TOTAL’s results are affected by a variety of factors, including changes in crude oil and natural gas prices as well as refining and marketing margins, which are all generally expressed in dollars, and changes in exchange rates, particularly the value of the euro compared to the dollar. Higher crude oil and natural gas prices generally have a positive effect on the income of TOTAL, since the Exploration & Production segment’s oil and gas business and Gas, Renewables & Power segment’s downstream gas business are positively impacted by the resulting increase in revenues. Lower crude oil and natural gas prices generally have a negative effect on the income of TOTAL, since its Upstream oil and gas business is negatively impacted by the resulting decrease in revenues realized from production. Higher crude oil and natural gas prices generally have a corresponding positivenegative effect. The effect of changes in crude oil prices on the activities of TOTAL’s Refining & Chemicals and Marketing & Services activitiessegments depends upon the speed at which the prices of refined petroleum products adjust to reflect such changes. TOTAL’s results are also significantly affected by the costs of its activities, in particular those related to exploration and production, and by the outcome of its strategic decisions with respect to cost reduction efforts. In addition,

TOTAL’s results are affected by general economic and political conditions and changes in governmental laws and regulations, as well as by the impact of decisions by OPEC on production levels. For more information, see “refer to "Item 3. — 3.- 3.2 Risk Factorsfactors” and “Item 4. — Other Matters”".

After fallingBenefiting from $100/b in 2014the rise of oil prices to $52/$71/b on average in 2015, Brent prices were highly2018 compared to $54/b in 2017, while remaining volatile, in 2016, fluctuating between $27/b and $58/b, with an average of $44/b for the year. In this difficult environment, the Group demonstrated its resilience by generatingreported adjusted net income of $13.6 billion in 2018, an increase of 28%, a return on average capital employed close to 12%, the highest profitability among the majors, dueand a pre-dividend breakeven below $30/b.

These excellent results reflect the strong growth of more than 8% for the Group’s hydrocarbon production, which reached a record level of 2.8 Mboe/d in 2018 and led to a 71% increase in Exploration & Production’s adjusted net operating income. The year was highlighted by the strengthstart-up of its integrated modelIchthys in Australia, Yamal LNG in Russia, deep-water projects Kaombo Norte in Angola and commitmentEgina in Nigeria, as well as the counter-cyclical acquisitions of its teams to reduceMaersk Oil and new offshore licenses in the breakeven.United Arab Emirates.

In this context, TOTAL’s net income (Group share) in 20162018 increased by 22%33% to $6,196 million from $5,087$11,446 million in 2015,2018 compared to $8,631 million in 2017, mainly due to higher hydrocarbon prices and growth of the Group’s production. Adjustments to net income (Group share), which include the after-tax inventory effect, special items and the impact of changes in fair value, had a lessnegative impact of $2,113 million in 2018. Excluding these items, as mentioned above, adjusted net income (Group share) increased by 28% to $13,559 million in 2018, compared to $10,578 million in 2017, in line with the contribution from the segments. For additional information, refer to "- 5.2 Group results 2016-2018" and "- 5.3 Business segment reporting", below.

In addition, the Group maintained its financial discipline. Net investments ⁽¹⁾ were $15.6 billion in 2018, in line with its objective, and $4.2 billion in cost reduction was achieved. Debt adjusted cash flow (DACF) ⁽²⁾ was $26 billion in 2018, driven largely by the 31% increase in cash flow from Exploration & Production. The Group’s balance sheet was solid with a gearing ⁽³⁾ ratio of 15.5%, below the target limit of 20%.

The Group is continuing to expand along the value chain of integrated gas and low-carbon electricity. With its acquisition of Engie’s LNG assets TOTAL is the second largest publicly-traded player in the LNG business, and its position will be strengthened with the 2019 start-up of the Cameron LNG project. In addition, the Group accelerated its growth in low-carbon electricity, notably with the acquisition of Direct Énergie.

In an environment of lower European refining margins, the Downstream relied on the availability of its units and the diversity of its portfolio to generate $6.5 billion of cash flow and profitability of more than 25%. The Group is continuing to implement its strategy for growth in petrochemicals by launching projects in the United States, Saudi Arabia, South Korea and Algeria. TOTAL has also continued to expand Marketing & Services in fast-growing areas, notably in Mexico, Brazil and Angola.

Conforming to the shareholder return policy announced in February 2018, the Group increased the 2018 dividend by 3.2% and bought back $1.5 billion of its shares in 2018. Given the solid financial position, which is benefiting from growing cash flow, the Board of Directors confirmed the shareholder return policy for 2019. It plans to increase the interim dividend by 3.1% to 0.66 euros per share, end the scrip dividend option following the general assembly meeting, and continue the share buyback policy in the amount of $1.5 billion in a $60/b environment.

Outlook

Since the start of 2019, Brent has traded around $60/b in a context of oil supply and demand near the record-high level of 100 Mb/d. In a volatile environment, the Group is pursuing its strategy for integrated growth along the oil, gas and low-carbon electricity chains.

The Group has clear visibility on its 2019 cash flow, supported by the strong contribution of project start-ups in 2018 and recent acquisitions.

The Group maintains financial discipline to reduce its breakeven to remain profitable across a broader range of environments. In particular, it is targeting cost reductions of $4.7 billion, projected net investments of $15-16 billion in 2019 and an Opex target of $5.5/boe.

In Exploration & Production, production is expected to grow by more than 9% in 2019, thanks to the ramp-ups of Kaombo Norte, Egina and Ichthys plus the start-ups of Iara 1 in Brazil, Kaombo South in Angola, Culzean in the UK and Johan Sverdrup in Norway. Determined to take advantage of the favorable cost environment, the Group plans to launch projects in 2019, notably including Mero 2 in Brazil, Tilenga and Kingfisher in Uganda and Arctic LNG 2 in Russia.

The Group is pursuing its strategy for profitable growth along the integrated gas and low-carbon electricity chains. Effective 2019, the Group will report the new iGRP segment (integrated Gas, Renewables & Power) which combines the Gas, Renewables & Power segment with the upstream gas and LNG activities currently reported within the Exploration & Production segment.

Affected by an abundance of available products, European refining margins have been very volatile since the start of the year. In 2019, the Downstream will continue to rely on its diversified portfolio, notably its integrated Refining & Chemical platforms in the U.S. and Asia-Middle East as well as its non-cyclical Marketing & Services segment.

In this context, the Group is continuing to implement its shareholder return policy announced in February 2018, by increasing the dividend in 2019 by 3.1%, in line with the objective to increase the dividend by 10% over the 2018-20 period. Taking into account its strong financial position, the Group will eliminate the scrip dividend option from June 2019. Within the framework of its program to buy back $5 billion of shares over the 2018-20 period, the Group expects to buy back $1.5 billion of its shares in 2019 in a $60/b Brent environment (for additional information concerning the Group’s dividends and dividend policy, refer to point 6.2 of chapter 6 (starting on page 229) of the 2018 Registration Document, which is incorporated herein by reference).

(2)  DACF= debt adjusted cash flow, is defined as cash flow from operating activities before changes in working capital at replacement cost, without financial charges.

(3)  "Gearing" refers to the net-debt-to-capital-ratio. "Net-debt-to-capital-ratio"= net debt/ (net debt + shareholders’ equity). For additional information, refer to Note 15.1(E) ("Net-debt-to-capital ratio") to the Consolidated Financial Statements in the 2018 Registration Document (on page 325), which is incorporated herein by reference.

5.2        Group results 2016-2018

(a)  Adjusted results are defined as income using replacement cost, adjusted for special items, excluding the impact of changes in fair value. See "- 5.3 Business segment reporting" below for further details.

(b)  Including acquisitions and increases in non-current loans. For additional information on investments, refer to point 2.5 of chapter 2 of the 2018 Registration Document (starting on page 68), which is incorporated herein by reference.

