UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM20-F

OR

FOR THE FISCAL YEAR ENDED DECEMBER 31, 20152018

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, 2015,2018, there were 87,338,65287,604,645 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, 4,600,000 Series E Preferred Shares and 6,000,000 Series F 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:

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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, 2015.2018. 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, 2014,2018, 2017, and 2013,2016, and the

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consolidated balance sheets at December 31, 20152018 and 2014,2017, 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:

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)

All of the statistical data and other information presented in this section entitled “General Market Overview—World Oil Demand / Supply and Trade,” 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 Overview

(World Oil Demand/Supply and the Tanker Market

All text, data and charts provided by Howe Robinson)Robinson Partners

World Oil Demand/Supply and2018 was by many accounts the Tanker Market

Theworst year on record for tanker market enjoyed its highest earnings in over seven years in 2015, benefitting directly from lower oil prices. The sharp declineshipping in the price21^st century. Earnings for both the crude and products tanker markets disappointed for a third year in a row, with tonnage oversupply across the board and rising bunker prices hurting both segments. Excess OPEC crude production inQ4-18—ahead of oila further 1.2 million bpd output cut agreement starting from January 2019—pushed earnings down to levels not seen since winter 2016/2017, resulting in yearly averages equal or below the second half2017 levels in some cases. Despite some small pockets of 2014positive news, especially US crude exports, the overall market picture for crude tankers was this time driven by a global crude oversupply, rather than a decline in demand which was the driver behind the last sharp drop in oil prices during the financial crisisone 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 consumptionlargely flat tonne-mile growth in 2018, as OPEC adjusted production when needed to restore some parts ofprice stability in the world, strategic and commercial crude andmarket.

Global 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 productionrose by over 12.5 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 furtherYoY 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 infrastructure in the US Gulf coast, the natural crude export hub for US crude, falling US crude production, and a lack 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 last 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 299.99 million bpd in Q1-2016, fall2018 as any losses from the OPEC+ group were more than offset by increases elsewhere, mostly in North America. Meanwhile, significant OECD crude stock-drawing over the past year also contributed to 1.5almost flat crude tanker tonne-miles in 2018.

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Clean petroleum products stock-draws kept up a strong pace as well, keeping product tanker trade growth at a negative deviation from its long term mean of4-5% per year. The reversal of the 2015-2016 stockpiling dragged down cargo counts significantly in the first half of the year, and the absence of major export refinery expansions since 2015 also allowed the significantly high supply growth to catch up with ease and take a toll on owners’ earnings. Refinery throughput, however, continued to grow last year with an estimated YoY increase of 600,000 bpd in 2018, followed by a further 1.2 million bpd rise in refinery runs in 2019.

VLCC earnings (basis TD3_C) fell 18% YoY to average $19,000/day in 2018, with earnings stubbornly below $10,000/day in the first half of the year.

Suezmax earnings (basis 70% TD20 and 30% TD6) rose slightly by ~$1,000/day to $14,000/day while the Aframax Composite (basis an average of TD7, TD8, TD9, TD19 & TD17) increased by 16% YoY to $13,000/day.

In the products market, LR2 (basis TC1) earnings remained at similar levels to 2017 at $11,000/day, LR1 (basis TC5) earnings fell 10% YoY to $6,700/day while the MR Composite (basis an average of TC2/14, TC6, TC7, TC10 & TC11/4) dropped 8% YoY to average $11,000/day.

Nominal freight rates (on a $/tonne basis) in 2018 rose slightly for all sizes relative to 2017; however, rising bunker prices reduced owners’ earnings for most of the year.

Newbuilding and second-hand prices increased across the board on the back of increased steel prices and a rush by some owners to catch the bottom of the market. Ordering activity, however, was relatively muted last year with VLCCs and MRs as the only sectors in which owners showed real interest, mostly in the first half of the year. Some relief for supply growth was provided by record high scrapping activity, mostly in the crude sector, with 32 VLCCs, 21 Suezmaxes and 42 Aframaxes heading for scrap yards during the year.

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Global Oil Supply and Demand

Total World Crude Production Excluding Biofuels (Source: IEA)

World oil production rose by 2.5 million bpd YoY to 99.99 million bpd in Q2-20162018 as any losses from OPEC+ were more than offset by increases elsewhere. OPEC, along with tennon-OPEC producing countries, extended their 1.2 million bpd production cuts into the first half of 2018; however, involuntary losses from the likes of Venezuela and then sharply narrowAngola pushed total OPEC production 150,000 bpd lower YoY to 31.91 million bpd in the first half of 2018. This led major producers within the OPEC+ group to step in and increase their output to bring compliance down to 100% (as opposed to the 140% overcompliance at the time). US sanctionsre-imposition on Iran started taking a toll on total production in the second half of the year to average 0.3with Iran losing almost 1 million bpd – leavingsince the announcement was made in May 2018, to end 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 witnessed in the OECD Americas where stocks built by 93.2 million bbls. Stocks 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 surpluses 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 1.52.8 million bpd, less at 6.26 million bpdthe lowest level since March 2015. A rebound in October, highlightingNigerian and Libyan production, increases from Saudi Arabia, Russia, the powerful effect that stockbuilding has on Chinese crude import levelsUAE and by extension, crude tanker demand.

OPEC production roseIraq, and ever-growing US output led to supply outpacing demand by 1.07 million bpd in 2015 asQ3-18, resulting in 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 forgoOPEC+ group announcing a production ceiling altogether as they welcomed back Indonesia and as the uncertainty surrounding Iranian production growth following the liftingnew round of sanctions raised questions over the correct level of the ceiling. This decision was largely viewed as symbolic as OPEC had been pumping well above its 301.2 million bpd ceiling for many months. Recently,production cuts, this time excluding Iran, Venezuela and Libya, as of January 19. Saudi Arabia, Bahrain, Venezuela, Qatarthe UAE and Russia agreedalone opened the floodgates inQ4-18 to freeze production at January 2016 levels which, atmanage and pocket any revenues from 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 anywayadditional barrels in the year, ormarket before the cuts come into place in some cases was expectedJanuary with their production dropping by 780,000 bpdquarter-on-quarter to even fall. Iran and Iraq have so far not committed to an output freeze.

