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.

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 2017 were $5,078 million, compared with $2,529 million in 2016. The increase was mainly driven by higher realised oil, gas, and liquefied natural gas (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. See “Integrated Gas” on pages 24-25.

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. See “Upstream” on pages 31-32.

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. See “Downstream” on pages 46-47.

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. See “Corporate” on page 53.

EARNINGS 2016-2015

Income for the period was $4,777 million in 2016, compared with $2,200 million in 2015. After current cost of supplies adjustment, total segment earnings were $3,692 million in 2016, compared with $4,155 million in 2015. BG Group plc (BG) was consolidated within Shell’s results with effect from February 2016 following its acquisition.

Integrated Gas earnings in 2016 were $2,529 million, compared with $3,170 million in 2015. The decrease was mainly driven by higher operating expenses and depreciation, lower oil and LNG prices, and higher taxation. These impacts were partly offset by higher production and LNG liquefaction volumes, lower impairment charges and well write-offs.

Upstream earnings in 2016 were a loss of $3,674 million, compared with a loss of $8,833 million in 2015. The lower loss in 2016 was partly explained by the significant charges in 2015 associated with the decision to cease Alaska drilling activities and the Carmon Creek project in Canada and other impairments. In addition, earnings in 2016 benefited from higher production volumes and lower operating expenses, partly offset by lower oil and gas prices, higher depreciation, and lower gains on divestments.

Downstream earnings in 2016 were $6,588 million, compared with $10,243 million in 2015. The decrease was mainly due to lower realised refining and trading margins and a higher effective tax rate. There was a partial offset from stronger marketing margins, in turn partly offset by the impact of divestments and unfavourable exchange rate effects and fair value accounting of commodity derivatives.

Corporate earnings in 2016 were a loss of $1,751 million, compared with a loss of $425 million in 2015. Interest expense was significantly higher in 2016, due to additional debt for the BG acquisition and debt assumed on the acquisition, partly offset by lower foreign exchange losses. There were also BG acquisition costs and lower tax credits in 2016, and a gain in 2015 on the sale of an office building.

production available for sale

Oil and gas production available for sale in 2017 was 1,338 million barrels of oil equivalent (boe), or 3,664 thousand boe per day (boe/d), compared with 1,342 million boe, or 3,668 thousand boe/d, in 2016. In 2017, production from new fields offset the impact of field declines and divestments.

[A] See “Oil and gas information” on pages 42-43.
[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 38-40 and set out in more detail in “Supplementary information – oil and gas (unaudited)” on pages 179-188.

Before taking production into account, our proved reserves increased by 368 million boe in 2017. This comprised increases of 343 million boe from Shell subsidiaries and 25 million boe from the Shell share of joint ventures and associates. The increase from Shell subsidiaries included 927 million boe from revisions and reclassifications, 706 million boe from extensions and discoveries, and 97 million boe from improved recovery, partly offset by net sales of minerals in place of 1,387 million boe mainly related to synthetic crude oil in Canada.

In 2017, total oil and gas production was 1,383 million boe, of which 1,338 million boe was available for sale and 45 million boe was consumed in operations. Production available for sale from subsidiaries was 1,168 million boe and 38 million boe was consumed in operations. The Shell share of the production available for sale of joint ventures and associates was 170 million boe and 7 million boe was consumed in operations.

Accordingly, after taking production into account, our proved reserves decreased by 1,015 million boe in 2017, to 12,233 million boe at December 31, 2017, with a decrease of 863 million boe from subsidiaries and a decrease of 152 million boe from the Shell share of joint ventures and associates.

CAPITAL INVESTMENT AND OTHER INFORMATION

Capital investment was $24.0 billion in 2017, compared with $79.9 billion in 2016, which included $52.9 billion related to the BG acquisition.

Divestments were $17.3 billion in 2017, compared with $5.0 billion in 2016.

