TNP Tsakos Energy Navigation Ltd

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. 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”).

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Our audited consolidated statements of comprehensive income/(loss), other comprehensive income/(loss), stockholders’ equity and cash flows for the years ended December 31, 2015, 2014, and 2013, and the consolidated balance sheets at December 31, 2015 and 2014, together with the notes thereto, are included in “Item 18. Financial Statements” and should be read in their entirety.

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

Capitalization

The following table sets forth our (i) cash and cash equivalents, (ii) restricted cash and (iii) consolidated capitalization as of December 31, 2015 on:

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Other than these adjustments, there has been no material change in our capitalization from debt or equity issuances, re-capitalization or special dividends between December 31, 2015 and April 5, 2016.

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

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

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World Oil Demand/Supply and the Tanker Market

The tanker market enjoyed its highest earnings in over seven years in 2015, benefitting directly from lower oil prices. The sharp decline in the price of oil since the second half of 2014 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 crisis of 2008-2009. The crude surplus and low oil prices of 2015 triggered a multitude of beneficial demand factors for the tanker market which included record consumption growth in some parts of the world, strategic and commercial crude and oil product stockbuilding demand, floating storage plays, exceptionally high refining runs, infrastructure bottlenecks leading to vessel delivery delays and many more. The added demand for tanker tonnage also allowed tanker owners to hold on to the benefit of the lower cost of bunker fuels (which are highly correlated with crude oil). Furthermore, this strong upward shift in tanker demand occurred during a year of low fleet growth in most sectors, which allowed for freight rates to rise sharply.

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

Global Oil Prices and WTI-Brent Differential

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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 2 million bpd in Q1-2016, fall to 1.5 million bpd in Q2-2016 and then sharply narrow in the second half of the year to average 0.3 million bpd – leaving the year with an average surplus of approximately 1 million bpd.

Total OECD crude stocks reached 1,119.3 million barrels at the end of 2015, nearly a 15% year-on-year increase from 2014. The largest build was 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 1.5 million bpd less at 6.26 million bpd in October, highlighting the powerful effect that stockbuilding has on Chinese crude import levels and, by extension, crude tanker demand.

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

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

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

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

Non-OPEC production demonstrated its resilience in the face of tumbling oil prices as output only began to show steady declines after peaking in October 2015 at 57.89 million bpd. Output in major non-OPEC producing nations is now expected to fall by approximately 600,000 bpd in 2016 after rising by 1.4 million bpd in 2015. However, the forecasted decline in non-OPEC production will be more than offset by an expected rise in OPEC production – driven by Iran. OPEC 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 of 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

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

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

Global Oil Supply and Demand YoY Growth

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

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

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

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

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

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

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Chinese Crude Imports and Stock Building

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

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GDP and Oil Demand Growth vs. Tanker Earnings

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

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Crude Tanker Tonne-Miles and Select Crude Imports

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

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

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

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

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

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US Oil Product Imports and Exports

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

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

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

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

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

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

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

World Tanker Fleet

VLCC fleet growth remained low in 2015, growing at a year-on-year rate of 2.8% after rising by 2.4% in 2014 and 2.1% in 2013. Years of consecutive low fleet growth have enabled a more pronounced freight response to the recent changes in demand. Lower fleet growth in 2015 was attributable to a low level of additions at only 18 vessels while 3 VLCCs were removed from the trading fleet which were all converted to floating storage units – this is less than the 9 and 17 vessels that were removed in 2013 and 2014, respectively, as the tight market found employment for several older vessels while the buoyant market and dropping scrap steel prices dissuaded scrapping. Slippage in 2015 was 25%, slightly less than the 2009-2014 average of 27.6%, as the well performing markets encouraged ships to be taken on time. The removal of the three floating storage units (“FSUs”) from the fleet were under 20 years old – with one under 10 years of age – doing little to change the average age of the fleet, which currently stands at 19 years of age. As of the 1 ^st of January 2016 there were 70 VLCCs scheduled for delivery for the year – applying the average slippage of the past six years of 27.3% this would imply expected additions of 51 VLCCs into the fleet this year and expected removals of 7, pushing fleet growth up to 6.7% - the highest since 2011. The current orderbook translates into heavy fleet growth over the next couple of years as well, with a reasonable expectation for heavy 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 consecutive year of low fleet growth of 1.4% after contracting in 2014 at a rate of -0.2%. The low fleet growth this past year was due to a very low delivery figure of only 9 Suezmaxes against 3 removals, however for the second year in a row more than 10 orders were cancelled during the 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, Suezmax fleet growth in 2016 is poised to jump markedly with 48 scheduled deliveries for 2016 as at the 1 ^st of January 2016, using the slippage average since 2009 approximately 31 of the scheduled deliveries are actually expected to deliver against 5 removals leaving fleet growth somewhere in the range of 6%. Suezmax fleet growth is expected to experience peak fleet growth come 2017 according to the orderbook, fleet growth will then ease from there but likely not back to the lows seen in 2014 and 2015.

Aframax fleet growth in 2015 rose to 2.9% from -1.2% in 2014 on the back of relatively high deliveries of 31 and very low removals compared to earlier years as the fleet had already cleared itself of older tonnage, although the average age of the fleet remains at 20 years as it was for end-2014. At the start of 2015 there were 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 estimate fleet growth 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 year saw a marked movement of coated vessels switching to trading Dirty Petroleum Product (“DPP”) from trading Clean Petroleum Product (“CPP”), due to the attractive Aframax earnings. The percentage of the fleet trading DPP increased from ~32.5% at the

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start of 2015 to over 35% at the end of the year. Approximately 21 vessels switched to dirty while 5 vessels cleaned up in 2015, equating to a net dirty up 16. So far in 2016 there have been a net dirty up of 4 vessels as benchmark Aframax earnings have retained a slim lead over benchmark LR earnings.

Panamax fleet growth contracted by 2% in 2015, following a contraction of 1% in 2014, as only 3 vessels delivered during the year against removals of 11 vessels. All but one of the Panamaxes that were removed were scrapped, the remainder was converted to FSUs. two of the Panamaxes removed were older than 30 years old, the average age of the total 11 Panamaxes removed from the fleet in 2015 was 24 years old – the average age for the fleet is now just under 10 years. At the start of 2015 there were 11 Panamaxes on order, the majority of which were fully coated, while only 2 fully coated and 1 uncoated Panamax delivered during the year which brings slippage to 66.7% compared to a 2009-2014 average of 42%. As at the 1 ^st of January 2016, the orderbook for 2016 stood at 30 Panamaxes, 5 of which are uncoated, of this total it is estimated that 16 will deliver using average slippage since 2009 of 45.5% and as removals are easing off we expect positive fleet growth of just under 3% - the highest fleet growth since 2011. As with Aframaxes, fleet growth on the Panamaxes is poised to peak in 2017 at an estimated 7%. Switching of fully coated trading capacity between CPP and DPP was not as pronounced on the LR1s, in 2015 approximately 10 LR1s switched to dirty while 8 switched to clean trading, however as with the LR2s there was a much more marked switch to DPP in the first half of the year.

In 2015, MR (45,000 dwt – 55,000 dwt) fleet growth reached a six-year high of 9.1% as 108 vessels were added to the fleet and only 1 vessel was removed – which was converted to long-term storage. 2015 slippage for MR deliveries was much lower than the 2009-2014 average of 32.2% at 19.4% as, like other vessel classes, higher earnings encouraged deliveries to occur on time. This past year was expected to be the large delivery year for the eco-MR ordering spree of 2013, expected additions to the fleet is now anticipated to fall by more than 30% this coming year and stay at a lower level going forward into the next few years. MR fleet growth is expected to ease off in 2016 to just above 5% with 106 scheduled deliveries as at the 1 ^st of January 2016, applying the average slippage rate since 2009 of 30.4% this equates to expected fleet additions of 74 against expected removals of 5, fleet growth for later years is expected at a slightly lower pace given higher removals due to ageing.

Handy product tanker fleet growth (27,000 dwt – 45,000 dwt) broke its five-year contraction streak in 2015, growing at a rate of 2.3%. In 2015 there was both a rise in additions and a fall in removals compared to 2014; 39 ships were added to the fleet with 20 removed which equates to a net fleet growth of 19 vessels. Slippage in 2015 was a very low 2.5%, only 1 vessel slipped into 2016, this compares to an average slippage between 2009-2014 of 33.3%. As at the 1 ^st of January 2016, the orderbook for the current year stood at 54 vessels, applying average slippage since 2009 of 28.9% this translates into an expected 2016 delivery schedule of 38 which, against expected removals of 20 driven mainly by age, leads to a similar net fleet growth in 2016 of 2.2%. As additions to the fleet fall slightly going forward and as removals accelerate due to the aging fleet (about 14% of the fleet is over 20 years old, although Handy trading is flexible in terms of age), fleet growth is, unlike the crude and LR sectors, expected to continue to fall but remain positive over the next few years.

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

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In 2015, a total of 73 VLCCs were ordered – the most in at least the past four years. Over half of the orders were made in the 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 purchases in 2015 that may have otherwise been made later. 3 VLCCs were ordered in the first month of 2016, bringing the total orderbook to 138 against a fleet of 656 at the time of writing.