Since the announcement of sanctions was made, Iranian exports have collapsed below 1 million bpd and despite waivers granted to a few countries, traditional buyers in Europe, Japan and South Korea have appeared to be quite sceptical on purchasing these barrels.

Angola has also been one of last year’s underperformers as steep declines at mature fields and years’ long under-investment pushed output 150,000 bpd lower at 1.49 million bpd. However, Total’s ultra-deep Kaombo projectstart-up in July 2018, and an improvement in the country’s commercial terms has recently sparked some interest from international oil majors, which might revive somewhat the West African country’s oil industry in 2019.

On the bright side, Libyan and Nigerian output rebounded in 2018 with combined gains of 210,000 bpd YoY to 970,000 bpd and 1.6 million bpd, respectively, however Libya’s sustainability remains questionable as militia attacks shut in significant volumes from month to month. Saudi Arabian output stood 370,000 bpd higher YoY to 10.33 million bpd; however, it fluctuated from 9.92 million bpd in March 2018 to its historically high levels of 11.06 million bpd in November 2018 as the Kingdom was opening/closing the taps when necessary to keep oil supply on track with oil demand during the year. The UAE hit a record-high output in November 2018 at 3.33 million bpd, to average the year 2.5% higher YoY at 3 million bpd, while Iraqi production rose by 90,000 bpd to 4.56 million bpd with exports from Basrah rising to an unprecedented 3.63 million bpd in December 2018.

Totalnon-OPEC production rose by 2.7 million bpd YoY to 62.58 million bpd in 2018, driven by increases mostly in North America. US oil production climbed by 2.15 million bpd to average the year at 15.42 million bpd, with crude accounting for 1.6 million bpd of the 500,000 bpd Neutral Zonetotal growth. Increased production that the Emirate shares with Saudi Arabia following a dispute over its development.

At the endand some infrastructure developments have more than doubled crude exports, which as 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 sanctionsNov-18 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 2.86at 2.33 million bpd. The IEA expects Iranian outputmajority of these additional barrels are heading east, contributing 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 production 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 bpd this year as the resilient US oil industry, populated by many independent producers, only began to see consecutive month-on-month declines at the very end of 2015. Buoyant production from 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 lifting oftonne-mile effect on the crude export ban is not 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, 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 oftanker market. U.S. supply growth is expected to slow down in 2016. Reportedly,2019, remaining at a rather healthy 1.3 million bpd YoY, due to increasing base decline and as shale producers moderate the Russianpace of expansion following an almost 40% drop in crude prices inQ4-18.

Canadian production rose by 7.3% YoY to 5.17 million bpd; however, oil industryproduction might decline this year as it faces record high discounts for its crude and brimming inventories. Alberta announced in early December it would mandate temporary production cuts of 325,000 bpd inQ1-19 to drawdown the excess crude in storage and 95,000 bpd for the rest of the year. For the remaining OECD countries, North Sea crude production dropped by 100,000 bpd YoY to 3.39 million bpd, while Mexican output fell by 6.7% YoY to 2.08 million bpd. Total OECD oil output was 2.27 million bpd higher YoY, while a further 1.23 million bpd increase is ableexpected in 2019.

Non-OECD production rose only marginally YoY to keep functioning29.06 million bpd with Russia providing the only significant gains in total output. Even though Russia was part of the OPEC+ production cut agreement and its adherence to the deal had been quite strong, production set anall-time high of 11.78 million bpd inDec-18, to average the year 170,000 bpd higher at 11.49 million bpd. Kazakhstan’s oil output set a record high level of 2.03 million bpd inNov-18 with the recent low oil prices, however, government incomeyear averaging at 1.93 million bpd, 5.6% higher compared to 2017, as its Tengiz, Kashagan and Karachaganak were pumping at steadily growing rates. Output innon-OECD Asia continued its downward trajectory for a third consecutive year driven by falling Chinese production that has feltposted losses of 40,000 bpd which are expected to deepen by a sharper pinch. An ongoing debate for raising export levies and crude extraction taxesfurther 50,000 bpd drop in 2019. Brazilian production was quite disappointing last year, as the much-anticipated jump in output didn’t materialise with 2018 standing 40,000 bpd lower compared to 2017 at 2.7 million bpd due to delays on offshore production to bolster the national budget may reduce the country’s oil output accordingplatforms’start-ups. However, thanks to some commentators. North Sea production also remained resilient in 2015, production from NorwayFPSOs 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 estimatedoffshore fields 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 proteststarted up 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 growth2018, and a number of government efforts (mentioned previously as artificial demand caps) thatadditional offshore production facilities scheduled to come online in 2019, Brazilian output is expected to post the second biggest growth after the US this year at around 365,000 bpd.

OECD industry crude stocks have come significantly off their early 2017 peak levels, averaging 100 million bbls lower YoY at 1,087.5 million bbls in 2018, comfortably below their five-year average (although not below thepre-2015 stock-build average). Between May and September, OECD crude inventories dropped by 77 million

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bbls; however, lower oil prices and seasonal factors contributed to a 48 million bbl build in the last quarter of the year. The increase inQ4-18 was driven by stockbuilding in North America where crude inventories rose counter-seasonally to 610.9 million bbls inNov-18 – their highest level in a year, despite refineries coming back from maintenance. High refining utilisation pushed down crude stocks during the first eight months of the year; however, higher shale oil and Canadian production have started to overwhelm capacity and stocks are stemmingcurrently above their five-year average. OECD Europe stocks reached their lowest level sinceFeb-15 inDec-18 at 325.3 million bbls, while OECD Pacific inventories have stood below their five-year average sinceMar-18.

Total OECD Crude Stocks vs.5-Year Average (Source: IEA)

2018 global oil demand growth in an effortgrew by 1.3 million bpd YoY, at a slower pace compared to reduce pollution. Chinese refining capacity expanded2017 (+1.6m bpd YoY) and below initial expectations of 1.5 million bpd YoY growth. Demand marginally outpaced supply by approximately 650,000100,000 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 meetQ1-18 before the 2017 change in domestic fuel specifications tomarket turned into oversupply for the China 5 standard and amid a domestic fuel glut that has seen product exports surge towards the endrest of the year.

