Unless otherwise indicated, references in this prospectus to “Teekay LNG Partners,” “we,” “us” and “our” and similar terms refer to Teekay LNG Partners L.P. and/or one or more of its subsidiaries, except that those terms, when used in this Annual Report in connection with the ~~common~~ units described herein, shall mean specifically Teekay LNG Partners L.P. References in this Annual Report to “Teekay Corporation” refer to Teekay Corporation and/or any one or more of its subsidiaries.

In addition to historical information, this Annual Report contains forward-looking statements that involve risks and uncertainties. Such forward-looking statements relate to future events and our operations, objectives, expectations, performance, financial condition and intentions. When used in this Annual Report, the words “expect,” “intend,” “plan,” “believe,” “anticipate,” “estimate” and variations of such words and similar expressions are intended to identify forward-looking statements. Forward-looking statements in this Annual Report include, in particular, statements regarding:

We do not intend to revise any forward-looking statements in order to reflect any change in our expectations or events or circumstances that may subsequently arise. You should carefully review and consider the various disclosures included in this Annual Report and in our other filings made with the SEC that attempt to advise interested parties of the risks and factors that may affect our business prospects and results of operations.

Set forth below is selected consolidated financial and other data of Teekay LNG Partners and its subsidiaries for the fiscal years ~~2010~~2012 through ~~2014,~~2016, which have been derived from our consolidated financial statements. The following table should be read together with, and is qualified in its entirety by reference to, (a) “Item 5 – Operating and Financial Review and Prospects,” included herein, and (b) the historical consolidated financial statements and the accompanying notes and the Report of Independent Registered Public Accounting Firm therein (which are included herein), with respect to the consolidated financial statements for the years ended December 31, ~~2014, 2013~~2016, 2015 and ~~2012.~~

From time to time we purchase vessels from Teekay Corporation. In 2010, we acquired three conventional tankers from Teekay Corporation. This transaction was deemed to be a business acquisition between entities under common control. Accordingly, we have accounted for this transaction in a manner similar to the pooling of interest method whereby our financial statements prior to the date these vessels were acquired by us are retroactively adjusted to include the results of these acquired vessels. The periods retroactively adjusted include all periods that we and the acquired vessels were both under the common control of Teekay Corporation and the acquired vessels had begun operations. As a result, our consolidated statements of income for the year ended December 31, 2010 reflect the results of operations of these three vessels, referred to herein as the~~Dropdown Predecessor~~, as if we had acquired them when each respective vessel began operations under the ownership of Teekay Corporation, which was between May 2009 and September 2009. Please refer to “Item 5 – Operating and Financial Review and Prospects: Results of Operations – Items You Should Consider When Evaluating Our Results of Operations.”

2014.

The amount of cash we can distribute on our common and preferred units principally depends upon the amount of cash we generate from our operations, which may fluctuate based on, among other things:

The actual amount of cash we will have available for distribution also will depend on factors such as:

The amount of cash we generate from our operations may differ materially from our profit or loss for the period, which will be affected by non-cash items. As a result of this and the other factors mentioned above, we may make cash distributions during periods when we record losses and may not make cash distributions during periods when we record net income.

Our cash distribution policy, which is consistent with our partnership agreement, requires us to distribute each quarter all of our Available Cash (as defined in our partnership agreement, which takes into account cash reserves for, among other things, future capital expenditures and credit needs). Accordingly, our growth may not be as fast as businesses that reinvest their Available Cash to expand ongoing operations.

In determining the amount of cash available for distribution, the board of directors of our General Partner, in making the determination on our behalf, approves the amount of cash reserves to set aside, including reserves for future maintenance capital expenditures, anticipated future credit needs, working capital and other matters. We also rely upon external financing sources, including commercial borrowings and proceeds from debt and equity offerings, to fund our capital expenditures. Accordingly, to the extent we do not have sufficient cash reserves or are unable to obtain financing, our cash distribution policy may significantly impair our ability to meet our financial needs or to grow.

Global crude oil prices have significantly declined since mid-2014. The significant decline in oil prices has also contributed to depressed natural gas prices. Lower oil prices may negatively affect both the competitiveness of natural gas as a fuel for power generation and the market price of natural gas, to the extent that natural gas prices are benchmarked to the price of crude oil. These declines in energy prices, combined with other factors beyond our control, have adversely affected energy and master limited partnership capital markets and available sources of financing for our capital expenditures and debt repayment obligations. As a result, effective for the quarterly distribution for the fourth quarter of 2015, we reduced our quarterly cash distributions per common unit to $0.14 from $0.70, and our near-term business strategy is primarily to focus on funding and implementing existing growth projects and repaying or refinancing scheduled debt obligations with cash flows from operations rather than pursuing additional growth projects. It is uncertain when the energy and capital markets will normalize and when, if at all, the board of directors of our General Partner may increase quarterly cash distributions on our common units.

To fund our existing and future debt obligations and capital expenditures, including our LNG carrier newbuildings, we will be required to use cash from operations, incur borrowings, and/or seek to access other financing sources. Our access to potential funding sources and our future financial and operating performance will be affected by prevailing economic conditions and financial, business, regulatory and other factors, many of which are beyond our control. If we are unable to access additional bank financing and generate sufficient cash flow to meet our debt, capital expenditure and other business requirements, we may be forced to take actions such as:

Such measures might not be successful, available on acceptable terms or enable us to meet our debt, capital expenditure and other obligations. Some of such measures may adversely affect our business and reputation. In addition, our financing agreements may restrict our ability to implement some of these measures.

Use of cash from operations and possible future sale of certain assets will reduce cash available for distribution to unitholders. Our ability to obtain bank financing or to access the capital markets for future offerings may be limited by our financial condition at the time of any such financing or offering as well as by adverse market conditions. Even if we are successful in obtaining necessary funds, the terms of such financings could limit our ability to pay cash distributions to unitholders or operate our business as currently conducted. In addition, incurring additional debt may significantly increase our interest expense and financial leverage, and issuing additional equity securities may result in significant unitholder dilution and would increase the aggregate amount of cash required to maintain our quarterly distributions to unitholders.

We must make substantial capital expenditures to maintain, over the long term, the operating capacity of our fleet. These maintenance capital expenditures include capital expenditures associated with dry docking a vessel, modifying an existing vessel or acquiring a new vessel to the extent these expenditures are incurred to maintain the operating capacity of our fleet. These expenditures could increase as a result of changes in:

In addition, our actual maintenance capital expenditures vary significantly from quarter to quarter based on, among other things, the number of vessels dry docked during that quarter. Certain repair and maintenance items are more efficient to complete while a vessel is in dry dock. Consequently, maintenance capital expenditures will typically increase in periods when there is an increase in the number of vessels dry docked. Our significant maintenance capital expenditures reduce the amount of cash we have available for distribution to our unitholders.

Our partnership agreement requires our General Partner to deduct estimated, rather than actual, maintenance capital expenditures from operating surplus (as defined in our partnership agreement) each quarter in an effort to reduce fluctuations in operating surplus. The amount of estimated maintenance capital expenditures deducted from operating surplus is subject to review and change by the conflicts committee of our General Partner’s board of directors at least once a year. In years when estimated maintenance capital expenditures are higher than actual maintenance capital expenditures —– as we expect will be the case in the years we are not required to make expenditures for mandatory dry dockings —– the amount of cash available for distribution to unitholders will be lower than if actual maintenance capital expenditures were deducted from operating surplus. If our General Partner underestimates the appropriate level of estimated maintenance capital expenditures, we may have less cash available for distribution in future periods when actual capital expenditures begin to exceed our previous estimates.

We and Teekay Corporation regularly evaluate and pursue opportunities to provide the marine transportation requirements for new or expanding LNG and LPG projects. The award process relating to LNG transportation opportunities typically involves various stages and takes several months to complete. Neither we nor Teekay Corporation may be awarded charters relating to any of the projects we or it pursues. If any LNG project charters are awarded to Teekay Corporation, it must offer them to us pursuant to the terms of an omnibus agreement entered into in connection with our initial public offering. If we elect pursuant to the omnibus agreement to obtain Teekay Corporation’s interests in any projects Teekay Corporation may be awarded, or if we bid on and are awarded contracts relating to any LNG and LPG project, we will need to incur significant capital expenditures to buy Teekay Corporation’s interest in these LNG and LPG projects or to build the LNG and LPG carriers.

~~To fund the remaining portion of existing or future~~

Our substantial capital expenditures ~~we will be required to use cash from operations or incur borrowings or raise capital through the sale of debt or additional equity securities. Use of cash from operations will~~may reduce our cash available for ~~distributions~~distribution to our unitholders. ~~Our ability to obtain bank financing or to access the capital markets for future offerings may be limited by our financial condition at the time~~Funding of any ~~such financing or offering as well as by adverse market conditions resulting from, among other things, general economic conditions~~capital expenditures with debt may significantly increase our interest expense and ~~contingencies~~financial leverage, and ~~uncertainties that are beyond our control.~~funding of capital expenditures through issuing additional equity securities may result in significant unitholder dilution. Our failure to obtain the funds for necessary future capital expenditures could have a material adverse effect on our business, results of operations and financial condition and on our ability to make cash ~~distributions. Even if we are successful in obtaining necessary funds, the terms of such financings could limit our ability to pay cash~~ distributions to unitholders. In addition, incurring additional debt may significantly increase our interest expense and financial leverage, and issuing additional equity securities may result in significant unitholder dilution and would increase the aggregate amount of cash required to maintain our level of quarterly distributions to unitholders, which could have a material adverse effect on our ability to make cash distributions.

A shipowner is typically is required to expend substantial sums as progress payments during construction of a newbuilding, but does not derive any income from the vessel until after its delivery. If we were unable to obtain financing required to complete payments on any future newbuilding orders, we could effectively forfeit all or a portion of the progress payments previously made.

~~Our ability to grow may be adversely affected by our cash distribution policy.~~

Our cash distribution policy, which is consistent with our partnership agreement, requires us to distribute all of our available cash (as defined in our partnership agreement) each quarter. Accordingly, our growth may not be as fast as businesses that reinvest their available cash to expand ongoing operations.

As at December 31, ~~2014,~~2016, our consolidated debt, capital lease obligations and advances from affiliates totaled ~~$2.0~~$2.2 billion and we had the capacity to borrow an additional ~~$135.6~~$243.7 million under our revolving credit facilities. These facilities may be used by us for general partnership purposes. If we are awarded contracts for new LNG or LPG projects, our consolidated debt and capital lease obligations will increase, perhaps significantly. We will continue to have the ability to incur additional debt, subject to limitations in our credit facilities. Our level of debt could have important consequences to us, including the following:

Our ability to service our debt depends upon, among other things, our future financial and operating performance, which is affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as further reducing distributions, reducing, cancelling or delaying our business activities, acquisitions, investments or capital expenditures, selling assets, ~~restructuring~~seeking to restructure or ~~refinancing~~refinance our debt, or seeking additional debt or equity capital or seeking bankruptcy protection. We may not be able to effect any of these remedies on satisfactory terms, or at all.

The operating and financial restrictions and covenants in our financing arrangements and any future financing agreements for us could adversely affect our ability to finance future operations or capital needs or to engage, expand or pursue our business activities. For example, the arrangements may restrict our ability to:

Some of our financing arrangements require us to maintain a minimum level of tangible net worth, to maintain certain ratios of vessel values as it relates to the relevant outstanding principal balance, a minimum level of aggregate liquidity, a maximum level of leverage and require ~~two~~certain of our subsidiaries to maintain restricted cash deposits. Please read "Item 5 – Operating and Financial Review and Prospects: Credit Facilities". Our ability to comply with covenants and restrictions contained in debt instruments may be affected by events beyond our control, including prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, compliance with these covenants may be impaired. If restrictions, covenants, ratios or tests in the financing agreements are breached, a significant portion or all of the obligations may become immediately due and payable, and the lenders’ commitment to make further loans may terminate. This could lead to cross-defaults under other financing agreements and result in obligations becoming due and commitments being terminated under such agreements. We might not have or be able to obtain sufficient funds to make these accelerated payments. In addition, our obligations under our existing credit facilities are secured by certain of our vessels, and if we are unable to repay debt under the credit facilities, the lenders could seek to foreclose on those assets.

The payment of principal and interest on our debt and capital lease obligations reduces cash available for distribution ~~to us and~~ on our units. In addition, our financing agreements prohibit the payment of distributions upon the occurrence of the following events, among others:

We have derived, and believe that we will continue to derive, a significant portion of our revenues and cash flow from a limited number of customers. Please read “Item 18 – Financial Statements: Note 34 – Segment Reporting.”

We could lose a customer or the benefits of a time-charter if:

If we lose a key LNG time-charter, we may be unable to redeploy the related vessel on terms as favorable to us due to the long-term nature of most LNG time-charters and the lack of an established LNG spot market. If we are unable to redeploy a LNG carrier, we will not receive any revenues from that vessel, but we may be required to pay expenses necessary to maintain the vessel in proper operating condition. In addition, if a customer exercises its right to purchase a vessel, we would not receive any further revenue from the vessel and may be unable to obtain a substitute vessel and charter. This may cause us to receive decreased revenue and cash flows from having fewer vessels operating in our fleet. Any compensation under our charters for a purchase of the vessels may not adequately compensate us for the loss of the vessel and related time-charter.

If we lose a key conventional tanker customer, we may be unable to obtain other long-term conventional charters and may become subject to the volatile spot market, which is highly competitive and subject to significant price fluctuations. If a customer exercises its right under some charters to purchase or force a sale of the vessel, we may be unable to acquire an adequate replacement vessel or may be forced to construct a new vessel. Any replacement newbuilding would not generate revenues during its construction and we may be unable to charter any replacement vessel on terms as favorable to us as those of the terminated charter.

The loss of certain of our customers, time-charters or vessels, or a decline in payments under our charters, could have a material adverse effect on our business, results of operations and financial condition and our ability to make cash ~~distributions.~~

distributions to unitholders.

Pursuant to certain services agreements between us and certain of our operating subsidiaries, on the one hand, and certain direct and indirect subsidiaries of Teekay Corporation and certain of our joint venture partners, on the other hand, the Teekay Corporation subsidiaries and certain of our joint venture partners provide to us ~~administrative and business development~~various services ~~and to our~~including, in the case of operating subsidiaries, ~~significant~~substantially all of their managerial, operational and administrative services (including vessel maintenance, crewing for some of our vessels, purchasing, shipyard supervision, insurance and financial services) and other technical and advisory services, and in the case of Teekay LNG Partners L.P., various administrative services. Our operational success and ability to execute our growth strategy depend significantly upon Teekay Corporation’s and certain of our joint venture partners’ satisfactory performance of these services. Our business will be harmed if Teekay Corporation or certain of our joint venture partners ~~fails~~fail to perform these services satisfactorily or if Teekay Corporation or certain of our joint venture partners ~~stops~~stop providing these services to us.