(c)  Including divestments and reimbursements of non-current loans.

(d)  "Net investments" = gross investments - divestments - repayment of non-current loans - other operations with non-controlling interests. For additional information on investments, refer to point 2.5 of chapter 2 of the 2018 Registration Document (starting on page 68), which is incorporated herein by reference.

(e)  "Organic investments" = net investments, excluding acquisitions, divestments and other operations with non-controlling interests. For additional information on investments, refer to point 2.5 of chapter 2 of the 2018 Registration Document (starting on page 68), which is incorporated herein by reference.

(f)  "Resource acquisitions"= acquisition of a participating interest in an oil and gas mining property by way of an assignment of rights and obligations in the corresponding permit or license and related contracts, with a view to producing the recoverable oil and gas.

(g)  The change in working capital as determined using the replacement cost method was $174 million in 2018, $1,184 million in 2017 and $(467) million in 2016. For information on the replacement cost method, refer to Note 3 ("Business segment information") to the Consolidated Financial Statements in the 2018 Registration Document (starting on page 265), which is incorporated herein by reference.

2018 vs. 2017

The Brent price rose to $71/b on average in 2018 from $54/b in 2017, while remaining volatile. In 2018, TOTAL’s average liquids price realization ⁽¹⁾ increased by 28% to $64.2/b in 2018 from $50.2/b in 2017. TOTAL’s average gas price realization ⁽²⁾ increased by 17% to $4.78/Mbtu in 2018 from $4.08/Mbtu in 2017. The Group’s European Refining Margin Indicator ("ERMI") ⁽³⁾ decreased by 21% to $32.3/t on average in 2018 compared to $40.9/t in 2017, mainly due to rising crude oil prices.

The euro-dollar exchange rate averaged $1.1810/€ in 2018, compared to $1.1297/€ in 2017.

Non-Group sales were $209,363 million in 2018 compared to $171,493 million in 2017, an increase of 22% reflecting the increased hydrocarbon prices and Group production. Non-Group sales increased 30% for the Exploration & Production segment, 26% for the Gas, Renewables & Power segment, 22% for the Refining & Chemicals segment and 21% for the Marketing & Services segment.

Net income (Group share) in 2018 increased by 33% to $11,446 million in 2018 compared to $8,631 million in 2017, mainly due to higher hydrocarbon prices and growth of the Group’s production. Adjustments to net income (Group share), which include the after-tax inventory effect, special items and the impact of changes in fair value, had a negative impact of $2,113 million in 2018, mainly due to an inventory effect and an impairment on Ichthys related to the sale of a partial interest by the Group, as well as the impairment of production facilities by SunPower ⁽⁴⁾. For a detailed overview of adjustment items for 2018, refer to Note 3 to the Consolidated Financial Statements in the 2018 Registration Document (starting on page 265), which is incorporated herein by reference. In 2017, adjustments to net income (Group share), which included special items of $(2,213) million and after-tax inventory valuation effect of $282 million, had a negative impact on net income (Group share) of special$1,947 million. Special items in 2016, with2017 included mainly an impairment of Fort Hills in Canada (following the Group demonstrating its resilience despiteoperator announcement of the 19% dropincrease of the project’s costs), Gladstone LNG in hydrocarbon prices. Adjustments to net income (Group share), which include special itemsAustralia and theafter-tax inventory valuation effect, hadassets in Congo, partially offset by a negative impactgain on the sale of $2,091 million in 2016.Atotech. Excluding these items, adjusted net income declinedincreased by 21%28% to $8,287$13,559 million in 20162018, compared to $10,518$10,578 million in 2015, primarily2017, in line with the contribution from the segments.

Income taxes in 2018 amounted to $6,516 million, 2.2 times higher than $3,029 million in 2017, due to the impactrelative weight and higher tax rates in the Exploration & Production segment in a higher hydrocarbon price environment.

(2)  Consolidated subsidiaries, excluding fixed margins.

(3)  The ERMI is a Group indicator intended to represent the margin after variable costs for a hypothetical complex refinery located around Rotterdam in Northern Europe that processes a mix of lower Brentcrude oil and other inputs commonly supplied to this region to produce and market the main refined products at prevailing prices on Upstream results, partially offsetin this region. The indicator margin may not be representative of the actual margins achieved by the contribution from downstream activities. For additional information, referGroup in any period because of the Group’s particular refinery configurations, product mix effects or other company-specific operating conditions.

(4)  As of December 31, 2018, TOTAL held an interest of 55.66% in SunPower, an American company listed on NASDAQ and based in California.

In 2018, the Company bought back 72,766,481 TOTAL shares on the market, i.e., 2.76% of the Company’s outstanding share capital as of December 31, 2018. See also "- — 2. Results 2014-20165.4.4 Shareholders’ equity”", below. In 2017, the Company did not buy back any shares.

Fully-diluted earnings per share was $4.24 in 2018 compared to $3.34 in 2017, an increase of 27%.

The Group’s resilience was supported by outstanding production growth overAsset sales completed were $5,172 million for the past two years (14.3%, including 4.5% in 2016). Infull-year 2018, comprised mainly of the Upstream, the Group strengthened its positionsale of a 4% interest in the Middle East by enteringIchthys project in Australia and the Al Shaheen fieldsale of the Group’s share of the LNG re-gas terminal at Dunkirk, as well as the sale of Joslyn in Qatar,Canada, Rabi in Gabon, the Martin Linge and Visund fields in Norway, an interest in Fort Hills in Canada, SunPower’s sale of its interest in 8point3, the marketing activities of TotalErg in Italy, the Marketing & Services network in Haiti, and the contribution of the Bayport polyethylene unit in the United States to the joint venture formed with Borealis and Nova in which TOTAL holds 50%. Asset sales were $4,239 million in 2017.

Acquisitions completed were $8,314 million for the full-year in 2018, including $4,493 million in resource acquisitions, comprised of the extension of licenses in Nigeria and the acquisition of shale gas assets. The Group is preparing future growth with the signinga network of major dealsservice stations in Brazil, with Petrobras, in Uganda and in Iran onas well as notably the giant South Pars 11 project. The Group renewed its reserves with a replacement rateacquisitions of 136% at constant prices and delivered promising exploration results, with two major discoveriesDirect Énergie, Engie’s LNG business, the increase in the United States (North Platte)share of Novatek to 19.4%, interests in the Iara and Nigeria (Owowo).Lapa fields in Brazil, two new 40-year offshore concessions in Abu Dhabi, which follow the previous Abu Dhabi Marine Areas Ltd (ADMA) offshore concession, and the acquisition of offshore assets from Cobalt in the Gulf of Mexico. Acquisitions were $1,476 million in 2017, including $714 million in resource acquisitions.

Despite lower refining margins,The Group’s cash flow from operating activities for the Downstreamfull-year 2018 was $24,703 million, an increase of 11% compared to $22,319 million for the full-year 2017. The change in working capital at replacement cost for the full-year 2018, which is the decrease in working capital of $769 million as determined in accordance with IFRS adjusted for the pre-tax inventory valuation effect of $(595) million, was $174 million compared to $1,184 million for the full-year 2017. Operating cash flow excluding the change in working capital at replacement cost for the full year 2018 was $24,529 million, an increase of 16% compared to $21,135 million for the full-year 2017. Operating cash flow excluding the change in working capital at replacement cost and excluding financial charges (DACF) for the full-year 2018 was $26,067 million, an increase of 18% compared to $22,183 million for the full-year 2017. The Group’s net cash flow⁽¹⁾ once again achieved its objectives and thereby demonstrated that its results are sustainable, withwas $8,961 million for the full-year 2018 compared to $9,499 million for the full-year 2017, due to an increase of $3,932 million in net investments partially offset by a $3,394 million increase in operating cash flow before changes in working capital changes at replacement cost⁽²⁾ of $7 billioncapital.