An important development this past World oil demand started the year worth mentioning is independent, or teapot, refineries being givenstrongly, supported by cold weather in Europe and the ability to processUS, thestart-up of petrochemical capacity in the US, and directly import crude in place of fuel oil. A reported total of 12 independent refiners have been given crude processing quotassolid economic growth. As a resultQ1-18 demand grew by February 2016 totaling just over1.8 million bpd YoY, with OECD nations contributing 1 million bpd while most have also been allocated direct crude import quotas. In order to receive these quotasof 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 crudetotal. A significant YoY drop in European 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 forslowdown in US growth pushed world demand 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 fallQ2-18 at only 560,000 bpd. A 50% increase in oil prices driven byinQ2-18 that was partly passed through toend-users and currency depreciation in some countries that amplified the oversupply should supposedly support global demand as a resultimpact 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 fallwere partly responsible for the slowdown. Robustnon-OECD demand growth in their domestic demand. The fall in oil price has sharply reduced an entire industry’s level of investment, itself a contribution to globalQ3-18 increased total 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,99.79 million bpd.Non-OECD Asia, supported by 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 portionmain contributor to global growth accounting for 74% of the risetotal growth inQ3-18. Global oil demand growth accelerated slightly through the end of the year to 1.4 million bpd inQ4-18. The US was the main contributor to OECD growth in the second half of the year, supported by ethane and gasoil, with OECD demand posting 420,000 bpd gains in the year. Totalnon-OECD demand was stronger, with growth accelerating in the second half of 2018, and is estimated to have increased by 850,000 bpd in 2018.

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Total Global Oil Demand (Source: IEA)

Crude Tanker Demand

In 2018, world crude trade experienced a 1.8% YoY fall in terms of volumes due to excessive stock-drawing, a slowdown in total Russian flowsoil demand growth, geopolitical turmoil, and production losses from Venezuela, Angola and Iran that offset Atlantic production increases and OPEC decision making just to name a few. In terms of tonne-miles, however, crude tanker trade saw a slight YoY increase of 0.5% amid increased Atlantic/East crude trade in the first half of the year. VLCC demand came off by 1.8% YoY with volumes falling from 21.49 million bpd inJan-18 down to 19.22 million bpd inSep-18 before rebounding back at 20.82 million bpd inQ4-18.

Significant increases on VLCC crude liftings from the US heading east were not enough to offset any losses from South America and West Africa. On the other hand, Suezmax trade grew by 2.3% YoY in terms of volumes, while the tonne-mile effect was non-seaborne)much more pronounced with a YoY growth of 6.5%. 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 exportsThe main contributor to the far eastern nation rose by an equivalent amount to Middle Eastern volumes (excluding Saudi Arabia) – thisgrowth was in large part due to rising Kozmino ESPO crude loadingsthe market share Suezmaxes gained on the long-haul Brazil/East 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 occurredLibya/East trades, while additional barrels from West Africa a fallin the first quarter of 90,000 bpd, duethe year also supported the overall Suezmax trade in 2018.

Aframax crude volumes collapsed last year by 6.1% 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 resultan average 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 3.9211.32 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 scheduledcompared 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 9.3812.05 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 flows2017 as liftings 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 importingtraditional key regions including Europe, Japan,the Baltic, the Mediterranean (the “Med”) 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 storageCaribbean towards the end of the year and increased competition from Suezmaxes in the Black Sea, South America and Libya took a toll on total Aframax crude shipments. Despite a dip inQ1-18, tonne-miles rebounded and following a strongQ4-18 they saw a 3.4% YoY increase as more NW Europe barrels made their way to the US.

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Fuel oil trade also declined last year across all sectors posting a 4.7% YoY drop in terms of volumes and a 6.2% YoY fall in terms of tonne-miles, with Aframaxes hurt the most. Falling fuel oil trade is expected to continue going forward especially as the warmernew lower sulphur bunker regulation comes into play in less than usual winter weathera year from now.

Total Crude Tanker Demand Split by Vessel Size—Volumes vs. Tonne-miles (Source: Lloyds List Intelligence)

Asia/Far East imports were once again the main contributor to the tonne-mile growth in Q4-2015 did not generate enough demand growth.2018. Tonne-miles rose by 6.2% YoY driven by a 13.6%quarter-on-quarter increase inQ4-18 most of which was concentrated in China. Other than the traditional MEG suppliers, Chinese imports from Russia and Brazil surged last year, while Libyan barrels made their way east in 2018 supporting longer-haul Suezmax trade. US exports to Asia stood at 1.13 million bpd inNov-18 compared to 524,000 bpd at the beginning of the year. Despite Europe being inundated by diesel importsstrong buying interest for US barrels from China in the first half of year, trade war tensions between the two countries brought volumes down to zero with US crude making its way to South Korea, Japan and Taiwan instead. With the production cuts in place, exports from the Middle East Russiadropped slightly YoY. Despite growing shipments to Asia Far East, the loss of market share in the US and Asia – alongthe Med pushed tonne-milesex-MEG down by 2.6% YoY, hurting primarily the VLCC sector. Flows from the Middle East were also affected by the significant drop in exports from Iran after the US announcedre-imposition of sanctions on Tehran. Iranian shipments fell to 0.62 million bpd inDec-18 compared to April’s high of 2.61 million bpd. Declining local production resulted in a fall in West African exports last year; however, exports out of Nigeria were boosted in the second half of the year. As explained above, South American exports dropped last year following a 570,000 bpd YoY fall in Venezuelan output and Brazil’s disappointing output levels; however, tonne-miles out of the region rose by 8.4% YoY in the last quarter of the year as thestart-up of a few offshore platforms in Brazil pushed exports higher with the majority of these incremental barrels heading east of Suez.