Our ability to compete for the transportation requirements of LNG and oil projects and to enter into new time-charters and expand our customer relationships depends largely on our ability to leverage our relationship with Teekay Corporation and its reputation and relationships in the shipping industry. Our ability to compete for the transportation requirement of LPG projects and to enter into new charters and expand our customer relationships depends largely on our ability to leverage our relationship with one of our joint venture partners and ~~their~~its reputation and relationships in the shipping industry. If Teekay Corporation or certain of our joint venture partners suffer material damage to its reputation or relationships it may harm our ability to:

If our ability to do any of the things described above is impaired, it could have a material adverse effect on our business, results of operations and financial condition and our ability to make cash ~~distributions.~~

distributions to unitholders.

Our operating subsidiaries may also contract with certain subsidiaries of Teekay Corporation and certain of our joint venture partners to have newbuildings constructed on behalf of our operating subsidiaries and to incur the construction-related financing. Our operating subsidiaries would purchase the vessels on or after delivery based on an agreed-upon price. None of our operating subsidiaries currently has this type of arrangement with Teekay Corporation or any of its affiliates or any joint venture partners.

Global crude oil prices have significantly declined since mid-2014. The significant decline in oil prices has also contributed to depressed natural gas prices. A continuation of lower natural gas or oil prices or a further decline in natural gas or oil prices may adversely affect our business, results of operations and financial condition and our ability to make cash distributions, as a result of, among other things:

Our growth strategy focuses on ~~continued~~ expansion in the LNG and LPG shipping sectors. Accordingly, our growth depends on continued growth in world and regional demand for LNG and LPG and marine transportation of LNG and LPG, as well as the supply of LNG and LPG. Demand for LNG and LPG and for the marine transportation of LNG and LPG could be negatively affected by a number of factors, such as:

Reduced demand for LNG and LPG shipping would have a material adverse effect on our future growth and could harm our business, results of operations and financial condition.

Demand for our vessels and services in transporting oil depends upon world and regional oil markets. Any decrease in shipments of crude oil in those markets could have a material adverse effect on our conventional ~~tanker business. Upon completion~~tankers business, financial condition and results of ~~the remaining charter terms for our conventional tankers, any adverse changes in the oil markets may affect our ability to enter into long-term fixed-rate contracts for our conventional tankers.~~ operations.

Historically, those markets have been volatile as a result of the many conditions and events that affect the price, production and transport of oil, including competition from alternative energy sources. Past slowdowns of the U.S. and world economies have resulted in reduced consumption of oil products and decreased demand for vessels and services, which reduced vessel earnings. Additional slowdowns could have similar effects on our operating results.

~~A continuation of the recent significant declines in natural gas and oil prices may adversely affect our growth prospects and results of operations.~~

Global natural gas and crude oil prices have significantly declined since mid-2014. A continuation of lower natural gas or oil prices or a further decline in natural gas or oil prices may adversely affect our business, results of operations and financial condition and our ability to make cash distributions, as a result of, among other things:

Future adverse economic conditions or other developments relating directly to our customers may lead to a decline in our customers’ operations or ability to pay for our services, which could result in decreased demand for our vessels and services. Our customers’ inability to pay for any reason could also result in their default on our current contracts and charters. The decline in the amount of services requested by our customers or their default on our contracts with them could have a material adverse effect on our business, financial condition and results of operations.

A complete LNG project includes production, liquefaction, regasification, storage and distribution facilities and LNG carriers. Existing LNG projects and infrastructure are limited, and new or expanded LNG projects are highly complex and capital-intensive, with new projects often costing several billion dollars. Many factors could negatively affect continued development of LNG infrastructure or disrupt the supply of LNG, including:

If the LNG supply chain is disrupted or does not continue to grow, or if a significant LNG explosion, spill or similar incident occurs, it could have a material adverse effect on our business, results of operations and financial condition and our ability to make cash ~~distributions.~~

distributions to unitholders.

One of our principal objectives is to enter into additional long-term, fixed-rate LNG, LPG and oil charters. The process of obtaining new long-term charters is highly competitive and generally involves an intensive screening process and competitive bids, and often extends for several months. Shipping contracts are awarded based upon a variety of factors relating to the vessel operator, including:

We compete for providing marine transportation services for potential energy projects with a number of experienced companies, including state-sponsored entities and major energy companies affiliated with the energy project requiring energy shipping services. Many of these competitors have significantly greater financial resources than we do or Teekay Corporation does. We anticipate that an increasing number of marine transportation companies – including many with strong reputations and extensive resources and experience – will enter the energy transportation sector. This increased competition may cause greater price competition for time-charters. As a result of these factors, we may be unable to expand our relationships with existing customers or to obtain new customers on a profitable basis, if at all, which would have a material adverse effect on our business, results of operations and financial condition and our ability to make cash ~~distributions.~~

distributions to unitholders.

The delivery of newbuildings or vessel conversions or upgrades we may order or undertake or otherwise acquire, could be delayed, which would delay our receipt of revenues under the charters for the vessels. In addition, under some of our charters if delivery of a vessel to our customer is delayed, we may be required to pay liquidated damages in amounts equal to or, under some charters, almost double, the hire rate during the delay. For prolonged delays, the customer may terminate the time-charter and, in addition to the resulting loss of revenues, we may be responsible for additional, substantial liquidated damages.

Our receipt of newbuildings or of vessel conversions or upgrades could be delayed because of:

If delivery of a vessel is materially delayed, it could adversely affect our results or operations and financial condition and our ability to make cash ~~distributions.~~

~~We may be unable~~distributions to ~~secure charters for our LNG newbuildings before their scheduled deliveries.~~

Between July 2013 and February 2015, we entered into agreements with DSME for the construction of nine LNG newbuildings that are expected to deliver between 2016 and 2018 (with the option to order up to four additional vessels). However, we have not entered into time charter contracts for two of the LNG newbuildings. The process of obtaining new charters is highly competitive. Consequently, we may be unable to secure charters for these or other newbuildings we may order before their scheduled delivery, if at all, which could harm our business, results of operations and financial condition and our ability to make cash distributions.

unitholders.

LNG shipping historically has been transacted with long-term, fixed-rate time-charters, usually with terms ranging from 20 to 25 years. One of our principal strategies is to enter into additional long-term, fixed-rate LNG time-charters. In recent years, the number of spot, short-term and medium-term LNG charters of under four years has been increasing. In ~~2013,~~2016, they accounted for approximately ~~27%~~28% of global LNG trade.

If an active spot, short-term or medium-term market continues to develop, we may have increased difficulty entering into long-term, fixed-rate time-charters for our LNG carriers and, as a result, our cash flow may decrease and be less stable. In addition, an active short-term, medium-term or spot LNG market may require us to enter into charters based on changing market prices, as opposed to contracts based on a fixed rate, which could result in a decrease in our cash flow in periods when the market price for shipping LNG is depressed.

Vessel values for LNG and LPG carriers and conventional tankers can fluctuate substantially over time due to a number of different factors, including:

Vessel values may decline from existing levels. If the operation of a ~~charter terminates,~~vessel is not profitable, or if we ~~may be unable to redeploy the~~cannot re-deploy a vessel at attractive rates ~~and,~~upon termination of its contract, rather than continue to incur costs to maintain and finance ~~it,~~the vessel, we may seek to dispose of it. Our inability to dispose of the vessel at a reasonable value could result in a loss on its sale and adversely affect our results of operations and financial condition.

Further, if we determine at any time that a vessel’s future useful life and earnings require us to impair its value on our financial statements, we may need to recognize a significant charge against our earnings.

The charter hire rates and the value and operational life of a vessel are determined by a number of factors, including the vessel’s efficiency, operational flexibility and physical life. Efficiency includes speed, fuel economy and the ability for LNG or LPG to be loaded and unloaded quickly. More efficient vessel designs, engines or other features may increase efficiency. Flexibility includes the ability to access LNG and LPG storage facilities, utilize related docking facilities and pass through canals and straits. Physical life is related to the original design and construction, maintenance and the impact of the stress of operations. If new LNG or LPG carriers are built that are more efficient or flexible or have longer physical lives than our vessels, competition from these more technologically advanced LNG or LPG carriers could reduce recharter rates available to our vessels and the resale value of the vessels. As a result, our business, results of operations and financial condition could be harmed.

We are investing in technology upgrades such as MEGI twin engines for certain LNG carrier newbuildings. These new engine designs may not perform to ~~specifications~~expectations which may result in performance issues or claims based on charter party agreements.

We are modifying one of our LNG carrier newbuildings into a FSU to service a LNG regasification and receiving terminal in Bahrain in which we will have a 30% ownership interest, please read “Item 18 – Financial Statements: Note 6a (i) – Equity Accounted Investments.” We may be unable to operate the FSU efficiently, which may result in performance issues or claims based on charter party agreements. In addition, we or our joint venture partners may be unable to operate a LNG receiving and regasification terminal properly, which could reduce the expected output of this terminal. As a result, our business, results of operations and financial condition could be harmed.

Adverse effects upon the oil and gas industry relating to climate change may also adversely affect demand for our services. Although we do not expect that demand for oil and gas will lessen dramatically over the short term, in the long term climate change may reduce the demand for oil and gas or increased regulation of greenhouse gases may create greater incentives for use of alternative energy sources. Any long-

term material adverse effect on the oil and gas industry could have a significant financial and operational adverse impact on our business that we cannot predict with certainty at this time.

Our growth strategy includes selectively acquiring existing LNG and LPG carriers or LNG and LPG shipping businesses. Historically, there have been very few purchases of existing vessels and businesses in the LNG and LPG shipping industries. Factors that may contribute to a limited number of acquisition opportunities in the LNG and LPG industries in the near term include the relatively small number of independent LNG and LPG fleet owners and the limited number of LNG and LPG carriers not subject to existing long-term charter contracts. In addition, competition from other companies could reduce our acquisition opportunities or cause us to pay higher prices.

Any acquisition of a vessel or business may not be profitable to us at or after the time we acquire it and may not generate cash flow sufficient to justify our investment. In addition, our acquisition growth strategy exposes us to risks that may harm our business, financial condition and operating results, including risks that we may:

Unlike newbuildings, existing vessels typically do not carry warranties as to their condition. While we generally inspect existing vessels prior to purchase, such an inspection would normally not provide us with as much knowledge of a vessel’s condition as we would possess if it had been built for us and operated by us during its life. Repairs and maintenance costs for existing vessels are difficult to predict and may be substantially higher than for vessels we have operated since they were built. These costs could decrease our cash flow and reduce our liquidity.

Our vessels and their cargoes are at risk of being damaged or lost because of events such as:

An accident involving any of our vessels could result in any of the following:

The operation of LNG and LPG carriers and oil tankers is inherently risky. Although we carry hull and machinery (marine and war risks) and protection and indemnity insurance, all risks may not be adequately insured against, and any particular claim may not be paid. In addition, only certain of our LNG carriers carry insurance covering the loss of revenues resulting from vessel off-hire time based on its cost compared to our off-hire experience. Any significant off-hire time of our vessels could harm our business, operating results and financial condition. Any claims covered by insurance would be subject to deductibles, and since it is possible that a large number of claims may be brought, the aggregate amount of these deductibles could be material. Certain of our insurance coverage is maintained through mutual protection and indemnity associations, and as a member of such associations we may be required to make additional payments over and above budgeted premiums if member claims exceed association reserves.

We may be unable to procure adequate insurance coverage at commercially reasonable rates in the future. For example, more stringent environmental regulations have led in the past to increased costs for, and in the future may result in the lack of availability of, insurance against risks of environmental damage or pollution. A catastrophic oil spill, marine disaster or natural disasters could result in losses that exceed our insurance coverage, which could harm our business, financial condition and operating results. Any uninsured or underinsured loss could harm our business and financial condition. In addition, our insurance may be voidable by the insurers as a result of certain of our actions, such as our ships failing to maintain certification with applicable maritime regulatory organizations.

Changes in the insurance markets attributable to terrorist attacks or political change may also make certain types of insurance more difficult for us to obtain. In addition, the insurance that may be available may be significantly more expensive than our existing coverage.

Because our operations, and the operations of certain of our customers, are primarily conducted outside of the United States, they may be affected by economic, political and governmental conditions in the countries where we and they engage in business. Any disruption caused by these factors could harm our business or the business of these customers, including by reducing the levels of oil and gas exploration, development and production activities in these areas. We derive some of our revenues from shipping oil, LNG and LPG from politically and economically unstable regions, such as Angola and Yemen. Hostilities, strikes, or other political or economic instability in regions where we or these customers operate or where we or they may operate could have a material adverse effect on the growth of our business, results of operations and financial condition and ability to make cash distributions, or on the ability of these customers to make payments or otherwise perform their obligations to us. In addition, tariffs, trade embargoes and other economic sanctions by the United States or other countries against countries in which we operate or to which we trade may harm our business and ability to make cash distributions and a government could requisition one or more of our vessels, which is most likely during war or national emergency. Any such requisition would cause a loss of the vessel and could harm our cash flow and financial results.

Terrorist attacks, piracy, ~~and~~ the current conflicts in the Middle East, ~~and~~ other current and future conflicts and political change, may adversely affect our business, operating results, financial condition, ability to raise capital and future growth. Continuing hostilities in the Middle East may lead to additional armed conflicts or to further acts of terrorism and civil disturbance in the United States, or elsewhere, which may contribute to economic instability and disruption of LNG, LPG and oil production and distribution, which could result in reduced demand for our ~~services.~~

services or impact on our operations and or our ability to conduct business.

In addition, LNG, LPG and oil facilities, shipyards, vessels, pipelines and oil and gas fields could be targets of future terrorist attacks and warlike operations and our vessels could be targets of pirates, hijackers, terrorists or ~~hijackers.~~warlike operations. Any such attacks could lead to, among other things, bodily injury or loss of life, vessel or other property damage, increased vessel operational costs, including insurance costs, and the inability to transport LNG, LPG and oil to or from certain locations. Terrorist attacks, war, piracy, hijacking or other events beyond our control that adversely affect the distribution, production or transportation of LNG, LPG or oil to be shipped by us could entitle our customers to terminate our charter contracts, which would harm our cash flow and our business.

Terrorist attacks, or the perception that LNG or LPG facilities and carriers are potential terrorist targets, could materially and adversely affect expansion of LNG and LPG infrastructure and the continued supply of LNG and LPG to the United States and other countries. Concern that LNG or LPG facilities may be targeted for attack by terrorists has contributed to significant community and environmental resistance to the construction of a number of LNG or LPG facilities, primarily in North America. If a terrorist incident involving ana LNG or LPG facility or LNG or

LPG carrier did occur, in addition to the possible effects identified in the previous paragraph, the incident may adversely affect construction of additional LNG or LPG facilities in the United States and other countries or lead to the temporary or permanent closing of various LNG or LPG facilities currently in operation.

Acts of piracy have historically affected ocean-going vessels trading in regions of the world such as the South China Sea, Gulf of Guinea and the Indian Ocean off the coast of Somalia. While there ~~continue~~continues to be a significant ~~numbers~~risk of piracy ~~incidents~~ in the Gulf of Aden and Indian Ocean, recently there have been increases in the frequency and severity of piracy incidents off the coast of West ~~Africa.~~Africa and a resurgent piracy risk in the Straits of Malacca and surrounding waters. If these piracy attacks result in regions in which our vessels are deployed being named on the Joint War Committee Listed Areas, war risk insurance premiums payable for such coverage can increase significantly and such insurance coverage may be more difficult to obtain. In addition, crew costs, including costs which may be incurred to the extent we employ on-board armed security guards and escort vessels, could increase in such circumstances. 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 and results of operations.