See also "- 5.4 Liquidity and ROACE⁽³⁾ above 30%Capital Resources", the highest among the majors. Results from the Refining & Chemicals segment were underpinned by the strong performance of its Asia and Middle East integrated platforms, while Marketing & Services results were driven by growth in retail and lubricants.below.

Financial discipline was successfully maintained across all business segments both for investments ($18.3 billion including resource acquisitions) and operating costs, with savings of $2.8 billion in2017 vs. 2016 exceeding the objective of $2.4 billion. Production costs were reduced to $5.9/boe in 2016, compared to $9.9/boe in 2014.

The $10 billion asset sale program is around 80% complete following the closing of the Atotech sale, and this contributedBrent price rose to the Group’s financial strength with anet-debt-to-equity ratio at 27%, lower than it was in 2014.

In this context, the Board of Directors proposed to increase the dividend, despite the volatility of hydrocarbon prices, to€2.45/share, corresponding to a fourth quarter dividend of€0.62/share, a 1.6% increase compared to the previous three quarterly dividends. This demonstrates the Board’s confidence in the strength of the Group’s results and balance sheet as well as its prospects for cash flow growth.

Brent increased following the announced production cuts agreed by OPEC andnon-OPEC countries, including Russia. However, inventory levels are high and prices are likely to remain volatile. In this context, the Group is continuing to cut costs with the objective of achieving $3.5 billion of cost savings in 2017 and bringing production costs down to $5.5/boe for the year. Investments are moving into the sustainable range needed to deliver profitable future growth and are expected to be between $16 billion and $17 billion in 2017 including resource acquisitions.

In the Upstream, production is set to grow by more than 4% in 2017, supporting the objective of increasing production on average by 5% per year from 2014 to 2020. As a result of this growth, the sensitivity of the portfolio to Brent increases to $2.5 billion⁽⁴⁾ for a $10/b change in Brent in 2017. The Group plans to take advantage of the favorable cost environment by launching around 10 projects over the next 18 months and adding attractive resources to the portfolio.

In 2017, the Downstream is expected to continue generating stable operating cash flow before working capital changes at replacement cost of around $7 billion thanks to its diverse portfolio of activities. Refining & Chemicals’ performance has been strengthened by the restructuring and the segment will continue to benefit from the quality of its integrated platforms, notably in Antwerp, in the United States, in Asia and in the Middle East. The final investment decision to launch the Port Arthur side-cracker is expected to be made in 2017. The Marketing & Services segment is pursuing its cash generation growth strategy by leveraging its strong position in high-potential retail and lubricant markets.

In 2017, the Group expects its breakeven will continue to fall, reaching less than $40/bpre-dividend. Cash flow from operations is expected to cover investments and the cash portion of the dividend at $50/b. TOTAL confirms its medium-term objective to achieve anet-debt-to-equity ratio of 20%.

The Group is committed to maintaining attractive returns for its shareholders and will eliminate the discount on the scrip dividend with Brent at $60/b.

After falling from $100/b in 2014 to $52/$54/b on average in 2015, Brent prices were highly volatile2017 from $44/b in 2016 fluctuating between $27/b and $58/b, with an average of $44/b for the year.while remaining volatile. In 2016,2017, TOTAL’s average liquids price realization⁽¹⁾ decreased increased by 15%25% to $40.3/$50.2/b from $47.4/$40.3/b in 2015.2016. TOTAL’s average natural gas price realization for the Group’s consolidated subsidiaries decreased in 2016increased by 25%15% to $3.56/Mbtu from $4.75/$4.08/Mbtu in 2015. In the downstream, the2017 from $3.56/Mbtu in 2016. The Group’s European refining margin indicator (“ERMI”) was $34/ERMI increased to $40.9/t on average in 2017 compared to $34.1/t in 2016, a 30% decrease comparedan increase of 20% due to the high levels in 2015 ($48.5/t), in the context of highelevated petroleum stocks.product demand. In the fourth quarter of 2016,2017, the ERMI was $41.0/$35.5/t. ThePetrochemicals continued to benefit from a favorable environment for petrochemicals remained favorable.

The Euro remained stable in 2016albeit down compared to the US Dollar, with thea year ago.

The euro-dollar exchange rate averagingaveraged $1.13/€ in 2017 compared to $1.11/€ in 2016 and 2015.2016.

In this lessoverall more favorable environment,non-Group sales in 20162017 were $171,493 million compared to $149,743 million a decreasein 2016, an increase of 9% compared to $165,357 million for 2015. The decrease in15% reflecting the increased hydrocarbon prices and refining margins were partially offset by production growth and strong results for petrochemicals.Group production. Non-Group sales decreased 13%increased 11% for the UpstreamExploration & Production segment, 7%27% for the Gas, Renewables & Power segment, 15% for the Refining & Chemicals segment and 11%12% for the Marketing & Services segment.

Net income (Group share) in 20162017 increased by 22%39% to $8,631 million from $6,196 million from $5,087 million in 2015,2016, mainly due to higher hydrocarbon prices and growth of the Group’s production. In 2017, adjustments to net income (Group share), which included special items of $(2,213) million and after-tax inventory valuation effect of $282 million, had a less negative impact on net income (Group share) of $1,947 million. Special items included mainly an impairment of Fort Hills in 2016Canada (following the operator announcement of special items (as further discussed below)the increase of the project’s costs), withGladstone LNG in Australia and assets in Congo, partially offset by a gain on the Group demonstrating its resilience despite the 19% drop in hydrocarbon prices due to the strengthsale of its integrated model and commitment of its teams to reducing the breakeven.Atotech. In 2016, adjustments to net income (Group share), which included special items of $(2,567) million andafter-tax inventory valuation effect of $479 million, had a negative impact on net income (Group share) of $2,091 millionmillion. Special items in 2016. Special items2016 included impairments on Gladstone LNG in Australia, Angola LNG, and Laggan-Tormore in the United Kingdom, reflecting the decrease in gas price assumptions for the coming years. For a detailed overview of adjustment items for 2016, refer to Note  3 to the Consolidated Financial Statements in the 2016 Registration Document (starting onpage 215), which is incorporated herein by reference. In 2015, adjustment items, which included special items of $(4,675) million andafter-tax inventory valuation effect of $(747) million, had a negative impact on net income (Group share) of $5,431 million. Special items included impairments on Fort Hills in Canada and Gladstone LNG in Australia as well as in Libya, an adjustment to depreciation on Usan in Nigeria following the cancellation of the sale process and the impairment of exploration projects that will not be developed. Excluding these items, adjusted net income declinedin 2017 increased by 21%28% to $10,578 million compared to $8,287 million in 2016 compared to $10,518 million in 2015, primarily due to2016. The increase was the impactresult of lower Brent prices on Upstream results, partially offset by thea much higher contribution from downstream activities.Exploration & Production and the continued decrease in the Group’s breakeven.

Income taxes in 20162017 amounted to $3,029 million, 3.1 times higher than $970 million a decrease of 41% compared to $1,653 million in 2015,2016, due to the relative weight and lowerhigher tax rates in the UpstreamExploration & Production segment in a lowerhigher hydrocarbon price environment.

In 2017, the Company did not buy back any of its shares. In 2016, the Company bought back 100,331,268 TOTAL treasury shares owned by Group affiliates under the authorization granted by the shareholders at the meeting of May 24, 2016, which were subsequently canceled by the Company’s Board of Directors (for additional information, refer to point 3 (“Share buybacks”) of chapter 8 of the 2016 Registration Document (starting onpage 183), which is incorporated herein by reference). TOTAL bought back approximately 4.7 million of its own shares in 2015 (i.e., approximately 0.19% of the share capital as of December 31, 2015) under the authorization granted by the shareholders at the meeting of May 29, 2015. The number of fully-diluted shares at December 31, 2016, was 2,436 million compared to 2,336 million at December 31, 2015.Directors.