Similarly, strong crude earnings encouraged heavy Suezmax ordering in 2015 with a total of 79 orders as at the end of 2015 that will deliver on the back of the smaller Suezmax fleet, which at the time of writing totals 435 vessels. Over a third of the orders were made in the fourth quarter of the year with mainly South Korean shipbuilders throughout 2015, although almost a third were made with Chinese shipbuilders during the year. Despite the marked fall in VLCC (South Korean) newbuilding prices, Suezmax newbuilding prices stayed relatively stable throughout the year – dipping to $64m for two months in September and ending the year back at $65m. So far in 2016, Suezmax ordering continues to outpace VLCC ordering with a total of 4 Suezmaxes ordered in the first month of the year, bringing the total orderbook up to 129 vessels at the time of writing.

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

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

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

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

Secondhand vessels, unlike newbuildings, could be used immediately for trading – which is partly the reason behind their price appreciation this past year, and importantly since 2014, amid the resurgent market since late-2014. VLCC 5-year old prices rose $1 million throughout the year, but this marks a 30% rise in price since January 2014 which was first brought on by the contango storage play possibility towards the end of 2014. Suezmax prices similarly rose only minimally year-on-year but represent a $22 million increase in price since January 2014. Aframax secondhand prices rose by $1.5 million, and 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 meeting at the end of November 2014 kept crude tanker earnings on their upward march that had started in Q4-2014. Q2-2015 was the strongest quarter-on-quarter earnings period - usually the spring months are a seasonal lull for crude tankers while refinery maintenance is in full swing in Europe and Asia, however, this time all three crude tanker benchmarks were more than double from Q2-2014 earnings as refineries worked to run near full capacity and capture booming gasoline demand growth during the peak demand season. This also led to surpluses of fuel oil among other products to be carried on tankers. Earnings again trended higher during the third quarter, but largely due to a very strong July as earnings then seasonally fell with refinery maintenance limiting demand later that quarter. Exceptional earnings in October and December on the VLCCs, and consistently strong earnings on the Suezmaxes and Aframaxes ensured 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 fell below $30/bbl. The reduction in bunkers from their highs of over $600/ton in the first half of 2014 to well under $200/ton at the end of 2015 reduced the percentage of bunkers over gross freight (basis TD3 Middle East/Japan) from over 80% to under 20%, which means that after paying for bunker costs, shipowners had 80% or more leftover to cover other costs and hold as profit as opposed to under 20% which was the case when bunker prices were above $600/ton in 2013-14. The importance of the fall in bunker price in relation to earnings cannot be highlighted enough. The low

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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, are expected to steadily pick up eventually eating into tanker earnings. In addition, the boon in oil prices that was propagated from the plunge in oil prices has now been factored into demand growth, oil prices cannot fall by another $50/bbl when they are already at ~$30/bbl. This, among other factors such as lower demand in oil producing nations, lower industrial demand, removal of subsidies in some countries, etc. has lowered the oil demand growth outlook for 2016 and onwards. Floating storage remains a possibility pending a widening of both the crude and now products contango, in Northwest Europe the gasoil contango has strengthened markedly since the build-up of supply due to a mild winter, low Rhine water levels keeping the product trapped along the coast and an influx of cargoes from the Mideast Gulf, Russia, the US and Asia. If floating storage once again becomes viable, it will act as a floor to the market. Finally, the possibility of slowing down tanker speed to stem fleet supply growth is for the most part out of the question as low bunker prices do not justify slowing down until the market reaches very low levels.

The products sector likewise started out on a strong note in 2015 as earnings for the year were approximately $10,000/day higher on the HRP MR Selected Composite and similar annual gains were made in the LR market. The two new Middle Eastern refineries that came online provided significant cargo volume for LRs, while a cold start to 2015 and strong gasoline demand globally kept the fleet busy from the start of the year 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.

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VLCC Time Charter Equivalent Spot Market Earnings

VLCC

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

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

Overall, 2015 VLCC (TD3 Middle East/Japan) earnings averaged $65,923/day – more than twice the average of 2014. So far this year, VLCC earnings have averaged only slightly down after December’s high as refinery maintenance in North America and a pullback in buying in January 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.

Suezmax Time Charter Equivalent Spot Market Earnings

Suezmax

Similar to 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

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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 supply in West Africa encouraged a rally at the end of November, and the very strong VLCC market during December helped 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/day in 2015 basis our standard assumptions. With the removal of the US crude export ban and fall in US production towards the end of the year, there has been renewed crude purchasing from West 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.

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Aframax Time Charter Equivalent Spot Market Earnings

Aframax

The Aframax composite (a straight average of six worldwide voyages) rose more than 20% from the final quarter of 2014 to average above $39,000/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/day in January, while TD7 North Sea/UK Continent rose above $50,000/day during the same month amid a particularly cold winter in northern Europe. Similar to the other crude benchmarks, the Aframax composite remained unusually high in Q2-2015 – almost three times the level it was during Q2-2014 – to average over $40,000/day with marked strength in all six routes comprising the benchmark particularly in June, as 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 this year.

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MR Time Charter Equivalent Spot Market Earnings

MR

The MR Composite (a straight average of six worldwide voyages) retained its strength going into 2016, marking up average earnings of close to $24,000/day in Q1-2016, pulling on strength particularly in the west with the cross-Mediterranean and Atlantic triangulation routes. As with the crude benchmarks, MR 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, at the height of summer gasoline demand, pushing Q3-2015 to also be the highest quarter for MR earnings during the year at around $27,500/day.

Earnings in Q4-2015 averaged under $20,000/day as the Mediterranean market toppled from its highs earlier in the season, leading MRs from the region looking to ballast north to where the ex-UKC market was still performing relatively well. Overall, the MR Composite averaged $23,697/day in 2015 compared to an annual average in 2014 of $13,954/day. Fleet supply growth is finally tapering off on the MRs. Arguably, to an extent in 2015 any jumps in freight were still limited by the heavy fleet supply growth during the year, particularly towards the end of the year. Another summer of high gasoline demand is expected, which should lift the west MR trades despite refineries being much more prepared this year 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, and the opening of new facilities in

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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 due to the nature of many LNG contracts (linked to the price 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.

Global LNG Imports by Region

Global LNG exports rose by over 10% in Australasia to approximately 80 million tons with the start-up of BG Group’s QCLNG Train 2 in mid-2015 on Australia’s eastern Curtis Island, with the first shipment at the start of July, and a continued growth in exports from ExxonMobil’s LNG project in Papau New Guinea. Middle Eastern LNG exports fell year-on-year as the region marked an increase in imports. Yemen’s 6.7 million tonne Balhaf plant was shut down early in the year and remains closed due to conflict in the region. Exports from Africa, Europe and the Americas were also down slightly year-on-year as project start-ups were delayed.

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Global LNG Exports by Region

Since the start of 2014, LNG prices in the east have more than halved due to their predominant nature of being linked to the price of Brent. Whereas LNG prices in the UK and the US, linked instead usually to natural gas hubs, have only fallen marginally in the past two years. In Asia, the lack of demand response from the fall in LNG prices can be linked to the re-emergence of nuclear power in the region, a direct competitor to LNG. Japanese prices have fallen to well under $10/mmbtu from just over $20/mmbtu during the start of 2014. The country restarted two Sendai Nuclear units in 2015 and will restart another two Takahama nuclear plants in Q1-2016, while a mild start to the winter saw a further fall in price. South Korea started two nuclear units last June and July, the next unit is not expected until April 2016 but an expected build in LNG storage by the South Korean electricity provider Kepco will keep LNG demand growing in 2016 despite the nuclear threat.

LNG supply in 2016 is expected to rise by an estimated 10% year-on-year, or 24.5 million metric tons, with more than three quarters of the rise coming from the Australasia region as the Yemeni plant is expected to remain offline due to a struggling UN peace process in the country. The second 4.5 million tons per annum (“mtpa”) train at Conoco Phillip’s Australia Pacific’s LNG facility loaded its first cargoes in January and is expected to start commercial operations by the end of Q1-2016, while Chevron’s 15.6 mtpa Gorgon project on Australia’s Barrow Island has started the commissioning process with the first cargo set to be loaded in February or March. In West Africa, the Angola LNG export project was reported to have started recommissioning at the end of January, meaning that commercial exports from the plant may start at the end of Q2-2015 while in Nigeria ENI has lifted a force majeure from mid-December on loadings form the 22 mtpa Bonny LNG terminal. Other major supply developments are longer term, however there are expectations that investment will now switch to the demand side, meaning regasification facilities in import regions, particularly in South Asia, as opposed to liquefaction projects.

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LNG Tankers In Service and On Order

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

Risk Factors

Risks Related To Our Industry

Charter rates are cyclical and can be volatile. A return to the poor charter markets for crude oil carriers and product tankers which existed from 2008 to 2015 could affect our future revenues, earnings and profitability.

After reaching highs during the summer of 2008, charter rates for crude oil carriers and product tankers fell dramatically thereafter, with only occasional temporary seasonal or regional rate spikes until the end of 2014 when charter rates began to stabilize at higher levels in response to the steep decline in the price of oil. The year 2015 was the strongest year for tanker charter rates since 2008.

