UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM20-F

OR

FOR THE FISCAL YEAR ENDED DECEMBER 31, 20152017

OR

OR

Date of event requiring this shell company report

For the transition period fromto

Commission file number001-31236

TSAKOS ENERGY NAVIGATION LIMITED

(Exact name of Registrant as specified in its charter)

Not Applicable

(Translation of Registrant’s name into English)

Bermuda

(Jurisdiction of incorporation or organization)

367 Syngrou Avenue

175 64 P. Faliro

Athens, Greece

011-30210-9407710

(Address of principal executive offices)

Paul Durham

367 Syngrou Avenue

175 64 P. Faliro

Athens, Greece

Telephone:011-30210-9407710

E-mail: ten@tenn.gr

Facsimile:011-30210-9407716

(Name, Address, Telephone Number,E-mail and Facsimile Number of Company Contact Person)

Securities registered or to be registered pursuant to Section 12(b) of the Act:

Securities registered or to be registered pursuant to Section 12(g) of the Act: None

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act: None

As of December 31, 2015,2017, there were 87,338,65286,319,583 of the registrant’s Common Shares, 2,000,000 Series B Preferred Shares, 2,000,000 Series C Preferred Shares, and 3,400,0003,424,803 Series D Preferred Shares and 4,600,000 Series E Preferred Shares outstanding.

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  ¨☐    No  x☒

If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.    Yes  ¨☐    No  x☒

Note—Checking the box above will not relieve any registrant required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 from their obligations under those Sections.

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x☒    No  ¨☐

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of RegulationS-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  x☒    No  ¨☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, anon-accelerated filer or a non-accelerated filer.an emerging growth company. See definitionthe definitions of “accelerated filer and large“large accelerated filer”, “accelerated filer” and “emerging growth company” in Rule12b-2 of the Exchange Act. (Check one):

Large accelerated filer  ¨☐    Accelerated filer   x☒    Non-accelerated filer  ¨☐    Emerging growth company  ☐

If an emerging growth company that prepares its financial statements in accordance with U.S. GAAP, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  ☐

Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:

If “Other” has been checked in response to the previous question, indicate by check mark which financial statement item the registrant has elected to follow.    Item 17  ¨☐    Item 18  ¨☐

If this is an annual report, indicate by check mark whether the registrant is a shell company (as defined in Rule12b-2 of the Exchange Act).    Yes  ¨☐    No  x☒

FORWARD-LOOKING INFORMATION

All statements in this Annual Report on Form20-F that are not statements of historical fact are “forward-looking statements” within the meaning of the United States Private Securities Litigation Reform Act of 1995. The disclosure and analysis set forth in this Annual Report on Form20-F includes assumptions, expectations, projections, intentions and beliefs about future events in a number of places, particularly in relation to our operations, cash flows, financial position, plans, strategies, business prospects, changes and trends in our business and the markets in which we operate. These statements are intended as forward-looking statements. In some cases, predictive, future-tense or forward-looking words such as “believe,” “intend,” “anticipate,” “estimate,” “project,” “forecast,” “plan,” “potential,” “may,” “should” and “expect” and similar expressions are intended to identify forward-looking statements, but are not the exclusive means of identifying such statements.

Forward-looking statements include, but are not limited to, such matters as:

We caution that the forward-looking statements included in this Annual Report on Form20-F represent our estimates and assumptions only as of the date of this Annual Report on Form20-F and are not intended to give any assurance as to future results. These forward-looking statements are not statements of historical fact and represent only our management’s belief as of the date hereof, and involve risks and uncertainties that could cause actual results to differ materially and inversely from expectations expressed in or indicated by the forward-looking statements. Assumptions, expectations, projections, intentions and beliefs about future events may, and often do, vary from actual results and these differences can be material. There are a variety of factors, many of which are beyond our control, which affect our operations, performance, business strategy and results and could cause actual reported results and performance to differ materially from the performance and expectations expressed in these forward-looking statements. These factors include, but are not limited to, supply and demand for crude oil carriers, product tankers and LNG carriers, charter rates and vessel values, supply and demand for crude oil and petroleum products and liquefied natural gas, accidents, collisions and spills, environmental and other government regulation, the availability of debt financing, fluctuation of currency exchange and interest rates and the other risks and uncertainties that are outlined in this Annual Report on Form20-F. As a result, the forward-looking events discussed in this Annual Report on Form20-F might not occur and our actual results may differ materially from those anticipated in the forward-looking statements. Accordingly, you should not unduly rely on any forward-looking statements.

We undertake no obligation to update or revise any forward-looking statements contained in this Annual Report on Form20-F, whether as a result of new information, future events, a change in our views or expectations or otherwise. New factors emerge from time to time, and it is not possible for us to predict all of these factors. Further, we cannot assess the impact of each such factor on our business or the extent to which any factor, or combination of factors, may cause actual results to be materially different from those contained in any forward-looking statement.

PART I

Tsakos Energy Navigation Limited is a Bermuda company that is referred to in this Annual Report onForm 20-F, together with its subsidiaries, as “Tsakos Energy Navigation,” “the Company,” “we,” “us,” or “our.” This report should be read in conjunction with our consolidated financial statements and the accompanying notes thereto, which are included in Item 18 to this report.

Not Applicable.

Not Applicable.

Selected Consolidated Financial Data and Other Data

The following table presents selected consolidated financial and other data of Tsakos Energy Navigation Limited for each of the five years in the five-year period ended December 31, 2015.2017. The table should be read together with “Item 5. Operating and Financial Review and Prospects.” The selected consolidated financial data of Tsakos Energy Navigation Limited is a summary of, is derived from and is qualified by reference to, our consolidated financial statements and notes thereto which have been prepared in accordance with U.S. generally accepted accounting principles (“US GAAP”).

Our audited consolidated statements of comprehensive income/(loss),income, other comprehensive income/(loss),income, stockholders’ equity and cash flows for the years ended December 31, 2015, 2014,2017, 2016, and 2013,2015, and the consolidated balance

sheets at December 31, 20152017 and 2014,2016, together with the notes thereto, are included in “Item 18. Financial Statements” and should be read in their entirety.

Selected Consolidated Financial and Other Data

(Dollars inIn thousands of U.S. dollars, except for share and per share amounts and fleet data)

Derivation of time charter equivalent per day (amounts in thousands of U.S. dollars except for days and per day amounts):

Ratio of Earnings to Fixed Charges and Preference Dividends

The following table sets forth our ratio of earnings to fixed charges and preference dividends for the periods presented:

Other than these adjustments, there has been no material change in our capitalization from debt or equity issuances,re-capitalization or special dividends between December 31, 20152017 and April 5, 2016.20, 2018.

This table should be read in conjunction with our consolidated financial statements and the notes thereto, and “Item 5. Operating and Financial Review and Prospects,” included elsewhere in this Annual Report.

Reasons For the Offer and Use of Proceeds

Not Applicable.

General Market Overview—World Oil Demand / Supply and Trade (Howe Robinson)the Tanker Market

All of the statistical data and other information presented in this section entitled “General Market Overview—World Oil Demand / Supply and Trade,the Tanker Market,” including the analysis of the various sectors of the oil tanker industry, has been provided by Howe Robinson Partners (UK) Ltd (“Howe Robinson”). Howe Robinson has advised that the statistical data and other information contained herein are drawn from its database and other sources. In connection therewith, Howe Robinson has advised that: (a) certain information in Howe Robinson’s database is derived from estimates or subjective judgments; (b) the information in the databases of other maritime data collection agencies may differ from the information in Howe Robinson’s database; and (c) while Howe Robinson has taken reasonable care in the compilation of the statistical and other information and believes it to be accurate and correct, data compilation is subject to limited audit and validation procedures.

General Market OverviewIn 2017, OPEC’s market management agreement altered trade flows, increasing voyage distances as Atlantic crude oil became attractive to Asian buyers. U.S. crude exports increased substantially and large volumes were sent east. Due to recent U.S. infrastructure plans, we expect this trade to grow.

(All text, dataInvoluntary over compliance with OPEC prescribed targets for reduced production by Venezuela and charts providedunder compliance by Howe Robinson)

World Oil Demand/Supplysome Middle East Gulf (MEG) producers all helped solidify tanker demand. Product demand exceeding domestic refinery capacity in South and Central America helped increase U.S. product exports to the region. Longer haul West-East naphtha movements grew, drawing more LRs into the Atlantic Basin. Chinese product export quotas increased, with exports to destinations primarily served by the MR market. However, except for occasional rallies, overall earnings remained subdued across all markets as the increase in demand for tonnage still did not match tonnage supply and the market remains in structural oversupply.

OPEC

Initially OPEC increased production during 2014-2016 in an attempt to defend their market share against an increasingly assertive shale market. The ever lowering breakeven of shale producers and their increased hedging activities ensured that oil production globally, exceeded demand. This led to two outcomes:

Within this environment, OPEC along with tennon-OPEC nations agreed in November 2017 to limit their production with the nominal target being a return of stocks to their five year average beginning in January 2018. OPEC agreed to a cut of 1.2mb/d withnon-OPEC signatories cutting 558kb/d. As a result of the cut, stocks dropped by 216m bbl to 2,850m bbl. Nigeria and Libya, although OPEC members, were exempt from the cuts due to domestic instability.

If the deal works fully and OPEC achieves its stated objective of reducing stocks to their five-year average by June, then there will be extra pressure on the group’s ability to maintain the agreement. If the agreement subsides by June, then we may see old trade routes such as increased volumesMEG-Eastre-emerge at the risk of longer haulWAF-East stems.

OPEC Supply

Compliance by OPEC members as a group with OPEC prescribed targets for reduced production has been strong, average compliance was 103% during 2017. However this masks over compliance by some members and under compliance by others.

Saudi Arabia

Saudi compliance with OPEC prescribed targets for reduced production averaged 119% during 2017, the highest voluntary decline and compliance of anyOPEC/Non-OPEC member. We expect compliance to remain strong and supportive of the oil prices, at least until the Saudi Aramco IPO. After initially running down domestic stocks in order to maintain exports, production compliance translated into reduced exports. Saudi Arabia has concentrated the effects of the production cut on exports to the U.S.. Saudi exports to the U.S. decreased from a monthly average of 4,522kt/month in 2016 (17.3% market share) to 3,370kt/month in 2017(Jan-Oct) (15% market share). Consequently, crude tonne-miles (TM) fell 27% year-over-year (YoY) to average 39.42bn TM in 2017. Increased Asian demand, coupled with stronger U.S. domestic production would, we expect, result in increased displacement of Saudi exports to the U.S. in favour of the Far East. The market share of exports to the Far East increased to 52% during 2017, however in terms of TM the rise was only marginal (+1% YoY to 85bn TM). Displaced Saudi-West trade has reduced fleet efficiency and we expect, with the ramping up of West Atlantic crude production, fleet efficiency would decrease further, creating a floor in West Atlantic/East rates. Saudi refinery capacity additions reflect Saudi intentions of capturing a greater share of the value addition chain.

Iran

Iran achieved an increase in the production deal, with the agreement to cap production 90kb/d higher at 3.8mb/d. National Iranian Tanker Company (NITC) vessels storing crude oil have been wound back. The expected post sanctions boost in production capacity has not occurred (although production has increased) largely resulting from the threat of a return of sanctions from the Trump administration. The U.S. has stated that further waivers to Iranian sanctions will not be granted unless the nuclear deal is renegotiated. This represents a

major downside risk to supply, if sanctions are reimposed and assuming Europe supports the return of sanctions, Iranian supply could quickly return to 2015 levels. In addition, Iran’s low cost reserves appear to present an attractive investment opportunity for IOCs, however the new IPC (oil exploration contract) contract, although better than the previous buyback model, still causes consternation and may delay a ramp up of Iranian production capacity. Iranian exports to Europe increased during 2017 from 435kb/d in 2016 to an average of 664kb/d last year, primarily to Italy. Market share of European exports increased (from 21% in 2016 to 32% in 2017) primarily at the cost of decreased exports to India (467kb/d in 2016 to 4.9kb/d in 2017). Crude TM demand rose by 8% YoY from 43.8bn TM in 2016 to 47.1bn TM last year with TM to South Europe and the Black Sea surging by 47% YoY to 11.3bn TM at the expense of Indian TM demand that fell by 6% YoY to 1.8bn TM.

Iraq

Iraqi compliance with the OPEC agreement has been notable for itsnon-compliance. Average Iraqi compliance has been 45% during 2017, with January 2018 compliance at 33%. There is uncertainty around the status of exports via northern Iraq, which were halted in September 2017 after the Kurdish Regional Government (KRG) tabled and won referendum for independence from Iraq for Kurdistan. This suspended 650kb/d of production of which 600kb/d was historically exported, via Ceyhan into Europe. The Iraqi government has announced that it has reached a deal with KRG to restart Kirkuk pipeline deliveries, however this has not been confirmed by the KRG and no further details have been given.