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Monthly US Crude Exports By Destination (Source: Energy Information Administration)

Products Tanker Demand

Despite a 1.2% increase in global oil demand, products tanker trade disappointed for another year in 2018. Sizeable stock-drawing sincemid-2016 significantly dampened trade and arbitrage movements, as major OECD regions relied less on imports to serve their own surging outputenergy needs. For the first half of the year, OECD products inventories were on average 25 million bbls below their five-year average at 1,414 million bbls. DuringQ3-18, OECD products stocks rose by 64.6 million bbls compared toQ2-18, the largest quarterly gain in three years, amid record high refinery runs in the US driven by lower crude prices and strong demand for products exports. Following a counter-seasonal reduction in gasoline US stocks due to high refining runs –lower prices that reduced gasoline imports to the US managedand an 8.2 million bbls fall in middle distillates on the back of higher demand, OECD America inventories dropped by 19 million bbls on the quarter inQ4-18. Lower diesel refinery output in Europe and a seasonal increase in kerosene consumption in Asia due to also boost distillate exportscolder weather contributed to total OECD products stocks to fall again below their five-year average. The closer global product stocks are to their “normalized” historical levels, the region, howevermore sensitive to arbitrage-driven movements the market becomes, with a large portion of the past years’ stock-draws expected to return to seaborne volumes in 2019 and beyond.

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Total OECD Product Stocks vs.5-Year Average (Source: IEA)

Refining margins in 2018 were 24.7% lower YoY in NW Europe/Med, 24.5% lower YoY on the US Gulf and 28.7% lower YoY in Singapore. The impact of stock-drawing finally appeared in refinery margins inMay-18 when despite a $5/bbl increase in Brent prices, product cracks persisted and margins rose.

Refining margins strengthened in NW Europe/Med during the first couple months of the second half of the year, as volatile crude prices in August eventually resulted in a lower average feedstock cost to refiners. However,Sep-18 brought an unpleasant surprise as the rapid rise in oil prices resulted in margins crashing in most of the regions to levels last seen at the start of 2016 the arbitrage had come under increasing pressureyear even as refinery throughput was lower on the back of seasonal maintenance. The year closed with refinery margins in Singapore falling by 65%month-on-month and by 46% in NW Europe/Med despite a significant drop in Brent crude prices with global refinery throughput hitting 83.03 million bpd inDec-18.

Following high refinery runs of 81.7 million bpd inQ4-17,Q1-18 throughput was 1 million bpd lowerquarter-on-quarter to 80.7 million bpd due to an oversupply of distillates on both sidesunplanned outages in the US, lower than expected throughput in China and a more extensive maintenance programme in the MEG. Driven by a push inQ2-18, refinery runs closed the first half of the Atlantic.year on a positive note with the east of Suez dominating the growth in refining activity, as China’s 760,000 bpd YoY growth proved to be higher than total growth of 380,000 bpd, more than offsetting a 605,000 bpd decline in the Atlantic Basin.

PerhapsFollowing a 3.2 million bpd decline between September-October, OECD throughput rose to 39.43 million bpd inDec-18.Non-OECD throughput growth fell to just 230,000 bpd inQ4-18, significantly lower compared to the most notable eventrest of the year’s 1.1 million bpd average growth. The drop came from Latin America, which posted its largest YoY decline at 630,000 bpd. Total refinery throughput has been growing consistently on a yearly basis with the IEA estimating a 0.6 million bpd YoY increase in 2018 to 82.1 million bpd. In 2019 global refinery

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throughput is expected to rise by a further 1.2 million bpd YoY to 83.3 million bpd withnon-OECD countries contributing 44.4 million bpd of the total (+0.7 million bpd YoY) and OECD the remaining 38.9 million bpd (+0.5 million bpd). China is expected to be the driving force with an estimated 0.5 million bpd increase to 12.5 million bpd, followed by OECD Americas that is forecast to gain 0.3 million bpd YoY to 19.7 million bpd this year.

Refining Margins (Brent in EU, Dubai in Singapore) and Global Refinery Throughput (Source: IEA)

The lack of mega export-refinery additions over the past three years has also hurt the product tanker market; however, this trend is expected to reverse this year for the US downstream sector occurredas 2.6 million bpd of refining capacity is scheduled to come online in 2019. Most of last year’s refinery additions came online 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 isyear, hence they are expected to be completed in 2016 with theramp up production this year. Petrochina’s 260,000 bpd Anning refinery exported its first production of biodiesel. Finally, it has recently been announced that Phillip’s 66 is again looking fordiesel cargoend-April, while 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 30,000200,000 bpd expansion at the 320,000state-owned CNOOC’s Huizhou refinery has supported gasoline exports from China. Vietnam’s 200,000 bpd Bandar AbbasNghi Son refinery atstarted commercial production inmid-November after months of tests and it offered its first gasoline export cargo inSep-18 after receiving the endgovernment’s approval to start exporting oil products. Along with the 130,000 Dung Quat refinery that came online in 2009, they are expected to meet 70% 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,oil products demand and reduce Vietnam’s dependency on supply mainly from South Korea. The 300,000 RAPID refinery in Malaysia has started test runs after receiving its first cargo inDec-18, while Chinese refiner Hengli’s 400,000 bpd Dalian plant started trial operations inmid-December. SOCAR inaugurated its 215,000 bpd STAR refinery in Turkey inmid-October; however, the 210,000 bpd Port Harcourt, 125,000 bpd Warri and 110,000 bpd Kaduna refinery have however been plaguedfirst tanker delivery is not expected beforeJun-19.

World Tanker Fleet (all numbers from 1^st of January 2018 to 1^st of January 2019).

After a couple years of stubbornly high fleet growth, VLCC fleet growth in 2018 came in at its lowest level in a decade at 0.8%, driven by a numberincreased removals that made 2018 the heaviest scrapping year since 2010. Despite 38 VLCC deliveries, 32 vessels were reported as scrapped with the vast majority leaving the fleet in the

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first half of start-up problems for several months and so remain outthe year (24 removals, as opposed to eight in the second half of commission which will support product imports2018). Due to weak market conditions slippage averaged at 37.7%—much higher than the historical average of 25.1%. 76 VLCCs are scheduled to come into the country from primarily Europe, but also the US.

High refinery outputmarket in the west, encouraged by lofty margins, kept the west2019 with ten of them already delivered 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 naphthaJanuary. Scrapping is expected to continue coming from China as they add an estimated 296,000 bpd of reforming capacityslow down 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 helpas owners might be tempted to keep west/east arbitrage economics supported, although west/east naphtha, as always, remainsolder tonnage around in competition with LPG as an alternative feedstock and with regional condensate splitting capacityanticipation of a stronger market inAsia-Pacific.