As of April 5, 2016, 22 of the vessels owned by our subsidiary companies were employed under spot charters, and 13 of the vessels were employed on time charters which, if not extended, are scheduled to expire on various dates between August 2016 and June 2028. In addition, 15 of our subsidiaries’ vessels have profit sharing provisions in their time charters that are based upon prevailing market rates. If low rates in the charter market return and continue for any significant period in 2016, it will affect the charter revenue we will receive from these vessels, which could have an adverse effect on our revenues, profitability and cash flows. Declines in prevailing charter rates also affect the value of our vessels, which follows the trends of charter rates and earnings on our charters, and could affect our ability to comply with our loan covenants.

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

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

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

Moreover, as a result of the ongoing economic crisis in Greece and the related austerity measures implemented by the Greek government, as well as the capital controls in effect in Greece since mid-2015, our operations may be subjected to new regulations that may require us to incur new or additional compliance or other administrative costs and may require that we pay to the Greek government new taxes or other fees or that dividends we pay be subject to withholding taxes. Furthermore, the commitments by the Greek government to the nations’ creditors and potential shift in its policies may potentially lead to Greece’s exit from the Eurozone, if not satisfied, which could affect our technical and commercial managers’ operations located in Greece.

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

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

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Despite turbulence in the world economy in recent years, there has been some rebound in worldwide demand for oil and oil products, which industry observers forecast will continue. In the event that this rebound falters, the production of and demand for crude oil and petroleum products will again encounter pressure which could lead to a decrease in shipments of these products and consequently this would have an adverse impact on the employment of our vessels and the charter rates that they command. However, if the recent reduction in oil prices continues in 2016, it may lead to declining output. In particular, the charter rates that we earn from our vessels employed on spot charters, under pool arrangements and contracts of affreightment, and on time-charters with profit-share may decline and remain at low levels for a prolonged period of time.

Our operating results are subject to seasonal fluctuations.

The tankers owned by our subsidiary companies operate in markets that have historically exhibited seasonal variations in tanker demand, which may result in variability in our results of operations on a quarter-by-quarter basis. Tanker markets are typically stronger in the winter months as a result of increased oil consumption in the northern hemisphere, but weaker in the summer months as a result of lower oil consumption in the northern hemisphere and refinery maintenance. As a result, revenues generated by the tankers in our fleet have historically been weaker during the fiscal quarters ended June 30 and September 30. However, there may be periods in the northern hemisphere, such as in the winter of 2011/2012, when the expected seasonal strength does not materialize to the extent required to support sustainable profitable rates due to tanker overcapacity.

An increase in the supply of vessels without an increase in demand for such vessels could cause charter rates to decline, which could have a material adverse effect on our revenues and profitability.

Historically, the marine transportation industry has been cyclical. The profitability and asset values of companies in the industry have fluctuated based on certain factors, including changes in the supply and demand of vessels. The supply of vessels generally increases with deliveries of new vessels and decreases with the scrapping of older vessels and/or the removal of vessels from the competitive fleet either for storage purposes or for utilization in offshore projects. The newbuilding order book equaled approximately 15% of the existing world tanker fleet at March 31, 2016, by number of vessels. No assurance can be given that the order book will not increase further in proportion to the existing fleet. If supply increases, and demand does not match that increase, the charter rates for our vessels could decline significantly. In addition, any decline of trade on specific long-haul trade routes will effectively increase available capacity with a detrimental impact on rates. A return to weak charter rates could have a material adverse effect on our revenues and profitability.

The global tanker industry is highly competitive.

We operate our fleet in a highly competitive market. Our competitors include owners of VLCC, suezmax, aframax, panamax, handymax and handysize tankers, as well as owners in the shuttle tanker and LNG markets, which are other independent tanker companies, as well as national and independent oil companies, some of which have greater financial strength and capital resources than we do. Competition in the tanker industry is intense and depends on price, location, size, age, condition, and the acceptability of the available tankers and their operators to potential charterers.

Acts of piracy on ocean-going vessels, although recently declining in frequency, could still adversely affect our business.

Despite a decline in the frequency of pirate attacks on seagoing vessels in the western part of the Indian Ocean, such attacks remain prevalent off the west coast of Africa and between Malaysia and Indonesia. If piracy

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attacks result in regions in which our vessels are deployed being characterized by insurers as “war risk” zones, as the Gulf of Aden has been, or Joint War Committee (JWC) “war and strikes” listed areas, premiums payable for such insurance coverage could increase significantly and such insurance coverage may be more difficult to obtain. Crew costs, including those due to employing onboard security guards, could increase in such circumstances. In addition, while we believe the charterer remains liable for charter payments when a vessel is seized by pirates, the charterer may dispute this and withhold charter hire until the vessel is released. A charterer may also claim that a vessel seized by pirates was not “on-hire” for a certain number of days and it is therefore entitled to cancel the charter party, a claim that we would dispute. We may not be adequately insured to cover losses from these incidents, which could have a material adverse effect on us. In addition, hijacking as a result of an act of piracy against our vessels, or an increase in cost, or unavailability of insurance for our vessels, could have a material adverse impact on our business, financial condition, results of operations and cash flows.

Terrorist attacks, international hostilities, economic and trade sanctions and the economic situation in the Eurozone can affect the tanker industry, which could adversely affect our business.

Major oil and gas producing countries in the Middle East have become involved militarily in the widening conflicts in Iraq, Syria and Yemen. Armed conflicts with insurgents and others continue, as well, in Libya, another major oil exporting country. Any of these hostilities could seriously disrupt the production of oil or LNG and endanger their export by vessel or pipeline, which could put our vessels at serious risk and impact our operations and our revenues, expenses, profitability and cash flows in varying ways that we cannot now project with any certainty.

The increasing number of terrorist attacks throughout the world, longer-lasting wars, international incidents such as that between Turkey and Russia or international hostilities, such as in the Ukraine, Afghanistan, Iraq, Syria, Libya and Yemen, could damage the world economy and adversely affect the availability of and demand for crude oil and petroleum products and negatively affect our investment and our customers’ investment decisions over an extended period of time. In addition, sanctions against oil exporting countries such as Iran, Sudan, Syria and Russia may also impact the availability of crude oil which would increase the availability of tankers, thereby negatively impacting charter rates. We conduct our vessel operations internationally and despite undertaking various security measures, our vessels may become subject to terrorist acts and other acts of hostility like piracy, either at port or at sea. Such actions could adversely impact our overall business, financial condition and results of operations. In addition, terrorist acts and regional hostilities around the world in recent years have led to increases in our insurance premium rates and the implementation of special “war risk” premiums for certain trading routes.

Our charterers may direct one of our vessels to call on ports located in countries that are subject to restrictions imposed by the U.S. government, which could negatively affect the trading price of our common shares.

On charterers’ instructions, our subsidiaries’ vessels may be requested to call on ports located in countries subject to sanctions and embargoes imposed by the U.S. government, the UN or the EU and countries identified by the U.S. government, the UN or the EU as state sponsors of terrorism. The U.S., UN- and EU- sanctions and embargo laws and regulations vary in their application, as they do not all apply to the same covered persons or proscribe the same activities, and such sanctions and embargo laws and regulations may be amended or strengthened over time.

On January 16, 2016, “Implementation Day” for the Iran Joint Comprehensive Plan of Action (JCPOA), the United States lifted its secondary sanctions against Iran which prohibited certain conduct by non-U.S. companies and individuals that occurred entirely outside of U.S. jurisdiction involving specified industry sectors in Iran, including the energy, petrochemical, automotive, financial, banking, mining, shipbuilding and shipping sectors. By lifting the secondary sanctions against Iran, the U.S. government effectively removed U.S. imposed restraints on dealings by non-U.S. companies, such as our Company, and individuals with these formerly targeted Iranian business sectors. Non-U.S. companies continue to be prohibited under U.S. sanctions from (i) knowingly engaging in conduct that seeks to evade U.S. restrictions on transactions or dealings with Iran or that causes the

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export of goods or services from the United States to Iran, (ii) exporting, reexporting or transferring to Iran any goods, technology, or services originally exported from the U.S. and / or subject to U.S. export jurisdiction and (iii) conducting transactions with the Iranian or Iran-related individuals and entities that remain or are placed in the future on OFAC’s list of Specially Designated Nationals and Blocked Persons (SDN List), notwithstanding the lifting of secondary sanctions. The U.S. has the ability to reimpose sanctions against Iran, including if, in the future, Iran does not comply with its obligations under the nuclear agreement.

The U.S. government’s primary Iran sanctions remain largely unchanged after Implementation Day and, as a consequence, U.S. persons continue to be broadly prohibited from engaging in transactions or dealings in or with Iran or its government. These sanctions broadly restrict U.S. persons from engaging in transactions or dealings with the Government of Iran and Iranian financial institutions, which effectively impacts the transfer of funds to, from, or through the U.S. financial system whether denominated in US dollars or any other currency.

As a result of the lifting of U.S. secondary sanctions (and relevant EU sanctions) relating to Iran, we can anticipate that some of our charterers may direct our vessels to carry cargoes to or from Iran. This could have various effects on us, such as affecting our reputation and our relationships with our investors and financing sources, affecting the cost of our insurance with respect to such voyages, and potentially increase our exposure to foreign currency fluctuations. Investor perception of the value of our shares may also be adversely affected by the consequences of war, the effects of terrorism, civil unrest and governmental actions in these and surrounding countries.