Southern Iraq export capacity (4.6mb/d) is running ahead of production (3.5mb/d in January 2018). The bottleneck in increasing exports appears to be the terms at which production contracts were issued and delays in installing field infrastructure. Delays in a field infrastructure development programme have seen forecast production from the southern fields decrease from 7.5mb/d to 5mb/d.

Iraq has been focusing on increasing exports to the U.S. instead of the eastern markets. Exports to the U.S. rose by an average of 745kt/month in 2017 over 2016. U.S. market share of Iraqi imports from the tracked countries increased from 12% to 16% over the same period, while TM demand rose by 26% YoY from 22.8bn TM in 2016 to 28.7bn TM.

As forecast production capacity is set to increase, and as there are no export infrastructure bottlenecks we expect exports to the U.S. to increase this year.

Venezuela

Venezuelan production collapsed in 2017 by 22% from 2.02mb/d at the start of 2017 to 1.61mb/d in January 2018. As a result, involuntary Venezuelan compliance increased from 22% in January 2017 to 484% in January 2018. Venezuela has been confronted with a number of problems, primarily oil backed debts, which are affecting field investment and export opportunities.

PDVSA has oil backed debts of USD 25bn, owed mainly to China and Russia. Loans have to be repaid with oil deliveries and are therefore non cash generating. The main cash generating businesses were exports to the

U.S. and India. Exports to these two countries decreased in 2017 in favour of Russia and China. TM to India and the U.S. fell by 16% and 17% YoY to 12.6bn TM and 4bn TM, respectively, while TM to China rose by 15% YoY to 15.1bn TM. Although, after the purchase by Rosneft of the Essar refinery in Vadinar in the summer of last year, we expect an increase in the Venezuela-India trade which will still not be cash generative.

A decrease in sales to India and the U.S. has led to a lack of cash available to invest in field maintenance and has resulted in production deterioration. Production from Orinoco Heavy field, the main field remaining in substantial production requires spiking with naphtha to meet export specifications. With a decrease in cash generative oil sales, PDVSA is having difficulties purchasing naphtha, which in turn is creating volatility in its Orinoco Heavy specification. The volatility in specification made marketing more difficult creating a vicious circle.

Angola

After Venezuela, Angola is expected to post the biggest decline in production over the medium term. Angolan production has already decreased by 700kb/d during 2017. However, this year they may experience a bounce in production capacity with the 230kb/d Kaombo field expected to come online. However, of tracked countries, exports remained stable in 2017 versus 2016. West-East exports increased with exports to the Far East increasing in 2017 whilst in almost all other tracked destinations its market share decreased. However, crude TM demand rose marginally by 1% YoY to 54.3bn TM driven by a 12% YoY increase in the TM demand to China.

Nigeria

Nigerian liquids production increased during 2017 with reported crude production increasing from 1.43mb/d to 1.66mb/d in 2017. In November 2017, at OPEC’s extension meeting, Nigeria voluntarily agreed to extend its cap on crude production at 1.8mb/d, however, Nigerian liquids production was 2.09mb/d in January 2018.

300-400k b/d of that is condensate production out of which 107kb/d is from the Akpo field alone and the Agbami field production is220-250k b/d. There is no OPEC wide agreement on how to define condensate, the Nigerian Oil Minister insists some fields are condensate fields despite disagreement regarding their grade by outside analysts. Much of Nigerian condensate gets blended into the crude stream before export—making exact counting difficult. However, even after accounting for Nigerian condensate production, Nigeria managed to breach its production cap of 1.80m b/d in December. There is no reason to believe that this trend would not continue for the foreseeable future or at least until such time that OPEC agrees on an overall production cap for Nigeria whether by defining condensate or by imposing an overall liquids production cap. Increasing Nigerian production would provide support to the tanker market. Crude TM demand out of Nigeria rose by 7% YoY to 37.09bn TM.

Libya

Libya also agreed to keep its crude output below 1m b/d. Libyan production was 1m b/d in January, however, structural problems in Libya remain. The national oil company has had its budget slashed by 50%, which will impact field maintenance and, by extension, production reliability. Due to the similarity of Libyan and shale crudes, weaker Libyan production allows for increased U.S. exports. However, the opposite is also true, therefore Libya may feel less pressure to conform to the output agreement than others such as Nigeria. Additionally the pressure to conform may be less as the questions over sustainability of production are more profound. Field production or export capacity is consistently being attacked and brought offline. Most recently the Elephant field was brought offline after an attack by the parastatal Petroleum Facilities Guards (PFG), an indication of the insecurity in production sustainability.

Non-OPEC supply

Russia

January 2018 Russian production was 11.33m b/d. Russia insisted and won approval for amid-term review of the OPEC extension agreement in June 2018. Russia completed the second spur of the ESPO pipeline with first oil pumping through the pipeline at the start of 2018. The second ESPO spur adds an additional 300kb/d of export capacity. In order to fill the additional pipeline Russia has diverted its West Siberian sweet crude, which was previously blended into the Urals grade, to ESPO. The diversion of West Siberian crude to ESPO has led to Urals crude sulphur levels increasing, and in some cases hitting 1.8% (the maximum permitted levels) sulphur content. If this trend continues and sulphur levels increase we can expect traditional Urals destinations of Europe to decrease imports of this grade. Some buyers have already started looking for alternatives, which could increase exports from the U.S. A lack of new supply due to theOPEC/Non-OPEC deal capping production has prevented additional sweet barrels from coming onstream. The Far Eastern exports have increased by 6% while 2017 Black Sea exports have remained stable. Russian TM out of the Black Sea increased by 50% YoY while TM out of the Far Eastern Russian ports rose by 5% YoY last year following an 11% YoY fall in 2016.

Mexico

Mexican production declined by 230kb/d in 2017 to 2.1mb/d today, more than double its allotted cut of 100kb/d and is set to decline by a further 180kb/d this year. Exports to all tracked destinations fell, however the market share of exports to the U.S. increased by 4%. Driven by a strong second half of 2017, Mexican crude TM demand rose by 12% YoY to average at 17.5bn TM in 2017 while TM to the U.S. edged 14% higher YoY to 1.6bn TM.

USA

U.S. supply forecasts have consistently been beaten by the rise of shale. At the start of 2017 IEA predicted U.S. oil supply to be 12.84mb/d, average production in 2017 actually was13.2mb/d-growth of 670kb/d. Currently, production in 2018 is expected to be 14.72mb/d, a further growth of 1.52mb/d during 2017. Growth is dominated by production increases in the Permian Basin.

Although breakeven prices have risen slightly and are forecast to rise this year, the main cap on Permian Basin growth is not WTI price vs breakeven, but takeaway capacity for exports. Drilled but uncompleted wells (DUCs) generally increase in times of low oil prices as producers wait for prices to rebound before increasing production. However, Permian Basin DUCs are increasing despite the above breakeven oil price. This again is due to takeaway capacity blocking a further rise in production. The IEA expects U.S. pipeline capacity to increase to 2.5mb/d this year. With the building of the Diamond pipeline (200kb/d), moving crude from Cushing, Oklahoma to Memphis, the Capline pipeline has become superfluous. The 1.2mb/d Capline pipeline currently runs south/north from St. James, Louisiana (near LOOP) to Memphis and has stated that it intends to reverse the pipeline and provide an export route for Canadian and North Dakota crude production. Although the provisional reversal date is 2022, with LOOP expected to begin bidirectional operations this year, the Capline reversal may be accelerated particularly as currently pipeline flows have fallen to 250kb/d.

Growth in production has driven growth in exports. Crude exports rose by 115% from 520kb/d in 2016 to 1.12mb/d in 2017. Exports appear to be driven by the Brent/WTI price spread, which once it reaches $4/bbl, exports spike as imports from the U.S. become cost effective when adjusted for freight. Exports increased to both China/Far East and Europe. However exports to China/Far East increased by 7.8x compared with European imports which were comparatively lower at 3.1x. As export infrastructure capacity develops in the U.S., we expect exports to move away from being solely arbitrage driven and towards a more structural trade. A number of Asian company leaders have indicated that they intend to import increasing volumes from the U.S.

The tanker market enjoyed its highest earningsincrease in over seven yearsexports last year led to a rally in 2015, benefitting directlyTM demand as TM out of the U.S. surged by 340% YoY to 24.4bn TM in 2017 from lower oil prices.5.6bn TM in 2016. The sharp declinerise was mainly driven by increased volumes to the Far East

where TM rose to 11bn TM compared to slightly less than 1bn TM in 2016. VLCC TM demand rose to 14.1bn TM from 1.4bn TM in 2016 following the increased demand for long-haul voyages, while Suezmaxes rose to 6bn TM in 2017 compared to 1.5bn TM in 2016. Aframaxes saw the smallest YoY rise both in absolute (+1.8bn TM) and in percentage terms (+70%) as the trend of barrels heading east has substituted Aframax demand in favour of larger ships. The upcoming infrastructure developments in the priceU.S Gulf in order to accommodate the loading of larger ships might further reduce the Aframax market share in the U.S.

Demand

Global oil sincedemand increased by 1.64mb/d against a forecast increase of 1.3mb/d in January 2017. 2018 global demand is set to increase further by 1.4mb/d. Low oil prices, and strong economic growth helped oil demand growth during 2017. Demand growth is focused in the East of Suez region which will make up 57% of global demand growth (0.8mb/d), of which China and India contribute 75% (0.6mb/d).

China

China remains the swing factor for the crude tanker demand. 2017 oil demand grew by 660 kb/d, 2018 demand is expected to increase by 360kb/d to 12.87mb/d. In 2017 China surpassed the U.S. to become the world’s largest crude importer with imports increasing to 8.48mb/d in 2017 compared to 7.68mb/d in 2016. Imports from West Africa increased as OPEC cuts took hold, due to:

Saudi Arabia continued to follow its commercial strategy of focusing on maintaining its market share in Asia and imports from Saudi Arabia increased last year over 2016.

Russia has grown to become the largest import partner for China with imports reaching 1.21mb/d compared to imports from Saudi Arabia of 1.05mb/d in 2017. Imports from Russia will increase this year as the second ESPO spur started flowing in January 2018.

As discussed previously, U.S. crude exports were 150kb/d in 2017 up from virtually zero the year prior. We expect U.S. crude imports to increase this year. Consequently TM demand to China surged to 7.2bn TM from 1bn TM in 2016 with the majority of the increase benefiting the VLCC sector that rose to 6.7bn TM.

Against this, domestic production decreased by 110kb/d in 2017 and is expected to be 100k b/d less this year at 3.77mb/d. Chinese SPR fill rate for the whole year is not yet known, but SPR storage is expected to continue to provide support to the market. Imports increased last year from 7.68mb/d in 2016 to 8.48m b/d in 2017. 720kb/d of refinery capacity cameon-stream in 2017 (560kb/d new capacity and 182kb/d upgraded). Refineries require 21 days of stock to ensure smooth operations, 560kb/d of new capacity installed last year would have resulted in 11.8 mb of additional import demand (over actual crude demand). 200kb/d of capacity is expected to comeon-stream this year which would equal 4.2m b/d of additional stock holding requirement. The 400kb/d Myanmar pipeline from Ramree to the 260kb/d Anning refinery came onstream in the second quarter of 2017. The pipeline is expected to feed additional refineries to be established in Anning.

Teapots received a quota of 91.73m T for the whole 2017, while this year Beijing issued 55% higher quotas of 142.42mT. However there is a major downside risk that teapots may not be able to reach their quotas this year as the State Administration for Taxation (SAT) is intending to introduce new taxation laws and invoicing systems which will reduce teapot profits. Initially the new laws were announced to be implemented by January 2018, then were pushed to March 1, 2018 and are now targeted for May 1, 2018. If/when the new laws are implemented then we can expect crude demand from teapots to be reduced. This would primarily impact Brazilian crude grades which teapots prefer (56% of Brazilian imports in 2017 destined for teapots).

India

Indian oil demand is forecast to grow by 300 kb/d this year (2018 demand 4.98 mb/d) against 2017 growth of 120 kb/d (2017 demand 4.68 mb/d).

In late 2016, India decided to remove 500 and 1,000 rupee notes from circulation overnight in a bid to crack down on black money. This impacted first half of 2017 oil demand, which increased by 110kb/d over the first half of 2016, compared with growth of 635kb/d in the first half of 2015 over the first half of 2016. Oil demand growth started recovering in the second half of 20142017, however a general sales tax (GST) was introduced. Prior to

the introduction of the GST Indian states individually established their state tax regimes which would cause delays in inter-state trade and excess paperwork, increasing the cost of trade. The GST was intended to harmonise the taxation systems across the states, however confusion regarding its implementation and product categorisation caused confusion and interstate trade to slow and resultantly oil demand growth slowed.