Fully-diluted earnings per share based on 2,390 million weighted-average shares, was $3.34 in 2017 compared to $2.51 in 2016, compared to $2.16 in 2015, an increase of 16%33%.

Asset sales completed in 2017 were $1,864$4,239 million, in 2016, mainlyessentially comprised of the sale of a 15%Atotech, mature assets in Gabon, Gina Krog in Norway, part of the interest in the Gina Krog fieldFort Hills project in Norway,Canada, the FUKA gasSPMR pipeline network in the North SeaFrance and the retail networkLPG activities in Turkey.Germany. Asset sales completed in 2016 were $5,968 million in 2015.$1,864 million.

Acquisitions completed in 2017 were $2,033$1,476 million, in 2016, including $780$714 million of resource acquisitions, mainly comprised of the additional 75% interestbonus related to the license for Elk-Antelope in the Barnett shale gas fieldPapua New Guinea, a marketing and logistics network in the United States, and the acquisitions of Saft, LampirisEast Africa and a retail network23% equity share in the Dominican Republic.Tellurian, Inc. Acquisitions completed in 2016 were $3,441$2,033 million, in 2015, including $2,808$780 million of resource acquisitions.

In addition, in early 2018, the Group finalized the acquisition of assets in Brazil from Petrobras for $1.95 billion as well as the sale of TotalErg in Italy for $415 million (including the B2B and the LPG businesses). Finally, in March 2018, TOTAL S.A. finalized the acquisition of Mærsk Oil in a share and debt transaction.

The Group’s cash flow from operating activities for the full-year 2017 was $22,319 million, an increase of 35% compared to $16,521 million in 2016, a decrease of 17% compared to $19,946 million in 2015, essentially due to the decrease in cash flow from operations as a result of lower hydrocarbon prices and refining margins.2016. The change in working capital as determined in accordance with IFRS was $(1,119) million in 2016, compared to $1,683 million in 2015. In 2016, the change in working capital at replacement cost for the full-year 2017, which is the difference between the changedecrease in working capital of $(1,119)$827 million andas determined in accordance with IFRS adjusted for the pre-tax inventory valuation effect of $652$357 million, was $(467)$1,184 million compared to $570$(467) million in 2015.2016. Operating cash flow in 2016 excluding the change in working capital at replacement cost⁽¹⁾ was $16,988 million, a decrease of 12% compared to $19,376 million in 2015.

See also “— 3. Liquidity and Capital Resources”, below.

Market conditions were less favorable in 2015 compared to 2014, with the average Brent price having decreased by 47% to $52.4/b in 2015 compared to $99.0/b in 2014. In 2015, TOTAL’s average liquids price realization decreased by 47% to $47.4/b from $89.4/b in 2014. TOTAL’s average natural gas price realization for the Group’s consolidated subsidiaries decreased in 2015 by 28% to $4.75/Mbtu from $6.57/Mbtu in 2014. In the downstream, the ERMI more than doubled to $48.5/t in 2015 compared to $18.7/t in 2014. In the fourth quarter of 2015, the ERMI was $38.1/t. Petrochemical margins in Europe increased in 2015 due to a strong demand for polymers and the decrease in raw material costs.

The Euro depreciated in 2015 compared to the US Dollar, with the euro-dollar exchange rate averaging $1.11/€ in 2015 compared to $1.33/€ in 2014.

In this context,non-Group sales in 2015 were $165,357 million, a decrease of 30% compared to $236,122 million for 2014, due mainly to the decrease of oil and gas prices, withnon-Group sales decreasing 28% for the Upstream segment, 33% for the Refining & Chemicals segment and 27% for the Marketing & Services segment.

Net income (Group share) in 2015 increased by 20% to $5,087 million from $4,244 million in 2014, mainly due to a less negative impact on net income (Group share) in 2015 of special items, with the strong performance of the Group’s integrated model and its cost reduction program being demonstrated despite the 47% drop in the Brent price. Adjustments to net income (Group share), which included special items of $(4,675) million andafter-tax inventory valuation effect of $(747) million, had a negative impact on net income (Group share) of $5,431 million in 2015. Special items included impairments on Fort Hills in Canada and Gladstone LNG in Australia as well as in Libya, an adjustment to depreciation on Usan in Nigeria following the cancellation of the sale process and the impairment of exploration projects that will not be developed. In 2014, adjustment items, which included special items of $(6,165) million andafter-tax inventory valuation effect of $(2,453) million, had a negative impact on net income (Group share) of $8,593 million. Special items included impairments of oil sands in Canada, unconventional gas notably in the United States, refining in Europe and certain other assets in the Upstream, which was partially offset by a gain on asset sales, including for the Group’s interests in Shah Deniz in Azerbaijan and GTT. Excluding these items, adjusted net income (Group share) declined by 18% to $10,518 million in 2015 compared to $12,837 million in 2014, primarily due to the impact of lower Brent prices on Upstream results, partially offset by a higher contribution from downstream activities.

Income taxes in 2015 amounted to $1,653 million, a decrease of 81% compared to $8,614 million in 2014, as a result of the decrease in taxable income and the Group’s lower tax rate.

TOTAL bought back in 2015 approximately 4.7 million of its own shares (i.e., approximately 0.19% of the share capital as of December 31, 2015) under the authorization granted by the shareholders at the meeting of May 29, 2015. The number of fully-diluted shares at December 31, 2015, was 2,336 million compared to 2,285 million at December 31, 2014.

Fully-diluted earnings per share, based on 2,304 million weighted-average shares, was $2.16 in 2015 compared to $1.86 in 2014, an increase of 16%.

Asset sales were $5,968 million in 2015, comprised mainly of the sales of Bostik, interests in onshore blocks in Nigeria, Totalgaz, the Schwedt Refinery, the Geosel oil storage facility, coal mining assets in South Africa and partial interests in Laggan-Tormore and Fort Hills. Asset sales were $4,650 million in 2014.

Acquisitions were $3,441 million in 2015, including $2,808 million of resource acquisitions, comprised mainly of the renewal of the ADCO license in the United Arab Emirates, the acquisition of a further 0.7% in the capital of Novatek in Russia bringing the Group participation to 18.9%, and the carry on the Utica gas and condensate field in the United States. Acquisitions were $2,539 million in 2014, including $1,765 million of resource acquisitions.

Cash flow from operating activities was $19,946 million in 2015, a decrease of 22% compared to $25,608 million in 2014, essentially due to the decrease in cash flow from operations in the context of a 47% lower Brent price. The change in working capital as determined in accordance with IFRS was $1,683 million in 2015, compared to $4,480 million in 2014. In 2015, the change in working capital at replacement cost, which is the difference between the change in working capital of $1,683 million and the pre-tax inventory valuation effect of $(1,113) million, was $570 million compared to $1,011 million in 2014. Operating cash flow in 2015 excluding the change in working capital at replacement cost for the full-year 2017 was $19,376$21,135 million, a decreasean increase of 21%24% compared to $24,597$16,988 million in 2014.2016. Operating cash flow for the full-year 2017 excluding the change in working capital at replacement cost and without financial charges (DACF) was $22,183 million, an increase of 26% compared to $17,581 million in 2016. The Group’s net cash flow was $9,499 million for the full-year 2017 compared to $(769) million in 2016, mainly due to the nearly $4 billion increase in operating cash flow before working capital changes, the decrease in net investments related to the $3 billion decrease in organic investments and the sale of Atotech.

See also “"- — 3.5.4 Liquidity and Capital Resources”", below.