Operating expenses decreased by $3 billion in 2017, to $38 billion. In 2016, operating expenses included redundancy and restructuring charges of $2 billion.

Our return on average capital employed (ROACE) increased to 5.8%, compared with 3.0% in 2016, mainly driven by a higher income in 2017.

Gearing was 24.8% at the end of 2017, compared with 28.0% at the end of 2016, driven by debt repayments in 2017.

SIGNIFICANT ACCOUNTING ESTIMATES AND JUDGEMENTS

See Note 2 to the “Consolidated Financial Statements” on pages 142-148.

LEGAL PROCEEDINGS

See Note 25 to the “Consolidated Financial Statements” on pages 175-176.

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 94-117.

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 2016 return has been restated to reflect the change in average days (from 30 to 90 days) used in this indicator. 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 55.   

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 has been added because of the need to optimise the portfolio following the acquisition of BG. It recognises the importance of generating cash for financing activities, including distributions to shareholders. See “Non-GAAP measures reconciliations” on page 226.

Return on average capital employed (ROACE) is defined as annual income, 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 20 and “Non-GAAP measures reconciliations” on page 226.

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 19 and “Non-GAAP measures reconciliations” on page 225.

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 225) 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 securities, adjusted to an accruals basis. Capital investment is a measure used to make decisions about allocating resources and assessing performance. In 2016, capital investment also included the respective amount for the acquisition of BG. See “Liquidity and capital resources” on page 55 and “Non-GAAP measures reconciliations” on page 225.

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. It is a measure of the degree to which our operations are financed by debt. See “Liquidity and capital resources” on page 54.

OTHER PERFORMANCE INDICATORS

A number of changes have been made in 2017, including adding new indicators for greenhouse gas (GHG) emissions and incorporating Tier 2 process safety events, in order to provide more focus on Shell’s performance in these areas.

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. Changes in production have a significant impact on our cash flow. See “Summary of results” on page 20.

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 24.

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 46.

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. From 2017, each measure is shown separately. In 2016, the indicators covered at least 20 Shell-operated capital projects in the execution phase (post final investment decision). In 2017, we also included non-Shell-operated projects, expanding coverage to at least 35 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 59.

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 59.

Refining 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 to 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 page 66.

Chemicals greenhouse gas 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 to the atmosphere per metric tonne of petrochemicals production. See “Climate change and energy transition” on page 66.

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 12-13, “Summary of results” on page 20, “Oil and gas information” on pages 38-41 and “Supplementary information – oil and gas (unaudited)” on pages 179-188.

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 2016 number has been revised. See “Environment and society” on page 59.

Direct GHG emissions from facilities operated by Shell, expressed in CO₂ equivalent. See “Climate change and energy transition” on page 66.

Overview

Our Integrated Gas and New Energies 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, when contractually linked to the production and transportation of LNG, and the operation of the upstream and midstream infrastructure necessary to deliver gas to market. It markets and trades natural gas, LNG, crude oil, 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 1.6% in 2017, according to the International Energy Agency’s Oil Market Report published in January 2018, with the Brent crude oil price averaging $54 per barrel (/b), up $10/b from 2016.

Global gas demand grew by about 2.4% in 2017. A combination of weather conditions and increased global economic growth led to an increase in demand in most regions.

The global LNG market grew by 29 million tonnes (11.2%) year on year. Supply growth was primarily driven by the start-up of new projects in Australia and the USA. The majority of additional LNG supply was absorbed by North Asia and Southern Europe, offsetting a decline in imports by the Middle East and North Africa. LNG demand growth was supported by policy developments (China, South Korea and Taiwan), warmer weather in the summer months (Southern Europe) and delays in nuclear power station restarts (Japan).

Unlike crude oil pricing, which is global in nature, natural gas prices can vary from region to region.

In the USA, the natural gas price at the Henry Hub averaged $3.0 per million British thermal units (MMBtu) in 2017, 20% higher than in 2016, and traded in a range of $2.4-3.4/MMBtu.