World Tanker Fleet

VLCC fleet growth remained low in 2015, growing at 2020. Despite 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. Lowerforecasted 5.9% 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 92019, after accounting for slippage 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 shipsscrapping, 2019 might prove 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 removals towards the end of the decade as many VLCCs turn over the age of 20.

Suezmax fleet growth is also expected to have experienced its last consecutiveanother year of low fleet growth if we effectively remove roughly 1% of 1.4% after contractingthe VLCC fleet due to scrubber retrofits, 25 NITC vessels which may turn to storage under sanctions, and increased removals/scrapping if this year turns out to be another poor year in 2014 at a rateterms of -0.2%. earnings.

The lowSuezmax fleet came off peak fleet growth this past year was due to a very low delivery figure of only 9 Suezmaxes against 3 removals, however for the second year in a row more than 10 orders were cancelled during thelast year. Excluding the cancellations, slippage for 2015 was a low 10% compared to the 2009-2014 average of 43%. The average age 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,21 vessels that were removed from the Suezmax fleet were enough to offset 31 additions bringing the year’s growth in 2016 is poised to jump markedly with 482%. Excluding six cancellations, slippage for 2018 was at 35.4%, marginally lower than the historical average of 37%. We are counting 30 scheduled deliveries for 2016 as at the 1^st2019 with six of January 2016, using thethem already delivered in January; however, after accounting for slippage average since 2009 approximately 31 of the scheduled deliveries are actually expected to deliver against 5and forecasted removals, leaving fleet growth somewhere in the range of 6%. Suezmax fleet growth is expected at 3.2% in 2019.

In 2018, a total of 48 Aframaxes (including fully coated LR2s) were added to experience peakthe fleet, bringing total fleet growth comedown to 0.6% compared to 4% in 2017 accordingdue to negative growth in the uncoated Aframax fleet. Slippage was close to the orderbook,historical averages at about 31.4% as in the beginning of the year a total of 70 Aframaxes (including LR2s) were due to come into the market. 38 removals from the uncoated Aframax fleet more than offset the 26 additions, bringing fleet growth will then ease from there but likely not backfurther down to 2%, while 22 deliveries in the lows seen in 2014 and 2015.

AframaxLR2 fleet combined with only four removals brought fleet growth for their coated counterparts to 4.9%, albeit a five-year low level. Following another disappointing year in 2015 rose to 2.9% from -1.2%the products market and an uptick in 2014 on the backcrude market in the second half of relatively high deliveries of 31 and very low removals compared to earlier years as2018, the clean trading LR2 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 45 Aframaxes scheduled to deliver, of which 31 did deliver during the year, equating to a slippage rate of 26.2%. Nearly all the Aframax deliveries were fully coated. Four of the six Aframaxes that were removed were scrapped 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. Fleet growth is expected to accelerate in 2016 with 69 Aframaxes scheduled to deliver 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%, 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 estimateposted negative fleet growth for the first time since 2011 as in 2016 of 3.6%, which will further accelerate come 2017 with 77 vessels scheduled to deliver that year as at the 1^st of January 2016. This past year2018 we saw a marked movement of coated27 vessels switching from trading Clean Petroleum Products (CPP) to trading Dirty Petroleum Product (“DPP”) fromProducts (DPP) as opposed to seven thatcleaned-up bringing the year’s switching activity down to 20 netdirty-ups, providing extra pressure on the total dirty trading Clean Petroleum Product (“CPP”),Aframax fleet. A total of 65 Aframaxes are due to be delivered in 2019, out of which 39 are coated. In January we counted eight LR2 deliveries and seven uncoated Aframax additions. 2019 is expected to be a higher year in terms of fleet growth—2.3% after slippage and forecasted scrapping—however the attractive Aframax earnings. The percentagemarket’s anticipation for a much stronger products market in lieu of the fleet trading DPP increased from ~32.5% atnew lower sulphur regulation in January 2020 might decelerate the

Newbuildings

Price assessments were suspended2018 was a relatively muted year in late 2008terms of ordering activity as persistent low earnings, arguably lower availability of traditional finance, uncertainty over the upcoming regulations and early 2009 duehigher steel prices have resulted in ordering focusing primarily on VLCCs and MRs, with the rest of the sectors receivinglittle-to-no buying interest at all.

VLCC newbuilding prices in South Korea rose by $9.4 million YoY to a lack$92.2 million, although the $90 million threshold was only passedend-November with the year averaging at $87.5 million until then. Ordering activity was front loaded, with 34 out of liquiditythe total 42 orders 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. Overfirst half of the year. South Korea remained at the pole position with 69% of the total orders placed in the country’s shipyards. Ten orders were madeplaced in Japan and the second half of the year as earnings continued to strengthen, newbuilding prices remained attractive and as 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 purchasesremaining three in 2015 that mayChina. Six VLCC orders have otherwisealready been made later. 3 VLCCs were orderedplaced in the first month of 2016, bringing2019.

2018 was the totallowest contracting year for Suezmaxes since 2013, with only eleven firm orders from a handful of owners as soon as the crude market picked up from September onwards. Before September, the Suezmax orderbook additions were close to 138 against a fleet of 656 at the time of writing.

Similarly, strong crude earnings encouraged heavy Suezmaxzero, with only two orders in April. Following an ordering in 2015 with a total of 79 orders asspree at the end of 2015 that will deliver onQ3-18, newbuilding prices rose by 15.8% YoY to $61.4 million. Apart from one vessel ordered in China, the backrest have been contracted in South Korea yards. So far in 2019 there have been two Suezmax orders.

Aframax newbuilding South Korean prices increased by $8 million to $52 million by the end of 2018. Aframax ordering activity came off significantly in 2018 with 12 uncoated Aframax and 14 LR2 orders placed as opposed to 22 and 32 in 2017, respectively. Coated orders however might prove to be higher the closer we head to the delivery date and more information in terms of the smaller Suezmax fleet, which at the time of writing totals 435 vessels. Over a thirdvessels’ coating is revealed. Half of the 2018 firm orders have been concluded with South Korean yards, followed by Philippines. No Panamax/LR1 order had been reported in 2018 compared to 11 in 2017.