5.3        Business segment reporting

The financial information for each business segment is reported on the same basis as that used internally by the chief operating decision-maker in assessing segment performance and the allocation of segment resources. Due to their particular nature or significance, certain transactions qualifying as “special items”"special items" are excluded from the business segment figures. In general, special items relate to transactions that are significant, infrequent or unusual. In certain instances, certain transactions such as restructuring costs or asset disposals, which are not considered to be representative of the normal course of business, may qualify as special items although they may have occurred in prior years or are likely to recur in following years.

In accordance with IAS 2, the Group values inventories of petroleum products in its financial statements according to theFirst-In,First-Out (FIFO) method and other inventories using the weighted-average cost method. Under the FIFO method, the cost of inventory is based on the historic cost of acquisition or manufacture rather than the current replacement cost. In volatile energy markets, this can have a significant distorting effect on the reported income. Accordingly, the adjusted results of the Refining & Chemicals and Marketing & Services segments are presented according to the replacement cost method in order to facilitate the comparability of the Group’s results with those of its competitors and to help illustrate the operating performance of these segments excluding the impact of oil price changes on the replacement of inventories. In the replacement cost method, which approximates theLast-In,First-Out (LIFO) method, the variation of inventory values in the statement of income is, depending on the nature of the inventory, determined using either themonth-end price differential between one

period and another or the average prices of the period. The inventory valuation effect is the difference between the results under the FIFO and replacement cost methods.

The effect of changes in fair value presented as an adjustment item reflects, for trading inventories and storage contracts, differences between internal measures of performance used by TOTAL’s management and the accounting for these transactions under IFRS, which requires that trading inventories be recorded at their fair value usingperiod-end spot prices. In order to best reflect the management of economic exposure through derivative transactions, internal indicators used to measure performance include valuations of trading inventories recorded at their fair value based on forward prices. Furthermore, TOTAL, in its trading activities, enters into storage contracts, the future effects of which are recorded at fair value in the Group’s internal economic performance. IFRS, by requiring accounting for storage contracts on an accrual basis, precludes recognition of this fair value effect.

The adjusted business segment results (adjusted operating income and adjusted net operating income) are defined as replacement cost results, adjusted for special items, excluding the effect of changes in fair value. For further information on the adjustments affecting operating income on asegment-by-segment basis, and for a reconciliation of segment figures to figures reported in the Company’s audited consolidated financial statements,Consolidated Financial Statements, see Note 3 to the Consolidated Financial Statements in the 20162018 Registration Document (starting onpage 215265), which is incorporated herein by reference.

The Group measures performance at the segment level on the basis of adjusted net operating income. Net operating income comprises operating income of the relevant segment after deducting the amortization and the depreciation of intangible assets other than leasehold rights, translation adjustments and gains or losses on the sale of assets, as well as all other income and expenses related to capital employed (dividends fromnon-consolidated companies, income from equity affiliates and capitalized interest expenses) and after income taxes applicable to the above. The income and expenses not included in net operating income that are included in net income are interest expenses related to long-term liabilities net of interest earned on cash and cash equivalents, after applicable income taxes (net cost of net debt andnon-controlling interests). Adjusted net operating income excludes the effect of the adjustments (special items and the inventory valuation effect) described above. For further discussion of the calculation of net operating income and the calculation of return on average capital employed (ROACE⁽¹⁾), see Note 3 to the Consolidated Financial Statements in the 20162018 Registration Document (starting onpage 215265), which is incorporated herein by reference.

2016 comparative information is restated at the segment level.

2018 vs. 20152017

MarketIn 2018, market conditions were lessmore favorable than in 2016 compared to 2015.2017. The average realized price of liquids decreasedincreased by 15%28% and the average realized gas pricesprice by 25%17%.

For the full-year 2016,2018, hydrocarbon production was 2,4522,775 kboe/d, an increase of 4.5%more than 8% compared to 2,347 kboe/d2,566 in 2015,2017, due to:

-+9% for start-ups and ramp-ups on new projects, notably Yamal LNG, Moho Nord, Fort Hills, Kashagan, Kaombo Norte and Ichthys.

-+3% portfolio effect. The addition of Maersk Oil, Al Shaheen in Qatar, Waha in Libya, Lapa and Iara in Brazil as well as the acquisition of an additional 0.5% of Novatek were partially offset by the expiration of the Mahakam permit at the end of 2017 and the sales of Visund in Norway and Rabi in Gabon.

--4% for natural field declines and PSC price effect ⁽¹⁾.

For a discussion of the Group’s proved reserves, refer to point 2.1.1.2 (“Reserves”2.1.3 ("Reserves") of chapter 2 of the 20162018 Registration Document (starting onpage 1034), which is incorporated herein by reference. See also point 1 (“9.1 ("Oil and gas information pursuant to FASBAccounting Standards Codification 932”932") of chapter 119 of the 20162018 Registration Document (starting onpage 308362), which is incorporated herein by reference, for additional information on proved reserves, including tables showing changes in proved reserves by region.

Non-Group sales for the Exploration & Production segment in 20162018 were $14,683$10,989 million compared to $16,840$8,477 million in 2015,2017, an increase of 30%.

The segment’s adjusted net operating income was $10,210 million in 2018, an increase of 71% compared to $5,985 million in 2017, due to the increase in hydrocarbon prices, despite a decrease of 13%.tax rate that increased in line with the increase in hydrocarbon prices, and strong production growth.

The effective tax rate increased from 41.2% in 2017 to 46.5% in 2018, in line with the increase in oil prices.

Adjusted net operating income for the Exploration & Production segment excludes special items. In 2018, the exclusion of special items had a positive impact on the segment’s adjusted net operating income of $1,022 million due to the impairment on Ichthys related to the sale of a partial interest by the Group and other assets mainly located in Algeria, Colombia and Congo (for additional information, refer to Note 3 to the Consolidated Financial Statements in the 2018 Registration Document (starting on page 265), which is incorporated herein by reference). In 2017, the exclusion of special items had a positive impact on the segment’s adjusted net operating income of $3,880 million. Special items mainly included impairments of Fort Hills in Canada (following the operator announcement of the increase of the project��s costs), Gladstone LNG in Australia, assets in the Republic of the Congo and gas assets in the United Kingdom, as well as assets in the United States and Norway.

Technical costs ⁽¹⁾ for consolidated affiliates, calculated in accordance with ASC 932 ⁽²⁾, continued decreasing to $18.9/boe in 2018, including $5.7/boe of production costs, compared to $19.5/boe in 2017, including $5.4/boe of production costs.

The segment’s cash flow from operating activities excluding financial charges for the full-year 2018 was $19,803 million, an increase of 54% compared to $12,821 million for the full-year 2017. Operating cash flow excluding the change in working capital at replacement cost and excluding financial charges for the full-year 2018 was $19,374 million, an increase of 31% compared to $14,753 million for the full-year 2017. Operating cash flow before working capital changes less organic investments for the full-year 2018 was $10,210 million compared to $5,985 million in 2017, an increase of 71%.

For information on the segment’s capital expenditures, refer to points 2.1.2 ("Exploration and development") (on page 34) and 2.5 ("Investments") (starting on page 68) of chapter 2 of the 2018 Registration Document, which are incorporated herein by reference. See also "- 5.4 Liquidity and Capital Resources", below.

In this context, the segment’s ROACE for the full-year 2018 was 9% compared to 6% for the full-year 2017.

2017 vs. 2016

In 2017, market conditions were more favorable than in 2016. The average realized price of liquids increased by 25% and the average realized gas price by 15%.