However, the IEA expects demand growth to return with vigour this year. Instability in many OPEC countries and increasing U.S. production has prompted Indian refiners to seek to diversify their crude import sources. Indian refiners imported increasing volumes from both West Africa and the U.S. Additionally as the Dubai benchmarked crudes (e.g. Saudi crude) increased relative to Brent benchmarked crudes, Atlantic grades became more attractive. Starting at zero imports from the U.S., India began importing in earnest from August onwards at an average of 61kb/d (August 2017 to November 2017). Imports are expected to increase further as multiple Indian refineries’ management teams have indicated.

In 2017 India added two refineries of a total capacity of 164kb/d with a 120kb/d refinery built on the South Western coast and the second refinery built inland. This year no notable refinery additions are expected, rather the growth in demand is assumed to come from increasing utilisation rates.

Europe

European oil demand increased by 360kb/d in 2017 over 2016 and is expected to increase by 160kb/d this year. 2017 oil demand growth was attributable to lower oil prices, which have firmed recently, easing demand growth this year. In particular gasoil demand increased in 2017.

The increase in demand was fed by the MEG and North Africa. MEG exports were primarily from Iran, imports from Iran increased from 435kb/d in 2016 to 798kb/d in 2017. Iranian imports now make up 7% of imports, up from 3.9% in 2016. Russian imports decreased by 31kb/d in 2017 after increasing by 245kb/d in 2016. Over the near term, we expect the downside to Russian imports to increase due to the prevailing political environment.

USA

U.S. crude demand increased by 130kb/d in 2017 over 2016 and is expected to increase further by 200kb/d this year to 20.02mb/d. Year on year imports remained stable at 7.8mb/d in 2017. Imports from West Africa and the MEG (excluding Saudi Arabia) increased whilst imports from the Caribbean and Saudi Arabia decreased. Almost all West African export partners increased their volumes in 2017. The main increase from the MEG was from Iraq, which increased by 192kb/d in 2017. Better Iraqi export infrastructure and a strategic decision to replace Saudi supplies has resulted in higher Iraqi exports to the U.S. Decreases from the Caribbean were from Venezuela and Colombia. Colombian exports are expected to decrease due to a falling investment in producing fields and a resurgence in guerrilla attacks.

Products Market

China Product Market

Chinese refinery capacity increased by 560kb/d in 2017 with an additional 180kb/d of upgrading capacity installed. Chinese clean product demand was 8.2mb/d in 2017 and is expected to 8.47mb/d this year. Independent refinery quotas increased from 1.75mb/d in 2017 to 3.8mb/d this year.

Gasoline

Chinese gasoline demand increased in 2017 by 59kb/d over 2016 to 2.93mb/d and is expected to grow by 118kb/d in 2018 to 3.05mb/d. However exports concurrently rose from 81kt/month in 2016 (full year) to 88kt/month in 2017 (full year), the majority of the increase in exports were destined for Singapore and Malaysia, helping firm eastern MR demand. We expect gasoline exports to increase this year, primarily within the East – continuing to provide support to eastern MRs. Last year’s first six months gasoline export quota was 4.44kt compared with current year’s first six months export quota of 6.5kt. Additionally, the Chinese SAT has introduced a domestic consumption tax of ¥1.52/ltr for gasoline and an invoicing system which would accurately identify products. These factors would most likely push smaller refineries out of domestic markets to focus on exports.

Gasoil

Gasoil demand increased by 86kb/d in 2017 over 2016 and is expected to increase by another 48kb/d this year to reach 3.5mb/d. Many of the factors affecting the gasoline trade also apply to the gasoil market. Similar to the gasoline market, despite rising domestic demand, gasoil exports have increased over the same time period. The largest increase in exports were to the short haul routes to South Korea, Hong Kong and Philippines. Again, similar to the gasoline market, the SAT has introduced a domestic gasoil consumption tax of ¥1.20/ltr, pushing out smaller refineries into the export market.

Jet

Jet demand increased by 63kb/d in 2017 and is expected to increase by 35kb/d this year to 748kb/d. Jet exports to most major destinations either fell or were stable in 2017 over 2016. Total jet exports grew by 2% in 2017 compared to 9% in 2016 and 12% in 2015. As domestic Chinese jet demand increases and the U.S. continues on its path as the major product exporter, particularly in the West of Suez market, we expect Chinese jet exports growth to remain subdued.

India Products market

Indian refinery capacity increased by 164kb/d in 2017 and is expected to increase by 16kb/d this year. Major refinery capacity additions are expected to comeon-stream post 2020. As the previously discussed twin shocks to the economy of GST and demonetisation dissipate, we expect Indian product demand growth to strengthen this year. Jet demand was not affected by the demonetisation shock as the majority of passenger ticket purchases are transacted through credit cards. Jet demand increased by 9% in 2017 over the previous year and is expected to continue to grow strongly this year due to increasing affordability and growing incomes.

Gasoline

Indian domestic demand increased by 7% in 2017 and by 12% in 2016, mainly due to an increase in passenger car sales. In addition, Indian gasoline fuel standards were tightened in 2017 to Bharat IV standard (the equivalent of Euro IV) nationwide. As a result imports increased last year by 9%, primarily from Iran which has become self-reliant in gasoline production after thestart-up of the Persian Gulf Star refinery. Phase one of the refinery (120kb/d capacity) was completed in 2017 with Phase two (120kb/d) starting up in February this year. As gasoline demand is expected to continue to grow strongly this year, short haul imports could increase, helping support the MR market.

Gasoil

Indian gasoil demand increased by 3.3% in 2017 compared by 5.5% on average for the two years preceding that. Previously discussed macro events affected diesel demand in 2017, second quarter diesel demand remained rangebound in 2017 as opposed to when diesel demand grew strongly over the same period. However, diesel demand is expected to return to stronger growth this year (164kb/d). In April 2017, India introduced regulations for heavy diesel trucks and buses fuel efficiency standards. Heavy truck and buses make up 60% of gasoil demand. Regulations will be implemented in two phases with phase one to be implemented beginning in April 2018 and presents some downside risk to diesel demand growth.

U.S. Product market

The U.S. has continued on its path of becoming a product exporter. U.S. refinery capacity utilisation has increased every year since 2008, reaching an average of 92% last year. The majority of exports originate from the U.S. Gulf region which has now become the largest product exporter in the world.

Gasoil and Gasoline

Little to no refinery capacity additions in South America (40kb/d addition in Argentina in 2017) coupled with rising demand helped push U.S. product exports to South & Central America to grow by 15% over 2016, albeit from a small base. Exports were driven by the fire and subsequent shutdown of the 330kb/d Salina Cruz refinery in Mexico. As a global crude oversupply, rather thanresult, the average outage for South and Central America Atlantic increased from 4kb/d in 2016 to 314kb/d in 2017. However, current year outages are expected to decrease this year with Salina Cruz returning to production albeit at half capacity. As a declineresult, current year gasoil export growth to South and Central America is not expected to be as strong as 2017. Exports to Europe have remained broadly rangebound.

Gasoline exports grew by 9% in 2017 over the preceding year. Similar to gasoil export drivers, gasoline exports to South and Central America increased in 2017. U.S. TM demand (basis LRs) to South and Central America rose by 105.3m TM to 204.5m TM last year.

Europe

Similar to the U.S., European refinery utilisation rates also increased in 2017 to 88% as increased demand from Latin America and West Africa supported production.

Gasoil and Gasoline

After year on year increases in gasoil imports since 2014, imports were stable in 2017. Gasoil demand is expected to increase slightly this year (34kb/d). European gasoline exports increased 3.8% in 2017 over 2016 with the market share of each destination remaining broadly stable. As exports from U.S. led to reduced European exports to West Africa, European exports to the destination declined by 14% from an average of 316kt/month to 272kt/month. Domestic gasoline demand is expected to remain stable this year and return to its long term declining trend next year.

West-East Naphtha Movements

Atlantic Basin availability of naphtha increased due to an increase in U.S. Shale production, and some European refineries switching to ethane, this led to an excess of naphtha which was exported east. As a result

West/East naphtha exports increased by 11.5% in 2017 to 1.2MT/month. The trend is expected to continue, particularly as a heavy maintenance schedule is expected in the driver behindMiddle East this year, tightening MEG naphtha supply.

World Tanker Fleet

VLCC fleet growth remained elevated in 2017 at 5.9%, however slightly lower compared to 2016 (6.6%) as, despite higher deliveries, we also experienced an uptick in scrapping. In total, fifty VLCCs came into the last sharp dropmarket, making 2017 the highest year VLCC delivery year since 2011. The delivery schedule was front loaded with 29 vessels delivered in oil prices during the financial crisis of 2008-2009. The crude surplus and low oil prices of 2015 triggered a multitude of beneficial demand factors for the tanker market which included record consumption growth in some partsfirst half of the world, strategicyear (First Quarter of 2017 17 VLCCs and commercial crudeSecond Quarter of 2017 12 VLCCs) and oil product stockbuilding demand, floating storage plays, exceptionally high refining runs, infrastructure bottlenecks leading to vessel delivery delays and many more. The added demand for tanker tonnage also allowed tanker owners to hold on to the benefit of the lower cost of bunker fuels (which are highly correlated with crude oil). Furthermore, this strong upward shift in tanker demand occurred during a year of low fleet growth in most sectors, which allowed for freight rates to rise sharply.

Brent crude lost approximately 77% of its value from its $115/bbl peak in June 2014 to a low of just above $26/bbl in mid-January 2016. Despite a temporary resurgence in both Brent and WTI prices during Q2-2015, at the end of June world powers and Iran reached an agreement that would see sanctions soon lifted on the country which, combined with rising crude supply elsewhere, triggered a pronounced sell-off that tailed off into 2016. US crude production remained unexpectedly high, while OPEC’s two largest members, Saudi Arabia and Iraq, boosted their combined production by over 1 million bpd over the year. Concerns of a weakening Chinese economy has also brought the price of oil under pressure, particularly in August 2015, as oil prices traded below $40/bbl for the first time since early 2009 and again in late December after periods of high volatility on the Shanghai Stock Exchange. The lifting of sanctions on Iran became effective in mid-January 2016, eventually pushing prices down further to bottom out below $30/bbl.

Global Oil Prices and WTI-Brent Differential

WTI switched to trade at a premium to Brent during the last days of 2015, following the lifting of the 40-year old US crude export ban. As a slightly higher quality crude in terms of API gravity and sulphur content, WTI should logically trade at a premium to Brent, but its landlocked nature amid booming domestic production has led it to trade at a discount since the so-called “shale revolution”. The WTI discount to Brent has been re-established as the US crude has yet to emerge as a major export grade. Export infrastructure21 in the US Gulf coast, the natural crude export hub for US crude, falling US crude production,second half (Third Quarter of 2017 11 VLCCs and a lackFourth Quarter of demand amid the ongoing crude surplus has limited US crude’s global reach and has for now kept it largely landlocked. Possible crude export markets for US crude could be Latin America, particularly Venezuela for blending purposes, Europe where it could compete with light, sweet West African crude and potentially Asia where both US condensate and some very high quality crude can be used for condensate splitting. The greater the export demand for the crude, the more WTI will appreciate in value relative to other grades. US domestic refineries, however, would prefer for the WTI discount to remain to continue providing them with a feedstock cost advantage relative to their international competitors.

The IEA estimates that the crude oversupply in 2015 averaged 2m bpd, with a global crude stockbuilding rate estimated at around 1.4 million bpd (all IEA data captured last2017 10 VLCCs). Nine vessels were removed from the February 2016 report). Stocks in some areas approached near capacity; for example in Cushing, US, stocks rose to 64.2 million bbls – only 0.8 million bbls below the operational capacity of the Cushing storage facilities. Stocks in other areas, notably China and India, were expanded as part of a long-term strategic plan but the low crude prices also helped to encourage that strategic and other commercial stockbuilding. As of the February update, the IEA is estimating that the crude surplus will remain at around 2 million bpd in Q1-2016, fall to 1.5 million bpd in Q2-2016 and then sharply narrowfleet, with eight scrapped in the second half of the yearyear. Only two vessels from the 52 originally scheduled to be delivered in 2017 slipped into 2018—slippage in 2017 was at historical low levels of 4%, significantly lower than the 2009-2016 slippage average 0.3 million bpd – leaving the year with an average surplus of approximately 1 million bpd.