MR newbuilding South Korean prices rose by $2.5 million over 2018 to $36.5 million by the end of the year. 68 MR orders were madeplaced last year with 40 of them contracted in the fourth quarterfirst half of the year with mainlywhen average MR newbuilding prices were at $35.1m. South Korean shipbuilders throughout 2015, although almostyards remained at the top spot with 35 orders placed, followed by China where 19 orders were placed. In January we saw four MR orders from a single buyer. For a third were madeconsecutive year, Handy ordering activity remained below ten, with Chinese shipbuilders during the year. Despite the marked fallonly seven firm orders in VLCC (South Korean) newbuilding prices, Suezmax newbuilding prices stayed relatively stable throughout the year – dipping to $64m for two months2018—six in SeptemberChina and ending the year back at $65m. So farone in 2016, Suezmax ordering continues to outpace VLCC ordering with a totalSouth Korea—all of 4 Suezmaxes orderedthem placed in the first monthhalf of the year.

Given the past few years’ low earnings environment and aforementioned factors that continue to weigh on ordering activity, we may experience another year bringingof low ordering activity in 2019. However, the total orderbook uplooks relatively empty after 2019 and if 2020 proves to 129 vessels atbe a good year for vessel owners as many anticipate, combined with the time of writing.

Aframaxneed for replacement tonnage due to the fleet’s ageing profile, we might see an uptick in 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.new decade.

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

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Second-hand prices increased across all sectors YoY, driven by a rush to a lackcatch the bottom 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-yearcycle that sparked more buying interest. However, five-year old prices rose $1 million throughout the year, but this marksdid not rise as much as newbuilding prices. For 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 secondhandVLCC, second-hand prices rose by $1.56.6%, compared to 11.4% for newbuildings. The VLCC market looks quite well-supplied up to at least 2020, meaning owners with access to finance might prefer to pay the premium of a newbuild in anticipation of better market earnings against an empty orderbook for the new decade and an ageing fleet that should keep removals elevated going forward. Suezmax second-hand prices increased by 8.8% to $43.5 million, andwhile Aframax five-year old prices remained largely unchanged as opposed to an 18.2% increase in newbuilding prices. MR second-hand prices rose by 13% to $26 million, a much stronger growth compared to the newbuildings, with the decline 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, reflecting the market’s demand to acquire vessels immediately in order to capture the 2015 market earnings spike.

Vessel earnings

On the whole, tanker earnings had an extraordinary earnings streak last year due to a combination of surging 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, 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 meetingstrengthening starting at the end of November 2014 kept crudeQ1-18.

Vessel Earnings

2018 turned out to be the one of the most disappointing years for tanker earnings on their upward march that had started in Q4-2014. Q2-2015 wasrecent decades. Earnings were dragged further down for a third consecutive year by oversupply and higher bunker costs and it would have been even worse if it wasn’t for the strongest quarter-on-quarter earnings period - usually the spring months areQ4 uptick—driven by a seasonal lull forwave of excess OPEC 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 alsoproduction—that led to surpluses of fuel oil among other productsa decent winter market for all vessel sizes.

VLCC earnings (basis TD3C round voyage) fell 18% YoY to be carried on tankers. Earnings again trended higher during the third quarter, but largely due to a very strong July asaverage $19,000/day in 2018 with 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 a strong finish to the year for crude tanker earnings which were up almost 50% on the VLCCs, and over 15% on Suezmaxes and Aframaxes year-on-year compared to the also strong Q4-2014.

As already explained, the low oil price environment sparked a multitude of positive demand factors for the tanker market but in addition it has also lead to a reduction in the primary voyage cost for shipowners: bunkers. Bunker prices fell to an annual low 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 fellstubbornly below $30/bbl. The reduction in bunkers from their highs of over $600/ton$10,000/day in the first half of 2014the year. Suezmax earnings (basis 70% TD20 and 30% TD6 round voyages) rose slightly by ~$1,000/day to well under $200/ton$14,000/day while the Aframax Composite (basis an average of TD7, TD8, TD9, TD19 & TD17 round voyages) increased by 16% YoY to $13,000/day. In the products market, LR2 (basis TC1 round voyage) earnings remained at similar levels to 2017 at $11,000/day, LR1 (basis TC5 round voyage) earnings fell 10% YoY to $6,700/day while the endMR Composite (basis an average of 2015 reduced the percentage of bunkers over gross freight (basis TD3 Middle East/Japan) from over 80%TC2/14, TC6, TC7, TC10 & TC11/4) dropped 8% YoY 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 bunkeraverage $11,000/day.

Oil 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 until the end of the year and into early 2017. Therefore, earnings 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 – rose steadily up untilend-October when they took a hit reaching 2017 low levels by the end of the year. Rotterdam IFO380 averaged at $401/tonne in 2018, $100/tonne higher compared to 2017. Going forward, oil prices are expected to steadily pick up eventually eating into tanker earnings. In addition,fall with EIA forecasting Brent averaging $10/bbl lower YoY to $61/bbl and WTI to $55/bbl pushing bunker prices lower giving owners’ earnings room for improvement this year. However, with the boon in oil prices that was propagatedIMO2020 regulation just months away from implementation, 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 loweredprice for HSFO is expected to start coming off 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 floorcloser we head to the market. Finally, the possibility of slowing down tanker speed to stem fleet supply growth isdeadline as demand for the most part out offuel will start falling. That should support owners’ earnings inQ2-Q3; however, the question as lowneed to use bunker prices do not justify slowing down until the market reaches very low levels.

The products sector likewise started out oncostlier compliant fuels in Q4 might put a strong note in 2015 as earnings for the year were approximately $10,000/day higherceiling 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 to 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 Spot Market Earnings (Source: Howe Robinson Partners)

VLCC

Buoyed by

VLCC

Starting from a spur storage play excitement,low level in January, VLCC earnings (TD3 Middle East/Japan) rose slightly from December 2014 to average just over $73,000/stood well below $10,000/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 periodfirst half of the year forand at times below OPEX levels. The uptick in Q4 pushed the VLCC market.average at ~$19,000/day (basis TD3C MEG/China round voyage). The strength continued into Q3-2015 whereOPEC+ group’s commitments to extend their production cuts toQ1-18 along with involuntary losses from elsewhere (i.e. Venezuela, Angola) and stock-drawing in OECD nations were enough to pushQ1-18 andQ2-18 earnings averaged above $57,115/to their lowest quarterly levels on record since 2000 withQ1-18 averaging at ~$8,750/day as refineriesandQ2-18 at $9,500/day.