For the full-year 2017, hydrocarbon production was 2,566 thousand barrels of oil equivalent per day (kboe/d), an increase of 5% compared to 2,452 kboe/d in 2016, due to the following:

-+5% due to new start-ups and ramp-ups, notably Moho Nord, Kashagan, Edradour and Glenlivet, and Angola LNG;

-+2% portfolio effect, mainly due to taking over the giant Al Shaheen oil field concession in Qatar and acquiring an additional 75% interest in the Barnett shale in the United States, partially offset by the exit from the Upstreamsouthern sector in the Republic of the Congo and asset sales in Norway;

-+1% related to improved security conditions in Libya and Nigeria; and

--3% due to natural field decline, the PSC price effect and OPEC quotas.

Non-Group sales for the Exploration & Production segment was $3,633in 2017 were $8,477 million compared to $7,629 million in 2016, a decreasean increase of 24%11%.

The segment’s adjusted net operating income was $5,985 million in 2017, an increase of 86% compared to 2015. The$3,217 million in 2016, notably due to production growth, cost reductions and an increase in production combined with the decrease in operating costs as well as the loweroil and gas prices.

The effective tax rate partially offsetincreased from 27.7% in 2016 to 41.2% in 2017, in line with the impact of lowerrise in hydrocarbon prices.

Adjusted net operating income for the UpstreamExploration & Production segment excludes special items. The exclusion of special items had a positive impact on the segment’s adjusted net operating income in 2017 of $3,880 million. Special items mainly included impairments of Fort Hills in Canada (following the operator announcement of the increase of the project’s costs), Gladstone LNG in Australia, assets in the Republic of the Congo and gas assets in the United Kingdom, as well as assets in the United States and Norway. In 2016, the exclusion of $2,055 million, comprisedspecial items had a positive impact on the segment’s adjusted net operating income of $1,872 million. Special items mainly ofincluded impairments on Gladstone LNG in Australia, Angola LNG and Laggan-Tormore in the United Kingdom, reflecting the decrease in gas price assumptions for the coming years (for additional information,years.

Technical costs for consolidated affiliates, calculated in accordance with ASC 932 continued to fall, to $19.5/boe in 2017 compared to $20.4/boe in 2016. This decrease was mainly due to the reduction in production costs from $5.9/boe in 2016 to $5.4/boe in 2017.

The segment’s cash flow from operating activities excluding financial charges for the full-year 2017 was $12,821 million, an increase of 30% compared to $9,866 million in 2016. Operating cash flow for the full-year 2017 excluding the change in working capital at replacement cost and without financial charges was $14,753 million compared to $10,592 million in 2016, an increase of 39%.

In this context, the segment’s ROACE for the full-year 2017 was 6% compared to 3% for the full-year 2016.

(2)  Financial Accounting Standards Board (FASB) Accounting Standards Codification Topic 932, Extractive industries - Oil and Gas.

5.3.2     Gas, Renewables & Power segment

(a)  For the definitions of "operating income" and "net operating income", refer to Note 3 to the Consolidated Financial Statements in the 20162018 Registration Document (starting onpage 215265), which is incorporated herein by reference). In 2015, the exclusion of special items had a positive impact on the segment’s adjusted net operating income of $5,990 million, comprised mainly of impairments on Fort Hills in Canada and Gladstone LNG in Australia as well as in Libya, an adjustment to depreciation on Usan in Nigeria following the cancellation of the sale process and the impairment of exploration projects that will not be developed.

Technical costs⁽¹⁾ for consolidated subsidiaries, calculated in accordance with ASC 932⁽²⁾, were reduced to $20.4/boe in 2016 compared to $23.0/boe in 2015. This decrease was essentially due to the reduction in operating costs from $7.4/boe in 2015 to $5.9/boe in 2016.

Cash flow from operating activities was $9,675 million in 2016, a decrease of 13% compared to $11,182 million in 2015. Operating cash flow in 2016 for the segment excluding the change in working capital at replacement cost of $(237) million ($3 million in 2015) was $9,912 million, a decrease of 11% compared to $11,179 million in 2015, essentially due to the decrease in hydrocarbon prices, partially offset by the increase in production and decrease in operating costs.

For information on the Upstream segment’s capital expenditures, refer to points 2.1.1.1 (“Exploration and development”) (onpage 10) and 3 (“Investments”) (starting onpage 42) of chapter 2 of the 2016 Registration Document, which are incorporated herein by reference. See also “— 3. Liquidity and Capital Resources”, below.

In this context, the segment’s ROACE for the full-year 2016 was 3% compared to 5% for the full-year 2015.

2015 vs. 2014

Market conditions were less favorable in 2015. The average realized price of liquids fell by 47% and the average realized price of gas by 28% compared to 2014.

For the full-year 2015, hydrocarbon production was 2,347 kboe/d, an increase of 9.4% compared to 2014, due to the following:

For a discussion of the Group’s proved reserves, refer to point 2.1.1.2 (“Reserves”) of chapter 2 of the 2016 Registration Document (starting onpage 10), which is incorporated herein by reference.

(b)  Adjusted for special items. See also point 1 (“Oil and gas information pursuantNote 3 to FASB Accounting Standards Codification 932”) of chapter 11 of the 2016Consolidated Financial Statements in the 2018 Registration Document (starting onpage 308265), which is incorporated herein by reference, forreference.

(c)  Including acquisitions and increases in non-current loans. For additional information on proved reserves, including tables showing changes in proved reservesinvestments, refer to point 2.5 of chapter 2 of the 2018 Registration Document (starting on page 68), which is incorporated herein by region.reference.

(d)  Including divestments and reimbursements of non-current loans.

(e)  "Organic investments" = net investments, excluding acquisitions, divestments and other operations with non-controlling interests. For additional information on investments, refer to point 2.5 of chapter 2 of the 2018 Registration Document (starting on page 68), which is incorporated herein by reference.

2018 vs. 2017

Non-Group sales for the Gas, Renewables & Power segment in 20152018 were $16,840$16,136 million compared to $23,484$12,854 million in 2014, a decrease2017, an increase of 28%26%.

AdjustedThe segment’s adjusted net operating income from the Upstream segment was $4,774$756 million for the full-year 2015, a decrease of 55% compared to $10,504in 2018, 1.6 times higher than $485 million for 2014, essentiallyin 2017, notably due to the lower pricegood performance of hydrocarbons, partially offset by anLNG and gas/power trading activities. The acquisitions of Direct Énergie and the LNG business of Engie account for the increase in production, a decreaseinvestments to $3.5 billion in operating costs, and a lower effective tax rate.the full-year 2018, 4.4 times higher than $797 million in the full-year 2017.

Adjusted net operating income for the UpstreamGas, Renewables & Power segment excludes special items. The exclusion of special items had a positive impact on the segment’s adjusted net operating income in 20152018 of $5,990 million, comprised mainly of impairments on Fort Hills in Canada and Gladstone LNG in Australia as well as in Libya, an adjustment to depreciation on Usan in Nigeria following the cancellation of the sale process and$751 million. Special items included the impairment of exploration projects that will not be developed.production facilities by SunPower (for additional information, refer to Note 3(D) to the Consolidated Financial Statements in the 2018 Registration Document (starting on page 275), which is incorporated herein by reference). In 2014,2017, the exclusion of special items had a positive impact on the segment’s adjusted net operating income of $4,507 million, comprised mainly of the impairment of the Group’s oil sands assets in Canada, its unconventional gas assets, notably in the United States, and certain other assets in the Upstream segment.$870 million.

Technical costs for consolidated subsidiaries, calculated in accordance with ASC 932, were $23.0/boe in 2015 compared to $28.3/boe in 2014. This reduction was essentially due to the execution of the Group’s program to reduce operating costs (which decreased from $9.9/boe in 2014 to $7.4/boe in 2015) and lower depreciation (portfolio effect).