Total OECD crude stocks reached 1,119.3 million barrels at the end of 2015, nearly a 15% year-on-year increase from 2014. The largest build was witnessed27.8%. 61 VLCCs are currently scheduled to come in the OECD Americas where stocks built by 93.2 million bbls. Stocksmarket in OECD Europe rose by 36.5 million bbls and by 25 million bbls in OECD Asia Oceania. Middle distillate stocks rose by 87 million bbls in all OECD regions, the largest gain was in Europe but this was closely followed by the Americas, amid slowing global demand growth for the fuel and high output from refiners who raised their products output in order to capture firmer gasoline margins but leaving large surpluses2018, of middle distillates to be stockpiled. Gasoline stocks were the only type to fall year-on-year as demand growth accelerated - since the primary buyers of gasoline are individual consumers for passenger car use this makes the fuel much more elastic (i.e. demand will respond to lower prices) than gasoil, which relates more to industrial demand. OECD fuel oil stocks also rose by a smaller 16.4 million bbls.

In 2015, Chinese stockbuilding reached its highest level yet at an average of 670,000 bpd for the year. This jump in stockbuilding activity was attributable to a one-time build in refinery stocks after the government issued a rule whereby refineries had to maintain crude oil inventories of at least 15 days when international crude prices are below $130/bbl and at least 10 days of inventory when prices exceed $130/bbl. This boosted stockbuilding activity by approximately 200,000 bpd, while the remainder of stockbuilding was for commercial facilities and SPRs that came online during the year. Months of very strong imports during the year marked moments when stockbuilding took place, notably Chinese crude imports rose to a record 7.89m bpd in December. However, imports only two months prior were more than 1.5 million bpd less at 6.26 million bpd in October, highlighting the powerful effect that stockbuilding has on Chinese crude import levels and, by extension, crude tanker demand.

OPEC production rose by 1.07 million bpd in 2015 as the organization agreed in November 2014 and re-affirmed in June 2015 not to cut production to lift prices. At the most recent OPEC bi-annual meeting in December 2015 the organization decided to forgo a production ceiling altogether as they welcomed back Indonesia and as the uncertainty surrounding Iranian production growth following the lifting of sanctions raised questions over the correct level of the ceiling. This decision was largely viewed as symbolic as OPEC hadfive have been pumping well above its 30 million bpd ceiling for many months. Recently, Saudi Arabia, Bahrain, Venezuela, Qatar and Russia agreed to freeze production at January 2016 levels which, at the time of writing, has done little to stifle a rise in oil prices as oil production from those countries was not expected to rise much above January 2016 levels anyway in the year, or in some cases was expected to even fall. Iran and Iraq have so far not committed to an output freeze.

Iraq accounted for over 60% of production growth among the OPEC countries, despite ongoing violence in the northwest. Iraqi output rose by approximately 660,000 bpd to reach an average output of 3.99 million bpd for 2015 but production had climbed month on month to 4.3 million bpd by December 2015. The jump in Iraqi production was driven by two developments. First, the benchmark Basrah crude was split into a Heavy and Light grade in May which improved the consistency of the oil Iraq sent to its customers and enabled a rise in the Heavy stream outflow. Second, with support from improved pipeline infrastructure and greater autonomy, production from the autonomous Kurdistan region grew from an average of 200,000 bpd in 2012 and 2013 to average 550,000 bpd in 2015. Saudi Arabia was the second-largest contributor to OPEC production growth with output rising year-on-year by 450,000 bpd in 2015. The UAE and Angola were the only other OPEC members (apart from Iran) to boost year-on-year output, by 100,000 bpd and 120,000 bpd respectively.

Production fell relatively minimally for most of other OPEC members. Algeria and Indonesia continue to experience a long-term decline in their output, while internal disruptions caused Nigeria production to fall by 100,000 bpd year-on-year. Output in Libya rose temporarily at the start of March 2015 to over 500,000 bpd but fell only a couple of months later following the closure of the eastern port of Zueitina while nearly all the countries’ export infrastructure remains closed or is under force majeure in early 2016. Kuwaiti production fell by only 20,000 bpd, but was lower throughout the year due in part to the shut in of the 500,000 bpd Neutral Zone production that the Emirate shares with Saudi Arabia following a dispute over its development.

At the end of June 2015, Iran and the P5+1 negotiating countries came to a final agreement to end international sanctions on Iran given that they fulfilled a number of nuclear neutralizing requirements. After fulfilling those requirements, international sanctions were effectively lifted in mid-January 2016, however US sanctions tied to non-nuclear related issues remain on a number of Iranian entities and individuals. Subsequently, Iran has vehemently promised to boost crude output by 500,000 bpd within months of sanctions being lifted in the hopes of restoring output to pre-sanction levels of just below 4 million bpd from a 2015 average of 2.86 million bpd. The IEA expects Iranian output to rise by around 600,000 bpd in 2016, further boosting OPEC’s market share as non-OPEC output is projected to fall this year.

Non-OPEC production demonstrated its resilience in the face of tumbling oil prices as output only began to show steady declines after peaking in October 2015 at 57.89 million bpd. Output in major non-OPEC producing nations is now expected to fall by approximately 600,000 bpd in 2016 after rising by 1.4 million bpd in 2015. However, the forecasted decline in non-OPEC production will be more than offset by an expected rise in OPEC production – driven by Iran. OPEC productiondelivered. Slippage is expected to rise by more than 700,000 bpd in 2016, leaving total global crude production relatively flat year-on-year at 96.5 million bpd - roughly 100,000 bpd higher than 2015 output. On the other hand, the IEA expects demand growth to average 1.2 million bpd in 2015, down from 1.6 million bpd last year, which leaves the 2016 average crude surplus at around 1 million bpd, as previously mentioned.

US crude output peaked in April 2015 at 13.24 million bpd, and averaged 12.92 million bpd for the year. Output in the US is expected to fall by about 500,000 bpdbe high this year as the resilient US oil industry, populated by many independent producers, only beganmarket remains weak in part due to see consecutive month-on-month declines at the very endoversupply of 2015. Buoyant production fromtonnage. Weak spot earnings, rising steel prices and rising costs for shipowners for the US Gulf of Mexico delayed the fall in total US production; output in the Gulf of Mexico rose by 142,000 bpd in 2015 with similar growth expected again this year. By mid-January 2016 the total number of active rigs in the US stood at 515, 68% below the peak in October 2014. Meanwhile production from new wells drilled has fallen to less than 240,000 bpd which is behind legacy declines of more than 350,000 bpd. The liftinginstallation of the crude export ban is notballast water treatment system are expected to lead to a rise in US crude production for export while global oil prices remain low and there is a persistent oversupply. The decline in US crude production, however,higher removals from the fleet this year. However, scrapping is expected to boost seaborne imports into the country. The small and entrepreneurial independent producers that characterize much of the US shale oil industry are likely to boost output again at the first sign of a rise in oil prices which makes a large part of US production very elastic.

Conversely, Canadian production is expected to rise in 2016 by 100,000 bpd, 20,000 bpd more than it rose in 2015, to reach 4.46 million bpd as fields and projects invested in years ago come to fruition. However, investment in the region, and therefore output in the longer term, has plunged due to the very high cost nature of

in-situ bitumen and oil sands production. In addition, Canadian oil prospects have been further inundated by the blocking of the 830,000 bpd Keystone XL pipeline by President Obama in 2015 and further delays and public concern over the 1.1 million bpd Energy East pipeline, 890,000 bpd Trans Mountain pipeline and the 520,000 bpd Northern Gateway pipeline projects.

Despite grappling with a combination of economic sanctions and low oil prices, Russian production rose year-on-year by 150,000 bpd in 2015 to reach a post-Soviet record of 10.73 million bpd, but its pace of supply growth is expected to slow in 2016. Reportedly, the Russian oil industry is able to keep functioning with the recent low oil prices, however, government income has felt a sharper pinch. An ongoing debate for raising export levies and crude extraction taxes on production to bolster the national budget may reduce the country’s oil output according to some commentators. North Sea production also remained resilient in 2015, production from Norway and the UK rose by a combined 140,000 bpd in 2015 after reaching a peak of 3.03 million bpd in Q4-2015 – although the region is drilling new wells at a 50-year low. Production is now expected to fall going forward, it is estimated that successive declines this year will leave output averaging 2.82 million bpd. The North Sea oil industry has been hit hard by the plunge in oil prices, with a recent report estimating that 150 oil platforms (25%) could be lost in UK waters within the next 10 years; unless the industry adapts it could see these fields shut down permanently. Finally, despite a national oil workers protest at the end of the year, Brazilian production rose almost 200,000 bpd to 2.53 million bpd by virtue of a rise in output at the offshore Lula pre-salt field by 200,000 bpd to 380,000 bpd throughout the year. However, the state-owned oil company Petrobras cut its capital spending projections by 25% for the 2015-2019 period at the start of 2016, warning that production may not grow as expressed previously due to the continued low oil price and the devaluation of the nation’s currency.

Global Oil Supply and Demand YoY Growth

The drop in oil prices during 2015 was welcomed by consumers as year-on-year demand growth almost doubled in 2015 compared to 2014 from 0.88 million bpd to 1.61 million bpd. Due to the price sensitivity of gasoline as an end-consumer product, as opposed to middle distillates which are driven by stickier industrial consumption, the transportation fuel experienced the largest demand growth in many parts of the world. As the price of oil slipped throughout the year, demand likewise accelerated particularly during Q3-2015 when it stood at 95.38 million bpd – over 2 million bpd higher than in the same period of 2014. This was a result of a very robust

US summer driving season where US drivers drove a record 280 billion miles in July, in addition to vigorous gasoline demand growth in China, India, and elsewhere. The fall in crude prices also widened refining margins, leading many refineries to delay maintenance and thus keep refining demand for crude abnormally high throughout the year even if this has translated into a building of undesirable middle distillate stocks.

Indian oil demand growth overtook that of China in 2015, expanding at a pace of 5.8% versus 5.3% for China to levels of 3.98m bpd and 11.18 million bpd respectively. Demand in India is expected to rise by a similar percentage this year, while Chinese oil demand growth is expected to fall below 3%. A weak monsoon season during Q3-2015 aided diesel demand in India, while India’s total products demand reached a five-month high in October with the onset of the festival season pushing passenger car sales to jump by 22%. Meanwhile, a slowdown in Chinese industrial growth has seen diesel demand rise by only 14,000 bpd, or 0.4%, compared to a rise in gasoline consumption of 193,000 bpd, or 8.6%, as the economy becomes increasingly consumer driven.

In the wake of low oil prices, many countries took advantage of this position to either reduce subsidies or increase environmental disincentives for oil consumption as the low oil price reduced clean energy’s cost competitiveness and induced heavy oil demand growth that if left unabated could cause serious pollution damage. These measures can be considered as artificial demand caps, reducing otherwise natural demand growth. Some examples include a handful of Mideast Gulf countries (Saudi Arabia, Bahrain, the UAE) reducing their generous fuel subsidies to bring relief to their strained budgets, India and Indonesia sharply reducing or completely removing fuel subsides, China imposing a freeze on fuel prices when crude oil falls below $40/bbl, India banning new luxury diesel vehicles in Delhi and imposing a green tax on commercial vehicles in the city and more recently Venezuela relaxing its heavy fuel subsidies. The IEA advises that the expected demand growth risk is tilted towards the downside amid weak emerging and oil producing nation economies and an expected steady rise in oil, and fuel, prices as the year progresses. That being said, other industry watchers have a more optimistic view and it would not be the first time early year forecasts would prove overly pessimistic.

Chinese oil demand rose to an average of 11.18 million bpd this past year, an increase of 570,000 bpd or approximately 5.3% from 2014. This outpaced demand growth in 2014 of 300,000 bpd, but is in line with recent annual growth of 3-5% since growing by 11% in 2010 and at similar levels in prior years. Demand is expected to slow in 2016 to a growth rate of 3%, reflecting decelerating GDP growth and a number of government efforts (mentioned previously as artificial demand caps) that are stemming oil demand growth in an effort to reduce pollution. Chinese refining capacity expanded by approximately 650,000 bpd in 2015, this comprised of three state-owned refineries each totaling 100,000 bpd and 350,000 bpd of teapot expansions. Most Chinese refinery expansions in 2016 have been delayed as refiners instead focus on upgrading capacity to meet the 2017 change in domestic fuel specifications to the China 5 standard and amid a domestic fuel glut that has seen product exports surge towards the end of the year.