In Europe, natural gas prices were higher than in 2016. The average price at the UK National Balancing Point (NBP) was $5.8/MMBtu, compared with $4.3/MMBtu in 2016. 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 2017 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 17-18.

PRODUCTION AVAILABLE FOR SALE

In 2017, production was 324 million barrels of oil equivalent (boe), or 887 thousand boe per day (boe/d), compared with 323 million boe, or 884 thousand boe/d in 2016. Liquids production decreased by 9%, mainly due to a shutdown at our Pearl GTL plant in Qatar. Natural gas production increased by 4% compared with 2016, mainly due to the start-up of Gorgon train 3 in Australia, partly offset by lower gas production at Pearl.

LNG LIQUEFACTION VOLUMES

LNG liquefaction volumes of 33.2 million tonnes in 2017 were 7% higher than in 2016, mainly reflecting the additional month’s contribution of assets acquired with BG and our strong operational performance. There were also incremental volumes from the start-up of Gorgon train 3. These impacts were partly offset by a higher level of unplanned maintenance activity and lower feedgas availability at Queensland Curtis LNG (QCLNG) in Australia and Atlantic LNG in Trinidad and Tobago.

LNG sales volumes of 66.0 million tonnes in 2017 were 16% higher than in 2016, mainly reflecting higher purchased volumes from third parties and higher offtake from Gorgon, Nigeria LNG and Brunei LNG.

Earnings 2017-2016

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.

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 Petroleum Limited (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.

As a result of the change in the fiscal functional currency of a number of Shell entities in Australia to the US dollar, the impact of exchange rate movements of the Australian dollar on deferred tax balances will be significantly reduced in 2018.

Earnings 2016-2015

BG was consolidated within Shell’s results with effect from February 2016, following its acquisition.

Segment earnings in 2016 were $2,529 million, which included a net charge of $1,171 million as described above. Segment earnings in 2015 were $3,170 million, which included a net charge of $1,887 million, including impairments of $1,109 million and the impact of the weakening of the Australian dollar on deferred tax positions of $560 million.

Excluding the net charges described above, segment earnings were $3,700 million in 2016 compared with $5,057 million in 2015. Earnings were impacted by higher operating expenses and depreciation mainly due to the consolidation of BG (around $1,860 million), lower oil and LNG prices (around $1,730 million), higher taxation (around $570 million), and other net negative impacts of around $120 million. These impacts were partly offset by higher oil and gas production and LNG liquefaction volumes (around $2,260 million), mainly as a result of the BG acquisition, and lower well write-offs (around $660 million).

capital investment AND DIVESTMENTS

Capital investment in 2017 was $3.8 billion, compared with $26.2 billion in 2016, of which $21.8 billion related to the acquisition of BG.

Divestments in 2017 were $3.1 billion, compared with $0.4 billion in 2016, mainly due to the divestment of our interest in Woodside.

Portfolio and business development

Key portfolio events in 2017 included the following:

■ In May, we acquired Centrica’s interest in the North Coast Marine Area (NCMA) block offshore Trinidad and Tobago, increasing our interest from 45.88% to 63.19%. In August, we acquired Chevron’s interests in Trinidad and Tobago, which included increasing our interest in the Shell-operated East Coast Marine Area (ECMA) block from 50% to 100%.

In January 2018, we announced an agreement to acquire a 43.83% interest in Silicon Ranch Corporation, a leading US developer, owner, and operator of solar assets. The transaction was completed in March 2018.

The following major operational milestones were reached in 2017:

The Pearl GTL plant (Shell interest 100%) operated at a reduced rate of production from December 2016, due to unforeseen maintenance required on the gasifier units, until a controlled shutdown in February 2017. The plant resumed full production in July after repairs to the gasifier units were completed.