CashThe segment’s cash flow from operating activities excluding financial charges for the full-year 2018 was $11,182$(670) million in 2015, a decrease of 33% compared to $16,666$1,055 million for the full-year 2017. The increase in 2014.working capital related to the consolidation of the acquisitions of Direct Énergie and the LNG business of Engie was mainly responsible for the negative cash flow from operations in the full-year 2018. Operating cash flow in 2015 for the segment excluding the change in working capital at replacement cost and excluding financial charges was $513 million for the full-year 2018, an increase of $3 million ($(2,001) million in 2014) was $11,179 million, a decrease of 40%74% compared to $18,667$294 million in 2014.for the full-year 2017.

For information on the Upstream segment’s capital expenditures,investments, refer to points 2.1.1.1 (“Exploration and development”) (onpage 10) and 3 (“Investments”) (starting onpage 42)point 2.5 of chapter 2 of the 20162018 Registration Document (starting on page 68), which areis incorporated herein by reference. See also “"- — 3.5.4 Liquidity and Capital Resources”", below.

In this context, the segment’s ROACE for the full-year 20152018 was 5%11% compared to 11%10% for the full-year 2014.full year 2017.

2016 vs. 2015

The ERMI averaged $34/t in 2016, a decrease of 30% compared to the high level of 2015, in the context of high petroleum product stocks. In the fourth quarter of 2016, the ERMI was $41.0/t. Refinery throughput for the full-year 2016 decreased by 3% compared to 2015, notably due to shutdowns in Europe and the United States in the second quarter and the sale of the Schwedt refinery in Germany.

Non-Group sales for the Gas, Renewables & Power segment in 20162017 were $65,632$12,854 million compared to $70,623$10,124 million in 2015, a decrease2016, an increase of 7%27%.

The segment’s adjusted net operating income was $4,201$485 million in 2017, an increase of 10% compared to $439 million in 2016.

Adjusted net operating income for the Gas, Renewables & Power segment excludes special items. The exclusion of special items had a positive impact on the segment’s adjusted net operating income in 2017 of $870 million. Special items included an impairment concerning SunPower ⁽¹⁾ in the United States given the depressed economic environment of the solar activity. In 2016, the exclusion of special items had a positive impact on the segment’s adjusted net operating income of $533 million.

The segment’s cash flow from operating activities excluding financial charges for the full-year 2017 was $1,055 million, an increase of 79% compared to $589 million in 2016. Operating cash flow for the full-year 2017 excluding the change in working capital at replacement cost and without financial charges was $294 million compared to $176 million in 2016, an increase of 67%.

In this context, the segment’s ROACE for the full-year 2017 was 10% compared to 9% for the full year 2016.

5.3.3     Refining & Chemicals segment

(a)  Includes share of TotalErg, and African refineries reported in the Marketing & Services segment.

(b)  Based on distillation capacity at the beginning of the year.

(a)  For the definitions of "operating income" and "net operating income", refer to Note 3 to the Consolidated Financial Statements in the 2018 Registration Document (starting on page 265), which is incorporated herein by reference.

(b)  Adjusted for special items. See Note 3 to the Consolidated Financial Statements in the 2018 Registration Document (starting on page 265), which is incorporated herein by reference.

(c)  Including acquisitions and increases in non-current loans. For additional information on investments, refer to point 2.5 of chapter 2 of the 2018 Registration Document (starting on page 68), which is incorporated herein by reference.

(d)  Including divestments and reimbursements of non-current loans.

(e)  "Organic investments" = net investments, excluding acquisitions, divestments and other operations with non-controlling interests. For additional information on investments, refer to point 2.5 of chapter 2 of the 2018 Registration Document (starting on page 68), which is incorporated herein by reference.

2018 vs. 2017

Refinery throughput was stable in full-year 2018 compared to full-year 2017. Lower throughput in Europe linked to planned maintenance, notably at Antwerp during the second quarter, was offset by higher throughput outside Europe. The ERMI decreased to $32.3/t on average in 2018 compared to $40.9/t in 2017, a decrease of 14%21% mainly due to rising crude oil prices.

Non-Group sales for the Refining & Chemicals segment in 2018 were $92,025 million compared to 2015, essentially due$75,505 million in 2017, an increase of 22%.

The segment’s adjusted net operating income was resilient at $3,379 million for the full-year 2018, a decrease of 11% compared to the decrease$3,790 million in refining margins. Petrochemicals continued to generate good results, notably due to the strong contribution from the Group’s major integrated platforms in Asia and the Middle East.2017.

Adjusted net operating income for the Refining & Chemicals segment excludes any after-tax inventory valuation effect and special items. The exclusion of the inventory valuation effect had a positive impact on the segment’s adjusted net operating income in 2018 of $413 million compared to a negative impact of $298 million in 2017. The exclusion of special items had a positive impact on the segment’s adjusted net operating income in 2018 of $116 million, compared to a negative impact of $2,117 million in 2017.

The segment’s cash flow from operating activities excluding financial charges for the full-year 2018 was $4,308 million, a decrease of 42% compared to $7,411 million for the full-year 2017. Operating cash flow for the full-year 2018 excluding the change in working capital at replacement cost and excluding financial charges was $4,388 million compared to $4,728 million for the full-year 2017, a decrease of 7%.

For information on the segment’s investments, refer to point 2.5 of chapter 2 of the 2018 Registration Document (starting on page 68), which is incorporated herein by reference. See also "- 5.4 Liquidity and Capital Resources", below.

In this context, the segment’s ROACE for the full-year 2018 was 31% compared to 33% for the full year 2017.

2017 vs. 2016

Refinery throughput decreased by 7% for the full-year 2017 compared to 2016 as a result of the definitive ending of distillation capacity at La Mède (France) and Lindsey (UK) and the temporary shutdown due to Hurricane Harvey in the United States. The ERMI increased to $40.9/t on average in 2017 compared to $34.1/t in 2016, an increase of 20% due to elevated petroleum product demand. In the fourth quarter of 2017, the ERMI was $35.5/t. Petrochemicals continued to benefit from a favorable environment albeit down compared to a year ago.

Non-Group sales for the Refining & Chemicals segment in 2017 were $75,505 million compared to $65,632 million in 2016, an increase of 15%.

The segment’s adjusted net operating income was $3,790 million for the full-year 2017, a decrease of 10% compared to $4,195 million in 2016, notably due to the impact of Hurricane Harvey, the impact of modernization work on the Antwerp platform and the sale of Atotech in early 2017 as well as lower trading results due to the evolution of the market into backwardation ⁽¹⁾.

Adjusted net operating income for the Refining & Chemicals segment excludes any after-tax inventory valuation effect and special items. The exclusion of the inventory valuation effect had a negative impact on the segment’s adjusted net operating income in 20162017 of $500$298 million compared to a positivenegative impact of $590$500 million in 2015.2016. The exclusion of special items had a positivenegative impact on the segment’s adjusted net operating income in 20162017 of $113 million compared to a negative impact in 2015 of $920$2,117 million, consisting essentially of gainsa gain on asset sales.the sale of Atotech, compared to a positive impact of $169 million in 2016.

CashThe segment’s cash flow from operating activities excluding financial charges for the full-year 2017 was $4,587$7,411 million, an increase of 62% compared to $4,584 million in 2016, a decrease of 29% compared to $6,432 million in 2015.2016. Operating cash flow in 2016 for the segmentfull-year 2017 excluding the change in working capital at replacement cost of $(291)and without financial charges was $4,728 million ($647compared to $4,873 million in 2015) was $4,878 million,2016, a decrease of 16% compared to $5,785 million in 2015.

For information on the Refining & Chemicals segment’s investments, refer to point 3 (“Investments”) of chapter 2 of the 2016 Registration Document (starting onpage 42), which is incorporated herein by reference. See also “— 3. Liquidity and Capital Resources”, below.3%.

In this context, the segment’s ROACE for the full-year 20162017 was 38%33% compared to 41%38% for the full year 2015.2016.