An important development this past year worth mentioning is independent, or teapot, refineries being given the ability to process and directly import crude in place of fuel oil. A reported total of 12 independent refiners have been given crude processing quotas by February 2016 totaling just over 1 million bpd, while most have also been allocated direct crude import quotas. In order to receive these quotas the independent refiners had to reduce inefficient capacity, build a certain level of stocks, and comply with other efficiency-promoting requirements. The independent refiners constitute a new source of crude demand, but they are at the mercy of reduced fuel oil demand as fuel oil was their previous feedstock, and will therefore add to Chinese crude demand this year as they did at the latter end of 2015. However, independent refineries have a lower utilization on average than their state-owned counterparts, despite utilization with crude oil feedstock an improvement from fuel oil, and so it is doubtful that the full quotas will be utilized.

Chinese Crude Imports and Stock Building

In their February 2016 update the IMF has estimated global GDP growth for 2015 at 3.0%, reducing it from earlier forecasts of 3.3% amid an uneven and modest recovery in advanced economies and a challenging outlook for emerging economies. In tune with expectations for growth in 2014, the IMF restated that risks remain tilted to the downside with a rebalancing of China’s economy, lower commodity prices, a slowdown among emerging countries and the slow, yet fragile, exit of accommodative monetary policy by the US as most other advanced economies look instead towards easing monetary conditions.

GDP and Oil Demand Growth vs. Tanker Earnings

Growth in emerging and developing markets declined for the fifth consecutive year, with many of those economies drawing a large portion of their finances from commodities, while advanced economies continued to embark on a slow recovery. The fall in oil prices driven by the oversupply should supposedly support global demand as a result of the higher propensity to spend in oil importing countries relative to oil exporting countries, but a number of factors have reduced the otherwise positive impact. The IMF cited financial woes in many oil exporters limiting their ability to smoothen the shock of the drop in oil prices, leading to a significant fall in their domestic demand. The fall in oil price has sharply reduced an entire industry’s level of investment, itself a contribution to global demand growth. The IMF expects global GDP growth to pick up to 3.4% in 2016 and 3.6% in 2017. In the long term, the “lower for longer” oil price phenomenon has reduced oil industry investment to a point where the global economy could witness skyrocketing oil prices later down the line.

Crude Tanker Tonne-Miles and Select Crude Imports

As importing regions, China and India continued to be the driving force behind crude ton-mile demand growth. The approximate 540,000 bpd year-on-year rise in Chinese seaborne volumes in 2015 came from a combination of Middle Eastern, east coast South American and Russian volumes (only a small portion of the rise in total Russian flows was non-seaborne). Saudi Arabia only met 4% of China’s increase in crude appetite last year, with Kuwait, Iraq and Oman gaining more of a foothold boosting their shipments by 80,000 bpd, 70,000 bpd and 50,000 bpd respectively. Russian exports to the far eastern nation rose by an equivalent amount to Middle Eastern volumes (excluding Saudi Arabia) – this was in large part due to rising Kozmino ESPO crude loadings and China’s independent refineries’ healthy appetite for the grade. Previously limited to Aframaxes, the Kozmino export terminal began loading Suezmaxes in November 2015 with loadings at the terminal reportedly climbing more than 20% year-on-year. Generating the greatest boost in ton-mile growth, however, would be the 140,000 bpd year-on-year gain in east coast South America flows to China which was wholly provided for by Brazil as Argentinean flows remained flat at 10,000 bpd. The greatest annual fall in volumes occurred from West Africa, a fall of 90,000 bpd, due to a decline in imports from Angola, Congo, Equatorial Guinea and Nigeria as Europe took more West African crude to feed their surge in refining runs but also as West Africa struggled to sell their crude amid the global oil glut.

The rise in Indian ton-miles was a result of increased flows from Mexico, Saudi Arabia and West Africa – but mileage growth was certainly impeded by a 90,000 bpd year-on-year fall in volumes from the Caribs in 2015. Overall, Indian crude imports grew only 2% year-on-year to 3.92 million bpd, but in 2014 import volumes actually fell year-on-year and so 2015 volumes were less than 1% or 20,000 bpd higher than in 2013. A lack of new Indian refining capacity was behind the low growth in crude volumes flowing into India, the 300,000 bpd Paradip refinery was scheduled to come online in 2015, after being delayed from 2013, but is now coming online in March 2016. The refinery is expected to take 60% Mexican Mayan crude, but is also thought to be capable of taking West African grades. India was a consistent buyer of West African crudes, particularly as they were depressed this year with a number of cargoes leftover at the end of each month attracting favorable discounts. India was also a strong buyer of Iraqi volumes, the country’s imports from Basrah rose by 170,000 bpd as reportedly the 9.7 million bbl Visakhapatnam SPR on the western coast of the country was filled with predominantly Iraqi crude.

2015 saw also a noticeable pick up in European crude ton-mile demand growth as refiners there greatly benefitted from the fall in crude prices relative to the pick-up in products demand. The EU28 seaborne volumes rose almost 6% to 9.38 million bpd while Russian pipeline volumes to the region only rose by 70,000 bpd. European refining runs rose by just under 700,000 bpd with the surge in refining margins bringing long-awaited relief to the region’s ailing downstream sector. The 510,000 bpd rise in seaborne imports was predominantly due to a rise in flows from the Middle East Gulf, the Eastern Mediterranean and West Africa. Iraqi flows into the EU28 rose by an astounding 270,000 bpd as volumes from Libya and Saudi Arabia waned. Angola was the primary benefactor in West Africa from the boost in runs, while in the East Mediterranean the EU28 took 120,000 bpd of more crude from Azerbaijan and in Latin America Mexico was the only country to see year-on-year export growth to the EU28 of 70,000 bpd.

Although US domestic production began to fall in 2015, seaborne imports continued to trend downwards, albeit at a slower pace than in 2014, falling 200,000 bpd year-on-year. Imports from Canada to the US, however, continued to grow, to the detriment of seaborne volumes, rising by almost 200,000 bpd. Other rises in crude flows into the US were from Latin America, principally Colombia and Ecuador, while imports continued to fall from the Mideast Gulf and West Africa although volumes from Iraq more than doubled in Q4-2015 to average 350,000 bpd while imports from Angola rose 60,000 bpd in Q3-2015 and another 30,000 bpd in Q4-2015. Going forward, US seaborne imports are poised to rise as domestic output is expected to fall in 2016 while WTI could strengthen relative to Brent as domestic output falls.

2015 was an extraordinary year for crude flows by virtue of the immense oversupply, this however has only temporarily delayed the long-term trend of refinery closures in major importing regions including Europe, Japan, and Australia in place of more efficient refineries in the Mideast Gulf and Asia. In the case of the Mideast Gulf, the area is expected to increasingly see higher value-added product exports in place of crude exports. However, in the short-term refining runs in crude importing regions remain relatively supported by the continued low oil price and healthy oil demand. The healthy oil demand included stockbuilding activity, while low oil prices also dramatically encouraged competitive and opportunistic buying and increased trading/blending activity, supporting ton-mile growth. Meantime, in line with long-term strategies, Asian crude buyers continue to widen their buying palate away from the Mideast Gulf to longer-haul destinations, particularly Latin America, which supported crude tanker ton-mile growth.

US Oil Product Imports and Exports

Retail gasoline prices in the US have fallen by over 50% from July 2014, incentivizing Americans to drive a record 283.749 billion miles in July 2015. Consequently, US gasoline imports during the third quarter were 747,000 bpd, almost 40% higher than during the same period last year despite domestic refineries running at full capacity. There were also slight upticks in distillate and kerosene imports in 2015 compared to 2014, which was aided by cold winter weather in Q1-2015 despite refineries shoveling significant amounts into storage towards the end of the year as the warmer than usual winter weather in Q4-2015 did not generate enough demand growth. Despite Europe being inundated by diesel imports from the Middle East, Russia and Asia – along with their own surging output due to high refining runs – the US managed to also boost distillate exports to the region, however at the start of 2016 the arbitrage had come under increasing pressure due to an oversupply of distillates on both sides of the Atlantic.

Perhaps the most notable event of the past year for the US downstream sector occurred at the end of 2015 with the lifting of the US crude export ban. The refining industry has been against a lifting of the crude ban as it would make US crude grades exportable, thereby removing their landlocked discount – propagated by the US shale revolution – and eroding US refiners’ advantageous feedstock cost. As mentioned, WTI switched to trade at a premium to Brent for a few weeks following the lifting of the ban, but by the time of writing it had switched back to trade at a discount to Brent. Reasons for this include limited ability for US crude exports to be realized due to insufficient export infrastructure, and an already oversupplied crude market and therefore little demand opportunity, while many US grades have a very light, sweet quality which makes it more likely to be sold in smaller cargoes (in addition to export infrastructure limiting cargo size). Moreover, it is only reasonable to expect a decline in US refining runs in the case of a decline in US oil demand growth – however this is not forecasted to be the case yet. Oil demand in Latin America, to which the US sends most of its product exports, will also prevent a decline in runs. Therefore, it can be expected that the US will continue to see greater product exports in place of imports, as it has since the shale oil revolution, although in the longer term US refineries will be subject to competition from the more efficient, modern refineries coming online in the Mideast Gulf and Asia.

Refining margins peaked in the summer, reaching an average of $9.75/bbl on the US Gulf coast in July and $6.97/bbl in Europe – their highest monthly averages since at least 2012. European refiners were particularly pleased after many months in recent years of negative margins in the region, as reported by the IEA. As a result, European refinery autumn refinery maintenance fell to its lowest in nine years, averaging just over 200,000 bpd compared to a 2007-2013 average of almost 1m bpd. Autumn refinery maintenance was also reduced in 2014 to under 600,000 bpd. The two years of delays will inevitably spell a very heavy maintenance period in the near future – perhaps at a time when the market can least afford it, i.e. this could lead to a larger than usual reduction in European crude demand during autumn seasonal maintenance at a time when the crude tanker market is weak.

The boost in margins has lent itself to temporarily relieve the long ailing and oversupplied European refining sector, but the long-term reduction in capacity has not been avoided. Total is still planning to halve capacity at its 222,000 bpd Lindsey refinery in 2016, while despite union protests their 153,000 bpd La Mede refinery, outside Marseille, will be converted into France’s first bio-refinery of 10,000 bpd and will stop refining crude oil at the end of 2016. ENI will also convert its 100,000 bpd Gela refinery in Sicily into a bio-refinery which is expected to be completed in 2016 with the first production of biodiesel. Finally, it has recently been announced that Phillip’s 66 is again looking for a buyer for its 71,000 bpd Whitegate refinery on the south coast of Ireland, if no buyer is found it may close. In Australia, BP closed the 102,000 bpd Bulwer refinery in Brisbane which leaves the country with four refineries at a combined capacity of 444,000 bpd, from a countrywide capacity of 844,000 bpd in 2003. In Asia, CPC closed the 220,000 bpd Kaohsiung refinery in Taiwan which removed substantial gasoil supplies from the Asia-Pacific region. Finally, a long-term refinery reduction plan that continues apace is that of Japan. Petrobras closed their 100,000 bpd Nishihara refinery in 2015, while the country needs to close another 400,000 bpd of capacity to reduce Japan’s total refining capacity to 3.45 million bpd under a government mandate to reconcile the downstream sector with dwindling domestic oil demand. To address the remaining 400,000 bpd closures, Japan’s top refineries have announced merger plans with each other and streamlining of adjacent refineries.

Two giant refineries in the Middle East Gulf came online nearly simultaneously during the summer of 2015, although both suffered some minor intermittent start-up problems. The two refineries boosted volumes for particularly LR tonnage out of the region destined for Europe, Asia and Australia as the country became more reliant on product imports following the refinery closures. The two refineries were the 416,000 bpd Ruwais expansion in the UAE and the 400,000 bpd Yanbu Yasref refinery on the Red Sea. The Yanbu refinery processes crude from a new oil field, thereby not reducing crude export volumes, and has become a major supplier of high specification diesel to Europe. Further expanding Middle Eastern refining muscle are two projects in Iran, the first was a small 30,000 bpd expansion at the 320,000 bpd Bandar Abbas refinery at the end of 2015 while a new 300,000 bpd refinery is due in Q2-2015 also in Bandar Abbas called the Persian Gulf Star that will produce mainly gasoline, Iran’s only net product import. NNPC, the state-owned Nigerian oil company, has also been eagerly expanding domestic refining capacity in an effort to cut the country’s product import bill. Three existing refineries, the 210,000 bpd Port Harcourt, 125,000 bpd Warri and 110,000 bpd Kaduna refinery have however been plagued by a number of start-up problems for several months and so remain out of commission which will support product imports into the country from primarily Europe, but also the US.