The U.S. also maintains embargoes on Cuba, North Korea, Sudan and Syria. We can anticipate that some of our charterers may request our vessels to call on ports located in these countries. Although we believe that we are in compliance with all applicable sanctions and embargo laws and regulations, and intend to maintain such compliance, there can be no assurance that we will be in compliance in the future, particularly as the scope of certain laws may be unclear and may be subject to changing interpretations. Any such violation could result in fines or other penalties and could result in some investors deciding, or being required, to divest their interest, or not to invest, in us. Additionally, some investors may decide to divest their interest, or not to invest, in us simply because we do business with companies that do lawful business in sanctioned countries. Moreover, our charterers may violate applicable sanctions and embargo laws and regulations as a result of actions that do not involve us or our vessels, and those violations could in turn negatively affect our reputation.

Failure to comply with the U.S. Foreign Corrupt Practices Act and other anti-bribery legislation in other jurisdictions could result in fines, criminal penalties, contract terminations and an adverse effect on our business.

We may operate in a number of countries throughout the world, including countries known to have a reputation for corruption. We are committed to doing business in accordance with applicable anti-corruption laws and have adopted a code of business conduct and ethics which is consistent and in full compliance with the U.S. Foreign Corrupt Practices Act of 1977, or the “FCPA”. We are subject, however, to the risk that persons and entities whom we engage or their agents may take actions that are determined to be in violation of such anti-corruption laws, including the FCPA. Any such violation could result in substantial fines, sanctions, civil and/or criminal penalties, or curtailment of operations in certain jurisdictions, and might adversely affect our business, results of operations or financial condition. In addition, actual or alleged violations could damage our reputation and ability to do business. Furthermore, detecting, investigating, and resolving actual or alleged violations is expensive and can consume significant time and attention of our senior management.

Efforts to take advantage of opportunities in pursuit of our growth strategy may result in financial or commercial difficulties.

A key strategy of management is to continue to renew and grow the fleet by pursuing the acquisition of additional vessels or fleets or companies that are complementary to our existing operations. If we seek to expand through acquisitions, we face numerous challenges, including:

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We cannot assure you that we will be able to integrate successfully the operations, personnel, services or vessels that we might acquire in the future, and our failure to do so could adversely affect our profitability.

We are subject to regulation and liability under environmental, health and safety laws that could require significant expenditures and affect our cash flows and net income.

Our business and the operation of our subsidiaries’ vessels are subject to extensive international, national and local environmental and health and safety laws and regulations in the jurisdictions in which our vessels operate, as well as in the country or countries of their registration. In addition, major oil companies chartering our vessels impose, from time to time, their own environmental and health and safety requirements. We have incurred significant expenses in order to comply with these regulations and requirements, including the costs of ship modifications and changes in operating procedures, additional maintenance and inspection requirements, contingency arrangements for potential spills, insurance coverage and full implementation of the new security-on-vessels requirements.

Because environmental regulations may become stricter, future regulations may limit our ability to do business, increase our operating costs and/or force the early retirement of our vessels, all of which could have a material adverse effect on our financial condition and results of operations.

International, national and local laws imposing liability for oil spills are also becoming increasingly stringent. Some impose joint, several, and in some cases, unlimited liability on owners, operators and charterers regardless of fault. We could be held liable as an owner, operator or charterer under these laws. In addition, under certain circumstances, we could also be held accountable under these laws for the acts or omissions of Tsakos Shipping & Trading S.A. (“Tsakos Shipping”), Tsakos Columbia Shipmanagement Ltd. (“TCM”) or Tsakos Energy Management Limited (“Tsakos Energy Management”), companies that provide technical and commercial management services for our subsidiaries’ vessels and us, or others in the management or operation of our subsidiaries’ vessels. Although we currently maintain, and plan to continue to maintain, for each of our subsidiaries’ vessels’ pollution liability coverage in the amount of $1 billion per incident (the maximum amount available), liability for a catastrophic spill could exceed the insurance coverage we have available, and result in our having to liquidate assets to pay claims. In addition, we may be required to contribute to funds established by regulatory authorities for the compensation of oil pollution damage or provide financial assurances for oil spill liability to regulatory authorities.

Maritime disasters and other operational risks may adversely impact our reputation, financial condition and results of operations.

The operation of ocean-going vessels has an inherent risk of maritime disaster and/or accident, environmental mishaps, cargo and property losses or damage and business interruptions caused by, among others:

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Any of these circumstances could adversely affect our operations, result in loss of revenues or increased costs and adversely affect our profitability and our ability to perform our charters.

Our subsidiaries’ vessels could be arrested at the request of third parties.

Under general maritime law in many jurisdictions, crew members, tort claimants, vessel mortgagees, suppliers of goods and services and other claimants may lien a vessel for unsatisfied debts, claims or damages. In many jurisdictions a maritime lien holder may enforce its lien by arresting a vessel through court process. In some jurisdictions, under the extended sister ship theory of liability, a claimant may arrest not only the vessel with respect to which the claimant’s maritime lien has arisen, but also any associated vessel under common ownership or control. While in some jurisdictions which have adopted this doctrine, liability for damages is limited in scope and would only extend to a company and its ship-owning subsidiaries, we cannot assure you that liability for damages caused by some other vessel determined to be under common ownership or control with our subsidiaries’ vessels would not be asserted against us.

Risks Related To Our Business

Any significant future declines in the values of our vessels could affect our ability to comply with various covenants in our credit facilities unless waived or modified by our lenders.

Our credit facilities, which are secured by mortgages on our subsidiaries’ vessels, require us to maintain specified collateral coverage ratios and satisfy financial covenants, including requirements based on the market value of our vessels, such as maximum corporate leverage levels. The appraised value of a ship fluctuates depending on a variety of factors including the age of the ship, its hull configuration, prevailing charter market conditions, supply and demand balance for ships and new and pending legislation. The oversupply of tankers and depressed tanker charter market adversely affected tanker values from the middle of 2008 to late 2013, and despite the young age of our subsidiaries’ fleet and extensive long-term charter employment on many of the vessels, resulted in a significant decline in the charter-free values of our vessels. Vessel values have recovered since the end of 2013 and may remain at current levels for a prolonged period, decline or rise. We were compliant with all of our loan covenants as at December 31, 2015. If we are unable to comply with the financial and other covenants under our credit facilities, including by repaying outstanding debt or posting additional collateral in the case of loan-to-asset value covenants, and are unable to obtain waivers, our lenders could accelerate our indebtedness. We have paid all of our scheduled loan installments and related loan interest consistently without delay or omission and none of our lenders under our credit facilities has requested such prepayment or additional cash collateral. Because of the cross-default provisions in our loan agreements, any such default could in turn lead to additional defaults under our other loan agreements and the consequent acceleration of the related indebtedness.

Charters at attractive rates may not be available when our current time charters expire.

During 2015, we derived approximately 41% of our revenues from time charters, as compared to 46% in 2014. As our current period charters on four of the vessels owned by our subsidiary companies expire in the remainder of 2016, it may not be possible to re-charter these vessels on a period basis at the attractive rates currently existing. If attractive period charter opportunities are not available, we would seek to charter the vessels owned by our subsidiary companies on the spot market, which is subject to significant fluctuations. In the event a vessel owned by one of our subsidiary companies may not find employment at economically viable rates, management may opt to lay up the vessel until such time that rates become attractive again (an action which our subsidiary companies have never undertaken). During the period of layup, the vessel will continue to incur expenditures such as insurance, reduced crew wages and maintenance costs.

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We are dependent on the ability and willingness of our charterers to honor their commitments to us for all of our revenues and the failure of our counterparties to meet their obligations under our charter agreements could cause us to suffer losses or otherwise adversely affect our business.

We derive a substantial portion of our revenues from the payment of charter hire by our charterers. 28 of our 50 vessels are currently employed under time charters including time charters with profit share. We could lose a charterer or the benefits of a time charter if:

If we lose a time charter, we may be unable to re-deploy the related vessel on terms as favorable to us or at all. We would not receive any revenues from such a vessel while it remained unchartered, but we may be required to pay expenses necessary to maintain the vessel in proper operating condition, insure it and service any indebtedness secured by such vessel.

If our charterers fail to meet their obligations to us or attempt to renegotiate our charter agreements, as part of a court-led restructuring or otherwise, we could sustain significant reductions in revenue and earnings which could have a material adverse effect on our business, financial condition, results of operations and cash flows, as well as our ability to pay dividends, if any, in the future, and comply with the covenants in our credit facilities.

If our exposure to the spot market increases, our revenues could suffer and our expenses could increase.