5.3.4     Marketing & Services segment

(a)  Excludes trading and bulk Refining sales, which are reported under the Refining & Chemicals segment; includes share of TotalErg.

(a)  For the definitions of "operating income" and "net operating income", refer to Note 3 to the Consolidated Financial Statements in the 2018 Registration Document (starting on page 265), which is incorporated herein by reference.

2015(b)  Adjusted for special items. See Note 3 to the Consolidated Financial Statements in the 2018 Registration Document (starting on page 265), which is incorporated herein by reference.

(c)  Including acquisitions and increases in non-current loans. For additional information on investments, refer to point 2.5 of chapter 2 of the 2018 Registration Document (starting on page 68), which is incorporated herein by reference.

(d)  Including divestments and reimbursements of non-current loans.

(e)  "Organic investments" = net investments, excluding acquisitions, divestments and other operations with non-controlling interests. For additional information on investments, refer to point 2.5 of chapter 2 of the 2018 Registration Document (starting on page 68), which is incorporated herein by reference.

2018 vs. 20142017

In 2015, the segment benefited from a favorable environment, notably in Europe. The ERMI averaged $48.5/t in 20152018, petroleum product sales increased by 1% compared to $18.7/t2017. The sale of TotalErg in 2014, mainly due to strong demand for gasoline. InItaly was offset by higher sales in the fourth quarterrest of 2015, the ERMI was $38.1/t. Refinery throughput in 2015 increased by 14% to 2,023 kb/d compared to 1,775 kb/d in 2014. Actions to improve the availability in Europe resulted in a high utilization rate of 89%. The segment also benefited from theramp-up of SATORP in Saudi Arabia. Petrochemical margins in Europe increased in 2015 due to strong demand for polymers and the decrease in raw material costs.world.

Non-Group sales for the Marketing & Services segment in 20152018 were $70,623$90,206 million compared to $106,124$74,634 million in 2014, a decrease2017, an increase of 33%21%.

The segment’s adjusted net operating income was stable in 2015 was $4,8892018 at $1,652 million, twice the levela decrease of $2,4891% compared to $1,676 million in 2014, due to strong industrial performance during a period of high margins and cost reduction programs.2017.

Adjusted net operating income for the RefiningMarketing & ChemicalsServices segment excludes anyafter-tax inventory valuation effect and special items. The exclusion of the inventory valuation effect had a positive impact on the segment’s adjusted net operating income in 20152018 of $590$5 million compared to a positive impact of $2,114$3 million in 2014, for both periods essentially due to a reduction of stock.2017. The exclusion of special items had a negativepositive impact on the segment’s adjusted net operating income in 20152018 of $920$31 million consisting essentially of gains on asset sales, compared to a positivenegative impact of $1,585$82 million in 2014, consisting essentially of impairments of European refining assets.2017.

CashThe segment’s cash flow from operating activities excluding financial charges for the full-year 2018 was $6,432$2,759 million, in 2015, an increase of 2%24% compared to $6,302$2,221 million in 2014.2017. Operating cash flow in 2015 for the segmentfull-year 2018 excluding the change in working capital at replacement cost of $647and without financial charges was $2,156 million ($2,274compared to $2,242 million in 2014) was $5,785 million, an increase2017, a decrease of 44% compared to $4,028 million in 2014.4%.

For information on the RefiningMarketing & ChemicalsServices segment’s investments, refer to point 3 (“Investments”)2.5 of chapter 2 of the 20162018 Registration Document (starting onpage 6842), which is incorporated herein by reference. See also “"- — 3.5.4 Liquidity and Capital Resources”", below.

In this context, the segment’s ROACE for the full-year 20152018 was 41%25% compared to 15%26% for the full year 2014.2017.

20162017 vs. 20152016

In 2016, refined2017, petroleum product sales decreased slightlywere generally stable compared to 2015, essentially due to the saleprevious year, with a move toward Africa and Asia where the Group has strong growth. European sales were affected by the divestment of the retail networkmature LPG distribution activities in Turkey. Excluding portfolio effects, retail network sales increased by around 4%. Sales of land-based lubricants also increased by around 4%.Belgium and Germany.

Non-Group sales for the Marketing & Services segment in 20162017 were $69,421$74,634 million compared to $77,887$66,351 million in 2015,2016, an increase of 12%.

The Marketing & Services segment’s results continue to grow in a decreasecontext of 11%.

Adjustedstrong retail margins, notably in Africa. The segment’s adjusted net operating income in 2016 for the segment2017 was $1,586$1,676 million, an increase of 8% compared to $1,559 million in 2016, a decrease of 7% compared to 2015. Excluding New Energies, which benefited in 2015 from the delivery of the Quinto solar farm in the United States, adjusted net operating income was stable despite asset sales (retail network in Turkey).2016.

Adjusted net operating income for the Marketing & Services segment excludes anyafter-tax inventory valuation effect and special items. The exclusion of the inventory valuation effect had a positive impact on the segment’s adjusted net operating income in 20162017 of $13$3 million compared to a positive impact of $169$13 million in 2015.2016. The exclusion of special items had a positivenegative impact on the segment’s adjusted net operating income in 20162017 of $534$82 million including restructuring charges related to New Energies, compared to a positive impact of $60$128 million in 2015.2016.

CashThe segment’s cash flow from operating activities excluding financial charges for the full-year 2017 was $1,623$2,221 million, an increase of 21% compared to $1,833 million in 2016, a decrease of 30% compared to $2,323 million in 2015.2016. Operating cash flow in 2016 for the segmentfull-year 2017 excluding the change in working capital at replacement cost of $(208)and without financial charges was $2,242 million ($258compared to $1,966 million in 2015) was $1,831 million, a decrease2016, an increase of 11% compared to $2,065 million in 2015.

For information on the Marketing & Services segment’s investments, refer to point 3 (“Investments”) of chapter 2 of the 2016 Registration Document (starting onpage  42), which is incorporated herein by reference. See also “— 3. Liquidity and Capital Resources”, below.14%.

In this context, the segment’s ROACE for the full-year 20162017 was 18%26% compared to 20%27% for the full year 2015.2016.

2015 vs. 20145.4

The segment’s petroleum product sales were 1,818 kb/d in 2015 compared to 1,769 kb/d in 2014, an increase of 3%. In addition to strong growth in Africa, the sector benefited from its strategic repositioning in Europe and demand stimulated by lower prices.

Non-Group sales for the segment in 2015 were $77,887 million compared to $106,509 million in 2014, a decrease of 27%.

Adjusted net operating income in 2015 for the segment was $1,699 million compared to $1,254 million in 2014, an increase of 35% benefiting from an increase in sales and margins in a favorable environment, and the contribution of SunPower.

Adjusted net operating income for the Marketing & Services segment excludes anyafter-tax inventory valuation effect and special items. The exclusion of the inventory valuation effect had a positive impact on the segment’s adjusted net operating income in 2015 of $169 million compared to a positive impact of $384 million in 2014. The exclusion of special items had a positive impact on the segment’s adjusted net operating income in 2015 of $60 million compared to a positive impact of $196 million in 2014.

Cash flow from operating activities was $2,323 million in 2015, a decrease of 15% compared to $2,721 million in 2014. Operating cash flow in 2015 for the segment excluding the change in working capital at replacement cost of $258 million ($705 million in 2014) was $2,065 million, an increase of 2% compared to $2,016 million in 2014.

For information on the Marketing & Services segment’s investments, refer to point 3 (“Investments”) of chapter 2 of the 2016 Registration Document (starting onpage  42), which is incorporated herein by reference. See also “— 3.        Liquidity and Capital Resources”, below.capital resources

In this context, the segment’s ROACE for the full-year 2015 was 20% compared to 13% for the full year 2014.