High refinery output in the west, encouraged by lofty margins, kept the west in surplus of naphtha and continued to support the west/east naphtha trade. Arb volumes, and freight demand, was particularly strong during the summer months, peaking in August just short of 2 million tons, as refineries in the west were running at near full capacity as margins reached their peaks for the year on the back of strong gasoline demand. In September, arb volumes dropped sharply in part due to problems at some petrochemical facilities in the Far East, weaker gasoline margins and as seasonal maintenance in the Far East set in. Despite west/east naphtha arb volumes climbing well above August highs of 2 million tons in January, the backlog of tonnage in the Middle East Gulf has prevented a similar strengthening in freight as it did in the summer. Far eastern demand for naphtha is expected to continue coming from China as they add an estimated 296,000 bpd of reforming capacity this year to meet China 5 fuel standards by the start of 2017, while runs in the west are expected to remain relatively high

which will help to keep west/east arbitrage economics supported, although west/east naphtha, as always, remains in competition with LPG as an alternative feedstock and with regional condensate splitting capacity inAsia-Pacific.

World Tanker Fleet

VLCC fleet growth remained low in 2015, growing at a year-on-year rate of 2.8% after rising by 2.4% in 2014 and 2.1% in 2013. Years of consecutive low fleet growth have enabled a more pronounced freight response to the recent changes in demand. Lower fleet growth in 2015 was attributable to a low level of additions at only 18 vessels while 3 VLCCs were removed from the trading fleet which were all converted to floating storage units – this is less than the 9 and 17 vessels that were removed in 2013 and 2014, respectively, as the tight market found employment for several older vessels while the buoyant market and dropping scrap steel prices dissuaded scrapping. Slippage in 2015 was 25%, slightly less than the 2009-2014 average of 27.6%, as the well performing markets encouraged ships to be taken on time. The removal of the three floating storage units (“FSUs”) from the fleet were under 20 years old – with one under 10 years of age – doing little to change the average age of the fleet, which currently stands at 19 years of age. As of the 1^st of January 2016 there were 70 VLCCs scheduled for delivery for the year – applying the average slippage of the past six years of 27.3% this would imply expected additions of 51 VLCCs into the fleet this year and expected removals of 7, pushing fleet growth up to 6.7% - the highest since 2011. The current orderbook translates into heavy fleet growth over the next couple of years as well, with a reasonable expectation for heavy removalsaccelerate towards the end of the decade as manyover 30 VLCCs turnare turning over the age of 20.20 each year after 2020, which along with the uncertainty regarding the impact of sulphur regulations on bunker fuel expected to come into force in January 2020, might make the decision for the owners a bit easier.

Suezmax2017 proved to be a heavy year in terms of deliveries for Suezmaxes, with 49 vessels coming into the market. The ten removed vessels were not enough to offset the heavy deliveries, bringing the year’s fleet growth is also expected to have experienced its last consecutive year of low fleet growth of 1.4% after contracting in 2014 at a rate of -0.2%. The low fleet growth this past year was due to a very low delivery figure of only 9 Suezmaxes against 3 removals, however for 8.5%—the second year in a row more than 10 orders were cancelled during the year.highest since 2011. Excluding the19 cancellations, slippage for 20152017 was a low 10%at 26%, lower than the 2009-2016 slippage average of 38.4%. Deliveries are expected to remain elevated this year, with 50 Suezmaxes

scheduled to be delivered, out of which twelve have already delivered in January and February. However, with an expected increase in removals for the reasons mentioned above, we expect fleet growth to ease off at 4.8%.

Aframax (including fully coated LR2s) fleet growth in 2017 fell to 3.9% from 4.9% in 2016, following higher removals compared to the 2009-2014 average of 43%. The average agepast couple years. In the beginning of the 3 removed Suezmaxes was 18 years old, although one ship was less than 10 years old and was the only one not to be scrapped but converted into an FSU. Considering the few deliveries made during the year, the age of the fleet in fact rose by 1 year to average 9 years old as at the 1^st of January 2016. Similar to the VLCC fleet growth outlook, Suezmax fleet growth in 2016 is poised to jump markedly with 48 scheduled deliveries for 2016 as at the 1^st of January 2016, using the slippage average since 2009 approximately 31 of the scheduled deliveries are actually expected to deliver against 5 removals leaving fleet growth somewhere in the range of 6%. Suezmax fleet growth is expected to experience peak fleet growth come 2017 according to the orderbook, fleet growth will then ease from there but likely not back to the lows seen in 2014 and 2015.

Aframax fleet growth in 2015 rose to 2.9% from -1.2% in 2014 on the back of relatively high deliveries of 31 and very low removals compared to earlier years as the fleet had already cleared itself of older tonnage, although the average age of the fleet remains at 20 years as it was for end-2014. At the start of 2015 there were 4582 Aframaxes scheduled to deliver,be delivered, of which 31 did deliver61 were delivered during the year, equating to a slippage rate of 26.2%25%. Nearly all47 of the Aframaxtotal deliveries were fully coated (LR2s). Following high LR2 deliveries and only four removals, LR2 fleet growth surged to 14.8% in 2017, the highest level since 2010. A total of 72 Aframaxes were scheduled to be delivered in 2018, eleven of which have already delivered. Of the Aframaxes scheduled to be delivered in 2018, 31 are coated. Four of the six Aframaxes that were removed were scrappedAfter accounting for slippage and averaged an age of 23, while the remaining two were converted to an FSU and a heavy load carrier and together averaged an age of 23.5. Fleetaccelerating removals, Aframax fleet growth is expected to accelerate in 2016 with 69 Aframaxes scheduled to deliverbe lower this year as at the 1^st of January 2016, two thirds of which are fully coated, removals are also expected to trend back up to the long-term average as older tonnage remains especially after scrapping was delayed this year to take advantage of the tight market, but it should be noted that the cut-off trading age for Aframaxes is more flexible than it is for VLCCs and Suezmaxes. Using the average slippage since 2009 of 31.9%3.1%, additions are expected to reach 47 with 15 vessels expected to be removed from the fleet in 2016. Overall, expected deliveries and removals will translate into an estimatewhile LR2 fleet growth in 2016 of 3.6%, which will further accelerate comeis estimated at 5.1%. In 2017, with 77 vessels scheduled to deliver that year as at the 1^st of January 2016. This past yearwe saw a marked movement of coated vessels24 LR2s switching to trading Dirty Petroleum Product (“DPP”)Products (DPP) from trading Clean Petroleum Product (“CPP”)Products (CPP), due to the attractive Aframax earnings. The percentage ofoffsetting somewhat the fleet pressure on the clean trading DPP increased from ~32.5% at the

as $79.25m in April. Attractive newbuilding prices led to a lacksurge in ordering activity with 59 VLCC orders being placed in 2017. 69% of liquiditythe total orders were placed in the tanker sale and purchase markets.

In 2015, a total of 73 VLCCs were ordered – the most in at least the past four years. Over half of the orders were made in the secondfirst half of the year, aspersistently low earnings continued to strengthen, newbuilding prices remained attractive and asslightly higher asset values slowed demand for new tonnage. Of the impending IMO Tier III engine standard that came into place at the start of 2016 would add an extra cost of $2-$4 million, encouraging purchases59 orders, 46 were placed in 2015 that maySouth Korea, followed by Japan (7 orders) and China (6 orders). Six VLCCs have otherwisealready been made later. 3 VLCCs were ordered in the first monthtwo months of this year by three different owners.

Despite a $2m decline in Suezmax newbuilding price to $53m, Suezmax orders remained relatively unchanged compared to 2016 bringingwith 23 orders placed by the end 2017. 14 orders were placed in the first half of 2017, with no orders placed in the Third Quarter of 2017. Similarly to VLCCs, the majority of the new tonnage was ordered in South Korean yards (14 orders), followed by Chinese (5 orders) and Japanese (4 orders). So far this year there have been no Suezmax orders.

Aframax newbuilding prices in South Korea rose by $2m in 2017 to $44m by the end of 2017. Total Aframax (coated and uncoated) orders were 54 in 2017 compared to only 17 in 2016. 14 of the total orderbookAframaxes orders last year are known to 138 againstbe coated (LR2s), however coated orders might end up being higher as we approach the delivery date and more information is revealed in terms of the vessels’ coating. In 2016, eight Panamax (coated and uncoated) orders were placed, with one of them being confirmed as coated (LR1). LR1 newbuilding prices in South Korea were unchanged YoY in January 2018 at $39m. The majority of both Aframaxes and Panamaxes have been ordered in China (21 Aframaxes and 5 Panamaxes). Between January and February 2018, two Aframax orders have been placed in South Korea.

MR newbuilding prices in South Korea also increased by $2m during 2017 to $34m by the end of 2017. Total MR orders rose to 62 compared to only 25 in 2016, however MRs have long passed their peak ordering activity when over 100 MRs were ordered each year during 2012 and 2013 as part of theireco-fleet renewal. The majority of MR orders were placed in South Korea (24 orders) followed by Vietnam (21 orders). For the first two months of 2018, 11 MR orders have been placed as MRs have started the year on a fleetpositive note in terms of 656earnings. Handymax ordering activity continued the downward trajectory of the past four years with only four vessels ordered, all of them at Chinese yards.

Expectations are that this year will prove to be the timebottom of writing.

Similarly, strong crudethe market in terms of earnings, encouraged heavy Suezmax ordering in 2015 with a total of 79 orders assome support might be provided at the end of 2015 that will deliver on the backthis year and in 2019 owners might start ordering in volume again as scrapping, especially of the smaller Suezmax fleet, which atolder tonnage, is expected to take off by the time of writing totals 435 vessels. Over a thirdend of the decade as the fleet starts to age. Moreover, high steel prices, along with the difficulty for the older tonnage to find employment in an oversupplied market, and the cost of ballast water treatment installation that is also hovering on owners’ balance sheets may create an environment of increased scrappings followed by increased orders were made in the fourth quarterfor replacement of the year with mainly South Korean shipbuilders throughout 2015, although almost a third were made with Chinese shipbuilders during the year. Despite the marked fall in VLCC (South Korean) newbuilding prices, Suezmax newbuilding prices stayed relatively stable throughout the year – dipping to $64m for two months in September and ending the year back at $65m. So far in 2016, Suezmax ordering continues to outpace VLCC ordering with a total of 4 Suezmaxes ordered in the first month of the year, bringing the total orderbook up to 129 vessels at the time of writing.fleet.

Aframax ordering in 2015 was no different, a total of 30 uncoated and 99 coated LR2s were ordered. In 2014 a total of 9 uncoated and 15 coated LR2s were put on order, but the high LR2 figure is not completely stand alone as 85 coated LR2s were ordered during 2013. Aframax ordering jumped in Q2-2015 and stayed high for the rest of the year as average annual earnings were almost double levels from 2014 and as (South Korean) newbuilding prices fell by $1 million, although keeping in mind the effect of the USD appreciation throughout 2015. Most recently, newbuilding prices have fallen by a further $1 million since the start of the year, 5 Aframaxes (believed to be uncoated) have since been ordered during January 2016 bringing the total orderbook to 192 against a fleet of 901 vessels (coated and uncoated) at the time of writing. Even though the majority of orders are specified as fully coated vessels, uncoated vessels can still be switched to fully coated before construction ends while for a short time uncoated vessels can trade clean for their very first voyages, although they will have to revert to dirty trades so as the refined products do not significantly erode their uncoated tanks.

MR ordering in 2015 was non-existent in Q1-2015, and only showed a total of 3 orders in Q2-2015 as the market took a breather from the vigorous eco-MR driven ordering from 2013 when 226 vessels were ordered. Despite the absence of newbuilding orders, prices actually increased in February 2015 to $37 million but shortly later sunk down to $36.5 million where they remained until July, they only declined later in the year to fall by $0.7m year-on-year as the market instead seemed to favor secondhand vessels. Earnings in the first three quarters of 2015 were at least double than during the same period last year which must have encouraged some orders despite the intense focus there seems to have been on crude ordering during the year. Throughout 2015, a total of 98 MRs were ordered, 95 of which were ordered in the second half of the year. There were only 2 MR orders in January 2016, which brings the orderbook to tally at 202 against a fleet of 1301 at the time of writing.

Despite the vast majority of annual tanker earnings in 2015 reaching their highest level since 2008, the same magnitude of rise was not reflected in newbuilding prices which lent itself to encourage high level of particularly crude and LR ordering witnessed last year. It could be argued that market players were intent instead on capturing the current market which limited the price appreciation on vessels that would not be delivering for another two years at least. In addition, it has been shown that years of strong earnings typically lead to years of high ordering, while the introduction of the IMO Tier III engine standard come 2016 also may have pushed some orders to happen in 2015 that may have otherwise happened later. Conversions from the dry bulk market into tanker orders also continued in 2015, there were estimated to be almost 40 dry conversions in 2015 and a handful of LNG conversions into tanker orders.