We continued to divest selected assets during 2017, including:

In September, Shell and KUFPEC agreed to cancel the January sale and purchase agreement for the sale of our 22.2% interest in the Bongkot field and adjoining acreage offshore Thailand. Subsequently, in January 2018, we agreed to sell our interest to PTT Exploration & Production Public Company Limited (PTTEP). The transaction is pending regulatory and other approvals, and expected to close in the second quarter of 2018.

In January 2018, Partners Group signed an agreement to join the Borssele III and IV offshore wind farm projects in the Netherlands, diluting our interest in the consortium from 40% to 20%.

Business and property

Our Integrated Gas business is described below by country.

EUROPE

Greece

In January 2017, Attiki Gas Supply Company S.A. was unbundled into separate supply and distribution companies, in line with Greek legislation. As a result, we have a 49% interest in both Attiki Gas Supply Company S.A. and Attiki Natural Gas Distribution Company S.A.

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. In August 2017, we took delivery of the Cardissa LNG bunker vessel, a purpose-built vessel which supplies LNG to marine and industrial customers.

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.

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 production-sharing contract (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 project execution began that month. Shell remains the operator of Changbei II.

In 2016, we handed back the Zitong and Fushun blocks in Sichuan to CNPC, and expect to complete the handover of the Jinqiu block to CNPC in 2018.

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 have a 32.5% interest in MGL, a natural gas distribution company in Mumbai.

We have a 74% interest in the Hazira regasification terminal in the state of Gujarat on the west coast.

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 committed to working together with the Indonesian government to move the project forward.

Iran

Shell transactions with Iran are disclosed separately. See “Section 13(r) of the US Securities Exchange Act of 1934 Disclosure” on page 224.

Malaysia

We have a 15% interest in Malaysia LNG Tiga located in Bintulu. We also 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.

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 production-sharing contract 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.

Due to unforeseen maintenance required on the gasifier units, Pearl GTL operated at a reduced rate of production from December 2016 until a controlled shutdown in February 2017. The plant resumed full production in July 2017 after the gasifier unit repairs were completed. In 2017, Pearl GTL produced around 3.5 million tonnes of GTL products.

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, an integrated oil and gas project located in a subarctic environment.

We have a 50% interest in the Salym fields in western Siberia, Khanty Mansiysk Autonomous District, where production was approximately 120 thousand boe/d in 2017.

We have a 50% interest in Khanty-Mansiysk Petroleum Alliance.

We have a 100% interest in the North Vorkutinsky 1, North Vorkutinsky 2 and Syriaga exploration and production licences in Komi Republic (Timan Pechora).

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 in relation to shale oil activities in 2014. Salym and Khanty-Mansiysk Petroleum Alliance 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 currently have the first aggregator licence to import LNG into Singapore. The exclusivity period has ended with the issuance of the second import licence in October 2017 to both Shell Eastern Trading (Pte) Ltd (Shell interest 100%) and Pavilion Gas Pte Ltd.

Thailand

We have a 22.2% interest in the Bongkot and G12/48 fields in the Gulf of Thailand and a 66.7% interest in exploration Blocks 7 and 8 where activity is currently suspended due to overlapping claims by Thailand and Cambodia. We have an agreement over Block 9a under which we receive royalties. Production from the Bongkot field supplies around 20% of the country’s gas demand.

In September, Shell and KUFPEC agreed to cancel the January sale and purchase agreement for the sale of our 22.2% interest in the Bongkot field and adjoining acreage offshore Thailand. Subsequently, in January 2018, we agreed to sell our interest to PTTEP. The transaction is pending regulatory and other approvals, and is expected to close in the second quarter of 2018.

OCEANIA

Australia

We have interests in offshore production 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 (of which Shell’s 13.3% interest was sold in 2017) is the operator on behalf of the NWS joint venture, which produced more than 450 thousand boe/d of gas and condensates in 2017.

We have a 25% interest in the Gorgon LNG project, which involves the development of some of the largest gas discoveries to date in Australia, beginning with the offshore Gorgon and Jansz-lo fields. Gorgon LNG began production in March 2016. The third and final train began operation in March 2017.

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 FLNG technology. The Prelude FLNG project is expected to produce about 110 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. Major milestones during 2017 were the sail away of the facility from the construction yard in South Korea and the start of hook-up and commissioning activities on site. Our other interests in the basin include a joint arrangement, with Shell as the operator, for the undeveloped 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, and the undeveloped Sunrise gas field in the Timor Sea (Shell interest 26.6%), both of which are operated by Woodside. 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. Our production of onshore natural gas from the Surat Basin supplies both this plant and the domestic market.

In December 2017, we signed a gas sales agreement between Arrow and QCLNG, under which uncontracted 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.

New Zealand

Our interests include the Maui (83.75%) and Pohokura (48%) natural gas fields. We are an operator with an approximate 61% interest in an exploration licence in the Great South Basin.

The business is under strategic review. During 2017, we sold our 50% interest in the Kapuni gas field. We are currently in discussions to sell our remaining interests.  

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 39.

Mozambique

In 2014, we signed a memorandum of understanding (MOU) with Mozambique national oil and gas company Empresa Nacional de Hidrocarbonetos to formalise a partnership to conduct a full feasibility study for a potential GTL project. Following the outcome of the Mozambique domestic gas allocation public tender process in January 2017, where we were announced as one of three winners, we signed a MOU with the government for the project development work programme.

Nigeria

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

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. In 2016, we completed drilling on all remaining wells. 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. This includes discussion between the government and the partners in Blocks 1, 2 and 4 to agree the investment framework for the potential project. To enable the agreed appraisal programme to be carried out and progress the development of the project, the Block 1 licence was extended and 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.

NORTH AMERICA

Canada

In 2014, we entered into a joint venture (Shell interest 50%) to evaluate an investment in an LNG export facility in Kitimat on the west coast of Canada. Together with our partners, our evaluation continues to progress.

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 and we are also drilling an exploration well. 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 plan to drill an exploration well in 2018.

Peru

We have a 20% interest in an 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, ECMA and NCMA blocks. In May 2017, we acquired Centrica’s interest in the NCMA block, increasing our interest from 45.88% to 63.19% and in August, we acquired Chevron’s interests in Trinidad and Tobago, which included increasing our interest in the Shell-operated ECMA block from 50% to 100%. 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, 6 and 7.

Rest of South America

We have interests in a gas pipeline connecting Uruguay to Argentina.

In December 2017, we sold our interest in Comgás, a natural gas distribution company in Brazil, to Cosan. We exchanged our common shares in Comgás for Cosan shares plus cash.

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. It 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.

In September 2017, we acquired MP2, which provides market-based solutions to commercial and industrial customers for managing energy supply, load, and generation throughout the eastern USA.

During 2017, we started marketing gas in Australia and Mexico, and power in Brazil.

NEW ENERGIES

In 2016, we formed a New Energies business. We pursue two main areas of opportunities: 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. Digital technologies complement our activities in both new fuels and power.

The New Energies portfolio is largely being built through acquiring established companies or through start-up companies. 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 Shell’s control framework. However, some of the more recently acquired, smaller companies are not yet in compliance. We are working to bring them into compliance with Shell’s control framework in a fit-for-purpose manner.

New fuels

Biofuels

We continue to invest in new ways to produce biofuels from sustainable feedstocks such as waste and cellulosic biomass from non-food plants. In 2017, we completed construction of a demonstration plant at the Shell Technology Centre Bangalore, India. This plant will demonstrate a technology called IH2 (a trademark of the Gas Technology Institute) that turns waste into transport fuel. In addition, we continue to look for opportunities to invest in third-party technologies and to collaborate in scaling these up for commercialisation.