The spot market for crude oil and petroleum product tankers is highly competitive. As of April 5, 2016, 22 of the vessels owned by our subsidiary companies were employed under spot charters. As a result of our increased participation in the spot market, we may experience a lower overall utilization of our fleet through waiting time or ballast voyages, leading to a decline in operating revenue. Moreover, to the extent our vessels are employed in the spot market, both our revenue from vessels and our operating costs, specifically our voyage expenses, will be significantly impacted by adverse movements in the cost of bunkers (fuel). See “—Fuel prices may adversely affect our profits.” Unlike time charters in which the charterer bears all of the bunker costs, in spot market voyages we bear the bunker charges as part of our voyage costs. As a result, while historical movements in bunker charges are factored into the prospective freight rates for spot market voyages periodically announced by World Scale Association (London) Limited and similar organizations, increases in bunker charges in any given period could have a material adverse effect on our cash flow and results of operations for the period in which the increase occurs. In addition, to the extent we employ our vessels pursuant to contracts of affreightment or under pooling arrangements, the rates that we earn from the charterers under those contracts may be subject to reduction based on market conditions, which could lead to a decline in our operating revenue.

We depend on Tsakos Energy Management, Tsakos Shipping and TCM to manage our business.

We do not have the employee infrastructure to manage our operations and have no physical assets. In common with industry practice, our subsidiaries own the vessels in the fleet and the contracts to construct our newbuildings. We have engaged Tsakos Energy Management to perform all of our executive and management functions. Tsakos Energy Management employees directly provide us with financial, accounting and other back-office services, including acting as our liaison with the New York Stock Exchange and the Bermuda Stock Exchange. Tsakos Energy Management, in turn, oversees and subcontracts part of commercial management

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(including treasury, chartering and vessel purchase and sale functions) to Tsakos Shipping, and day-to-day fleet technical management, such as vessel operations, repairs, supplies and crewing, to TCM. As a result, we depend upon the continued services provided by Tsakos Energy Management and Tsakos Energy Management depends on the continued services provided by Tsakos Shipping and TCM.

We derive significant benefits from our relationship with Tsakos Energy Management and its affiliated companies, including purchasing discounts to which we otherwise would not have access. We would be materially adversely affected if any of Tsakos Energy Management, Tsakos Shipping or TCM becomes unable or unwilling to continue providing services for our benefit at the level of quality they have provided such services in the past and at comparable costs as they have charged in the past. If we were required to employ a ship management company other than Tsakos Energy Management, we cannot offer any assurances that the terms of such management agreements would be on terms as favorable to the Company in the long term.

Tsakos Energy Management, Tsakos Shipping and TCM are privately held companies and there is little or no publicly available information about them.

The ability of Tsakos Energy Management, Tsakos Shipping and TCM to continue providing services for our and our subsidiaries’ benefit will depend in part on their own financial strength. Circumstances beyond our control could impair their financial strength and, because each of these companies is privately held, it is unlikely that information about their financial strength would become public. Any such problems affecting these organizations could have a material adverse effect on us.

Tsakos Energy Management has the right to terminate its management agreement with us and Tsakos Shipping and TCM have the right to terminate their respective contracts with Tsakos Energy Management.

Tsakos Energy Management may terminate its management agreement with us at any time upon one year’s notice. In addition, if even one director were to be elected to our board without having been recommended by our existing board, Tsakos Energy Management would have the right to terminate the management agreement on 10 days’ notice. If Tsakos Energy Management terminates the agreement for this reason, we would be obligated to pay Tsakos Energy Management the present discounted value of all payments that would have otherwise become due under the management agreement until June 30 in the tenth year following the date of the termination plus the average of the incentive awards previously paid to Tsakos Energy Management multiplied by 10. A termination as of December 31, 2015 would have resulted in a payment of approximately $170.2 million. Tsakos Energy Management’s contracts with Tsakos Shipping and with TCM may be terminated by either party upon six months’ notice and would terminate automatically upon termination of our management agreement with Tsakos Energy Management.

Our ability to pursue legal remedies against Tsakos Energy Management, Tsakos Shipping and TCM is very limited.

In the event Tsakos Energy Management breaches its management agreement with us, we or our subsidiaries could bring a lawsuit against it. However, because neither we nor they are ourselves party to a contract with Tsakos Shipping or TCM, it may be difficult to sue Tsakos Shipping and TCM for breach of their obligations under their contracts with Tsakos Energy Management, and Tsakos Energy Management may have no incentive to sue Tsakos Shipping and TCM. Tsakos Energy Management is a company with no substantial assets and no income other than the income it derives under the management agreement with us. Therefore, it is unlikely that we or our subsidiaries would be able to obtain any meaningful recovery if we or they were to sue Tsakos Energy Management, Tsakos Shipping or TCM on contractual grounds.

Tsakos Shipping provides chartering services to other tankers and TCM manages other tankers and could experience conflicts of interests in performing obligations owed to us and the operators of other tankers.

In addition to the vessels that it manages for our fleet, TCM technically manages a fleet of privately owned vessels and wishes to acquire third-party clients. These vessels are operated by the same group of TCM

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employees that manage our vessels, and we are advised that its employees manage these vessels on an “ownership neutral” basis; that is, without regard to who owns them. It is not impossible that Tsakos Shipping, which provides chartering service for nearly all vessels technically managed by TCM, might allocate charter or spot opportunities to other TCM managed vessels when our subsidiaries’ vessels are unemployed. It is also possible that TCM could in the future agree to manage more tankers that might directly compete with the fleet.

Clients of Tsakos Shipping have acquired and may acquire additional vessels that may compete with our fleet.

Tsakos Shipping and we have an arrangement whereby it affords us a right of first refusal on any opportunity to purchase a tanker which is 10 years of age or younger or contract to construct a tanker that is referred to or developed by Tsakos Shipping. Were we to decline any opportunity offered to us, or if we do not have the resources or desire to accept it, other clients of Tsakos Shipping might decide to accept the opportunity. In this context, Tsakos Shipping clients have in the past acquired modern tankers and have ordered the construction of vessels. They may acquire or order tankers in the future, which, if we decline to buy from them, could be entered into charters in competition with our vessels. These charters and future charters of tankers by Tsakos Shipping could result in conflicts of interest between their own interests and their obligations to us.

Our chief executive officer has affiliations with Tsakos Energy Management, Tsakos Shipping and TCM which could create conflicts of interest.

Nikolas Tsakos is the president, chief executive officer and a director of our company and the director and sole shareholder of Tsakos Energy Management. Nikolas Tsakos is also the son of the founder of Tsakos Shipping. These responsibilities and relationships could create conflicts of interest that could result in our losing revenue or business opportunities or increase our expenses.

Our commercial arrangements with Tsakos Energy Management and Argosy may not always remain on a competitive basis.

We pay Tsakos Energy Management a management fee for its services pursuant to our management agreement. We also place our hull and machinery insurance, increased value insurance and loss of hire insurance through Argosy Insurance Company, Guernsey, a captive insurance company affiliated with Tsakos interests. We believe that the management fees that we pay Tsakos Energy Management compare favorably with management compensation and related costs reported by other publicly traded shipping companies and that our arrangements with Argosy are structured at arm’s-length market rates. Our board reviews publicly available data periodically in order to confirm this. However, we cannot assure you that the fees charged to us are or will continue to be as favorable to us as those we could negotiate with third parties and our board could determine to continue transacting business with Tsakos Energy Management and Argosy even if less expensive alternatives were available from third parties.

We depend on our key personnel.

Our future success depends particularly on the continued service of Nikolas Tsakos, our president and chief executive officer and the sole shareholder of Tsakos Energy Management. The loss of Mr. Tsakos’s services or the services of any of our key personnel could have a material adverse effect on our business. We do not maintain key man life insurance on any of our executive officers.

Because the market value of our vessels may fluctuate significantly, we may incur impairment charges or losses when we sell vessels which may adversely affect our earnings.

The fair market value of tankers may increase or decrease depending on any of the following:

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The global economic downturn that commenced in 2008 resulted in a decrease in vessel values. The decrease in value accelerated during 2013 until the latter part of the year as a result of excess fleet capacity and falling freight rates. Although valuations have since recovered, they may rise further, remain the same or start to fall again depending on market conditions. In addition, although our subsidiaries currently own a modern fleet, with an average age of 8.6 years as of March 31, 2016, as vessels grow older, they generally decline in value.

We have a policy of considering the disposal of tankers periodically. If our subsidiaries’ tankers are sold at a time when tanker prices have fallen, the sale may be at less than the vessel’s carrying value on our financial statements, with the result that we will incur a loss.

In addition, accounting pronouncements require that we periodically review long-lived assets and certain identifiable intangibles for impairment whenever events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. An impairment charge for an asset held for use should be recognized when the estimate of undiscounted cash flows, excluding interest charges, expected to be generated by the use of the asset is less than its carrying amount. Measurement of the impairment charge is based on the fair value of the asset as provided by third parties. Such reviews may from time to time result in asset write-downs, as was the case in 2013 and 2012, which could adversely affect results of operations.

If TCM is unable to attract and retain skilled crew members, our reputation and ability to operate safely and efficiently may be harmed.

Our continued success depends in significant part on the continued services of the officers and seamen whom TCM provides to crew the vessels owned by our subsidiary companies. The market for qualified, experienced officers and seamen is extremely competitive and has grown more so in recent periods as a result of the growth in world economies and other employment opportunities. Although TCM has a contract with a number of manning agencies and sponsors various marine academies in the Philippines, Greece and Russia, we cannot assure you that TCM will be successful in its efforts to recruit and retain properly skilled personnel at commercially reasonable salaries. Any failure to do so could adversely affect our ability to operate cost-effectively and our ability to increase the size of the fleet.