Second-hand Prices

Price assessments were suspended in late 2008 and early 2009 due to a lack of liquidity in the tanker sale and purchase markets

Secondhand vessels, unlike newbuildings, could be used immediately for trading – which is partly the reason behind their price appreciation this past year, and importantly since 2014, amid the resurgent market since late-2014. VLCC 5-year old prices rose $1 million throughout the year, but this marks a 30% rise in price since January 2014 which was first brought on by the contango storage play possibility towards the end of 2014. Suezmax prices similarly rose only minimally year-on-year but represent a $22 million increase in price since January 2014. Aframax secondhandsecond-hand prices rose by $1.5 million,10% YoY to $61m, Aframax prices increased by 11% to $30m, MR prices grew by 15% to $23m while LR1 prices remained unchanged at the $25m levels. Suezmaxes fell marginally by 1% YoY to $40m.

Vessel Earnings

The tanker markets continued to be bearish in 2017 across all sectors. Oversupply of tonnage, especially for the crude sector, where four VLCCs and four Suezmaxes were delivered each month, and higher oil prices that

led to higher bunker costs which ate into owners’ earnings led to crude tanker rates revisiting the low levels of 2013, while product tanker rates also remained subdued. VLCC (basis TD3 round voyage) earnings fell 41% YoY to average $24,000/day in 2017 with earnings reaching levels as low as $8,000/day in September. Suezmax (basis TD20 round voyage) earnings declined by 48% YoY to $13,000/day while the declineAframax Composite (basis an average of TD7, TD8, TD9, TD19 & TD17 round voyages) fell by 43% YoY to $12,000/day. Freight cost hit record low levels in newbuilding prices the spread between the two narrowed to $9 million – the lowest since 2008 when they were priced above newbuildings. Finally, MR 5-year old prices also rose in value by $1.6 million while newbuild prices declined,2017, reflecting the market’s demandoversupply of vessels. In the products market, LR2 (basis TC1 round voyage) earnings fell by 31% YoY to acquire vessels immediately in order$11,000/day, LR1 (basis TC5 round voyage) dropped by 41% YoY to capture$7,000/day while the 2015 market earnings spike.MR Composite (basis an average of TC2/14, TC6, TC7, TC10 & TC11/4) declined by 14% YoY to $12,000/day. Freight cost for the LR routes was also at record low levels with TC1 averaging $15.75/tonne and TC5 at $17.71/tonne.

Vessel earnings

On the whole, tanker earnings had an extraordinary earnings streakOil prices and, as a result bunker prices, recovered last year, dueeating into owners’ earnings. Rotterdam IFO380 averaged at $302/tonne in 2017, $91/tonne higher YoY. Based on the latest EIA forecast Brent is expected to average $62.13/bbl and WTI at $58.17/bbl, maintaining support for firmer bunkers this year. With the oil market currently in backwardation, floating storage has almost evaporated as a combination of surgingvessel employment option, leading to an increase in the tonnage supply as more vessels become available for trading. However, as we come closer to 2020 when the new lower sulphur regulations for bunkers will come into force, high sulphur fuel oil (HSFO) demand is expected to fall significantly, leading to an increase in demand for oil, and thus tankers, in the low price environment, low fleet supply growth in most sectors and a lower bunker cost. Year-on-year, storage.

VLCC earnings doubled (basis TD3 Middle East/Japan), Suezmax earnings rose 78% (basis TD20 West Africa/Northwest Europe) and Aframax earnings rose 47% (basis the HRP Aframax composite). Apart from January 2015 on the HRP Aframax Composite, earnings on the three crude benchmarks averaged higher every month of 2015 than the corresponding 2014 month. Both a cold early winter in early 2015 and the continuation of a low oil price environment following OPEC’s pivotal meeting at the end of November 2014 kept crude tanker earnings on their upward march that had started in Q4-2014. Q2-2015 was the strongest quarter-on-quarter earnings period - usually the spring months are a seasonal lull for crude tankers while refinery maintenance is in full swing in Europe and Asia, however, this time all three crude tanker benchmarks were more than double from Q2-2014 earnings as refineries worked to run near full capacity and capture booming gasoline demand growth during the peak demand season. This also led to surpluses of fuel oil among other products to be carried on tankers.Time Charter Equivalent Spot Market Earnings again trended higher during the third quarter, but largely due to a very strong July as earnings then seasonally fell with refinery maintenance limiting demand later that quarter. Exceptional earnings in October and December on the VLCCs, and consistently strong earnings on the Suezmaxes and Aframaxes ensured

VLCC

Despite a strong finishstart to the year, for crude tankerVLCC earnings which were up almost 50%started falling after February 2017 to average the year at approximately $23,000/day (basis TD3 MEG/Japan round voyage). The heavy delivery schedule started to take

its toll on earnings that, combined with higher bunker prices, hit levels last seen in 2013. VLCC earnings averaged approximately $32,000/day in First Quarter of 2017, marking the lowest First Quarter since 2013. Earnings eased off further as the year progressed with Second Quarter of 2017 averaging at $23,000/day and Third Quarter of 2017 at $14,000/day. The much-anticipated winter market fell short of owners’ expectations as the traditionally stronger Fourth Quarter provided some support to earnings that rose to $24,000/day. Fifty VLCCs and over 15% on Suezmaxes and Aframaxes year-on-year comparedcoming into the market along with the extension of the production cut deal distorted the demand/supply balance in the VLCC market leading to the also strong Q4-2014.

As already explained, the low oil price environment sparkedlowest $/tonne paid since 2002 as freight cost averaged approximately $8.90/tonne. VLCC earnings had a multitude of positive demand factors for the tanker market but in addition it has also leaddisappointing start to a reduction in the primary voyage cost for shipowners: bunkers. Bunker prices fell to an annual lowthis year with earnings well below OPEX levels at the very end of the year but then have continued to fall to a 12-year low around mid-January 2016 of just above $100/ton (Rotterdam IFO380) as Brent fell below $30/bbl. The reduction in bunkers from their highs of over $600/ton in the first half of 2014 to well under $200/ton at the end of 2015 reduced the percentage of bunkers over gross freightcurrently approximately $5,000/day (basis TD3 Middle East/Japan) from over 80% to under 20%, which means that after paying for bunker costs, shipowners had 80% or more leftover to cover other costs and hold as profit as opposed to under 20% which was the case when bunker prices were above $600/ton in 2013-14. The importance of the fall in bunker price in relation to earnings cannot be highlighted enough. The low

bunker prices last year related to a low oil price which in this case stemmed from excess oil and lead to higher oil demand, all positive factors for demand for tankers throughout 2015 – this meant that vessel utilization increased and owners were able to hold on to the benefit of the declining bunker costs and inflate their profit margins.

Although supply growth is picking up in 2016 and for the next couple of years thereafter, fleet growth at the moment remains supportive as heavy deliveries on VLCCs, the first sector to reach peak fleet growth, are not expected to impact the market untilTD3C MEG/China round voyage). With OPEC extending its production cuts through the end of the year and into early 2017. Therefore, earningsfleet growth remaining resilient, we are unlikely to see any significant recovery in rates in the near-term. However, expectations on higher scrapping, increased U.S. production, rising Chinese import requirements amid higher crude import quotas granted by the government this year will remain supported by slowly building crude supply growth, continued strong oil demand growth and low bunker prices. That being said, the crude oil oversupply is projected to narrow come Q3-2016 and so oil prices, and by extension bunker prices, are expected to steadily pick up eventually eating into tanker earnings. In addition, the boon in oil prices that was propagated from the plunge in oil prices has now been factored into demand growth, oil prices cannot fall by another $50/bbl when they are already at ~$30/bbl. This, among other factors such as lower demand in oil producing nations, lower industrial demand, removal of subsidies in some countries, etc. has lowered the oil demand growth outlook for 2016 and onwards. Floating storage remains a possibility pending a widening of both the crude and now products contango, in Northwest Europe the gasoil contango has strengthened markedly since the build-up of supply due to a mild winter, low Rhine water levels keeping the product trapped along the coast and an influx of cargoes from the Mideast Gulf, Russia, the US and Asia. If floating storage once again becomes viable, it will act as a floor to the market. Finally, the possibility of slowing down tanker speed to stem fleet supply growth is for the most part out of the question as low bunker prices do not justify slowing down untilmight help the market reaches very low levels.

The products sector likewise started out on a strong note in 2015 as earnings for the year were approximately $10,000/day higher on the HRP MR Selected Composite and similar annual gains were made in the LR market. The two new Middle Eastern refineries that came online provided significant cargo volume for LRs, while a cold start to 2015 and strong gasoline demand globally kept the fleet busy from the start of the year torecover by the end of summer. However, this annual gain would have been higher without the weakness exhibited in Q4-2015, which was the only quarter to record lower earnings compared to the same quarter in 2014. Product earnings did also receive a boost from the lower bunker price while Worldscale rates stagnated at lower levels due to a number of factors including a build-up in LR tonnage in the Middle East Gulf after a strong naphtha arbitrage during the summer, limiting any breakaways in LR freight from the region, a build-up in product stocks on both sides of the Atlantic bringing both the diesel and gasoline arbitrages between the regions under pressure, and of course the immense MR fleet growth in 2015 which did not bring earnings crashing down but certainly added to supply during the year. As DPP earnings rose relative to CPP earnings the percentage of fully coated vessels trading DPP inched during 2015, exhibiting the ability of switching to act as a “cap” to earnings on both sides of the market.

VLCC Time Charter Equivalent Spot Market Earnings

VLCC

Buoyed by a spur storage play excitement, VLCC earnings (TD3 Middle East/Japan) rose slightly from December 2014 to average just over $73,000/day in January 2015 as 1-year TC rates rose to $42,500/day in the third week of the month. A lot of floating storage interest was generated when the Brent 12-month contango widened to above $10/bbl, prompting many to include a storage option in their TC arrangements or take vessels specifically to store. All of the earnings stated above and in subsequent comments are basis the HRP standard speed and consumption assumptions ~ 12-13 knots which we also refer to as Slow Steaming. The market fell seasonally in February and March, leaving earnings for the quarter to average over $58,000/day. Earnings in Q2 were extremely robust, averaging almost $63,000/day – almost four times the Q2-2014 average – especially considering it is a seasonally weak period of the year for the VLCC market. The strength continued into Q3-2015 where earnings averaged above $57,115/day as refineries in most parts of the world, particularly in the US and Europe, ran at as high utilization rates as possible to capture high refining margins. VLCC earnings, however, dropped quite sharply in August as Chinese buying dropped by about 1 million bpd with a sharp fall in implied stockbuilding activity, and in fact a very slight drawdown in crude stocks. A notable tightness in prompt supply in the Mideast Gulf in October boosted earnings for the month, which was later explained by a record for the year Chinese imports for the month of December, which would be roughly when the vessels would arrive from the Middle East. Meanwhile, the increasing amount of crude that is being transported around the world has congested infrastructure in many parts of the world, tying up supply and then contributing to temporary shortages of available vessels. These port delays, as opposed to weather delays, again helped to push TD3 to average over $100,000/day in December 2015 – bringing the seasonally strong Q4-2015 average above $83,000/day. Once again the explanation for the rush of demand transpired with a new record high import level being set for Chinese imports arriving in February at 8 million bpd.

The fall in oil prices encouraged strong stockbuilding activity yet again in China, and coincided with minimal stockbuilding in India with the opening of the Visakhapatnam SPR on the west coast. Overall, the low oil price invigorated the global seaborne oil trade: sometimes aggressive pricing by producing nations led regions to import certain grades of crude they would not otherwise purchase, purchasing became more opportunistic and experimental, while lower oil prices continued to support strong refinery demand. VLCC crude and DPP seaborne volumes rose in 2015 to the tune of 4.7%, or 900,000 bpd, from a decline of -130,000 bpd in 2014 mainly related to DPP (mainly Fuel Oil).

Overall, 2015 VLCC (TD3 Middle East/Japan) earnings averaged $65,923/day – more than twice the average of 2014. So far this year VLCC earnings have averaged only slightly down after December’s high as refinery maintenance in North America and a pullback in buying in January aheador the beginning of Chinese New Year has taken some steam out of the market. A slowly rising fleet growth this year and lower, yet still robust oil demand growth, is poised to support healthy VLCC earnings in 2015, although earnings are not expected to reach the extraordinary highs of 2015 even though the market will still draw upon many of those factors which aided it last year.2019.