~~Our substantial operations outside the United States expose us to political, governmental and economic instability, which could harm our operations.~~

Because our operations are primarily conducted outside of the United States, they may be affected by economic, political and governmental conditions in the countries where we engage in business. Any disruption caused by these factors could harm our business, including by reducing the levels of oil and gas exploration, development and production activities in these areas. We derive some of our revenues from shipping oil, LNG and LPG from politically and economically unstable regions, such as Angola and Yemen. Hostilities, strikes, or other political or economic instability in regions where we operate or where we may operate could have a material adverse effect on the growth of our business, results of operations and financial condition and ability to make cash distributions. In addition, tariffs, trade embargoes and other economic sanctions by the United States or other countries against countries in which we operate or to which we trade may harm our business and ability to make cash distributions. Finally, a government could requisition one or more of our vessels, which is most likely during war or national emergency. Any such requisition would cause a loss of the vessel and could harm our cash flow and financial results.

The LNG carrier newbuildings ordered by the Yamal LNG Joint Venture, which are scheduled for delivery between 2018 and 2020, will be specifically built for the Arctic requirements of the Yamal LNG Project and will have limited redeployment opportunities to operate as conventional trading LNG carriers if the project is abandoned or cancelled. If the project is abandoned or cancelled for any reason, either before or after commencement of operations, the Yamal LNG Joint Venture may be unable to reach an agreement with the shipyard allowing for the termination of the shipbuilding contracts (since no such optional termination right exists under these contracts), change the vessel specifications to reflect those applicable to more conventional LNG carriers and which do not incorporate ice-breaking capabilities, or find suitable alternative employment for the newbuilding vessels on a long-term basis with other LNG projects or otherwise.

The Yamal LNG Project may be abandoned or not completed for various reasons, including, among others:

If the project is not completed or is abandoned, proceeds if any, received from limited Yamal LNG project sponsor guarantees and potential alternative employment, if any, of the vessels and from potential sales of components and scrapping of the vessels likely would fall substantially short of the cost of the vessels to the Yamal LNG Joint Venture. Any such shortfall could have a material adverse effect on our financial condition, results of operations and ability to make distributions ~~on our common units.~~

to unitholders.

The Yamal LNG Joint Venture does not yet have in place financing for the six ARC7 Ice-Class LNG carrier newbuildings that will service the Yamal LNG Project. The estimated total fully built-up cost for the vessels is approximately $2.1 billion. As of December 31, 2016, $306.6 million has been funded by us and China LNG based on our proportionate ownership interests in the Yamal LNG Joint Venture. If the Yamal LNG Joint Venture is unable to obtain debt financing for the vessels on acceptable terms, if at all, or if our joint venture partner fails to fund its portion of the newbuilding financing, we may be unable to purchase the vessels and participate in the Yamal LNG Project.

The charter party under the Yamal LNG Joint Venture’s time-charter contracts for the Yamal LNG Project is Yamal Trade Pte. Ltd., a wholly-owned subsidiary of Yamal LNG, the project’s sponsor. If the Yamal LNG Project does not achieve expected results, the risk of charter party default may increase. Any such default could adversely affect our results of operations and ability to make distributions on our common and preferred units. If the charter party defaults on the time-charter contracts, we may be unable to redeploy the vessels under other time-charter contracts or may be forced to scrap the vessels.

~~Neither the Yamal LNG Joint Venture nor our joint venture partner may be able to obtain financing for the six LNG carrier newbuildings for the Yamal LNG Project.~~

The Yamal LNG Joint Venture does not have in place financing for the six LNG carrier newbuildings that will service the Yamal LNG Project. The estimated total fully built-up cost for the vessels is approximately $2.1 billion. If the Yamal LNG Joint Venture is unable to obtain debt financing for the vessels on acceptable terms, if at all, or if our joint venture partner fails to fund its portion of the newbuilding financing, we may be unable to purchase the vessels and participate in the Yamal LNG Project.

Some of our vessels are chartered to unrated entities ~~such as the four LNG carriers chartered to Angola LNG Supply Services LLC~~ and ~~the two LNG carriers chartered to Yemen LNG Company Limited. Some~~some of these unrated entities will use revenue generated from the sale of the shipped gas to pay their shipping and other operating expenses, including the charter fees. The price of the gas may be subject to market fluctuations and the LNG supply may be curtailed by start-up delays and stoppages. If the revenue generated by the charterer is insufficient to pay the charter fees, we may be unable to realize the expected economic benefit from these charter agreements.

~~Marine transportation is inherently risky, and an incident involving significant loss of or environmental contamination by any of our vessels could harm our reputation and business.~~

~~Our vessels and their cargoes are at risk of being damaged or lost because of events such as:~~

Our operations are affected by extensive and changing international, national and local environmental protection laws, regulations, treaties and conventions in force in international waters, the jurisdictional waters of the countries in which our vessels operate, as well as the countries of our vessels’ registration, including those governing oil spills, discharges to air and water, and the handling and disposal of hazardous substances and wastes. Many of these requirements are designed to reduce the risk of oil spills and other pollution. In addition, we believe that the heightened environmental, quality and security concerns of insurance underwriters, regulators and charterers will lead to additional regulatory requirements, including enhanced risk assessment and security requirements and greater inspection and safety requirements on vessels. We expect to incur substantial expenses in complying with these laws and regulations, including expenses for vessel modifications and changes in operating procedures.

These requirements can affect the resale value or useful lives of our vessels, require a reduction in cargo capacity, ship modifications or operational changes or restrictions, lead to decreased availability of insurance coverage for environmental matters or result in the denial of access to certain jurisdictional waters or ports, or detention in certain ports. Under local, national and foreign laws, as well as international treaties and conventions, we could incur material liabilities, including cleanup obligations, in the event that there is a release of petroleum or other hazardous substances from our vessels or otherwise in connection with our operations. We could also become subject to personal injury or property damage claims relating to the release of or exposure to hazardous materials associated with our operations. In addition, failure to comply with applicable laws and regulations may result in administrative and civil penalties, criminal sanctions or the suspension or termination of our operations, including, in certain instances, seizure or detention of our vessels. For further information about regulations affecting our business and related requirements on us, please read “Item 4 – Information on the Partnership: C.B. Operations - Regulations.”

~~Climate change and greenhouse gas restrictions may adversely impact our operations and markets.~~

Due to concern over the risk of climate change, a number of countries have adopted, or are considering the adoption of, regulatory frameworks to reduce greenhouse gas emissions. These regulatory measures include, among others, adoption of cap and trade regimes, carbon taxes, increased efficiency standards, and incentives or mandates for renewable energy. Compliance with changes in laws, regulations and obligations relating to climate change could increase our costs related to operating and maintaining our vessels and require us to install new emission controls, acquire allowances or pay taxes related to our greenhouse gas emissions, or administer and manage a greenhouse gas emissions program. Revenue generation and strategic growth opportunities may also be adversely affected.

Adverse effects upon the oil and gas industry relating to climate change may also adversely affect demand for our services. Although we do not expect that demand for oil and gas will lessen dramatically over the short term, in the long term climate change may reduce the demand for oil and gas or increased regulation of greenhouse gases may create greater incentives for use of alternative energy sources. Any long-term material adverse effect on the oil and gas industry could have a significant financial and operational adverse impact on our business that we cannot predict with certainty at this time.

We are paid in Euros under some of our charters, and certain of our vessel operating expenses and general and administrative expenses currently are denominated in Euros, which is primarily a function of the nationality of our crew and administrative staff. We also make payments under two Euro-denominated term loans. If the amount of our Euro-denominated obligations exceeds our Euro-denominated revenues, we must convert other currencies, primarily the U.S. Dollar, into Euros. An increase in the strength of the Euro relative to the U.S. Dollar would require us to convert more U.S. Dollars to Euros to satisfy those obligations, which would cause us to have less cash available for ~~distribution.~~distribution to unitholders. In addition, if we do not have sufficient U.S. Dollars, we may be required to convert Euros into U.S. Dollars for distributions to unitholders. An increase in the strength of the U.S. Dollar relative to the Euro could cause us to have less cash available for distribution in this circumstance. We have not entered into currency swaps or forward contracts or similar derivatives to mitigate this risk.

Because we report our operating results in U.S. Dollars, changes in the value of the U.S. Dollar relative to the Euro and Norwegian Kroner also result in fluctuations in our reported revenues and earnings. In addition, under U.S. accounting guidelines, all foreign currency-denominated monetary assets and liabilities such as cash and cash equivalents, accounts receivable, restricted cash, accounts payable, accrued liabilities, unearned revenue, advances from affiliates and long-term debt, ~~and capital lease obligations,~~ are revalued and reported based on the prevailing exchange rate at the end

A significant portion of our seafarers, and the seafarers employed by Teekay Corporation and its other affiliates that crew some of our vessels, are employed under collective bargaining agreements. While some of our labor agreements have recently been renewed, crew compensation levels under future collective bargaining agreements may exceed existing compensation levels, which would adversely affect our results of operations and cash flows. We may be subject to labor disruptions in the future if our relationships deteriorate with our seafarers or the unions that represent them. Our collective bargaining agreements may not prevent labor disruptions, particularly when the agreements are being renegotiated. Any labor disruptions could harm our operations and could have a material adverse effect on our business, results of operations and financial condition and our ability to make cash ~~distributions.~~

distributions to unitholders.

Our success depends in large part on Teekay Corporation’s and certain of our joint venture partners’ ability to attract and retain highly skilled and qualified personnel. In crewing our vessels, we require technically skilled employees with specialized training who can perform physically demanding work. The ability to attract and retain qualified crew members under a competitive industry environment continues to put upward pressure on crew manning costs.

If we are not able to increase our charter rates to compensate for any crew cost increases, our financial condition and results of operations may be adversely affected. Any inability we experience in the future to hire, train and retain a sufficient number of qualified employees could impair our ability to manage, maintain and grow our business.

We rely exclusively on the cash flow generated from our LNG and LPG carriers and conventional oil tankers that operate in the LNG, LPG and oil marine transportation business. Due to our lack of diversification, an adverse development in the LNG, LPG or oil shipping industry would have a significantly greater impact on our financial condition and results of operations than if we maintained more diverse assets or lines of business.

If we decline the offer to purchase the LNG carriers and time-charters described above, Teekay Corporation or Teekay Offshore may own and operate the LNG carriers, but may not expand that portion of its business.

In addition, pursuant to the omnibus agreement, Teekay Corporation, Teekay Offshore or any of their respective controlled affiliates (other than us and our subsidiaries) may:

If there is a change of control of Teekay Corporation or Teekay Offshore, the non-competition provisions of the omnibus agreement may terminate, which termination could have a material adverse effect on our business, results of operations and financial condition and our ability to make cash ~~distributions.~~

distributions to unitholders.

Teekay Corporation, which owns and controls our General Partner, indirectly owns our 2% ~~General Partner~~general partner interest and as at December 31, ~~2014~~2016 owned 31.7% of our common units. Although our General Partner has a ~~32.2% limited partner interest~~fiduciary duty to manage us in ~~us.~~a manner beneficial to us and our unitholders, the directors and officers of our General Partner have a fiduciary duty to manage our General Partner in a manner beneficial to Teekay Corporation. Furthermore, certain directors and officers of our General Partner are directors or officers of affiliates of our General Partner. Conflicts of interest may arise between Teekay Corporation and its affiliates, including our General Partner, on the one hand, and us and our unitholders, on the other hand. As a result of these conflicts, our General Partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. These conflicts include, among others, the following situations:

Our General Partner’s officers and directors have fiduciary duties to manage our business in a manner beneficial to us and our partners. Our General Partner has a Corporate Secretary but does not have a Chief Executive Officer or a Chief Financial Officer. The Corporate Secretary and all of the non-independent directors of our General Partner also serve as officers, management or directors of Teekay Corporation and/or other affiliates of Teekay Corporation. Consequently, these officers and directors may encounter situations in which their fiduciary obligations to Teekay Corporation or its other affiliates, on one hand, and us, on the other hand, are in conflict. The resolution of these conflicts may not always be in the best interest of us or our unitholders.

We and certain of our joint ventures are party and were party to lease arrangements whereby the lessor could claim tax depreciation on the capital expenditures it incurred to acquire these ~~vessels.~~vessels subject to the lease arrangements. As is typical in these leasing arrangements, tax and change of law risks are assumed by the lessee. The rentals payable under the lease arrangements are predicated on the basis of certain

tax and financial assumptions at the commencement of the leases. If an assumption proves to be incorrect or there is a change in the applicable tax legislation or the interpretation thereof by the United Kingdom ~~(U.K.)~~(or UK) taxing authority, the lessor is entitled to increase the rentals so as to maintain its agreed after-tax margin. Under the capital lease arrangements, we do not have the ability to pass these increased rentals onto our charter party. However, the terms of the lease arrangements enable us and our joint venture partner to jointly terminate the lease arrangement on a voluntary basis at any time. In the event of an early termination of the lease arrangements, the joint venture is obliged to pay termination sums to the lessor sufficient to repay its investment in the vessels and to compensate it for the tax effect of the terminations, including recapture of tax depreciation, if any.

In addition, the subsidiaries of another joint venture formed to service the Tangguh LNG project in Indonesia have lease arrangements with a third party for two LNG carriers. The terms of the lease arrangements provide similar tax and change of law risk assumption by this joint venture as we ~~had~~have with the three RasGas II LNG Carriers.

For financial or strategic reasons, we conduct a portion of our business through joint ventures. Generally, we are obligated to provide proportionate financial support for the joint ventures although our control of the business entity may be substantially limited. Due to this limited control, we generally have less flexibility to pursue our own objectives through joint ventures or to access available cash of the joint ventures than we would with our own subsidiaries. There is no assurance that our joint venture partners will continue their relationships with us in the future or that we will be able to achieve our financial or strategic objectives relating to the joint ventures and the markets in which they operate. In addition, our joint venture partners may have business objectives that are inconsistent with ours, experience financial and other difficulties that may affect the success of the joint venture, or be unable or unwilling to fulfill their obligations under the joint ventures, which may affect our financial condition or results of operations.

In addition to the following risk factors, you should read “Item 10. Additional Information — Taxation” for a more complete discussion of the expected material U.S. federal and non-U.S. income tax considerations relating to us and the ownership and disposition of our units.

U.S. citizens, residents or other U.S. taxpayers will be required to pay U.S. federal income taxes and, in some cases, U.S. state and local income taxes on their share of our taxable income, whether or not they receive cash distributions from us. U.S. ~~common~~ unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from their share of our taxable income.

If common unitholders sell their common units, they will recognize gain or loss for U.S. federal income tax purposes that is equal to the difference between the amount realized and their tax basis in those common units. Prior distributions in excess of the total net taxable income allocated decrease a common unitholder’s tax basis and will, in effect, become taxable income if common units are sold at a price greater than their tax basis, even if the price received is less than the original cost. Assuming we are not treated as a corporation for U.S. federal

income tax purposes, a substantial portion of the amount realized on a sale of common units, whether or not representing gain, may be ordinary income.

The decision of the United States Court of Appeals for the Fifth Circuit in Tidewater Inc. v. United States creates some uncertainty as to whether we will be classified as a partnership for U.S. federal income tax purposes.

In order for us to be classified as a partnership for U.S. federal income tax purposes, more than 90 percent of our gross income each year must be “qualifying income” under Section 7704 of the U.S. Internal Revenue Code of 1986, as amended (the~~Code~~). For this purpose, “qualifying income” includes income from providing marine transportation services to customers with respect to crude oil, natural gas and certain products thereof but does not include rental income from leasing vessels to customers.

~~The decision of the United States Court of Appeals for the Fifth Circuit in~~~~Tidewater Inc. v. United States,~~565 F.3d 299 (5th Cir. 2009) held that income derived from certain time chartering activities should be treated as rental income rather than service income for purposes of a foreign sales corporation provision of the Code. However, the Internal Revenue Service (or~~IRS) stated in an Action on Decision (AOD 2010-001) that it disagrees with, and will not acquiesce to, the way that the rental versus services framework was applied to the facts in the~~~~Tidewater~~~~decision, and in its discussion stated that the time charters at issue in~~~~Tidewater~~~~would be treated as producing services income for purposes of the passive foreign investment company provisions of the Code. The IRS’s statement with respect to~~~~Tidewater~~cannot be relied upon or otherwise cited as precedent by taxpayers. Consequently, in the absence of any binding legal authority specifically relating to the statutory provisions governing “qualifying income” under Section 7704 of the Code, there can be no assurance that the IRS or a court would not follow the~~Tidewater~~decision in interpreting the “qualifying income” provisions under Section 7704 of the Code. Nevertheless, we intend to take the position that our time charter income is “qualifying income” within the meaning of Section 7704 of the Code. No assurance can be given, however, that the IRS, or a court of law, will accept our position. As such, there is some uncertainty regarding the status of our time charter income as “qualifying income” and therefore some uncertainty as to whether we will be classified as a partnership for federal income tax purposes. Please read “Item 10 – Additional Information: Taxation – United States Tax Consequences – Classification as a Partnership.”

The anticipated after-tax benefit of an investment in common units may be reduced if we are not treated as a partnership for U.S. federal income tax purposes. If we are not treated as a partnership for U.S. federal income tax purposes, we would be treated as a corporation for such purposes, and common unitholders could suffer material adverse tax or economic consequences, including the following:

Please read “Item 10 – Additional Information: Taxation – United States Tax Consequences –— Possible Classification as a Corporation.”

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our units may be modified by administrative, legislative or judicial interpretation at any time. For example, members of Congress propose and consider substantive changes to the existing U.S. federal income tax laws that affect publicly traded partnerships. Further, on January 24, 2017, the U.S. Treasury Department and the IRS published in the Federal Register final regulations effective as of January 19, 2017 interpreting the scope of activities that generate qualifying income under Section 7704 of the Code. We believe that the income we currently treat as qualifying income satisfies the requirements for qualifying income under the final regulations. However, the impact on the final regulations of a regulatory freeze imposed by the income administration in a January 20, 2017 White House memorandum is not immediately clear. Should the final regulations be withdrawn or otherwise deemed inapplicable, we would need to rely on other guidance to determine if we satisfy the qualifying income exception and there could be some uncertainty as to whether we would be classified as a partnership for U.S. federal income tax purposes. Any modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any such changes could negatively impact the amount of cash available for distribution to our unitholders and the value of an investment in our units.

The IRS may contest the U.S. federal income tax positions we take and there is no assurance that our tax positions would be sustained by a court. Any contest with the IRS may materially and adversely affect the value of our units. In addition, the costs of any contest with the IRS will be borne by us reducing the cash available for distribution to our unitholders.

For taxable years beginning after December 31, 2017 the procedures for auditing large partnerships and for assessing and collecting taxes due (including applicable penalties and interest) as a result of a partnership audit have been changed. Unless we are eligible to (and choose to) elect to issue revised Schedules K-1 to our partners with respect to an audited and adjusted return, the IRS may assess and collect taxes (including any applicable penalties and interest) directly from us in the year in which the audit is completed under the new rules. If we are required to pay taxes, penalties and interest as the result of audit adjustments, cash available for distribution to our unitholders may be substantially reduced. In addition, because payment would be due for the taxable year in which the audit is completed, unitholders during that taxable year would bear the expense of the adjustment even if they were not unitholders during the audited taxable year.

We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our common units on the first business day of each month, instead of on the basis of the date a particular unit is transferred. Treasury Regulations allow a similar monthly simplifying convention starting with our taxable years beginning January 1, 2016. However, such regulations do not specifically authorize all aspects of the proration method we have adopted. If the IRS were to challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our common unitholders.

Investments in ~~common~~ units by U.S. tax-exempt entities, including individual retirement accounts (known as~~IRAs~~) IRAs), other ~~retirements~~retirement plans and non-U.S. persons raise issues unique to them. Assuming we are classified as a partnership for U.S. federal income tax purposes, virtually all of our income allocated to organizations exempt from U.S. federal income tax will be unrelated business taxable income and generally will be subject to U.S. federal income tax. In addition, non-U.S. persons may be subject to a 4 percent U.S. federal income tax on the U.S. source portion of our gross income attributable to transportation that begins or ends (but not both) in the United States, or distributions to them may be reduced on account of withholding of U.S. federal income tax by us in the event we are treated as having a fixed place of business in the United States or otherwise earn U.S. effectively connected income, unless an exemption applies and they file U.S. federal income tax returns to claim such exemption.

Furthermore, the U.S. federal income tax consequences to U.S. tax-exempt entities and non-U.S. persons with respect to an investment in our Series A preferred units is uncertain. Please read "Item 10 — Additional Information: Taxation — United States Tax Consequences — Tax-Exempt Organizations and Non-U.S. Investors."

We will be considered to have been terminated for U.S. federal income tax purposes if there is a sale or exchange of 50 percent or more of the total interests in our capital or profits within any 12-month period. Our termination would, among other things, result in the closing of our taxable year for all unitholders and could result in a deferral of depreciation deductions allowable in computing our taxable income. Please read “Item 10 – Additional Information: Taxation – United States Tax Consequences –— Disposition of Common Units –— Constructive Termination.”

In addition, if we are not treated as a partnership for U.S. federal income tax purposes, we expect that we also would fail to qualify for the Section 883 Exemption ~~in subsequent tax years~~ and that any resulting imposition of U.S. federal income taxes would result in decreased cash available for distribution to ~~common~~ unitholders.

A unitholder’s taxable income or loss with respect to a common unit each year will depend upon a number of factors, including the nature and fair market value of our assets at the time the holder acquired the common unit, whether we issue additional units or whether we engage in certain other transactions, and the manner in which our items of income, gain, loss and deduction are allocated among our partners. For this purpose, we determine the value of our assets and the relative amounts of our items of income, gain, loss and deduction allocable to our common unitholders and our ~~general partner~~General Partner as holder of the incentive distribution rights by reference to the value of our interests, including the incentive distribution rights. The IRS may challenge any valuation determinations that we make, particularly as to the incentive distribution rights, for which there is no public market. In addition, the IRS could challenge certain other aspects of the manner in which we determine the relative allocations made to our common unitholders and to the ~~general partner~~General Partner as holder of our incentive distribution rights. A successful IRS challenge to our valuation or allocation methods could increase the amount of net taxable income and gain realized by a common unitholder with respect to a common unit. The IRS could also challenge certain other tax positions that we have taken, including our position that certain of our subsidiaries that have been classified as corporations for U.S. federal income tax purposes in past years are not PFICs for federal income tax purposes. Any such IRS challenges, whether or not successful, could adversely affect the value of our common units.

~~Common unitholders~~

Unitholders may ~~be imposed upon common unitholders as a result of owning our common units. However, there is a risk that common unitholders will~~ be subject to tax in one or more countries, including Canada, as a result of owning our ~~common~~ units if, under the laws of any such country, we are considered to be carrying on business there. If ~~common~~ unitholders are subject to tax in any such country, ~~common~~ unitholders may be required to file a tax return with, and pay taxes to, that country based on their allocable share of our income. We may be required to reduce distributions to ~~common~~ unitholders on account of any withholding obligations imposed upon us by that country in respect of such allocation to ~~common~~ unitholders. The United States may not allow a tax credit for any foreign income taxes that ~~common~~ unitholders directly or indirectly incur. Any foreign taxes imposed on us or any of our subsidiaries will reduce our cash available for ~~common~~ unitholders.

Teekay LNG Partners L.P. is an international provider of marine transportation services for LNG, LPG and crude oil. We were formed in 2004 by Teekay Corporation (NYSE: TK), a portfolio manager of marine services to the global oil and natural gas industries, to expand its operations in the LNG shipping sector. Our primary growth strategy focuses on expanding our fleet of LNG and LPG carriers under long-term, fixed-rate charters. In executing our growth strategy, we may engage in vessel or business acquisitions or enter into joint ventures and partnerships with companies that ~~may~~ provide increased access to emerging opportunities from global expansion of the LNG and LPG sectors. We seek to leverage the expertise, relationships and reputation of Teekay Corporation and its affiliates to pursue these opportunities in the LNG and LPG sectors and may consider other opportunities to which our competitive strengths are well suited. Although we may acquire additional crude oil tankers from time to time, we view our conventional tanker fleet primarily as a source of stable cash flow as we seek to continue to expand our LNG and LPG operations.

Please see “Item 5 – Operating and Financial Review and Prospects: Management’s Discussion and Analysis of Financial Condition and Results of Operations – Significant Developments in ~~2014~~2016 and Early ~~2015.~~2017.”

As of December 31, ~~2014,~~2016, our fleet, excluding newbuildings, consisted of 2931 LNG carriers (including the six MALT LNG Carriers, four RasGas 3 LNG Carriers, four Angola LNG Carriers, and two Exmar LNG Carriers that are all accounted for under the equity method), 2125 LPG carriers (including the 1519 Exmar LPG Carriers that are accounted for under the equity method), ~~seven~~five Suezmax-class crude oil tankers, and one Handymax product tanker, all of which are double-hulled. Our fleet is relatively young ~~with~~and has an average age of approximately ~~seven~~nine years for our LNG carriers, approximately nine years for our LPG ~~Carriers~~carriers and approximately ~~nine~~12 years for our conventional tankers (Suezmax and Handymax), compared to world averages of ~~10, 16~~11, 15 and nine years, respectively, as of December 31, ~~2014.~~

2016.

We were formed under the laws of the Republic of The Marshall Islands as a limited partnership, Teekay LNG Partners L.P., on November 3, 2004, and maintain our principal executive ~~headquarters~~offices at 4^th4th Floor, Belvedere Building, 69 Pitts Bay Road, Hamilton, HM 08, Bermuda. Our telephone number at such address is (441) 298-2530.

We generate revenues by charging customers for the transportation of their LNG, LPG and crude oil using our vessels. The majority of these services are provided through either a time-charter or bareboat charter contract, where vessels are chartered to customers for a fixed period of time at rates that are generally fixed but may contain a variable component based on inflation, interest rates or current market rates.

Our vessels and our regasification terminal under construction in Bahrain primarily operate under ~~long-term,~~ fixed-rate ~~charters~~contracts with major energy and utility companies and Teekay Corporation. ~~The~~As of December 31, 2016, the average remaining term for these ~~charters~~contracts, including assets under construction, is approximately 1213 years for our LNG carriers and regasification terminal, approximately five years for our LPG carriers and approximately ~~three years~~one year for our conventional tankers (Suezmax and Handymax), subject, in certain circumstances, to termination or vessel purchase rights.

“Hire” rate refers to the basic payment from the customer for the use of a vessel. Hire is payable monthly, in advance, in U.S. Dollars or Euros, as specified in the charter. The hire rate generally includes two components – a capital cost component and an operating expense component. The capital component typically approximates the amount we are required to pay under vessel financing obligations and, for two of our conventional tankers, adjusts for changes in the floating interest rates relating to the underlying vessel financing. The operating component, which adjusts annually for inflation, is intended to compensate us for vessel operating expenses.

In addition, we may receive additional revenues beyond the fixed hire rate when current market rates exceed specified amounts under our time-charter contracts for two of our Suezmax tankers.

Hire payments may be reduced or, under some charters, we must pay liquidated damages, if the vessel does not perform to certain of its specifications, such as if the average vessel speed falls below a guaranteed speed or the amount of fuel consumed to power the vessel under normal circumstances exceeds a guaranteed amount. ~~Historically, we have had few instances of hire rate reductions, and only one in our joint venture with Exmar, that had a material impact on our operating results in prior years.~~

When a vessel is “off-hire” – or not available for service – the customer generally is not required to pay the hire rate and we are responsible for all costs. Prolonged off-hire may lead to vessel substitution or termination of the time-charter. A vessel will typically be deemed to be off-hire if it is in dry ~~dock.~~dock unless our contract specifies drydocking is not considered off-hire. We must periodically dry dock each of our vessels for inspection, repairs and maintenance and any modifications to comply with industry certification or governmental requirements. In addition, a vessel generally will be deemed off-hire if there is a loss of time due to, among other things: operational deficiencies; equipment breakdowns; delays due to accidents, crewing strikes, certain vessel detentions or similar problems; or our failure to maintain the vessel in compliance with its specifications and contractual standards or to provide the required crew.

The LNG carriers in our liquefied gas segment compete in the LNG market. LNG carriers are usually chartered to carry LNG pursuant to time-charter contracts, where a vessel is hired for a fixed period of time and the charter rate is payable to the owner on a monthly basis. LNG shipping historically has been transacted with long-term, fixed-rate time-charter contracts. LNG projects require significant capital expenditures and typically involve an integrated chain of dedicated facilities and cooperative activities. Accordingly, the overall success of an LNG project depends heavily on long-range planning and coordination of project activities, including marine transportation. Most shipping requirements for new LNG projects continue to be provided on a long-term basis, though the levels of spot voyages (typically consisting of a single voyage), short-term time-charters and medium-term time-charters have grown in the past few years.

The amount of LNG traded on a spot and short-term basis (defined as contracts with a duration of 4 years or less) has increased from approximately 19% of total LNG trade in 2010 to 28% in 2016.

In the LNG market, we compete principally with other private and state-controlled energy and utilities companies that generally operate captive fleets, and independent ship owners and operators. Many major energy companies compete directly with independent owners by transporting LNG for third parties in addition to their own LNG. Given the complex, long-term nature of LNG projects, major energy companies historically have transported LNG through their captive fleets. However, independent fleet operators have been obtaining an increasing percentage of charters for new or expanded LNG projects as some major energy companies have continued to divest non-core businesses.