Labor interruptions could disrupt our operations.

Substantially all of the seafarers and land based employees of TCM are covered by industry-wide collective bargaining agreements that set basic standards. We cannot assure you that these agreements will prevent labor interruptions. In addition, like many other vessels internationally, some of our subsidiaries’ vessels operate under so-called “flags of convenience” and may be vulnerable to unionization efforts by the International Transport Federation and other similar seafarer organizations which could be disruptive to our operations. Any labor interruption or unionization effort which is disruptive to our operations could harm our financial performance.

The contracts to build our newbuildings present certain economic and other risks.

As of March 31, 2016, our subsidiaries have a contract for the construction of a newbuilding LNG carrier, to be delivered in 2016, contracts for two VLCCs for delivery in 2016, contracts for the construction of nine

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aframax crude carriers for delivery in 2016 to 2017 and contracts for the construction of two LR1 product carriers for delivery in 2016 and a shuttle tanker for delivery in 2017. Our subsidiaries may also order additional newbuildings. During the course of construction of a vessel, we are typically required to make progress payments. While we typically have refund guarantees from banks to cover defaults by the shipyards and our construction contracts would be saleable in the event of our payment default, we can still incur economic losses in the event that we or the shipyards are unable to perform our respective obligations. Shipyards may periodically experience financial difficulties.

Delays in the delivery of these vessels, or any additional newbuilding or secondhand vessels our subsidiaries may agree to acquire, could delay our receipt of revenues generated by these vessels and, to the extent we have arranged charter employment for these vessels, could possibly result in the cancellation of those charters, and therefore adversely affect our anticipated results of operations. The delivery of newbuilding vessels could be delayed because of, among other things: work stoppages or other labor disturbances; bankruptcy or other financial crisis of the shipyard building the vessel; hostilities or political or economic disturbances in the countries where the vessels are being built, including any escalation of tensions involving North Korea; weather interference or catastrophic events, such as a major earthquake, tsunami or fire; our requests for changes to the original vessel specifications; requests from our customers, with whom our commercial managers arrange charters for such vessels, to delay construction and delivery of such vessels due to weak economic conditions and shipping demand or a dispute with the shipyard building the vessel.

Credit conditions internationally might impact our ability to raise debt financing.

Global financial markets and economic conditions have been disrupted and volatile in recent years. At times, the credit markets as well as the debt and equity capital markets were distressed and it was difficult for many shipping companies to obtain adequate financing. The cost of available financing also increased significantly, but for leading shipping companies has since declined. The global financial markets and economic conditions could again experience volatility and disruption in the future.

We have traditionally financed our vessel acquisitions or constructions with our own cash (equity) and bank debt from various reputable national and international commercial banks. In relation to newbuilding contracts, the equity portion usually covers all or part of the pre-delivery obligations while the debt portion covers the outstanding amount due to the shipyard on delivery. More recently, however, we have arranged pre-delivery bank financing to cover much of the installments due before delivery, and, therefore, we would be required to provide part of our equity at delivery. In addition, several of our existing loans will mature over the next few years, including the current year. In the event that the related vessels are not sold, or we do not wish to use existing cash for paying the final balloon payments, then re-financing of the loans for an extended period beyond the maturity date will be necessary. Current and future terms and conditions of available debt financing, especially for older vessels without time charter could be different from terms obtained in the past and could result in a higher cost of capital, if available at all. Any adverse development in the credit markets could materially alter our current and future financial and corporate planning and growth and have a negative impact on our balance sheet.

The future performance of our subsidiaries’ LNG carriers depends on continued growth in LNG production and demand for LNG and LNG shipping.

The future performance of our subsidiaries’ LNG carriers will depend on continued growth in LNG production and the demand for LNG and LNG shipping. A complete LNG project includes production, liquefaction, storage, re-gasification and distribution facilities, in addition to the marine transportation of LNG. Increased infrastructure investment has led to an expansion of LNG production capacity in recent years, but material delays in the construction of new liquefaction facilities could constrain the amount of LNG available for shipping, reducing ship utilization. The rate of growth in global LNG demand has fluctuated due to several factors, including the global economic crisis and continued economic uncertainty, fluctuations in the price of

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natural gas and other sources of energy, the continued acceleration in natural gas production from unconventional sources in regions such as North America and the highly complex and capital intensive nature of new or expanded LNG projects, including liquefaction projects. Growth in LNG production and demand for LNG and LNG shipping could be negatively affected by a number of factors, including:

The existing LNG carrier has been seeking employment since mid-February 2016 in the spot market and there is no charter arrangement for the LNG carrier newbuilding with expected delivery in late May 2016. Reduced demand for LNG or LNG shipping, or any reduction or limitation in LNG production capacity, could have a material adverse effect on our ability to secure future multi-year time charters for the LNG carriers, or for any new LNG carriers our subsidiaries may acquire, which could harm our business, financial condition, results of operations and cash flows, including cash available for dividends to our shareholders.

Demand for LNG shipping could be significantly affected by volatile natural gas prices and the overall demand for natural gas.

Gas prices are volatile and are affected by numerous factors beyond our control, including but not limited to the following:

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An oversupply of LNG carriers may lead to a reduction in the charter hire rates we are able to obtain when seeking charters in the future.

Driven in part by an increase in LNG production capacity, the market supply of LNG carriers has been increasing as a result of the construction of new ships. According to World Shipyard Monitor Database, during the period from 2005 to 2010, the global fleet of LNG carriers grew by an average of 14% per year due to the construction and delivery of new LNG carriers. From 2010, contracting accelerated with 53 orders in 2011, 39 in 2013, 63 in 2014, 31 in 2015 by which time the total LNG carrier order book was 142 vessels, representing 34.2% of the total fleet, with the majority of the newbuildings scheduled for delivery in 2016 and 2017. This and any future expansion of the global LNG carrier fleet that cannot be absorbed by existing or future LNG projects may have a negative impact on charter rates, ship utilization and ship values. Such impact could be amplified if the expansion of LNG production capacity does not keep pace with fleet growth.

Hire rates for LNG carriers may fluctuate substantially and have recently declined significantly. If rates remain low when we are seeking a new charter, our revenues and cash flows may decline.

The significant fall in oil prices over the past 24 months and the milder than expected Far Eastern winter have led to substantial declines in the price of LNG, which coupled with delays in liquefaction and regasification facilities under construction around the world and a higher order book particularly with vessel ordered on speculation, have led to declines in average rates for new spot and shorter-term LNG charters. Unless LNG charter market conditions improve over the next several months, we may have difficulty in securing new charters at attractive rates and durations for the Neo Energy , whose time charter expired in February 2016 and is currently seeking employment in the spot market, and for the Maria Energy, a newbuilding that is scheduled to be delivered in May 2016 for which employment has yet to be arranged.

We depend upon Hyundai Ocean Services to manage our LNG carrier.

Tsakos Energy Management has subcontracted all technical management of our LNG operation to Hyundai Ocean Services (“HOS”) for a fee. Neither Tsakos Energy Management nor TCM has the dedicated personnel for running LNG operations nor can we guarantee that they will employ an adequate number of employees to conduct LNG operations in the future. As such, we are currently dependent on the reliability and effectiveness of third-party managers for whom we cannot guarantee that their employees, both onshore and at-sea are sufficient in number or capability for their assigned role. We also cannot assure you that we will be able to continue to receive such services from HOS on a long-term basis on acceptable terms or at all.

Our growth in shuttle tankers depends partly on continued growth in demand for offshore oil transportation, processing and storage services.

Our growth strategy includes expansion in the shuttle tanker sector. Growth in this sector depends on continued growth in world and regional demand for these offshore services, which could be negatively affected by a number of factors, such as:

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Oil prices have declined substantially in the last 18 months, which has resulted in oil companies announcing reductions in oil production and exploration activities, including in offshore fields.

Fuel prices may adversely affect our profits.

While we do not bear the cost of fuel (bunkers) under time and bareboat charters, fuel is a significant, if not the largest, expense in our shipping operations when vessels are under spot charters. Increases in the price of fuel may, as a result, adversely affect our profitability. The price and supply of fuel is unpredictable and fluctuates based on events outside our control, including geopolitical developments.

If our counterparties were to fail to meet their obligations under a charter agreement we could suffer losses or our business could be otherwise adversely affected.

As of April 5, 2016, 28 of our subsidiaries’ vessels were employed under time charters and time charters with profit share. The ability and willingness of each of the counterparties to perform their obligations under their charters will depend on a number of factors that are beyond our control and may include, among other things, general economic conditions, the condition of the oil and energy industries and of the oil and oil products shipping industry as well as the overall financial condition of the counterparties and prevailing charter rates. There can be no assurance that some of our subsidiaries’ customers would not fail to pay charter hire or attempt to renegotiate charter rates and, if the charterers fail to meet their obligations or attempt to renegotiate charter agreements, we could sustain significant losses which could have a material adverse effect on our business, financial condition, results of operations and cash flows, as well as our ability to pay dividends in the future.

We may not have adequate insurance.