Suezmax Time Charter Equivalent Spot Market Earnings

Suezmax

SimilarSuezmax

Suezmax earnings in 2017 were similar to the VLCC market, the Suezmax composite (basis 70% ex-WAF and 30% BlackVLCCs, with TD6 (Black Sea/Med) experienced an uncharacteristically strong Q2-2015, envelopedaveraging 47% lower YoY at approximately $13,500/day and TD20 (WAF/UKC) 46% lower YoY at $13,000/day. Following theOPEC/non-OPEC market management deal, higher Dubai prices increased demand for (Brent priced) West African crudes last year, with WAF crude exports to Asia-Pacific rising by high earnings on either side at the start and end20% YoY to 1.48m bpd. Nigerian production returned last year, with output rising by 220k bpd YoY to 1.61m bpd in December, while Angolan output fell by 50k bpd YoY to 1.59m bpd as part of the year. Earnings rose strongly in January 2015, aided by the strength of the VLCC market and as OECD European runs in February rose above 12 million bpd for the first time since July 2013 – which is significant seeing as runs during the summer months are typically the highest of the year. The fall in crude oil prices and somewhat delayed reaction on retail fuel prices met to create high refining margins that European refineries had not been

accustomed to for decades, leading to an influx of crude imports to feed their renewed appetite. As a result, the Suezmax composite averaged over $47,000/day in Q1-2015, rising $7,000/day from the quarter earlier. The strength continued into Q2-2015 which was almost four times as high as the same quarter in 2014 at nearly $43,000/day – earnings were particularly strong in June as the first signs of record US gasoline consumptions began to trickle through, certifying that refineries should keep running at breakneck pace.

Earnings sunk in the third quarter as the summer demand tailed off and refineries underwent maintenance, although European refiners for the second year in a row delayed a considerable amount of maintenance compared to the historical average which aided Suezmax tanker demand. After averaging almost $35,000/day in Q3-2015, earnings rose as they usually do seasonally to average over $47,500/day in Q4. A fall in prompt supplyOPEC cut deal. However, Suezmaxes in West Africa encouraged a rallydid not manage to

benefit from the increased eastbound volumes as the majority ended up in VLCCs that increased their WAF market share to 49% from 42% in 2016. With 13 vessels coming into the market in the First Quarter of 2017, earnings averaged at $19,000/day for TD6 and $18,000/day for TD20. Despite the endreturn of November,Forcados in May, earnings edged further down in the Second Quarter to $12,500/day to sink at $7,750/day (TD6) and $8,750/day (TD20) in the very strong VLCC market during December helped to keep supplyThird Quarter. Pipeline leakages in July affected loadings of Bonny Light, however production remained unaffected with August output at 1.66m bpd, the highest level since March 2016. Earnings recovered somewhat tight ex-West Africa as supply moved to capturein the spike ex-Mideast Gulf, keeping earnings high at $67,000/day. Overall, the Suezmax composite averaged $43,089/day in 2015 basis our standard assumptions. With the removalFourth Quarter of the US crude export ban and fall in US production towards the end of the year, there has been renewed crude purchasing from West Africa2017, driven by the US, bringingseasonally stronger winter market and an ease in deliveries, with TD6 averaging $14,250/day and TD20 $13,500/day. In terms of $/tonne, both routes hit the phased out TD5 West Africa/US Atlantic Coast trade somewhat back into play. US refineries will looklowest levels on record, with TD6 averaging $5.66/tonne and TD20 $9.12/tonne. 2018 to import crude when the cost of bringing domestic volumes by train is more expensive. If WTI traded at a premium to Brent consistently (as it did immediately following the lifting of the ban) this would bode well for Suezmax demand. So fardate, TD6 averaged $4,000/day and T20 $5,750/day. Despite some recovery in 2016, earnings have averaged less than the 2015 annual average at the time of writing, although the market has picked up from its low at the start of February which is historically a weak month. High refining runs in Europe, and in other regions, a low delivery schedule until the end of 2016 and a strong VLCC market translates into healthy expectations for 2016.

in August. Driven by very strong earningsa stronger October, the Aframax Composite rose slightly in northern Europe which can be quite weather-sensitive during the winter months. TD17 Baltic/UK Continent averaged almost $75,000/Fourth Quarter of 2017 to $11,750/day, however December’s weakness in January, while TD7 North Sea/UK Continent rose above $50,000/day duringmost of the same month amid a particularly cold winter in northern Europe. Similarroutes weighed down the sector. The return of Libya to the other crude benchmarks,market has not translated into higher earnings so far due to its unsustainability while Aframaxes have been increasingly feeling the pressure from Suezmaxes in certain regions, such as the Black Sea. The Aframax composite remained unusually high in Q2-2015 – almost three times the level it was during Q2-2014 – to average over $40,000/day with marked strength in all six routes comprising the benchmark particularly in June, as exhibitedComposite remains subdued so far this year, with the Suezmaxes. Earnings fell inmajority of the third quarter to under $30,000/day due to notable weakness in TD11 Cross-Med which fell to under $18,000/day asroutes trading below $10,000/day. On the tonnage list outweighed cargo activity duringother hand, the period.

Earnings recovered in the fourth quarter to average almost $39,000/day, near where theyclean LR2 market has started the year as the Mediterranean market recovered but also as the weather-sensitive routes picked up despiteon a mild start to the winter. Overall, the Aframax composite averaged $37,262/day in 2015 as quarterly earnings establishedpositive note with TC1 currently trading at consistently higher levels than in 2014. Despite fleet growth in 2016 for the Aframax sector rising only slightly, the sector will be hurt by the supply growth on larger vessels and the newbuild coated Aframax tonnage pushing more (likely older) coated vessels into crude/fuel oil trades instead. Year-on-year earnings will be lower in 2016 but will still reach healthy levels given expectations of robust oil demand continuing for at least the first half of this year.

and pipelines remained offline in the USG for a further fallprolong period of time between August and September, pushing TC2 to record high levels of $24,000/day amid increased demand for gasoline and gasoil in price. South Korea started two nuclear units last June and July, the next unit is not expected until April 2016 but an expected build in LNG storage by the South Korean electricity provider Kepco will keep LNG demand growing in 2016 despite the nuclear threat.

LNG supply in 2016 is expected to rise by an estimated 10% year-on-year, or 24.5 million metric tons, with more than three quarters of the rise coming from the Australasia region as the Yemeni plant is expected to remain offlineU.S. However rates eased off quickly due to a struggling UN peace processoversupply of tonnage in the country.region followed the spike in the UKC/USG trade. Following refinery shutdowns in the USG, U.S. distillates exports to Europe fell to 136k bpd in September with TC14 generating negative TCEs between September and October. The second 4.5 million tons per annum (“mtpa”) trainlong-awaited products market recovery appears to be underway, with stocks in most major consuming regions at Conoco Phillip’s Australia Pacific’s LNG facility loaded its first cargoesor below their5-year averages and the fleet set to slow this year (2.8%). Following stronger earnings in January and is expected to start commercial operations bylate 2017, the end of Q1-2016, while Chevron’s 15.6 mtpa Gorgon project on Australia’s Barrow Island hasMR Composite started the commissioning process with the first cargo set to be loaded in February or March. In West Africa, the Angola LNG export project was reported to have started recommissioning at the end of January, meaning that commercial exports from the plant may start at the end of Q2-2015 while in Nigeria ENI has liftedyear on a force majeure from mid-December on loadings form the 22 mtpa Bonny LNG terminal. Other major supply developments are longer term, however there are expectations that investment will now switch to the demand side, meaning regasification facilities in import regions, particularly in South Asia, as opposed to liquefaction projects.

LNG Tankers In Service and On Order

A total of 420 LNG tankers were on the water as at the end of 2015, a year-on-year gain of 24 vessels and a gain of 60 vessels from the start of 2013. The orderbook totals 106 LNG tankers, one vessel lower than at the end of 2014. Freight to Japan trended down throughout 2016, while the arbs from Qatar and the Caribs spent the year under $2/mmbtu after swinging between $10/mmbtu and $3/mmbtu between 2011 to mid-2014. LNG tanker earnings east of Suez are down to $29,000/day, a year-on-year fall of 50%, while voyages west of Suez are also down 55% to $29,000/day. One-year term charters as a result are much softer, falling to $35,000/day – a year-on-year decline of 38%. Overall, the outlook is limited as scrapping remains low and the orderbook is healthy, but new liquefaction trains coming online this year, which will bring more LNG supply intopositive note. Since then the market is expected to provide for a modest recovery in freight in 2016.has come off slightly, however it remains at relatively healthy levels of approximately $13,000/day.

Risk Factors

Risks Related To Our Industry

CharterThe tanker industry is cyclical, resulting in charter rates are cyclical andthat can be volatile. A return to the poorPoor charter markets for crude oil carriers and product tankers which existed from 2008 to 2015 couldmay adversely affect our future revenues earnings and profitability.earnings.

After reaching highs during the summer of 2008,The volatility in charter rates, for crude oil carriers and product tankers fell dramatically thereafter, with only occasional temporary seasonal or regional rate spikes until the end of 2014 when charter rates began to stabilize at higher levels in responseturn our revenue and earnings, is due to the steep declinehistorically cyclical nature of the tanker industry. The typical cycle is partly created by material changes in the number of tankers available in the market resulting primarily from new deliveries to the market less vessels demolished or converted due to technical obsolescence and the number of vessels occupied on long-distance travel or delayed by geopolitical events. The cycle is also impacted by material changes to the supply of and demand for oil due primarily to corrections in the price of oil. The year 2015 was the strongest year for tanker charter rates since 2008.

oil and to geopolitical factors. As of April 5, 2016, 2220, 2018, about half of the vessels owned by our subsidiary companies were employed under spot charters based upon prevailing market rates (including time charters with a profit share component), and 13 of the remaining vessels were employed on time charters which, if not extended, are scheduled to expire on various dates between August 2016April 2018 and June 2028. In addition, 15 ofTanker charter rates declined significantly in 2016 and further declined in 2017, which had an adverse effect on our subsidiaries’ vessels have profit sharing provisions in their time charters that are based upon prevailing market rates.revenues, profitability and cash flows. If rates continue to be low rates in the charter market return and continue for any significant period in 2016,2018, it will affect the charter revenue we will receive from these vessels, which could have ana further adverse effect on our revenues, profitability and cash flows. Declines in prevailing charter rates also affect the value of our vessels, which followsare correlated to the trends of charter rates, and earnings on our charters, and could affect our ability to comply with our loan covenants.

Disruptions in world financial markets and the resulting governmental action in the United States and in other parts of the world could have a further material adverse impact on our results of operations, financial condition, cash flows and share price.

Global financial markets and economic conditions have been severely disrupted and volatile in recent years and remain subject to significant vulnerabilities, such as the deterioration of fiscal balances and the rapid accumulation of public debt, continued deleveraging in the banking sector and a limited supply of credit. While there are indications that the global economy ismay be improving, it is doing so at different rates in different part of the world and concerns over debt levels of certain European Union member states, poor liquidity of European banks and attemptsremains subject to find appropriate solutions are expected to lead to continued slow growth in most of Europe in 2016.downside risk. There can be no assurance that the global economic weakness or a recession will not return and that tight credit markets will not continue or become more severe.

In addition, the continuing sovereign debt crises in various Eurozone countries, including Greece,process of the UK to exit the European Union, as well as continued turmoil and hostilities in the Middle East and North Africa or potential hostilities between North and South Korea or between Ukraine and Russia,elsewhere in the world, could contribute to volatility in the global financial markets. These circumstances, along with there-pricing of credit risk and the reduced participation or withdrawal of certain financial institutions from financing of the shipping industry, will likely continue to affect the availability, cost and terms of vessel financing. If financing is not available to us when it is needed, or is available only on unfavorable terms, our business may be adversely affected, with corresponding effects on our profitability, cash flows and ability to pay dividends.

Moreover, as a result of the ongoingcontinuing economic crisis in Greece and the related austerity measures implemented by the Greek government, as well as the capital controls in effect in Greece sincemid-2015, our

operations may be subjected to new regulations that may require us to incur new or additional compliance or other administrative costs and may require that we pay to the Greek government new taxes or other fees or that dividends we pay be subject to withholding taxes. Furthermore, the commitments by the Greek government to the nations’ creditors and potential shift in its policies may potentially lead to Greece’s exit from the Eurozone, if not satisfied, which could affect our technical and commercial managers’ operations located in Greece.

The implementation by the U.S. or other governments of protectionist trade measures, including tariffs or other trade restrictions, could also adversely affect the world oil and petroleum markets.

The tanker industry is highly dependent upon the crude oil and petroleum products industries.

The employment of our subsidiaries’ vessels is driven by the availability of and demand for crude oil and petroleum products, the availability of modern tanker capacity and the scrapping, conversion or loss of older vessels. Historically, the world oil and petroleum markets have been volatile and cyclical as a result of the many conditions and events that affect the supply, price, production and transport of oil, including: