schedule measures the percentage of projects delivered on schedule. Project delivery on budget reflects the aggregate cost against the aggregate budget for those projects.

Total recordable case frequency (TRCF) is the number of employees and contract staff injuries requiring medical treatment or time off for every million hours worked. It is a standard measure of occupational safety. See “Environment and society” on page 67.

A Tier 1 process safety event is an unplanned or uncontrolled release of any material, including non-toxic and non-flammable materials, from a process with the greatest actual consequence resulting in harm to employees and contract staff, or a neighbouring community, damage to equipment, or exceeding a threshold quantity as defined by the API Recommended Practice 754 and IOGP Standard 456. A Tier 2 process safety event is a release of lesser consequence. See “Environment and society” on page 67.

Upstream/midstream greenhouse gas (GHG) intensity is a measure of GHG emissions (direct and indirect GHG emissions associated with imported energy, excluding emissions from exported energy), expressed in metric tonnes of carbon dioxide (CO₂) equivalent, emitted into the atmosphere per metric tonne of hydrocarbon production available for sale.  See “Climate change and energy transition” on pages 77-78.

Refining GHG intensity is a measure of GHG emissions (direct and indirect GHG emissions associated with imported energy, excluding emissions from exported energy), expressed in metric tonnes of CO₂ equivalent, emitted into the atmosphere per unit of Utilized Equivalent Distillation Capacity (UEDC^TM). UEDC^TM is a proprietary metric of Solomon Associates. It is a complexity-weighted normalisation parameter that reflects the operating cost intensity of a refinery based on size and configuration of its particular mix of process and non-process facilities. See “Climate change and energy transition” on pages 77-78.

Chemicals GHG intensity is a measure of GHG emissions (direct and indirect GHG emissions associated with imported energy, excluding emissions from exported energy), expressed in metric tonnes of CO₂ equivalent, emitted into the atmosphere per metric tonne of steam cracker high value petrochemicals production. The 2017 comparative has been revised to align with the current definition (previously petrochemical production only). See “Climate change and energy transition” on pages 77-78.

Proved oil and gas reserves are the total estimated quantities of oil and gas from Shell subsidiaries and Shell’s share from joint ventures and associates that geoscience and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs, at December 31, under existing economic conditions, operating methods and government regulations. Gas volumes are converted into barrels of oil equivalent (boe) using a factor of 5,800 standard cubic feet per barrel. Reserves are crucial to an oil and gas company, since they constitute the source of future production. Reserves estimates are subject to change due to a wide variety of factors, some of which are unpredictable. See “Risk factors” on pages 15-16, “Summary of results” on page 25, “Oil and gas information” on pages 44-46 and “Supplementary information – oil and gas (unaudited)” on pages 215-226.

The operational spills indicator is the number of incidents in respect of activities where we are the operator in which 100 kilograms or more of oil or oil products were spilled as a result of those activities and reached the environment. The 2017 number was updated from 99 to reflect the completion of investigations into spills. See “Environment and society” on page 68.

Overview

Our Integrated Gas business manages liquefied natural gas (LNG) activities and the conversion of natural gas into gas-to-liquids (GTL) fuels and other products, as well as our New Energies portfolio. It includes natural gas exploration and extraction, and the operation of upstream and midstream infrastructure necessary to deliver gas to market. It markets and trades natural gas, LNG, electricity and carbon-emission rights and also markets and sells LNG as a fuel for heavy-duty vehicles and marine vessels.

Business conditions

Global oil demand grew by 1.2% in 2018, according to the International Energy Agency’s Oil Market Report published in January 2019, with the Brent crude oil price averaging $71 per barrel (/b), up $17/b from 2017.

Global gas demand is estimated to have grown by about 3.2% in 2018. A combination of weather conditions, implementation of new policies such as the partial substitution of coal by gas-fired power generation in China, and global economic growth led to an increase in demand in most regions.

Global LNG imports grew by 28 million tonnes (9.6%) in 2018. LNG demand growth was supported by weather conditions, lower nuclear power generation and the start-up of new regasification capacity in Asia. China and India alone increased their regasification capacity by 19% and 33% from 2017 respectively, equal to 21 million tonnes per annum, in total. Supply growth was primarily driven by the start-up of new projects in Australia, the USA and Russia. The majority of additional LNG supply was absorbed by Asia, offsetting declines in the Middle East and North Africa.