The following table provides additional information about our LNG carriers as of December 31, ~~2014,~~2016, excluding our 1819 newbuildings scheduled for delivery between ~~2016~~2017 and 2020 in which our ownership ~~interest ranges~~interests range from 20% to 100%:

Vessel
   Capacity
Delivery
Our
Ownership
Charterer

Expiration of
Charter⁽¹⁾
   (cubic meters)
Operating LNG carriers:


Consolidated

Hispania Spirit
   137,814 2002 100 % Shell Spain LNG S.A.U. Sep. 2022⁽²⁾
Catalunya Spirit
   135,423 2003 100 % Gas Natural SDG Aug. 2023⁽²⁾
Galicia Spirit
   137,814 2004 100 % Uniòn Fenosa Gas Jun. 2029⁽³⁾
Madrid Spirit
   135,423 2004 100 % Shell Spain LNG S.A.U. Dec. 2024⁽²⁾
   Ras Laffan Liquefied
Al Marrouna
   149,539 2006 70 % Natural Gas Company Ltd. Oct. 2026⁽⁴⁾
   Ras Laffan Liquefied
Al Areesh
   148,786 2007 70 % Natural Gas Company Ltd. Jan. 2027⁽⁴⁾
   Ras Laffan Liquefied
Al Daayen
   148,853 2007 70 % Natural Gas Company Ltd. Apr. 2027⁽⁴⁾
   The Tangguh Production
Tangguh Hiri
   151,885 2008 69 % Sharing Contractors Jan. 2029
   The Tangguh Production
Tangguh Sago
   155,000 2009 69 % Sharing Contractors May 2029
Arctic Spirit
   87,305 1993 99 % Teekay Corporation Apr. 2018⁽⁴⁾
Polar Spirit
   87,305 1993 99 % Teekay Corporation Apr. 2018⁽⁴⁾
Wilforce
   155,900 2013 99 % Awilco LNG ASA Sep. 2018⁽⁵⁾
Wilpride
   155,900 2013 99 % Awilco LNG ASA Nov. 2017⁽⁵⁾
Equity Accounted

   Ras Laffan Liquefied
Al Huwaila
   214,176 2008 40 %⁽⁸⁾ Natural Gas Company Ltd. Apr. 2033⁽²⁾
   Ras Laffan Liquefied
Al Kharsaah
   214,198 2008 40 %⁽⁸⁾ Natural Gas Company Ltd. Apr. 2033⁽²⁾
   Ras Laffan Liquefied
Al Shamal
   213,536 2008 40 %⁽⁸⁾ Natural Gas Company Ltd. May 2033⁽²⁾
   Ras Laffan Liquefied
Al Khuwair
   213,101 2008 40 %⁽⁸⁾ Natural Gas Company Ltd. Jun. 2033⁽²⁾
Excelsior
   138,087 2005 50 %⁽⁹⁾ Excelerate Energy LP Jan. 2025⁽²⁾
Excalibur
   138,034 2002 50 %⁽⁹⁾ Excelerate Energy LP Mar. 2022
Soyo
   160,400 2011 33 %⁽¹⁰⁾ Angola LNG Supply Services LLC Aug. 2031⁽²⁾
Malanje
   160,400 2011 33 %⁽¹⁰⁾ Angola LNG Supply Services LLC Sep. 2031⁽²⁾
Lobito
   160,400 2011 33 %⁽¹⁰⁾ Angola LNG Supply Services LLC Oct. 2031⁽²⁾
Cubal
   160,400 2012 33 %⁽¹⁰⁾ Angola LNG Supply Services LLC Jan. 2032⁽²⁾
Meridian Spirit
   165,700 2010 52 %⁽¹¹⁾ Total E&P Norge AS Mansel Limited Nov. 2030⁽⁶⁾
Magellan Spirit
   165,700 2009 52 %⁽¹¹⁾ Vitol S.A. Sep. 2016⁽¹³⁾
Marib Spirit
   165,500 2008 52 %⁽¹¹⁾ Yemen LNG Company Limited Mar. 2029⁽⁶⁾
Arwa Spirit
   165,500 2008 52 %⁽¹¹⁾ Yemen LNG Company Limited Apr. 2029⁽⁶⁾
Methane Spirit
   165,500 2008 52 %⁽¹¹⁾ BP Shipping Limited Mar. 2015⁽⁷⁾
Woodside Donaldson
   165,500 2009 52 %⁽¹¹⁾ Pluto LNG Party Limited Jun. 2026⁽¹²⁾


Total Capacity:
4,553,079

, of which one LNG carrier newbuilding was delivered in February 2017:

The following table presents the percentage of our consolidated voyage revenues from LNG customers that accounted for more than 10% of our consolidated voyage revenues during ~~2014, 2013~~2016, 2015 and ~~2012.~~

   Year Ended December 31,
   2014 2013 2012
Ras Laffan Liquefied Natural Gas Company Ltd.
   17 % 17 % 18 %
Shell Spain LNG S.A.U.⁽¹⁾
   13 % 13 % 13 %
The Tangguh Production Sharing Contractors
   11 % 12 % 12 %

2014.

No other LNG customer accounted for 10% or more of our consolidated voyage revenues during any of these periods. The loss of any significant customer or a substantial decline in the amount of services requested by a significant customer could harm our business, financial condition and results of operations.

LPG shipping involves the transportation of three main categories of cargo: liquid petroleum gases, including propane, butane and ethane; petrochemical gases including ethylene, propylene and butadiene; and ammonia.

LPG carriers are mainly chartered to carry LPG on time-charters, contracts of affreightment or spot voyage charters. The two largest consumers of LPG are residential users and the petrochemical industry. Residential users, particularly in developing regions where electricity and gas pipelines are not developed, do not have fuel switching alternatives and generally are not LPG price sensitive. The petrochemical industry, however, has the ability to switch between LPG and other feedstock fuels depending on price and availability of alternatives.

The following table provides additional information about our LPG carriers as of December 31, ~~2014, excluding~~2016, and excludes our 50% ownership interest in ~~nine~~four newbuildings scheduled for delivery between ~~2015~~2017 and ~~2018:~~

Vessel
   Capacity    Delivery    Ownership
Contract
Type

Charterer

Expiration of Charter
   (cubic meters)
Operating LPG carriers:

Consolidated

Norgas Pan
   10,000    2009    99 % Bareboat    I.M. Skaguen ASA    Mar. 2024
Norgas Cathinka
   10,000    2009    99 % Bareboat    I.M. Skaguen ASA    Oct. 2024
Norgas Camilla
   10,000    2011    99 % Bareboat    I.M. Skaguen ASA    Sep. 2026
Norgas Unikum
   12,000    2011    99 % Bareboat    I.M. Skaguen ASA    Jun. 2026
Bahrain Vision
   12,000    2011    99 % Bareboat    I.M. Skaguen ASA    Oct. 2026
Norgas Napa
   10,200    2003    99 % Bareboat    I.M. Skaguen ASA    Nov. 2019

Vessel
Capacity Delivery
Ownership

Contract Type

Charterer

Expiration of Charter
(cubic meters)
Equity Accounted

Brugge Venture
35,418 1997 50%    Time charter    An international fertilizer company    Jan. 2016
Temse (Kemira Gas
renamed to Temse)
12,030 1995 50%    Time charter    An international fertilizer company    Feb. 2017
Libramont
38,455 2006 50%    Time charter    An international fertilizer company    May. 2026
Sombeke
38,447 2006 50%    Time charter    An international fertilizer company    Jul. 2027
Touraine
39,270 1996 50%    Time charter    An international fertilizer company    Nov. 2016
Bastogne
35,229 2002 50%    CoA⁽¹⁾    North Sea charters    Mar. 2016
Courcheville
28,006 1989 50%    Time charter    An international energy company    Sep. 2015
Eupen
38,961 1999 50%    Time charter    An international energy company    Jun. 2016
Brussels
35,454 1997 Capital lease⁽²⁾    Time charter    An international fertilizer company    Nov. 2017
Antwerpen
35,223 2005 Chartered-In    CoA⁽¹⁾    North Sea charters    Mar. 2016
Odin
38,501 2005 Chartered-In    CoA⁽¹⁾    North Sea charters    Jun. 2016
BW Tokyo
83,270 2009 Chartered-In    Time charter    An international trading company    Jun. 2016
Waregem
38,189 2014 50%    Time charter    An international trading company    Jan. 2020
Warinsart
38,213 2014 50%    Time charter    An international energy company    Jun. 2016
Waasmunster
38,245 2014 50%    CoA⁽¹⁾    North Sea charters    Jun. 2016


Total Capacity:
637,111

2018 of which one LPG carrier newbuilding was delivered in March 2017:

No LPG customer accounted for 10% or more of our consolidated voyage revenues during any of ~~2014, 2013~~2016, 2015, or ~~2012.~~

2014. The loss of any significant customer or a substantial decline in the amount of services requested by a significant customer could harm our business, financial condition and results of operations.

Oil has been the world’s primary energy source for decades. Seaborne crude oil transportation is a mature industry. The two main types of oil tanker operators are major oil companies (including state-owned companies) that generally operate captive fleets, and independent operators that charter out their vessels for voyage or time-charter use. Most conventional oil tankers controlled by independent fleet operators are hired for one or a few voyages at a time at fluctuating market rates based on the existing tanker supply and demand. These charter rates are extremely sensitive to this balance of supply and demand, and small changes in tanker utilization have historically led to relatively large short-term rate changes. Long-term, fixed-rate charters for crude oil transportation, such as those applicable to our conventional tanker fleet, are less typical in the industry. As used in this discussion, “conventional” oil tankers exclude those vessels that can carry dry bulk and ore, tankers that currently are used for storage purposes and shuttle tankers that are designed to transport oil from offshore production platforms to onshore storage and refinery facilities.

Oil tanker demand is a function of several factors, primarily the locations of oil production, refining and consumption and world oil demand and supply, while oil tanker supply is primarily a function of new vessel deliveries, vessel scrapping and the conversion or loss of tonnage.

The majority of crude oil tankers range in size from approximately 80,000 dwt to approximately 320,000 dwt. Suezmax tankers, which typically range from 120,000 dwt to 200,000 dwt, are the mid-size of the various primary oil tanker types. As of December 31, ~~2014,~~2016, the world tanker fleet included ~~444~~468 conventional Suezmax tankers, representing approximately 14% of worldwide oil tanker capacity, excluding tankers under 10,000 dwt.

No ~~other~~ conventional tanker customer accounted for 10% or more of our consolidated voyage revenues during ~~any of these periods.~~2016, 2015, and 2014. The loss of any significant customer or a substantial decline in the amount of services requested by a significant customer could harm our business, financial condition and results of operations.

Our primary long-term business objective is to increase distributable cash flow per ~~unit~~unit. However, based on upcoming capital requirements for our committed growth projects and scheduled debt repayment obligations, coupled with relative weakness in energy and master limited partnership capital markets, we believe it is in the best interests of our common unitholders to conserve more of our internally generated cash flows to fund these projects and to reduce debt levels. As a result, in December 2015, we reduced our quarterly distributions on our common

units and our near-term business strategy is primarily to focus on funding and implementing existing growth projects and repaying or refinancing scheduled debt obligations. Our operating cash flows remain largely stable and growing, supported by a large and well-diversified portfolio of fee-based contracts with high-quality counterparties.

In addition to our operational experience, Teekay Corporation’s in-house global shore staff performs, through its subsidiaries, the full range of technical, commercial and business development services for our LNG, LPG and ~~LPG~~conventional operations. This staff also provides administrative support to our operations in finance, accounting and human resources. We believe this arrangement affords a safe, efficient and cost-effective operation.

~~Critical ship~~ Vessel management ~~functions undertaken~~services are provided by subsidiaries of Teekay Corporation, ~~are:~~

located in various offices around the world. These include critical vessel ~~maintenance;~~

management functions such as:

~~crewing;~~

~~purchasing;~~

vessel maintenance (including repairs and dry docking) and certification;

crewing by competent seafarers;

procurement of stores, bunkers and spare parts;

management of emergencies and incidents;

supervision of shipyard ~~supervision;~~

and projects during construction of newbuildings and conversions;

insurance; and

financial management services.

These functions are supported by onboard and onshore systems for maintenance, inventory, purchasing and budget management.

In addition, Teekay Corporation’s day-to-day focus on cost control is applied to our operations. In 2003, Teekay Corporation and two other shipping companies established a purchasing cooperation agreement called the TBW Alliance, which leverages the purchasing power of the combined fleets, mainly in such commodity areas as marine lubricants, coatings and chemicals and gases. Through our arrangements with Teekay Corporation, we benefit from this purchasing alliance.

We believe that the generally uniform design of some of our existing and newbuilding vessels and the adoption of common equipment standards provide operational efficiencies, including with respect to crew training and vessel management, equipment operation and repair, and spare parts ordering.

Risk of Loss, Insurance and Risk Management

The operation of any ocean-going vessel carries an inherent risk of catastrophic marine disasters, death or injury of persons and property losses caused by adverse weather conditions, mechanical failures, human error, war, terrorism, piracy and other circumstances or events. In addition, the transportation of crude oil, petroleum products, LNG and LPG isare subject to the risk of spills and to business interruptions due to political circumstances in foreign countries, hostilities, labor strikes, sanctions and boycotts. The occurrence of any of these events may result in loss of revenues or increased costs.

We carry hull and machinery (marine and war risks) and protection and indemnity insurance coverage to protect against most of the accident-related risks involved in the conduct of our business. Hull and machinery insurance covers loss of or damage to a vessel due to marine perils such as collision, grounding and weather. Protection and indemnity insurance indemnifies us against liabilities incurred while operating vessels, including injury to our crew or third parties, cargo loss and pollution. The current maximum amount of our coverage for pollution is $1 billion per vessel per incident. We also carry insurance policies covering war risks (including piracy and terrorism) and, for some of our LNG carriers, loss of revenues resulting from vessel off-hire time due to a marine casualty. We believe that our current insurance coverage is adequate to protect against most of the accident-related risks involved in the conduct of our business and that we maintain appropriate levels of environmental damage and pollution insurance coverage. However, we cannot guarantee that all covered risks are adequately insured against, that any particular claim will be paid or that we will be able to procure adequate insurance coverage at commercially reasonable rates in the future. More stringent environmental regulations have resulted in increased costs for, and may result in the lack of availability of, insurance against risks of environmental damage or pollution.

~~We use in~~

In our operations, we use Teekay Corporation’s thorough risk management program that includes, among other things, risk analysis tools, maintenance and assessment programs, a seafarers competence training program, seafarers workshops and membership in emergency response organizations. We believe that we benefit from Teekay Corporation’s commitment to safety and environmental protection asbecause certain of its subsidiaries assist us in managing our vessel operations.

Flag, Classification, Audits and Inspections

Our vessels are registered with reputable flag states, and the hull and machinery of all of our vessels have been “Classed” by one of the major classification societies and members of International Association of Classification Societies Ltd. (orIACS): Bureau Veritas (or BV), Lloyd’s Register of Shipping, orthe American Bureau of ~~Shipping.~~

Shipping or DNV-GL.

The applicable classification society certifies that the vessel’s design and build conforms to the applicable Class rules and meets the requirements of the applicable rules and regulations of the country of registry of the vessel and the international conventions to which that country is a signatory. The classification society also verifies throughout the vessel’s life that it continues to be maintained in accordance with those rules. In order to validate this, the vessels are surveyed by the classification society, in accordance to the classification society rules, which in the case of our vessels follows a comprehensive five-year special survey cycle, renewed every fifth year. During each five-year period the vessel undergoes annual and intermediate surveys, the scrutiny and intensity of which is primarily dictated by the age of the vessel. As our vessels are modern and we have enhanced the resiliency of the underwater coatings of each vessel hull and marked the hull to facilitate underwater inspections by divers, their underwater areas are inspected in a dry-dock at five-year intervals. In-water inspection is carried out during the second or third annual inspection (i.e. during an Intermediate Survey).

In addition to class surveys, the vessel’s flag state also verifies the condition of the vessel during annual flag state inspections, either independently or by additional authorization to class. Also, port state authorities of a vessel’s port of call are authorized under international conventions to undertake regular and spot checks of vessels visiting their jurisdiction.

Processes followed onboard are audited by either the flag state or classification society acting on behalf of the flag state to ensure that they meet the requirements of the ISM Code. We also follow an internal process of internal audits undertaken annually at each office and ~~vessel annually.~~

vessel.

We follow a comprehensive inspections and audit regime supported by our sea staff, shore-based operational and technical specialists and members of our QATO program. We carry out ~~a minimum of~~ two ~~such~~internal inspections and one internal audit annually, which helps ensure us that:

our vessels and operations adhere to our operating standards;

the structural integrity of the vessel is being maintained;

machinery and equipment is being maintained to give reliable service;

we are optimizing performance in terms of speed and fuel consumption; and

~~the~~our vessel’s appearance supports our brand and meets customer expectations.

Our customers also often carry out vetting inspections under the Ship Inspection Report Program, which is a significant safety initiative introduced by the Oil Companies International Marine Forum to specifically address concerns about sub-standard vessels. The inspection results permit charterers to screen a vessel to ensure that it meets their general and specific risk-based shipping requirements.

We believe that the heightened environmental and quality concerns of insurance underwriters, regulators and charterers will generally lead to greater scrutiny, inspection and safety requirements on all vessels in the oil tanker, LNG and LPG carrier markets and will accelerate the scrapping or phasing out of older vessels throughout these markets.

Overall we believe that our relatively new, well-maintained and high-quality vessels provide us with a competitive advantage in the current environment of increasing regulation and customer emphasis on quality of service.

C.

Regulations

General

Our business and the operation of our vessels are significantly affected by international conventions and national, state and local laws and regulations in the jurisdictions in which our vessels operate, as well as in the country or countries of their registration. Because these conventions, laws and regulations change frequently, we cannot predict the ultimate cost of compliance or their impact on the resale price or useful life of our vessels. Additional conventions, laws, and regulations may be adopted that could limit our ability to do business or increase the cost of our doing business and that may materially affect our operations. We are required by various governmental and quasi-governmental agencies to obtain permits, licenses and certificates with respect to our operations. Subject to the discussion below and to the fact that the kinds of permits, licenses and certificates required for the operations of the vessels we own will depend on a number of factors, we believe that we will be able to continue to obtain all permits, licenses and certificates material to the conduct of our operations.

International Maritime Organization (or IMO)

The IMO is the United Nations’ agency for maritime ~~safety.~~safety and prevention of pollution. IMO regulations relating to pollution prevention for oil tankers have been adopted by many of the jurisdictions in which our tanker fleet operates. Under IMO regulations and subject to limited exceptions, a tanker must be of double-hull construction in accordance with the requirements set out in these regulations, or be of another approved design ensuring the same level of protection against oil pollution. All of our tankers are double hulled.

Many countries, but not the United States, have ratified and follow the liability regime adopted by the IMO and set out in the International Convention on Civil Liability for Oil Pollution Damage, 1969, as amended (orCLC). Under this convention, a vessel’s registered owner is strictly liable for pollution damage caused in the territorial waters of a contracting state by discharge of persistent oil (e.g. crude oil, fuel oil, heavy diesel oil or lubricating oil), subject to certain defenses. The right to limit liability to specified amounts that are periodically revised is forfeited under the CLC when the spill is caused by the owner’s actual fault or when the spill is caused by the owner’s intentional or reckless conduct. Vessels trading to contracting states must provide evidence of insurance covering the limited liability of the owner. In jurisdictions where the CLC has not been adopted, various legislative regimes or common law governs, and liability is imposed either on the basis of fault or in a manner similar to the CLC.

IMO regulations also include the International Convention for Safety of Life at Sea (orSOLAS), including amendments to SOLAS implementing the International Ship and Port Facility Security Code (orISPS), the ISM Code, the International Convention on Load Lines of 1966, and, specifically with respect to LNG and LPG carriers, the International Code for Construction and Equipment of Ships Carrying Liquefied Gases in Bulk (theIGC Code). SOLAS provides rules for the construction of and the equipment required for commercial vessels and includes regulations for their safe operation. Flag states which have ratified the convention and the treaty generally employ the classification societies, which have incorporated SOLAS requirements into their class rules, to undertake surveys to confirm compliance.

SOLAS and other IMO regulations concerning safety, including those relating to treaties on training of shipboard personnel, lifesaving appliances, radio equipment and the global maritime distress and safety system, are applicable to our operations. Non-compliance with IMO regulations, including SOLAS, the ISM Code, ISPS and the IGC Code, may subject us to increased liability or penalties, may lead to decreases in available insurance coverage for affected vessels and may result in the denial of access to or detention in some ports. For example, the U.S. Coast Guard (or USCG) and European Union authorities have indicated that vessels not in compliance with the ISM Code will be prohibited from trading in U.S. and European Union ports. The ISM Code requires vessel operators to obtain a safety management certification for each vessel they manage, evidencing the ship owner’s development and maintenance of an extensive safety management system. Each of the existing vessels in our fleet is currently ISM Code-certified, and we expect to obtain safety management certificates for each newbuilding vessel upon delivery.

LNG and LPG carriers are also subject to regulation under the IGC Code. Each LNG and LPG carrier must obtain a certificate of compliance evidencing that it meets the requirements of the IGC Code, including requirements relating to its design and construction. Each of our LNG and LPG carriers is currently IGC Code ~~certified.~~compliant, and each of the shipbuilding contracts for our LNG carrier newbuildings and for the LPG carrier newbuildings requires IGC Code compliance prior to delivery. A revised and updated IGC Code, ~~to take~~which takes account of

advances in science and technology, was adopted by the IMO’s Maritime Safety Committee (orMSC) on May 22, ~~2014. It is to enter~~2014 and entered into force on January 1, 2016 with an implementation/application date of July 1, 2016.

In addition, the IMO’s MSC has adopted the International Code of Safety for Ships using Gases or other Low-flashpoint Fuels (or the IGF Code), which is a mandatory code for ships fueled by gases or other low-flashpoint fuels. The IGF Code, which is applicable from January 1, 2017, sets out mandatory provisions for the arrangement, installation, control and monitoring of machinery, equipment and systems using low-flashpoint fuel, in order to minimize the risk to the ship, its crew and the environment taking into account the nature of these fuels.

Annex VI ~~(or~~~~Annex VI~~) of the IMO’s International Convention for the Prevention of Pollution from Ships ((or MARPOL) (or Annex VI) sets limits on sulfur oxide and nitrogen oxide emissions from ship exhausts and prohibits emissions of ozone depleting substances, emissions of volatile compounds from cargo tanks and the incineration of specific substances. Annex VI also includes a world-wide cap on the sulfur content of fuel oil and allows for special ~~areas~~"emission control areas" (or ECAs) to be established with more stringent controls on sulfur emissions.

Annex VI also provides for a three-tier reduction in nitrogen oxide (or NOx) emissions from marine diesel engines, with the final tier (‘‘Tier III’’) to apply to engines installed on vessels constructed on or after January 1, 2016 and which operate in the North American ECA or the U.S. Caribbean Sea ECA. The Tier III requirements are also to apply to ECAs designated in the future by the IMO. In October 2016, the IMO’s MEPC approved the designation of the North Sea and the Baltic Sea as ECAs for NOx emissions. These two new NOx ECAs and the related amendments to Annex VI of MARPOL are expected to be formally adopted by IMO’s MEPC in 2017 and the two new ECAs are expected to enter into effect on January 1, 2021.

The IMO has issued guidance regarding protecting against acts of piracy off the coast of Somalia. We comply with these guidelines.

~~In addition,~~

The IMO Ballast Water Management Convention has been adopted by 54 countries, the combined merchant fleets of which represent 53.30% of the gross tonnage of the world’s merchant shipping, and will enter into force on September 8, 2017. The convention stipulates two standards for discharged ballast water. The D-1 standard covers ballast water exchange while the D-2 standard covers ballast water treatment. Once effective, the convention will require the implementation of either the D-1 or D-2 standard. There will be a transitional period from the entry into force to the International Oil Pollution Prevention (or IOPP) renewal survey in which ballast water exchange (reg. D-1) can be employed. After the first IOPP renewal survey, vessels will be required to meet the discharge standard D-2 by installing an approved Ballast Water Management System (or BWMS). Ships constructed after entry into force will be required to have a treatment system installed at delivery. Besides the IMO ~~has proposed (by~~convention, ships sailing in U.S. waters are required to employ a type-approved BWMS which is compliant with United States Coast Guard (or USCG) regulations. So far the ~~adoption in 2004 of the International Convention~~USCG have issued Type Approval (or TA) for the ~~Control and Management of Ships’ Ballast Water and Sediments (or the~~~~Ballast Water Convention~~~~) that all tankers of the size we operate that were built starting in 2012 contain~~following ballast water treatment systems ~~to comply with~~(or BWTS):

•Alfa Laval;

•Ocean Saver; and

•Optimarin.

We expect the ~~ballast water performance standard specified~~USCG will issue more TAs for BWTS in the ~~Ballast Water Convention,~~future. Plans have been set for the decoupling of IOPP surveys with Harmonised System of Survey and ~~that all other similarly sized tankers install water ballast treatment systems,~~Certification for vessels planning to drydock in ~~order to comply~~2018 with approval from the ballast water performance standard from 2016. In the latter case, compliance is required not later than by the first intermediate or renewal survey in relation to the International Ballast Water Management Certificate, whichever occurs first, after the anniversary date of delivery of the relevant vessel in the year of compliance with the applicable standard. This convention has not yet entered into force, but when it becomes effective, weFlag and Classification Society. We estimate that the installation of ~~ballast water treatment systems on our tankers~~approved BWTS may cost between $2 million and $3 million per vessel.

The IMO has also developed and adopted an International Code for Ships Operating in Polar Waters (or Polar Code) which deals with matters regarding the design, construction, equipment, operation, search and rescue and environmental protection in relation to ships operating in waters surrounding the two poles. The Polar Code includes both safety and environmental provisions and will be mandatory, with the safety provisions becoming part of SOLAS and the environmental provisions becoming part of MARPOL. In November 2014, the IMO’s MSC adopted the Polar Code and the related amendments to SOLAS in relation to safety, while in May 2015, the IMO’s Marine Environment Protection Committee (orMEPC) ~~is expected to adopt~~adopted the environmental provisions of the Polar Code and associated amendments to ~~MARPOL at its next session in 2015. Once adopted, the~~MARPOL. The Polar Code ~~is to enter into force on~~has become mandatory for new vessels built after January 1, 2017.

For existing ships, this code will be applicable from the first intermediate or renewal survey beginning on or after January 1, 2018.

In addition to the requirements of major IMO shipping conventions, the exploration for and production of oil and gas within the Newfoundland & Labrador (or NL) offshore area is conducted pursuant to the Canada Newfoundland and Labrador Atlantic Accord Implementation Act (or the Accord Act) in accordance with the conditions of a license and authorization issued by the Canada-Newfoundland and Labrador Offshore Petroleum Board (or CNLOPB). Various regulations dealing with environmental, occupational health and safety, and other aspects of offshore oil and gas activities have been enacted under the Accord Act. The CNLOPB has also issued interpretive guidelines concerning compliance with the regulations, and compliance with CNLOPB guidelines may be a condition of the issuance or renewal of the license and authorizations. These regulations and guidelines require that shuttle tankers in the NL offshore area meet stringent standards for equipment, reporting and redundancy systems, and for the training and equipping of seagoing staff. Further, licensees are required by the Accord Act to provide a benefits plan satisfactory to CNLOPB. Such plans generally require the licensee to: establish an office in NL; give NL residents first consideration for training and employment; make expenditures for research and development and education and training to be carried out in NL; and give first consideration to services provided from within NL and to goods manufactured in NL. These regulatory requirements may change as regulations and CNLOPB guidelines are amended or replaced from time to time.

MARPOL Annex I also states that oil residue may be discharged directly from the sludge tank to the shore reception facility through standard discharge connections. They may also be discharged to the incinerator or to an auxiliary boiler suitable for burning the oil by means of a dedicated discharge pump. Oil residue tanks shall have no discharge connection to the engine room bilge system, bilge tank or OWS except in following cases:

the residue tank may be fitted with manually operated self-closing valves and arrangements for subsequent visual monitoring of the settled water that lead to an oily water holding tank or bilge well;

the sludge tank discharge piping and bilge water piping may be connected to a common line leading to the standard discharge connection; however, the interconnection of line shall not allow for the transfer of sludge to the bilge system; and

a screw down non-return valve in lines connecting to the standard discharge connection, provides an acceptable means for not allowing for the transfer of sludge to the bilge system. Ship operators and managers should, before the first IOPP renewal survey, ensure that such systems are compliant. In the event that modifications are required, system drawings will be subject to approval.

Annex I is applicable for existing vessels with a first renewal survey beginning on or after January 1, 2017. It is anticipated that most vessels constructed after December 31, 1991 already comply with Annex I as MARPOL has since provided a unified interpretation prohibiting interconnections between sludge and bilge systems.

MSC 91 adopted amendments to SOLAS Regulation II-2/10 to add a new paragraph 10.4 to clarify that a minimum of two-way portable radiotelephone apparatus for each fire party for fire-fighters' communication shall be carried on board. These radio devices shall be of explosion proof type or intrinsically safe type. All existing ships built before July 1, 2014 should comply with this requirement by the first safety equipment survey after July 1, 2018. All new vessels constructed (keel laid) on or after July 1, 2014 must comply with this requirement at the time of delivery.

As per MSC. 338(91), requirements have been highlighted for audio and visual indicators for breathing apparatus which will alert the user before the volume of the air in the cylinder has been reduced to no less than 200 liters. This applies to ships constructed on or after July 1, 2014. Ships constructed before July 1, 2014 must comply no later than July 1, 2019.

European Union (or EU)

Like the IMO, the EU has adopted regulations ~~for~~ phasing out single-hull tankers. All of our tankers are double-hulled. On May 17, 2011, the European commission carried out a number of unannounced inspections at the offices of some of the world’s largest container line operators starting an antitrust investigation. We are not directly affected by this investigation and believe that we are compliant with antitrust rules. Nevertheless, it is possible that the investigation could be widened and new companies and practices come under scrutiny within the EU.

The EU has also adopted legislation (Directive 2009/16/EC on Port State Control as subsequently amended) that: bans from European waters manifestly sub-standard vessels (defined as vessels that have been detained twice by EU port authorities, in the preceding two years); creates obligations on the part of EU member port states to inspect minimum percentages of vessels using these ports annually; provides for increased surveillance of vessels posing a high risk to maritime safety or the marine environment; and provides the EU with greater authority and control over classification societies, including the ability to seek to suspend or revoke the authority of negligent societies (Directive 2009/15/EC as amended by Directive 2014/111/EU of December 17, 2014). Two new regulations were introduced by the European Commission in September 2010, as part of the implementation of the Port State Control Directive. These came into force on January 1, 2011 and introduce a ranking system (published on a public website and updated daily) displaying shipping companies operating in the EU with the worst safety records. The ranking is judged upon the results of the technical inspections carried out on the vessels owned be a particular shipping company. Those shipping companies that have the most positive safety records are rewarded by subjecting them to fewer inspections, ~~whilst~~while those with the most safety shortcomings or technical failings recorded upon inspection will in turn be subject to a greater frequency of official inspections to their vessels.

The EU has, by way of Directive 2005/35/EC, which has been amended by Directive 2009/123/EC, created a legal framework for imposing criminal penalties in the event of discharges of oil and other noxious substances from ships sailing in its waters, irrespective of their flag. This relates to discharges of oil or other noxious substances from vessels. Minor discharges shall not automatically be considered as offences, except where repetition leads to deterioration in the quality of the water. The persons responsible may be subject to criminal penalties if they have acted with intent, recklessly or with serious negligence and the act of inciting, aiding and abetting a person to discharge a polluting substance may also lead to criminal penalties.

The EU has adopted ~~regulations~~a Directive requiring the use of low sulfur fuel. ~~Beginning~~Since January 1, 2015, vessels have been required to burn fuel with sulfur content not exceeding 0.1% while within EU member states’ territorial seas, exclusive economic zones and pollution control zones that are included in SOX Emission Control Areas. Other jurisdictions have also adopted regulations requiring the use of low sulfur fuel. ~~The~~Since January 1, 2014, the California Air Resources Board ~~(or~~~~CARB~~~~) requires~~has required vessels to burn fuel with 0.1% sulfur content or less within 24 nautical miles of ~~California as of~~California. China also established emission control areas in the Pearl River Delta, the Yangtze River Delta and the Bohai Bay rim area with restrictions, commencing on January 1, ~~2014.~~ 2016, in the maximum sulfur content of the fuel to be used by vessels within those areas, which limits become progressively stricter over time. Commencing January 1, 2017, all the key ports within the three China ECAs (i.e. Tianjin, Qinhuangdao, Tangshan, Huanghua, Shenzhen, Guangzhou, Zhuhai, Shanghai, Ningbo-Zhoushan, Suzhou and Nantong) have implemented the low sulfur bunker requirements.

IMO regulations require that, as of January 1, 2015, all vessels operating within ~~Emissions Control Areas (or~~ECAs) worldwide recognized under MARPOL Annex VI must comply with 0.1% sulfur requirements. Currently, the only grade of fuel meeting this low sulfur content requirement is ~~low~~0.1% sulfur marine gas oil (orLSMGO). Since ~~July~~January 1, ~~2010,~~2015, the applicable sulfur content limits in the North Sea, the Baltic Sea and the English Channel ~~sulfur control areas~~ECAs have been ~~1.00%~~0.1%. Other established ECAs under Annex VI to MARPOL are the North American ECA and the United States Caribbean Sea ECA. Certain modifications were completed on our Suezmax tankers in order to optimize operation on LSMGO of equipment originally designed to operate on Heavy Fuel Oil (orHFO), and to ensure our compliance with the EU Directive. In addition, LSMGO is more expensive than HFO and this impacts the costs of operations. However, for vessels employed on fixed-term business, all fuel costs, including any increases, are borne by the charterer.

Our exposure to increased cost is in our spot trading vessels, although our competitors bear a similar cost increase as this is a regulatory item applicable to all vessels. All required vessels in our fleet trading to and within

regulated low sulfur areas are able to comply with fuel requirements. The global cap on the sulfur content of fuel oil is currently 3.5%, to be reduced to 0.5% by January 1, 2020. The reduced global cap of 0.5% by January 1, 2020 was subject to a feasibility review, which was completed in 2016 and on the basis of which the IMO’s Marine Environment Protection Committee (or the MEPC) decided in October 2016 to implement the 0.5% global sulfur cap as of January 1, 2020.

The EU ~~has recently adopted~~Ship Recycling Regulation ~~(EU) No 1257/2013 which imposes rules regarding ship recycling~~(1257/2013) (or the EU Ship Recycling Regulation) entered into force on December 30, 2013. It aims to prevent, reduce and ~~management of hazardous materials on vessels. The Regulation sets out requirements for the recycling of vessels in an environmentally sound manner at approved recycling facilities, so as to~~ minimize ~~the adverse~~accidents, injuries and other negative effects ~~of recycling~~ on human health and the ~~environment.~~environment when ships are recycled and the hazardous waste they contain is removed. The ~~Regulation also contains rules~~legislation applies to ~~control~~all ships flying the flag of an EU country and ~~properly manage~~to vessels with non-EU flags that call at an EU port or anchorage. It sets out responsibilities for ship owners and for recycling facilities both in the EU and in other countries. Each new ship is required to have on board an inventory of the hazardous materials ~~on vessels and prohibits~~(such as asbestos, lead or ~~restricts the installation~~mercury) it contains in either its structure or equipment. The use of certain hazardous materials is forbidden. Before a ship is recycled, its owner must provide the company carrying out the work with specific information about the vessel and prepare a ship recycling plan. Recycling may only take place at facilities listed on ~~vessels. The Regulation aims at facilitating~~ the ~~ratification~~EU ‘List of facilities’. In 2014, the Council Decision 2014/241/EU was adopted, authorizing EU countries having ships flying their flag or registered under their flag to ratify or to accede to the Hong Kong International Convention for the Safe and Environmentally Sound Recycling of Ships adopted by the IMO in 2009 (which has not entered into force). It applies to vessels flying the flag of a Member State. In addition, certain of its provisions also apply to vessels flying the flag of a third country calling at a port or anchorage of a Member State. For example, when calling at a port or anchorage of a Member State, the vessels flying the flag of a third country will be required, amongst other things, to have on board an inventory of hazardous materials which complies with the requirements of the Regulation and to be able to submit to the relevant authorities of that Member State a copy of a statement of compliance issued by the relevant authorities of the country of their flag and verifying the inventory.Ships. The EU Ship Recycling Regulation is to apply ~~not earlier than December 31, 2015 and~~ not later than December 31, 2018, although certain of its provisions are to apply at different stages, with some of them being applicable from December 31, ~~2014~~2020. Pursuant to the EU Ship Recycling Regulation, the EU Commission has recently published the first version of a European List of approved ship recycling facilities meeting the requirements of the regulation, as well as four further implementing decisions dealing with certification and ~~certain others are to apply from December 31, 2020.~~

other administrative requirements set out in the EU Ship Recycling Regulation.

United States

The United States has enacted an extensive regulatory and liability regime for the protection and cleanup of the environment from oil spills, including discharges of oil cargoes, bunker fuels or lubricants, primarily through the Oil Pollution Act of 1990 (orOPA 90) and the Comprehensive Environmental Response, Compensation and Liability Act (orCERCLA). OPA 90 affects all owners, bareboat charterers, and operators whose vessels trade to the United States or its territories or possessions or whose vessels operate in United States waters, which include the U.S. territorial sea and 200-mile exclusive economic zone around the United States. CERCLA applies to the discharge of “hazardous substances” rather than “oil” and imposes strict joint and several ~~liabilities~~liability upon the owners, operators or bareboat charterers of vessels for cleanup costs and damages arising from discharges of hazardous substances. We believe that petroleum products, LNG and LPG should not be considered hazardous substances under CERCLA, but additives to oil or lubricants used on LNG or LPG carriers might fall within its scope.

Under OPA 90, vessel owners, operators and bareboat charters are “responsible parties” and are jointly, severally and strictly liable (unless the oil spill results solely from the act or omission of a third party, an act of God or an act of war and the responsible party reports the incident and reasonably cooperates with the appropriate authorities) for all containment and cleanup costs and other damages arising from discharges or threatened discharges of oil from their vessels. These other damages are defined broadly to include:

natural resources damages and the related assessment costs;

real and personal property damages;

net loss of taxes, royalties, rents, fees and other lost revenues;

lost profits or impairment of earning capacity due to property or natural resources damage;

net cost of public services necessitated by a spill response, such as protection from fire, safety or health hazards; and

loss of subsistence use of natural resources.

OPA 90 limits the liability of responsible parties in an amount it periodically updates. The liability limits do not apply if the incident was proximately caused by violation of applicable U.S. federal safety, construction or operating regulations, including IMO conventions to which the United States is a signatory, or by the responsible party’s gross negligence or willful misconduct, or if the responsible party fails or refuses to report the incident or to cooperate and assist in connection with the oil removal activities. Liability under CERCLA is also subject to limits unless the incident is caused by gross negligence, willful misconduct or a violation of certain regulations. We currently maintain for each of our ~~vessel’s~~vessels pollution liability coverage in the maximum coverage amount of $1 billion per incident. A catastrophic spill could exceed the coverage available, which could harm our business, financial condition and results of operations.

Under OPA 90, with limited exceptions, all newly built or converted tankers delivered after January 1, 1994 and operating in U.S. waters must be double-hulled. All of our tankers are double-hulled.

OPA 90 also requires owners and operators of vessels to establish and maintain with the ~~United States~~ Coast Guard ~~(or~~~~Coast Guard~~ ) evidence of financial responsibility in an amount at least equal to the relevant limitation amount for such vessels under the statute. The Coast Guard has implemented regulations requiring that an owner or operator of a fleet of vessels must demonstrate evidence of financial responsibility in an amount sufficient to cover the vessel in the fleet having the greatest maximum limited liability under OPA 90 and CERCLA. Evidence of financial responsibility may be demonstrated by insurance, surety bond, self-insurance, guaranty or an alternate method subject to approval by the Coast Guard. Under the self-insurance provisions, the shipowner or operator must have a net worth and working capital, measured in assets located in the United States against liabilities located anywhere in the world, that exceeds the applicable amount of financial responsibility. We have complied with the Coast Guard regulations by using self-insurance for certain vessels and obtaining financial guaranties from a third party for the remaining vessels. If other vessels in our fleet trade into the United States in the future, we expect to obtain guaranties from third-party insurers.

OPA 90 and CERCLA permit individual U.S. states to impose their own liability regimes with regard to oil or hazardous substance pollution incidents occurring within their boundaries, and some states have enacted legislation providing for unlimited strict liability for spills. Several coastal states, such as California and Alaska, require state-specific evidence of financial responsibility and vessel response plans. We intend to comply with all applicable state regulations in the ports where our vessels call.

Owners or operators of vessels, including tankers operating in U.S. waters, are required to file vessel response plans with the Coast Guard, and their tankers are required to operate in compliance with their Coast Guard approved plans. Such response plans must, among other things:

address a “worst case” scenario and identify and ensure, through contract or other approved means, the availability of necessary private response resources to respond to a “worst case discharge”;

describe crew training and drills; and

identify a qualified individual with full authority to implement removal actions.

We have filed vessel response plans with the Coast Guard and have received its approval of such plans. In addition, we conduct regular oil spill response drills in accordance with the guidelines set out in OPA 90. The Coast Guard has announced it intends to propose similar regulations requiring certain vessels to prepare response plans for the release of hazardous substances.

OPA 90 and CERCLA do not preclude claimants from seeking damages resulting from the discharge of oil and hazardous substances under other applicable law, including maritime tort law. Such claims could include attempts to characterize the transportation of LNG or LPG aboard a vessel as an ultra-hazardous activity under a doctrine that would impose strict liability for damages resulting from that activity. The application of this doctrine varies by jurisdiction.

The ~~United States~~U.S. Clean Water Act (or the Clean Water Act) also prohibits the discharge of oil or hazardous substances in U.S. navigable waters and imposes strict liability in the form of penalties for unauthorized discharges. The Clean Water Act imposes substantial liability for the costs of removal, remediation and damages and complements the remedies available under OPA 90 and CERCLA discussed above.

Our vessels that discharge certain effluents, including ballast water, in U.S. waters must obtain a Clean Water Act permit from the Environmental Protection Agency (orEPA) titled the “Vessel General Permit” and comply with a range of effluent limitations, best management practices, reporting, inspections and other requirements. The current Vessel General Permit incorporates Coast Guard requirements for ballast water exchange and includes specific technology-based requirements for vessels, and includes an implementation schedule to require vessels to meet the ballast water effluent limitations by the first drydocking after January 1, 2014 or January 1, 2016, depending on the vessel size. Vessels that are constructed after December 1, 2013 are subject to the ballast water numeric effluent limitations immediately upon the effective date of the 2013 Vessel General Permit. Several U.S. states have added specific requirements to the Vessel General Permit and, in some cases, may require vessels to install ballast water treatment technology to meet biological performance standards.

Greenhouse Gas Regulation

In February 2005, the Kyoto Protocol to the United Nations Framework Convention on Climate Change (or theKyoto Protocol) entered into force. Pursuant to the Kyoto Protocol, adopting countries are required to implement national programs to reduce emissions of greenhouse gases. In December 2009, more than 27 nations, including the United States, entered into the Copenhagen Accord. The Copenhagen Accord is non-binding, but is intended to pave the way for a comprehensive, international treaty on climate change. In December 2015 the Paris Agreement (or the Paris Agreement) was adopted by a large number of countries at the 21st Session of the Conference of Parties (commonly known as COP 21, a conference of the countries which are parties to the United Nations Framework Convention on Climate Change; the COP is the highest decision-making authority of this organization). The Paris Agreement, which entered into force on November 4, 2016, deals with greenhouse gas emission reduction measures and targets from 2020 in order to limit the global temperature increases to well below 2 degrees Celsius above pre-industrial levels. Although shipping was ultimately not included in the Paris Agreement, it is expected that the adoption of the Paris Agreement may lead to regulatory changes in relation to curbing greenhouse gas emissions from shipping.

In July 2011, the IMO adopted regulations imposing technical and operational measures for the reduction of greenhouse gas emissions. These new regulations formed a new chapter in Annex VI and became effective on January 1, 2013. The new technical and operational measures imposed by these new regulations include the “Energy Efficiency Design ~~Index,”~~Index” (or the EEDI), which is mandatory for newbuilding vessels, and the “Ship Energy Efficiency Management Plan,” which is mandatory for all vessels. In October 2016, the IMO’s MEPC adopted updated guidelines for the calculation of the EEDI. In addition, the IMO is evaluating various mandatory measures to reduce greenhouse gas emissions from international shipping, which may include market-based instruments or a carbon tax. In October 2014, the IMO’s MEPC agreed in principle to develop a system of data collection regarding fuel consumption of ships. In October 2016, the IMO adopted a mandatory data collection system under which vessels of 5,000 gross tonnage and above are to collect fuel consumption and other data and to report the aggregated data so collected to their flag state at the end of each calendar year. The new requirements are expected to enter into force on March 1, 2018. The IMO also approved a roadmap for the development of a comprehensive IMO strategy on reduction of greenhouse gas emissions from ships with an initial strategy to be adopted in 2018 and a revised strategy to be adopted in 2023.