Hydrogen electric

Shell is taking part in several initiatives to encourage the adoption of hydrogen-electric energy as a transport fuel. In Germany, the government is supporting the deployment of a national network of hydrogen-electric fuelling stations across the country by 2023. We are working on this project with our joint-venture partners in H2 Mobility Germany – Air Liquide, Daimler, Linde, OMV and Total. At the end of 2017, Shell already had nine hydrogen filling stations at its retail sites in Germany.

In the UK, we are partnering with ITM Power to make hydrogen fuel available at three retail sites in the south east of the country. The first station was inaugurated in February 2017 at our Cobham retail site. In the USA, we also have two hydrogen stations in Los Angeles, California. In 2017, we began working with Honda and Toyota, and with the support of the California state government, to build seven new stations in Northern California. We are assessing the potential for similar projects in Austria, Belgium, France, Luxembourg, the Netherlands, Switzerland and the USA.

Charging for battery-electric vehicles

In 2017, we acquired Netherlands-based NewMotion, a company with one of Europe’s biggest networks of EV charging points. It operates more than 30,000 private electric charge points in the Netherlands, Germany, France and the UK. It also provides 100,000 registered charge-card users access to over 50,000 public charge points in 25 European countries.

In 2017, we also signed an agreement with charging operator IONITY to offer high-powered charging points in 10 European countries, starting with 80 of its biggest highway stations, which will allow EV drivers to travel long distances. IONITY is a joint venture between BMW, Daimler, Ford and Volkswagen, which was formed to create a network of 350-kilowatt chargers next to major highways in Europe.

Power

Our share of capacity from wind power projects in the USA is more than 400 megawatts (MW).

In the Netherlands, we have an interest in the consortium that was awarded the concession by the Dutch government in December 2016 to develop the Borssele III and IV offshore wind farm projects, which are to be located 20 kilometres off the Dutch coast. In January 2018, Partners Group signed an agreement to join the projects, diluting our interest in the consortium from 40% to 20%.

Also in the Netherlands, we have a 50% interest in the Noordzeewind joint venture with Nuon, which has been set up for the development, construction and management of the Egmond aan Zee offshore wind farm. The farm comprises 36 wind turbines, each with a capacity of 3 MW.

We are exploring ways to deploy solar technologies to lower the carbon intensity of our operations.

We are also looking at how best to combine wind and solar power with our existing business and capabilities.

We are developing a solar power plant at our Moerdijk chemicals site in the Netherlands, with construction planned to begin in 2018. The plant is expected to provide an approximate peak capacity of 20 MW of renewable power. The power produced will be used by the Shell Moerdijk site.

In December 2017, we signed an agreement to buy First Utility, a leading independent UK household energy and broadband provider. The transaction was completed in February 2018.

In January 2018, we announced an agreement to acquire a 43.83% interest in Silicon Ranch Corporation, a leading US developer, owner, and operator of solar assets. The transaction was completed in March 2018.

Digital technologies

Digital technologies complement our activities in new fuels and power.

In the Netherlands, we have developed a fill-up-and-go system which allows drivers to pay online for fuel from their vehicles. This secure payment system saves drivers time.

In the USA, the Fitcar™ app transforms a regular car into a “connected car” and provides maintenance alerts and information on the engine, the location of nearby services and tracks users’ driving style, helping drivers save money, stay safe and take care of their vehicle.

We have developed an app, called Farepilot, that helps self-employed drivers to identify high demand areas to swiftly find their next fare and potentially save them fuel. We have invested through Shell Technology Ventures in tiramizoo, a German start-up whose online technology connects retailers with customers. We are collaborating on an online tool that efficiently schedules local deliveries in over 150 towns and cities in Germany and Austria. This approach improves customer service, lowers costs and, if widely adopted, could reduce urban traffic and, in turn, help improve local air quality.

Going forward, we are exploring services we could offer to home energy users. We have already developed a digital programme which helps customers in the UK bring all their energy bills together in one place and finds ways for them to save money.

Our approach to digital ventures involves exploring a range of options, and moving on swiftly if we conclude that a venture is not commercially viable.

INTEGRATED GAS DATA table