On the back of OPEC’s decision to increase production in most parts of the world, particularly in the US and Europe, ran at as high utilization rates as possibleorder to capture high refining margins.achieve 100% compliance on its original 1.2 million bpd, VLCC earnings however, dropped quite sharplyrose to $14,500/day in August as Chinese buying droppedQ3-18, while there-imposition of US sanctions on Iran and OPEC’s decision to further cut production by about 11.2 million bpd inQ1-19 generated an influx of barrels inQ4-18, pushing the market to a Q4 average last seen in 2016 at around $46,000/day.

VLCCs started 2019 quite positive; however, the market came off as quickly as expected and it would appear that this year’s demand for crude tankers could look strikingly similar to 2018 if it wasn’t for US crude exports. These are expected to be the main factor helping to absorb any tonnage growth—given OPEC+ production cuts combined 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 bywhat is setting up to be 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 Januaryseason ahead 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.IMO2020 implementation.

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Suezmax Time Charter Equivalent Spot Market Earnings

Suezmax Spot Market Earnings (Source: Howe Robinson Partners)

Suezmax

SimilarSuezmax

Suezmax earnings followed the same trajectory as VLCCs; however, the winter impact was much stronger withQ4-18 averaging at ~$34,000/day, $23,000/day higher compared toQ3-18. TD6 (Black Sea/Med) earnings averaged 42% higher YoY at ~$19,000/day, whereas TD20 (WAF/UKC) closed the year 6% lower YoY at ~$12,000/day. Despite a much more manageable fleet growth, Suezmaxes in West Africa didn’t manage to surprise on the upside with TD20 earnings setting record low levels for the most of the first half of the year.

Despite Nigeria’s production rebound to an average of 1.6 million bpd in 2018 compared to 1.53 million bpd in 2017, a 150,000 bpd YoY fall in Angolan output led to a decline in the area’s total production resulting in West African exports dropping by 1.4% YoY to 4.32m bpd. Suezmaxesex-WAF were traded below $9,000/day in the first three quarters of 2018, while a $20,000/day increasequarter-on-quarter to $28,000/day inQ4-18 brought the year’s average above that threshold. Following the VLCC market, the Suezmax composite (basis 70% ex-WAF and 30% Black Sea/Med) experienced an uncharacteristically strong Q2-2015, enveloped by high earnings on either side at the start and end 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 supplySuezmaxes in West Africa encouraged a rally athave already lost 50% of their earlyJan-19 earnings. Suezmaxes in the Black Sea started showing signs of recovery inMay-18 when earnings rose to $14,000/day from theJan-Apr average of $5,500/day.

Suezmax liftingsex-Black Sea rose by 9.3% YoY to 1.13 million bpd in 2018 and combined with weather related delays pushed the end of November, and the very strong VLCC market during December helpedyear earnings to keep supply somewhat tight ex-West Africa as supply moved to capture the spike ex-Mideast Gulf, keeping earnings high at $67,000/day. Overall, the Suezmax composite averaged $43,089/daylevels last seen in 2015, basis our standard assumptions. With the removalwithNov-Dec averaging at $60,000/day. Since then however, TD6 has dipped to an average of the US crude export ban and fall$22,000/day in US production towards the end of the year, there has been renewed crude purchasing from West Africa by the US, bringing the phased out TD5 West Africa/US Atlantic Coast trade somewhat back into play. US refineries will look 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 far 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.

Aframax Time Charter Equivalent Spot Market Earnings

Aframax Spot Market Earnings (Source: Howe Robinson Partners)

Aframax

Aframax

The Aframax composite (a straightComposite earnings (basis an average of six worldwide voyages) rose more than 20% fromTD7, TD8, TD9, TD19, TD14 and TD17) were no different to their VLCC and Suezmax counterparts and with the final quartersecond half of 20142018 support they posted their first yearly gains since 2015. The Aframax Composite averaged 16% higher YoY to average above $39,000/~$13,000/day in Q1-2015, propelled by very strong earnings in northern Europe which can be quite weather-sensitive during the winter months. TD17 Baltic/UK Continent averaged almost $75,000/2018, ranging from $5,000/day in January, while TD7 North Sea/UK Continent rose above $50,000/April to $41,000/day duringin December. With the same month amid a particularly cold winter in northern Europe. Similaruncoated Aframax fleet falling by-2% YoY, the upside might have been stronger if it wasn’t for the 20 LR2dirty-ups as soon as Aframaxes started trading at an $8,000/day premium to the other crude benchmarks,LR2s inQ4-18. Apart from TD17 (Baltic/UKC), the rest of the Aframax composite remained unusually high in Q2-2015 – almost three times the level it was during Q2-2014 – to average over $40,000/routes were trading below $10,000/day with marked strength in all six routes comprising the benchmark particularly in June, as exhibited with the Suezmaxes. Earnings fell in the third quarter to under $30,000/day due to notable weakness in TD11 Cross-Med which fell to under $18,000/day as the tonnage list outweighed cargo activity during the period.

Earnings recovered in the fourth quarter to average almost $39,000/day, near where they started the year as the Mediterranean market recovered but also as the weather-sensitive routes picked up despite a mild start to the winter. Overall, the Aframax composite averaged $37,262/day in 2015 as quarterly earnings established 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 the year bringing the combined average to ~$8,000/day. TD7 (North Sea/UKC) earnings doubled inQ3-18 to over $14,000/day compared to $7,000/day inQ2-18 amid a 10% increase in Aframax liftings from the North Sea, while seasonal factors and an 11.3%quarter-on-quarter increase in Aframax liftingsex-Baltic pushed TD17 earnings $19,000/day higher at ~$31,000/day inQ4-18.