Natural gas prices can vary from region to region.

In the USA, the natural gas price at the Henry Hub averaged $3.1 per million British thermal units (MMBtu) in 2018, 3% higher than in 2017, and traded in a range of $2.5-4.9/MMBtu.

In Europe, natural gas prices were higher than in 2017. The average price at the UK National Balancing Point was $7.9/MMBtu, compared with $5.8/MMBtu in 2017. At the main continental European gas trading hubs – in the Netherlands, Belgium and Germany – prices were also stronger, as reflected by stronger Dutch Title Transfer Facility prices.

Long-term contracted LNG prices in the Asia-Pacific region generally increased in 2018 as they are predominantly indexed to the price of Japan Customs-cleared Crude, which has increased in line with global oil prices. North Asia spot prices (reflected by the Japan Korea Marker) also increased due to relatively strong demand, particularly from China.

See “Market overview” on pages 21-23.

PRODUCTION AVAILABLE FOR SALE

In 2018, production was 349 million barrels of oil equivalent (boe), or 957 thousand boe per day (boe/d), compared with 324 million boe, or 887 thousand boe/d in 2017. Natural gas production increased by 9% compared with 2017, mainly due to the stronger operational performance of our assets, namely higher availability at Pearl GTL in 2018, and improved performance combined with full year production of all three trains at Gorgon in Australia, partially offset by the divestment of Bongkot field in Thailand. Liquids production increased 5%, mainly due to higher availability at Pearl GTL in Qatar.

LNG LIQUEFACTION VOLUMES

LNG liquefaction volumes of 34.3 million tonnes in 2018 were 3% higher than in 2017, driven by increased feed gas availability in Atlantic LNG in Trinidad and Tobago, Queensland Curtis LNG (QCLNG) in Australia and Oman LNG; less maintenance mainly in Gorgon and QCLNG in Australia; and incremental volumes from Gorgon with all trains operational for a full year; partly offset by divestments of our interests in Woodside Petroleum Limited (Woodside) in 2017 and Malaysia LNG in 2018.

LNG sales volumes of 71.21 million tonnes in 2018 were 8% higher than in 2017, driven by our increased LNG purchases from third parties and higher LNG liquefaction volumes.

Earnings 2018-2017

Segment earnings in 2018 were $11,444 million, which included a net gain of $2,045 million. The net gain primarily reflected gains of $1,937 million on sale of assets, mainly related to the divestment of assets in Thailand, New Zealand and India. It also comprised a gain of $481 million related to the fair value accounting of commodity derivatives and impairment charges of $371 million related to investments in Trinidad and Tobago and Shell’s investment in a joint venture. 

Segment earnings in 2017 were $5,078 million, which included a net charge of $190 million. The net charge mainly reflected a charge of $445 million on fair value accounting of commodity derivatives and a charge of $412 million as a result of US tax reform legislation, partly offset by a gain of $636 million from the strengthening Australian dollar on a deferred tax position.

Excluding the net gain and the net charge described above, segment earnings were $9,399 million in 2018 compared with $5,268 million in 2017. Earnings were positively impacted by increased contributions from trading and higher realised oil, gas and LNG prices (around $4,200 million), increased LNG volumes from various assets across the portfolio (around $615 million). Earnings were negatively impacted by higher operating expenses (around $502 million of which $246 million relates to growth of New Energy activities) and lower dividends due to divestments (around $274 million).

In 2018, the impact of exchange rate movements of the Australian dollar on deferred tax balances was significantly reduced, as a result of the change in the fiscal functional currency of a number of Shell entities in Australia to the US dollar with effect from January 1, 2018.

Earnings 2017-2016

Segment earnings in 2017 were $5,078 million, which included a net charge of $190 million as described above.

Segment earnings in 2016 were $2,529 million, which included a net charge of $1,171 million. The net charge included impairments of $451 million, reported mainly in share of profit of joint ventures and associates, the reassessment of a deferred tax asset in Australia of $533 million, onerous contract provisions in Europe and the USA of $390 million, and redundancy and restructuring charges of $245 million, partly offset by gains on divestments of $212 million and on the accounting reclassification of Shell’s interest in Woodside in Australia of $479 million (both reported in interest and other income).

Excluding the net charges described above, segment earnings were $5,268 million in 2017 compared with $3,700 million in 2016. Earnings were positively impacted by higher realised oil, gas and LNG prices (around $1,620 million), lower operating expenses (around $110 million), lower exploration charges (around $170 million), and lower well write-offs (around $100 million). Earnings were negatively impacted by a total of around $230 million from lower liquids production, mainly as a result of the shutdown at Pearl, partially offset by higher LNG liquefaction volumes across the portfolio. Other items, which included lower contributions from trading and higher taxation, had a net negative impact of around $200 million.

capital investment AND DIVESTMENTS

Capital investment in 2018 was $4.5 billion, compared with $3.8 billion in 2017.

Divestments in 2018 were $3.1 billion, in line with $3.1 billion in 2017.

Portfolio and business development

Key portfolio events in 2018 included the following:

In February 2019, we acquired sonnen, a provider of smart energy storage systems and innovative energy services for households, and Limejump, a UK-based digital energy-technology company.

The following major milestones were reached in 2018:

We continued to divest selected assets during 2018, including:

In November 2018, we agreed to sell our interest in the undeveloped Sunrise gas field in the Timor Sea (Shell interest 26.6%) to the government of Timor-Leste. The transaction is pending regulatory approval and expected to close in the first half of 2019.

Business and property

Our Integrated Gas business is described below by country.

EUROPE

Gibraltar

We have a 51% interest in the first LNG regasification facility in Gibraltar, construction of which was completed in 2018.

Netherlands

We have access to import and storage capacity at the GATE LNG terminal in the Netherlands (Shell capacity rights 1.4 million tonnes per annum, mtpa), enabling us to supply LNG to marine and road transport customers in northwest Europe. We are also using the terminal to supply LNG to our growing truck-refuelling network in the Netherlands.

Norway

Gasnor AS (Shell interest 100%) provides LNG fuel for ships and industrial customers and has a natural gas pipeline network.

UK

We have a 50% interest in the Dragon LNG regasification terminal, with long-term arrangements in place governing the use of capacity rights.

Rest of Europe

We also have interests in Cyprus.

ASIA (INCLUDING THE MIDDLE EAST AND RUSSIA)

Brunei

We have a 25% interest in Brunei LNG Sendirian Berhad, which sells most of its LNG on long-term contracts to customers in Asia.

China

We jointly develop and produce from the onshore Changbei tight-gas field under a PSC with China National Petroleum Corporation (CNPC). In 2016, we completed the Changbei I development programme under the PSC and subsequently handed over the production operatorship to CNPC. In December 2017, we took the final investment decision on the Changbei II Phase 1 project, and we expect the drilling programme and construction of facilities to be completed in 2021. Shell remains the operator of Changbei II.

In 2018, we completed the handover of the Jinqiu block in Sichuan to CNPC.

India

We have a 30% interest in the producing oil and gas field Panna/Mukta. We also have a 30% interest in the Mid Tapti and South Tapti fields, which ceased production in the first quarter of 2016.

We decreased our interest in the publicly-listed Mahanagar Gas Limited from 32.5% to 10%, a natural gas distribution company in Mumbai.

In December, we acquired Total’s 26% interest in the Hazira LNG and Port venture, increasing our interest from 74% to 100%. The Hazira LNG and Port venture, located in the state of Gujarat on the west coast, comprises two companies: Hazira LNG Pvt Ltd, which operates a regasification terminal; and Hazira Port Pvt Ltd, which manages a cargo port at Hazira.

Indonesia

We have a 35% interest in the INPEX Masela Ltd joint venture which owns and operates the offshore Masela block. In April 2016, the joint venture received a notification from the Indonesian government authorities instructing it to re-propose a plan for the Abadi gas field based on an onshore LNG project. The partners are preparing a new Plan of Development for submission to the government of Indonesia in 2019.

Iran

Shell transactions with Iran are disclosed separately. See “Section 13(r) of the US Securities Exchange Act of 1934 Disclosure” on page 262.

Malaysia

We operate a GTL plant, Shell MDS (Shell interest 72%), adjacent to the Malaysia LNG facilities. Using Shell technology, the plant converts gas into high-quality middle distillates, drilling fluids, waxes and specialty products.

In 2018, we sold our 15% interest in Malaysia LNG Tiga Sdn Bhd to the Sarawak State Financial Secretary.

Oman

We have a 30% interest in Oman LNG LLC, which mainly supplies Asian markets under long-term contracts. We also have an 11% interest in Qalhat LNG, which is part of the Oman LNG complex.

Qatar

We operate the Pearl GTL plant (Shell interest 100%) in Qatar under a development and PSC with the government. The fully-integrated facility has capacity for production, processing and transportation of 1.6 billion standard cubic feet per day (scf/d) of gas from Qatar’s North Field. It has an installed capacity of about 140 thousand boe/d of high-quality liquid hydrocarbon products and 120 thousand boe/d of natural gas liquids (NGL) and ethane.

We have a 30% interest in Qatargas 4, which comprises integrated facilities to produce about 1.4 billion scf/d of gas from Qatar’s North Field, an onshore gas-processing facility and one LNG train with a collective production capacity of 7.8 mtpa of LNG and 70 thousand boe/d of condensate and NGL.

Russia

We have a 27.5% interest in Sakhalin-2, the joint venture with Gazprom, an integrated oil and gas project located in a subarctic environment.

We have a 50% interest in Salym Petroleum Development N.V., the joint venture with GazpromNeft, developing the Salym fields in western Siberia, Khanty Mansiysk Autonomous District, where production was approximately 120 thousand boe/d in 2018.

We have a 50% interest in Khanty-Mansiysk Petroleum Alliance VOF partnership with GazpromNeft.

With effect from January 1, 2019, Salym and Khanty-Mansiysk Petroleum Alliance VOF partnership will be reported in the Upstream segment. Comparative information will not be adjusted.

As a result of European Union and US sanctions prohibiting certain defined oil and gas activities in Russia, we suspended our support to Salym and Khanty-Mansiysk Petroleum Alliance VOF partnership in relation to shale oil activities in 2014. Salym and Khanty-Mansiysk Petroleum Alliance VOF partnership also suspended any shale oil related activities in 2014.

Singapore

We have a 50% interest in a joint venture with KS Investments (the investment arm of Keppel Group) that holds a licence to supply LNG fuel for vessels in the Port of Singapore. We have aggregator licences to import LNG into Singapore.

Rest of Asia

We also have interests in Myanmar.

OCEANIA

Australia

We have interests in offshore production, LNG liquefaction and exploration licences in the North West Shelf (NWS) and Greater Gorgon areas of the Carnarvon Basin, as well as in the Browse Basin and Timor Sea. Woodside is the operator on behalf of the NWS joint venture, which produced more than 500 thousand boe/d of gas and condensates in 2018.

We have a 25% interest in the Gorgon LNG joint venture, which is operated by Chevron. The venture started operating in 2016, producing from the offshore Gorgon and Jansz-Io fields via a three train LNG plant on Barrow Island.

We are the operator of a permit in the Browse Basin in which two separate gas fields were found: Prelude and Concerto (Shell interest 67.5% in each). Our development concept for these fields is based on our floating liquified natural gas (FLNG) technology. The Prelude FLNG project, at its peak, is expected to produce about 130 thousand boe/d of gas and NGL, 3.6 mtpa of LNG, 1.3 mtpa of condensate and 0.4 mtpa of liquefied petroleum gas. During 2018, milestones included starting to commission the facilities and successful receipt of LNG and propane into the tanks. In December, wells were opened, entering the start-up phase. Our other interests in the basin include a joint arrangement, with Shell as the operator, for the Crux gas and condensate field (Shell interest 82%).

We are also a partner in the Browse joint arrangement (Shell interest 27%) covering the Brecknock, Calliance and Torosa gas fields, which is operated by Woodside. In November 2018, we agreed to sell our interest in the undeveloped Sunrise gas field in the Timor Sea (Shell interest 26.6%) to the government of Timor-Leste. We are a partner in both Shell-operated and other exploration joint arrangements in multiple basins, including Bonaparte, Browse, Exmouth Plateau, Greater Gorgon and Outer Canning.

We have a 50% interest in Arrow, a Queensland-based joint venture with CNPC. Arrow owns coal-bed methane assets and a domestic power business.

We have a 50% interest in train one and a 97.5% interest in train two of the Shell-operated QCLNG venture. The two-train liquefaction plant has an installed capacity of 8.5 mtpa. We also operate the venture’s natural gas operations, which include wells, compression stations and processing plants, in Queensland’s Surat Basin. We have interests ranging from 44% to 74% in 24 field compression stations and six central processing plants. Our production of natural gas from the onshore Surat Basin supplies the liquefaction plant and the domestic gas market.

A gas sales agreement between Arrow and QCLNG has been signed, under which gas from Arrow’s Surat Basin fields would flow to the QCLNG venture, that would then both sell gas to local customers and export it through its gas plant on Curtis Island.

AFRICA

Egypt

We have interests of 35.5% and 38%, respectively, in trains one and two of the Egyptian LNG (ELNG) plant. In January 2014, force majeure notices were issued under the LNG agreements as a result of domestic gas diversions severely restricting volumes available to ELNG. These notices remain in place. See “Oil and gas information” on page 45.

Mozambique

A feasibility study is ongoing for a potential GTL project, under a memorandum of understanding (MOU) signed with the government of Mozambique in 2017.

Nigeria

We have a 25.6% interest in Nigeria LNG Ltd, which operates six LNG trains located on Bonny Island.

Tanzania

We have a 60% interest in, and are the operator of, Blocks 1 and 4 offshore southern Tanzania. The blocks cover approximately 4,000 square kilometres of the Mafia Deep Offshore Basin and the northern part of the Rovuma Basin. We continue to develop a potential LNG project with partners in Block 2 in line with the Block 1 and 4 appraisal programme agreed with the Tanzanian government. We are engaging with the government to extend the Block 4 licence. The government has confirmed that the Block 4 licence, due to initially expire on October 31, 2017, remains in full force pending the grant of the licence extension.

Rest of Africa

We have a 17.9% share in the West African Gas Pipeline Company Limited which owns and operates a 678-kilometre pipeline that transports gas from Nigeria to Ghana, Benin and Togo. We also have interests in Gabon and Morocco.

NORTH AMERICA

Canada

In 2018, we took the final investment decision on LNG Canada, a liquified natural gas project in Kitimat, British Columbia. We also completed the dilution of interest from 50% to 40% in LNG Canada to Petronas. With LNG Canada’s other joint venture partners also having taken final investment decisions, construction started in October 2018. First LNG is expected before the middle of the next decade.

USA

We have offtake rights to 100% of the capacity (2.5 mtpa) of the Kinder Morgan-owned Elba Island liquefaction plant, which is under construction. Elba Island also has a regasification terminal in which we have contracted capacity of 11.6 mtpa.

We have 13.1 mtpa of contracted capacity in the Lake Charles regasification terminal in Louisiana. We are also evaluating a project to convert the existing regasification facility owned by Energy Transfer into a liquefaction plant in which we would have capacity rights.

SOUTH AMERICA

Bolivia

We have a 100% interest in the La Vertiente, Los Suris and Tarija XX East blocks and the La Vertiente gas processing plant. We have a 37.5% interest in the Caipipendi block, where we mainly produce from the Margarita field. We are also exploring in Caipipendi block. We also have a 25% interest in the Tarija XX West block where we produce from the Itaú field. We have the rights to explore and further develop the onshore Huacareta block (Shell interest 100%) and we are exploring there.

Peru

We have a non-Shell-operated 20% interest in the Peru LNG liquefaction plant.

Trinidad and Tobago

We are the largest shareholder in all four trains at Atlantic LNG. We also have an interest in three concessions with producing fields – Central Block, East Coast Marine Area (ECMA) and NCMA blocks. Shell has a 65% interest in Central Block and 100% interest in ECMA. In August 2018, we acquired ENI’s interest in the NCMA block, increasing our interest from 63.2% to 80.5%. We also have interests ranging from 35% to 100% in exploration activities in blocks 5(c), 5(d), 6(d), and Atlantic Area blocks 3, 5, and 6.

Rest of South America

We have a 40% interest in a gas pipeline connecting Uruguay to Argentina.

TRADING AND SUPPLY

Through our Shell Energy organisation, we market a portion of our share of equity production of LNG and trade LNG volumes around the world through our hubs in the UK, Dubai and Singapore. Trading and Supply also markets and trades natural gas, power and carbon-emission rights mainly in North America and Europe, of which a portion includes equity volumes from our upstream operations. We also market gas in Australia and Mexico, and power in Brazil.

NEW ENERGIES

Our New Energies business explores emerging opportunities linked to the energy transition and invests in those where we believe sufficient value is available. We focus on new fuels for transport, such as advanced biofuels, hydrogen and charging for battery-electric vehicles; and power, including from low-carbon sources such as wind and solar, as well as natural gas. Alongside our work in new fuels and power, we are exploring how digital technologies can best support our activities and customers.

The New Energies portfolio is being built through organic growth and acquisitions. Most of these opportunities are in business sectors that are different from Shell’s existing oil and gas businesses but have some similarities and/or adjacencies to our Downstream and gas and power trading businesses. New Energies companies are subject to the Shell Control Framework. Some are not yet in full compliance and we are working to bring them into compliance with the Shell Control Framework in a fit-for-purpose manner.

New fuels

We have a demonstration plant at the Shell Technology Centre Bangalore, India, that demonstrates a technology called IH2 that turns waste feedstock into transport fuel. The plant is in its final research and development stage, ahead of potentially scaling up for commercial production. We are also

investing in renewable natural gas (RNG) for use in natural-gas fuelled vehicles in the USA and in Europe. RNG is collected from landfill sites, food waste or manure and then processed until it is fully interchangeable with conventional natural gas.

In the USA, in August 2018, we announced plans to expand and upgrade the JC Biomethane plant in Junction City, Oregon, which we acquired in May 2018.

We are part of a joint-venture, H2 Mobility Germany to install hydrogen fuelling pumps at around 100 locations across Germany during 2019. Shell is taking part in several other initiatives to encourage the adoption of hydrogen-electric energy as a transport fuel.

Shell has also opened 26 hydrogen refuelling sites in Germany, the USA, the UK and Canada and has announced the construction of four stations in the Netherlands.

Shell offers fast charging services for electric vehicles (EV) at 26 retail sites in the Netherlands, China and the UK and is working with IONITY, a joint venture of automotive manufacturers, to offer 500 high-powered charging points across 10 European countries.

NewMotion, which we acquired at the end of 2017, operates private electric charge points in the Netherlands, Germany, France and the UK, for home and business use.

In January 2019, we acquired Greenlots, a California-based EV charging company. This acquisition marks Shell’s entry into the US EV market providing EV charging solutions at scale, including vehicle charging points, smart software and grid services to commercial and residential customers.

Power

We have interests in five onshore wind power projects in the USA and in one offshore wind power project – NoordzeeWind (Shell interest 50%) in the Netherlands. In total, our share of the energy capacity from these projects is more than 400 megawatts (MW).

In June 2018, the final investment decision was taken on the Borssele III and IV offshore wind farm projects in the Netherlands (Shell interest 20%). These wind farms are designed to have a total installed capacity of 731.5 MW. In December 2018, we formed 50/50 joint ventures with EDF Renewables and EDP Renewables to build wind farms off the coast of New Jersey and Massachusetts, respectively. This marks our entry into the US offshore wind market.

In 2018, we completed the acquisition of a 43.8% interest in Silicon Ranch Corporation, a developer, owner and operator of solar energy assets in the USA. In December 2018, a solar park started at Shell Moerdijk, the Netherlands, providing power to our chemicals plants.

In January 2019, we acquired a 49% interest in Cleantech Solar, which provides solar power to commercial and industrial customers across South-East Asia and India.

In February 2018, we completed the acquisition of First Utility, a leading independent UK household energy and broadband provider.  In February 2019, we acquired sonnen, a provider of smart energy storage systems and innovative energy services for households, and Limejump, a UK-based digital energy-technology company.