In the event of a casualty to a vessel or other catastrophic event, we will rely on our insurance to pay the insured value of the vessel or the damages incurred. We believe that we maintain as much insurance on the vessels in the fleet, through insurance companies, including Argosy, a related party company, and P&I clubs, as is appropriate and consistent with industry practice. However, we cannot assure you that this insurance will remain available beyond anniversary dates at reasonable rates, and we cannot assure you that the insurance we are able to obtain will cover all liabilities that we may incur, particularly those involving oil spills and catastrophic environmental damage. In addition, we may not be able to insure certain types of losses, including loss of hire, for which insurance coverage may become unavailable. Any uninsured or underinsured loss or liability could harm our business, financial condition, results of operations and cash flows, including cash available for payment of dividends to our shareholders.

We are subject to funding calls by our protection and indemnity clubs, and our clubs may not have enough resources to cover claims made against them.

Our subsidiaries are indemnified for legal liabilities incurred while operating their vessels through membership in P&I clubs. P&I clubs are mutual insurance clubs whose members must contribute to cover losses sustained by other club members. The objective of a P&I club is to provide mutual insurance based on the aggregate tonnage of a member’s vessels entered into the club. Claims are paid through the aggregate premiums of all members of the club, although members remain subject to calls for additional funds in the unlikely event

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aggregate premiums are insufficient to cover claims submitted to the club. Claims submitted to the club may include those incurred by members of the club, as well as claims submitted to the club from other P&I clubs with which our subsidiaries’ P&I clubs have entered into interclub agreements. We cannot assure you that the P&I clubs to which our subsidiaries belong will remain viable or that we will not become subject to additional funding calls which could adversely affect our profitability.

The insolvency or financial deterioration of any of our insurers or reinsurers would negatively affect our ability to recover claims for covered losses on our vessels.

We have placed our hull and machinery, increased value and loss of hire insurance with Argosy, a captive insurance company affiliated with Tsakos family interests. Argosy reinsures the insurance it underwrites for us with various reinsurers, however, the coverage deductibles of the reinsurance policies periodically exceed the coverage deductibles of the insurance policies Argosy underwrites for us. Argosy, therefore, would be liable with respect to the difference between those deductibles in the event of a claim by us to which the deductibles apply. Although these reinsurers have a minimum credit rating of ‘A-’, we do not have the ability to independently determine our insurers’ and reinsurers’ creditworthiness or their ability to pay any claims that we may have as a result of a loss. In the event of insolvency or other financial deterioration of our insurer or its reinsurers, we cannot assure you that we would be able to recover on any claims we suffer.

Our degree of leverage and certain restrictions in our financing agreements impose constraints on us.

We incur substantial debt to finance the acquisition of our vessels. At December 31, 2015, our debt to capital ratio was 49.7% (debt / debt plus equity), with $1.4 billion in debt outstanding. We are required to apply a substantial portion of our cash flow from operations to the payment of principal and interest on this debt. In 2015, 77% of our cash flow derived from operations was dedicated to debt service, excluding any debt prepayment upon the sale of vessels and voluntary early debt prepayments. This limits the funds available for working capital, capital expenditures, dividends and other purposes. Our degree of leverage could have important consequences for us, including the following:

In addition, our financing arrangements, which we secured by mortgages on our ships, impose operating and financial restrictions on us that restrict our ability to:

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We have a holding company structure which depends on dividends from our subsidiaries and interest income to pay our overhead expenses and otherwise fund expenditures consisting primarily of advances on newbuilding contracts and the payment of dividends to our shareholders. As a result, restrictions contained in our financing arrangements and those of our subsidiaries on the payment of dividends may restrict our ability to fund our various activities.

We are exposed to volatility in LIBOR and selectively enter into derivative contracts, which can result in higher than market interest rates and charges against our income.

Over the past twelve years we have selectively entered into derivative contracts both for investment purposes and to hedge our overall interest expense and, more recently, our bunker expenses. Our board of directors monitors the status of our derivatives in order to assess whether such derivatives are within reasonable limits and reasonable in light of our particular investment strategy at the time we entered into the derivative contracts.

Loans advanced under our secured credit facilities are, generally, advanced at a floating rate based on LIBOR, which has been stable and at historically low levels in recent years, but was volatile in prior years, which can affect the amount of interest payable on our debt, and which, in turn, could have an adverse effect on our earnings and cash flow. Our financial condition could be materially adversely affected at any time that we have not entered into interest rate hedging arrangements to hedge our interest rate exposure and the interest rates applicable to our credit facilities and any other financing arrangements we may enter into in the future, including those we enter into to finance a portion of the amounts payable with respect to newbuildings, increase. Moreover, even if we have entered into interest rate swaps or other derivative instruments for purposes of managing our interest rate or bunker cost exposure, our hedging strategies may not be effective and we may incur substantial loss.

We have a risk management policy and the Audit Committee to oversee all our derivative transactions. It is our policy to monitor our exposure to business risk, and to manage the impact of changes in interest rates, foreign exchange rate movements and bunker prices on earnings and cash flows through derivatives. Derivative contracts are executed when management believes that the action is not likely to significantly increase overall risk. Entering into swaps and derivatives transactions is inherently risky and presents various possibilities for incurring significant expenses. The derivatives strategies that we employ in the future may not be successful or effective, and we could, as a result, incur substantial additional interest costs. See “Item 11. Quantitative and Qualitative Disclosures About Market Risk” for a description of our current interest rate swap arrangements.

Our subsidiaries’ vessels may suffer damage and we may face unexpected dry-docking costs which could affect our cash flow and financial condition.

If our vessels suffer damage, they may need to be repaired at a dry-docking facility. The costs of dry-dock repairs can be both substantial and unpredictable. We may have to pay dry-docking costs that our insurance does not cover. This would result in decreased earnings.

If we were to be subject to tax in jurisdictions in which we operate, our financial results would be adversely affected.

Our income is not presently subject to taxation in Bermuda, which has no corporate income tax. We believe that we should not be subject to tax under the laws of various countries, other than the United States, in which we conduct activities or in which our customers are located. However, our belief is based on our understanding of the tax laws of those countries, and our tax position is subject to review and possible challenge by taxing authorities and to possible changes in law or interpretation. We cannot determine in advance the extent to which certain jurisdictions may require us to pay tax or to make payments in lieu of tax. In addition, payments due to us from our customers may be subject to tax claims.

If we or our subsidiaries are not entitled to exemption under Section 883 of the United States Internal Revenue Code of 1986, as amended, for any taxable year, we or our subsidiaries would be subject for those years

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to a 4% United States federal income tax on our gross U.S.-source shipping revenue, without allowance for deductions, under Section 887 of the Internal Revenue Code. The imposition of such tax could have a negative effect on our business and would result in decreased earnings available for distribution to our stockholders.

See “Tax Considerations—United States federal income tax considerations” for additional information about the requirements of this exemption.

If we were treated as a passive foreign investment company, a U.S. investor in our common shares would be subject to disadvantageous rules under the U.S. tax laws.

If we were treated as a passive foreign investment company (a “PFIC”) in any year, U.S. holders of our common shares would be subject to unfavorable U.S. federal income tax treatment. We do not believe that we will be a PFIC in 2016 or in any future year. However, PFIC classification is a factual determination made annually and we could become a PFIC if the portion of our income derived from bareboat charters or other passive sources were to increase substantially or if the portion of our assets that produce or are held for the production of passive income were to increase substantially. Moreover, the IRS may disagree with our position that time and voyage charters do not give rise to passive income for purposes of the PFIC rules. Accordingly, we can provide no assurance that we will not be treated as a PFIC for 2015 or for any future year. Please see “Tax Considerations—United States federal income tax considerations—Passive Foreign Investment Company Considerations” herein for a description of the PFIC rules.

Distributions on the common shares of non-U.S. companies that are treated as dividends for U.S. federal income tax purposes and are received by individuals generally will be eligible for taxation at capital gain rates if the common shares with respect to which the dividends are paid are readily tradable on an established securities market in the United States. This treatment will not be available to dividends we pay, however, if we qualify as a PFIC for the taxable year of the dividend or the preceding taxable year, or to the extent that (i) the shareholder does not satisfy a holding period requirement that generally requires that the shareholder hold the shares on which the dividend is paid for more than 60 days during the 121-day period that begins 60 days before the date on which the shares become ex-dividend with respect to such dividend, (ii) the shareholder is under an obligation to make related payments with respect to substantially similar or related property or (iii) such dividend is taken into account as investment income under Section 163(d)(4)(B) of the Internal Revenue Code. We do not believe that we qualified as a PFIC for our last taxable year and, as described above, we do not expect to qualify as a PFIC for our current or future taxable years. Legislation has been proposed in the United States Congress which, if enacted in its current form, would likely cause dividends on our shares to be ineligible for the preferential tax rates described above. There can be no assurance regarding whether, or in what form, such legislation will be enacted.

Because some of our subsidiaries’ vessels’ expenses are incurred in foreign currencies, we are exposed to exchange rate risks.