Libya’s return supported the Med market with TD19 earnings increasing by 22% YoY to ~$14,000/day; however, Aframaxes haven’t managed to pocket the whole benefit of the additional Libyan barrels as increased flows to the east have favoured Suezmaxes taking away market share from Aframaxes (58.3% in 2018 vs 72.6% in 2017). The Caribbean market (TD9) was quite resilient during 2018, averaging 26% higher YoY at $15,000/day; however, it remains to be seen how US sanctions on Venezuela will affect this year.

Similar to VLCCs and Suezmaxes, the Aframax market started this year quite strongly; however, earnings have more than halved compared to early January currently trading at $16,000/day. Nevertheless, the LR2 market looks more balanced with TC1 earnings (MEG/Japan) currently trading at a $6,000/day premium to the Aframax Composite and relatively rangebound at the$22,000/day-$26,000/day level.

MR Time Charter Equivalent Spot Market Earnings

MR Spot Market Earnings (Source: Howe Robinson Partners)

MR

TheMR

Historically speaking, according to our records (since 2000) the MR Composite (a straight(basis an average of six worldwide voyages) retained its strength going into 2016, marking up averageTC6, TC7, TC10 and TC2/14) has almost never averaged below $10,000/day annually—apart from 2002—and even though last year it was looking like they would have broken that floor, it turned out that theQ4-18 uptick brought 2018 MR earnings at around $11,000/day. 2018 set the historical minimum levels betweenMay-June and end July-September, with the first week of closeSeptember as the lowest week reported in terms of earnings since 2000 at below $6,000/day.

Even though it is difficult to $24,000/daypinpoint specific factors for the products market weakness in Q1-2016, pulling on strength particularlysuch a fragmented environment, we would highlight a massive 204 million bbls stockdrawing in OECD countries/Singapore betweenAug-16 andMay-18 as a major culprit, as well as a lack of new mega/export refinerystart-ups since 2015, and of course stubbornly high fleet growth.

Fluctuations in MR earnings were driven by the west as the east markets were largely rangebound on a quarterly basis with TC7 (Singapore/EC Australia) averaging between $10,000/day inQ3-18 to $12,000/day inQ2-18 and TC10 (South Korea/WCC) between $10,000/day inQ3-18 to $13,000/day inQ4-18. In the cross-Mediterranean and Atlantic triangulation routes. As with the crude benchmarks, MRwest, TC6

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(cross-Med) posted its historical low quarterly earnings during Q2-2015 also rose, despite it usually being a market lull during refinery maintenance, with jumps in both April and June – particularly on the western routes mentioned already. The MR Composite reached a yearly high in July,Q3-18 at the height of summer gasoline demand, pushing Q3-2015$3,000/day to also be the highest quarter for MR earnings duringaverage the year at around $27,500/day.$10,000/day, $2,000/day lower YoY. Atlantic basin activity saw a huge jump due to record high US gasoline exports withQ4-18 earnings 81% higher compared toQ3-18 at $14,000/day (basis TC2/14 triangulation).

Earnings in Q4-2015 averaged under $20,000/day asMRs started 2019 above their historical levels; however, following the Mediterranean market toppled from its highs earlierrest of the market’s downward trajectory they have already come off quite significantly albeit according to historical seasonality trends. With stock levels below their five-year average in the season, leading MRs frommajor consuming regions, 1.2 million bpd YoY growth in refinery runs, 2.2 million bpd of additional refinery capacity, of which around 45% will be export-oriented, and an increase in gasoil trade ahead of the region looking to ballast north to whereIMO2020 implementation, the ex-UKCproducts market looks underway in its long-awaited recovery as ofmid-2019.

General LNG Market Overview

2018 was certainly one of the better years in recent memory for LNG shipping because of the significant increase in short term rates and the large number of new buildings placed on order.

Although there was some consensus in early 2018 that the market was still performing relatively well. Overall, the MR Composite averaged $23,697/day in 2015 compareddue to an annual average in 2014 of $13,954/day. Fleet supply growth is finally tapering offimprove on the MRs. Arguably,back of fundamentals, industry participants certainly hadn’t anticipated such a rapid increase in rates. This rise can – to ansome extent in 2015 any jumps in freight were still limited by the heavy fleet supply growth during the year, particularly towards the end– be attributed to floating storage, a new feature of the year. Another summer of high gasoline demandLNG market that is expected, which should lift the west MR trades despite refineries being much more prepared this yearpartially driven by China and its hunger for evermore LNG. Indeed, up to 30 vessels were kept as floating storage worldwide with high stock levels, while robust oil demand growth of over 5% remains supportive for MR earnings.

The LNG Market

Asian 2015 LNG imports totaled 170.9 million tons, a 6.5% fall from last year’s record 180.9 million tons. The region accounted for 71% of total LNG flows, down from 75% in 2014, as consumption in Japan and South Korea slid following the restart of a number of nuclear facilities in Japan,cargoes on board waiting to discharge, and the opening of new facilitiesdemand for these vessels coupled with the increase in

South Korea. European LNG imports grew 4% to reach 39.6 million tons, while the world’s third largest import demand center in Latin America fell to 18.2 million tons while North American imports almost doubled to reach 3.9 million tons for the year. While the Middle East retained its spot as the world’s largest LNG exporter by a closely trailing Australia, imports more than doubled to the region to total 8.8 million tons in 2015. Despite a fall in prices tonne miles due to the natureopen arbitrage, pushed up rates to a peak which had not been seen before.

Storage for LNG over a period of manytime—rather than straight discharge—is an unusual feature for the LNG contracts (linkedmarket, and can now be considered due to the pricepartial or fullre-liquefaction (PRS or FRS) units on board the vessels, which allows the boil off to bere-liquefied and placed back into the cargo tanks. LNG carriers can therefore store LNG on board without losing much of Brent), this failed to stifle import demand growth in the trade’s most important demand center, Asia, while a mild winter for the second year in a row limited import growth towards the end of the year. Overall, import demand growth in Europe, North America and the Mideast Gulf marginally outweighed declines in Asia and Latin America to register a year-on-year growth of 0.06% or 1.4 million tons to reach a total of 239.7 million tons in 2015.their cargo.