The charterers of the vessels owned by our subsidiary companies pay in U.S. dollars. While most of the expenses incurred by our managers or by us on our subsidiaries’ behalf are paid in U.S. dollars, certain of these expenses are in other currencies, most notably the Euro. In 2015, Euro expenses accounted for approximately 34% of our total operating expenses, including dry-dockings. Declines in the value of the U.S. dollar relative to the Euro, or the other currencies in which we incur expenses, would increase the U.S. dollar cost of paying these expenses and thus would adversely affect our results of operations.

The Tsakos Holdings Foundation and the Tsakos family can exert considerable control over us, which may limit your ability to influence our actions.

As of April 5, 2016, companies controlled by the Tsakos Holdings Foundation or affiliated with the Tsakos Group own approximately 30% of our outstanding common shares. The Tsakos Holdings Foundation is a Liechtenstein foundation whose beneficiaries include persons and entities affiliated with the Tsakos family,

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charitable institutions and other unaffiliated persons and entities. The council which controls the Tsakos Holdings Foundation consists of five members, two of whom are members of the Tsakos family. As long as the Tsakos Holdings Foundation and the Tsakos family beneficially own a significant percentage of our common shares, each will have the power to influence the election of the members of our board of directors and the vote on substantially all other matters, including significant corporate actions.

Risks Related To Our Common and Preferred Shares

Future sales of our common shares could cause the market price of our common shares to decline.

Sales of a substantial number of our common shares in the public market, or the perception that these sales could occur, may depress the market price for our common shares. These sales could also impair our ability to raise additional capital through the sale of our equity securities in the future. We may issue additional common shares in the future and our shareholders may elect to sell large numbers of shares held by them from time to time.

The market price of our common shares and preferred shares may be unpredictable and volatile.

The market price of our common shares and Series B Preferred Shares, Series C Preferred Shares and Series D Preferred Shares may fluctuate due to factors such as actual or anticipated fluctuations in our quarterly and annual results and those of other public companies in our industry, mergers and strategic alliances in the tanker industry, market conditions in the tanker industry, changes in government regulation, shortfalls in our operating results from levels forecast by securities analysts, announcements concerning us or our competitors, our sales of our common shares or of additional preferred shares, changes in prevailing interest rates and the general state of the securities market. The tanker industry has been highly unpredictable and volatile. The market for common stock and preferred stock in this industry may be equally volatile. Therefore, we cannot assure you that you will be able to sell any of our common shares and preferred shares you may have purchased, or will purchase in the future, at a price greater than or equal to the original purchase price.

If the market price of our common shares falls to and remains below $5.00 per share, under stock exchange rules, our shareholders will not be able to use such shares as collateral for borrowing in margin accounts. This inability to use common shares as collateral may depress demand and certain institutional investors are restricted from investing in or holding shares priced below $5.00, which could lead to sales of such shares creating further downward pressure on and increased volatility in the market price of our common shares.

We may not be able to pay cash dividends on our common shares or preferred shares as intended if market conditions change.

During 2015, we paid dividends on our common shares totaling $0.24 per common share, totaling $20.6 million. On February 16, 2016, the Company announced a common share dividend of $0.08 per common share to be paid on April 7, 2016 to holders of record as of March 30, 2016. In addition, during 2015 we paid dividends on our preferred shares totaling $12.8 million and another $4.0 million in January and February 2016. Subject to the limitations discussed below, we currently intend to continue to pay cash dividends on our common shares and preferred shares. However, there can be no assurance that we will pay dividends or as to the amount of any dividend. The payment and the amount will be subject to the discretion of our board of directors and will depend, among other things, on restrictions in the Companies Act of 1981 of Bermuda, as amended, or the Companies Act, on our available cash balances, anticipated cash needs, our results of operations, our financial condition, and any loan agreement restrictions binding us or our subsidiaries, including a limit on dividends exceeding 50% of our net income for any particular year, plus certain additional amounts permitted to the extent 50% of our aggregate net income in prior years exceeded dividends paid during such years, as well as other relevant factors. Net losses that we incurred in certain of our historical periods as well as dividends that we historically paid reduce the amount of the accumulated consolidated net income from which we are permitted to pay dividends under our loan agreements while net income in other periods increases the amount. In addition, dividends on our

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common shares are subject to the priority of our dividend obligations relating to our Series B, Series C and Series D Preferred Shares. We may have insufficient cash to pay dividends on or redeem our Series B, Series C and Series D Preferred Shares, or pay dividends on our common shares. Depending on our operating performance for a particular year, this could result in no dividend at all despite the existence of net income, or a dividend that represents a lower percentage of our net income.

Because we are a holding company with no material assets other than the stock of our subsidiaries, our ability to pay dividends will depend on the earnings and cash flow of our subsidiaries and their ability to pay us dividends. In addition, the financing arrangements for indebtedness we incur in connection with our newbuilding program may further restrict our ability to pay dividends. In the event of any insolvency, bankruptcy or similar proceedings of a subsidiary, creditors of such subsidiary would generally be entitled to priority over us with respect to assets of the affected subsidiary. Investors in our common shares, Series B Preferred Shares, Series C Preferred Shares or Series D Preferred Shares may be adversely affected if we are unable to or do not pay dividends as intended.

Market interest rates may adversely affect the value of our Series B Preferred Shares, Series C Preferred Shares and Series D Preferred Shares.

One of the factors that influences the price of our Series B Preferred Shares, Series C Preferred Shares and Series D Preferred Shares is the dividend yield on these Preferred Shares (as a percentage of the price thereof) relative to market interest rates. An increase in market interest rates, which are currently at low levels relative to historical rates, may lead to lower prices for our shares when valued using their dividend yields. Higher interest rates would likely increase our borrowing costs and potentially decrease funds available for dividends. Accordingly, higher interest rates could affect the market prices of our Preferred Shares to decrease.

Holders of our Preferred Shares have extremely limited voting rights.

The voting rights of holders of Series B Preferred Shares, Series C Preferred Shares and Series D Preferred Shares are extremely limited. Our common shares are the only class or series of our shares carrying full voting rights. The voting rights of holders of these Preferred Shares are limited to the ability, subject to certain exceptions, to elect, voting together as a class with all other classes or series of parity securities upon which like voting rights have been conferred and are exercisable, one director if dividends for six quarterly dividend periods (whether or not consecutive) payable thereon are in arrears and certain other limited protective voting rights described in “Item 10. Additional Information—Description of Share Capital—Preferred Shares.”

Provisions in our Bye-laws and our management agreement with Tsakos Energy Management would make it difficult for a third party to acquire us, even if such a transaction is beneficial to our shareholders.

Our Bye-laws provide for a staggered board of directors, blank check preferred stock, super majority voting requirements and other anti-takeover provisions, including restrictions on business combinations with interested persons and limitations on the voting rights of shareholders who acquire more than 15% of our common shares. In addition, Tsakos Energy Management would have the right to terminate our management agreement and seek liquidated damages if a board member were elected without having been approved by the current board. These provisions could deter a third party from tendering for the purchase of some or all of our shares. These provisions may have the effect of delaying or preventing changes of control of the ownership and management of our company.

Because we are a foreign corporation, you may not have the same rights as a shareholder in a U.S. corporation.

We are a Bermuda corporation. Our Memorandum of Association and Bye-laws and the Companies Act govern our affairs. While many provisions of the Companies Act resemble provisions of the corporation laws of a number of states in the United States, Bermuda law may not as clearly establish your rights and the fiduciary responsibilities of our directors as do statutes and judicial precedent in some U.S. jurisdictions. In addition, apart

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from three non-executive directors, our directors and officers are not resident in the United States and all or substantially all of our assets are located outside of the United States. As a result, investors may have more difficulty in protecting their interests and enforcing judgments in the face of actions by our management, directors or controlling shareholders than would shareholders of a corporation incorporated in a U.S. jurisdiction.

In addition, you should not assume that courts in the country in which we are incorporated or where our assets are located would enforce judgments of U.S. courts obtained in actions against us based upon the civil liability provisions of applicable U.S. federal and state securities laws or would enforce, in original actions, liabilities against us based on those laws.

We are a “foreign private issuer” under NYSE rules, and as such we are entitled to exemption from certain NYSE corporate governance standards, and you may not have the same protections afforded to shareholders of companies that are subject to all of the NYSE corporate governance requirements.

We are a “foreign private issuer” under the securities laws of the United States and the rules of the NYSE. Under the securities laws of the United States, “foreign private issuers” are subject to different disclosure requirements than U.S. domiciled registrants, as well as different financial reporting requirements. Under the NYSE rules, a “foreign private issuer” is subject to less stringent corporate governance requirements. Subject to certain exceptions, the rules of the NYSE permit a “foreign private issuer” to follow its home country practice in lieu of the listing requirements of the NYSE, including (i) the requirement that a majority of the board of directors consist of independent directors, (ii) the requirement that the nominating/corporate governance committees be composed entirely of independent directors and have a written charter addressing the committee’s purpose and responsibilities, (iii) the requirement that the compensation committee be composed entirely of independent directors and have a written charter addressing the committee’s purpose and responsibilities, and (iv) the requirement of an annual performance evaluation of the nominating/corporate governance and compensation committees.

Nonetheless, a majority of our directors are independent, all of the members of our compensation, nominating and corporate governance committee are independent directors, and all of our board committees have written charters addressing their respective purposes and responsibilities.