The EU also has indicated that it intends to propose an expansion of an existing EU emissions trading regime to include emissions of greenhouse gases from vessels, and individual countries in the EU may impose additional requirements. The EU has adopted Regulation (EU) 2015/757 on the monitoring, reporting and verification of carbon dioxide (or CO2) emissions from vessels (or the MRV Regulation), which entered into force on July 1, 2015. The regulation aims to quantify and reduce CO2 emissions from shipping. It lists the requirements on monitoring, reporting and verification (or MRV) of carbon dioxide emissions and requires ship owners and operators to annually monitor,

report and verify CO2 emissions for vessels larger than 5,000 gross tonnage calling at any EU and EFTA (Norway and Iceland) port (with a few exceptions, such as fish-catching or fish-processing vessels). Data collection takes place on a per voyage basis and starts January 1, 2018. The reported CO2 emissions, together with additional data, such as cargo and energy efficiency parameters, are to be verified by independent verifiers and sent to a central database, managed by the European Maritime Safety Agency. To comply with the EU MRV regulation, Teekay Corporation has prepared an EU MRV monitoring plan and EU MRV monitoring template in line with legislative requirement. The approved EU-MRV monitoring plan is expected to be placed on all our vessels by August 31, 2017. The EU is currently considering a proposal for ~~a regulation establishing a system~~the inclusion of ~~monitoring, reporting and verification of greenhouse gas~~ shipping ~~emissions (or~~~~MRV system~~~~). The proposed MRV system may be the precursor to a market-based mechanism to be adopted~~ in the ~~future.~~ EU Emissions Trading System as from 2021 in the absence of a comparable system operating under the IMO.

In the United States, the EPA issued an “endangerment finding” regarding greenhouse gases under the Clean Air Act. While this finding in itself does not impose any requirements on our industry, it authorizes the EPA to regulate directly greenhouse gas emissions through a rule-making process. In addition, climate change initiatives are being considered in the United States Congress and by individual states. Any passage of new climate control legislation or other regulatory initiatives by the IMO, EU, the United States or other countries or states where we operate that restrict emissions of greenhouse gases could have a significant financial and operational impact on our business that we cannot predict with certainty at this time.

Vessel Security

The ISPS was adopted by the IMO in December 2002 in the wake of heightened concern over worldwide terrorism and became effective on July 1, 2004. The objective of ISPS is to enhance maritime security by detecting security threats to ships and ports and by requiring the development of security plans and other measures designed to prevent such threats. Each of the existing vessels in our fleet currently complies with the requirements of ISPS and ~~MTSA.~~

~~D. Properties~~

~~Other than~~the Maritime Transportation Security Act of 2002 (U.S. specific requirements). Procedures are in place to inform the Maritime Security Council Horn of Africa (or MSCHOA ) whenever our vessels ~~we do not have any material property.~~

are calling in the Indian Ocean Region or West Coast of Africa (or WAC) high risk area. In order to mitigate the security risk, security arrangements are required for vessels which travel through Gulf of Aden and WAC region.

E.

C. Organizational Structure

Our sole ~~general partner~~General Partner is Teekay GP L.L.C., which is a wholly-owned indirect subsidiary of Teekay Corporation (NYSE: TK). Teekay Corporation also controls its public subsidiaries Teekay Offshore Partners L.P. (NYSE: TOO) and Teekay Tankers Ltd. (NYSE: TNK).

Please read Exhibit 8.1 to this Annual Report for a list of our ~~significant~~ subsidiaries as at December 31, ~~2014.~~

2016.


D.	Properties

Other than our vessels, we do not have any material property.

~~Item 4A. Unresolved Staff Comments~~

Item 4A. Unresolved Staff Comments

Not applicable.

Item 5. Operating and Financial Review and Prospects

~~Item 5. Operating and Financial Review and Prospects~~

Management’s Discussion and Analysis of Financial Condition and Results of Operations

~~General~~

Overview

Teekay LNG Partners L.P. is an international provider of marine transportation services for LNG, LPG and crude oil. Our primary growth strategy focuses on expanding our fleet of LNG and LPG carriers under medium to long-term, fixed-rate charters. In executing our growth strategy, we may engage in vessel or business acquisitions or enter into joint ventures and partnerships with companies that ~~may~~ provide increased access to emerging opportunities from global expansion of the LNG and LPG sectors. We seek to leverage the expertise, relationships and reputation of Teekay Corporation and its affiliates to pursue these opportunities in the LNG and LPG sectors and may consider other opportunities to which our competitive strengths are well suited. Although we may acquire additional crude oil tankers from time to time, we view our conventional tanker fleet primarily as a source of stable cash flow as we continue to expand our LNG and LPG operations.

Global natural gas and crude oil prices have significantly declined since mid-2014. A continuation of lower natural gas or oil prices or a further decline in natural gas or oil prices may adversely affect investment in the exploration for or development of new or existing natural gas reserves or projects and limit our growth opportunities, as well as reduce our revenues upon entering into replacement or new charter contracts. In addition, lower oil prices may negatively affect both the competitiveness of natural gas as a fuel for power generation and the market price of natural gas, to the extent that natural gas prices are benchmarked to the price of crude oil. These changes may impact our ability to charter our LNG carriers after expiration of their charter contracts or impact the daily hire rates we are able to negotiate on any charters we are able to obtain. In addition, these changes may also impact our ability to access public debt and equity markets, which in turn may result in us having to obtain more expensive sources of financing for our committed capital expenditures.

SIGNIFICANT DEVELOPMENTS IN ~~2014~~2016 AND EARLY ~~2015~~

~~RasGas II~~2017

Bahrain LNG ~~Carriers~~

Joint Venture

On ~~December 22, 2014,~~November 15, 2016, the ~~Teekay Nakilat~~Bahrain LNG Joint Venture secured debt financing of $741.1 million related to the development of an LNG receiving and regasification terminal in Bahrain. The receiving and regasification terminal will be owned and operated by the Bahrain LNG Joint Venture under a 20-year agreement with Nogaholding which is scheduled to commence in early-2019. In conjunction with this project, we will supply a FSU, which will be modified from one of our nine wholly-owned LNG carrier newbuildings, and charter the FSU to the Bahrain LNG Joint Venture through a 20-year time-charter contract.

Charter Contracts with Skaugen

We have six LPG carriers currently on bareboat charter contracts with Skaugen with contract terms ending between 2019 and 2026. As at December 31, 2016, we had not been paid by Skaugen for a portion of the hire invoices for the period from August 2016 to December 2016 relating to these six vessels and totaling approximately $9.2 million. As an alternative payment for a portion of these amounts, Skaugen offered to us its 35% ownership interest in an LPG carrier, the Norgas Sonoma, which is owned by Skaugen Gulf Petchem Carriers B.S.C.(c), a joint venture between Skaugen (35%), Nogaholding (35%) and Suffun Bahrain W.L.L. (or Suffun) (30%) (or the Skaugen LPG Joint Venture). Both Nogaholding and Suffun exercised their option to participate in the sale of the Norgas Sonoma and as a result, on April 20, 2017, we acquired 100% ownership interest in the Skaugen LPG Joint Venture for $13.2 million. Upon closing this transaction on April 20, 2017, we applied the purchase price of $4.7 million, before taking into account working capital adjustments, relating to Skaugen's 35% ownership interest in the Skaugen LPG Joint Venture to the outstanding hire invoices owed by Skaugen to us. As a result, as at December 31, 2016, we had not recognized the revenue relating to the remaining $4.5 million of hire invoices outstanding from Skaugen given the uncertainty of its collection. Upon acquisition of the Skaugen LPG Joint Venture, we expect to continue to trade the Norgas Sonoma in the Norgas pool. In addition, there is uncertainty about Skaugen's ability to pay future invoices for our six LPG carriers on charter to them which may impact our revenues and cash flows in future periods if we are not able to redeploy the vessels at similar rates. Currently, lease payments from Skaugen represent approximately $6 million of revenue each quarter.

Charter Contracts with Awilco

We have two LNG carriers currently on bareboat charter contracts with Awilco with fixed contract terms ending in November 2017 and September 2018 with one-year extension options, in which Awilco has a purchase obligation to repurchase each vessel from us at the end of their respective contract terms. Awilco is currently facing financial challenges, including going concern issues, and their ability to continue to make charter payments to us and to honor their purchase obligations is in question. We are currently in discussions with them on possible financial alternatives, however, if no solution is reached, we would expect the two vessels to be redelivered to us prior to their contract maturities. If we are unable to reach an arrangement with them, our operating cash flows and voyage revenues may be negatively impacted from mid-2017 to the end of the firm contract periods by approximately $5 million and $3 million per vessel per quarter, respectively, which may be mitigated with any redeployment opportunities we are able to secure.

Preferred Share Issuance

On October 5, 2016, we issued in a public offering 5.0 million of our 9.0% Series A Cumulative Redeemable Perpetual Preferred Units (or Series A Preferred Units) at $25.00 per unit for net proceeds of approximately $120.7 million. Distributions are payable on the Series A Preferred Units at a rate of 9.0% per annum of the stated liquidation preference of $25.00. At any time on or after October 5, 2021, we may redeem the Series A Preferred Units, in whole or in part, at a redemption price of $25.00 per unit plus all accumulated and unpaid distributions to the date of redemption, whether or not declared.We used the net proceeds from the public offering for general partnership purposes, which included debt repayments and funding installment payments on future newbuilding deliveries. The Series A Preferred Units are listed on the New York Stock Exchange.

Bond Issuances

On October 28, 2016, we issued in the Norwegian bond market Norwegian Kroner (or NOK) 900 million in new senior unsecured bonds which mature in October 2021. The new bond issuance has an aggregate principal amount equivalent to approximately $110 million and all principal and interest payments have been economically swapped into U.S. Dollars with a fixed interest rate of approximately 7.72%. We used a portion of the net proceeds of the new bond issuance to repurchase a portion of our NOK bonds maturing in May 2017, at a price equal to 101.50% of the principal amount of the repurchased bonds of NOK 292 million ($35.3 million) for a total purchase price of NOK 296 million ($35.8 million). We used the remaining net proceeds for general partnership purposes, which included funding of newbuilding installments. The bonds are listed on the Oslo Stock Exchange.

On January 23, 2017, we issued in the Norwegian bond market NOK 300 million (equivalent to approximately $36 million) in new senior unsecured bonds through an add-on to our existing NOK bonds due in October 2021 priced at 103.75% of face value. All principal and interest payments have been economically swapped into U.S. Dollars with a fixed interest rate of 7.69%.

Sales of Suezmax Tankers

During February and March 2016, Centrofin Management Inc. (or Centrofin), the charterer for both the Bermuda Spirit and Hamilton Spirit Suezmax tankers, exercised its option under the charter contracts to purchase both vessels. As a result of Centrofin’s acquisition of the vessels, we recorded a $27.4 million loss on the sale of the vessels and associated charter contracts in the first quarter of 2016. The Bermuda

Spirit was sold on April 15, 2016 and the Hamilton Spirit was sold on May 17, 2016. We used the total proceeds of $94.3 million from the sales primarily to repay existing term loans associated with these vessels.

On November 30, 2016, we reached an agreement to sell the Asian Spirit for net proceeds of $20.6 million. As a result, we recorded an $11.5 million impairment on the write-down of the vessel in the fourth quarter of 2016. Delivery of the vessel to the new owners occurred on March 21, 2017. We used the net proceeds from the sales primarily to repay an existing term loan associated with the vessel.

LNG Carrier Newbuildings

On February 18, 2016 and July 19, 2016, we took delivery of the first two of the 11 MEGI LNG carrier newbuildings on order, which commenced their five-year charter contracts with a subsidiary of Cheniere Energy, Inc. on February 29, 2016 and August 1, 2016, respectively. As at December 31, 2016, we had nine wholly-owned LNG carrier newbuildings on order, of which one, the Torben Spirit, was delivered on February 28, 2017 and the remaining eight are scheduled for delivery between late-2017 and early-2019.

On September 27, 2016, we entered into a 15-year time-charter contract with the Yamal LNG project (or the Yamal LNG Project), sponsored by Novatek OAO, Total SA, China National Petroleum Corporation and Silk Road Fund, to provide the Yamal LNG Project with conventional LNG transportation services. The Yamal LNG Project, which is now fully financed, is currently scheduled to commence production in late-2017. The charter contract will be serviced by one of our previously unchartered 174,000 cubic meter (cbm) MEGI LNG carrier newbuilding that is scheduled for delivery in early-2019.

Additionally, in November 2016, we entered into a 10-month plus one-year option charter contract with a major energy company. The charter contract commenced on March 3, 2017 and is being serviced by our final previously unchartered 173,400 cbm MEGI LNG carrier newbuilding, the Torben Spirit, which was delivered to us on February 28, 2017. Prior to the conclusion of this charter, we will seek to secure a long-term contract on this vessel.

In December 2016, we entered into a 10-year $682.8 million sale-leaseback agreement with ICBC Financial Leasing Co., Ltd. (or ICBC Leasing) for four of our nine wholly-owned LNG carrier newbuildings delivering in 2017 and 2018, and at such dates, ICBC Leasing will take delivery and charter each respective vessel back to us. At the end of the 10-year tenor of these leases, we have an obligation to repurchase the vessels from ICBC Leasing. In April 2017, we entered into a 10-year $174.3 million sale-leaseback agreement with China Construction Bank Financial Leasing Co. Ltd. (or CCBL) for one of our nine wholly-owned LNG carrier newbuildings scheduled to deliver in late-2017, and at such date, CCBL will take delivery and charter the vessel back to us. At the end of the 10-year tenor of this lease, we have an obligation to repurchase the vessel from CCBL.

In addition to our nine wholly-owned LNG carrier newbuildings, we have a ~~70% ownership~~20% interest voluntarily terminated its 30-year capital lease arrangements with the lessor relating to the RasGas II LNG Carriers under capital lease. As part of this transaction, the Teekay Nakilat Joint Venture acquired the RasGas II LNG Carriers from the lessor and the Teekay Nakilat Joint Venture refinanced its original debt facility of $278 million with a new $450 million debt facility and terminated its interest rate swaps relating to its original debt, capital lease obligations and restricted cash deposits. Please read “Item 18 – Financial Statements: Note 4 – Leases and Restricted Cash” and “Note 13 – Commitments and Contingencies.”

~~LNG Newbuildings~~

~~On December 4, 2014, we secured time-charter contracts, ranging~~ in ~~duration from six to eight years plus extension options, with Royal Dutch Shell plc (or~~~~Shell~~~~) for five~~two LNG carrier newbuildings which charter contracts will commence upon the vessel deliveries starting from the second half of 2017 into 2018. In connection with securing these time-charter contracts with Shell, we exercised our option to order threeand a 30% interest in another two LNG carrier newbuildings ~~from DSME. In February 2015,~~(or the BG Joint Venture) scheduled for delivery between 2017 and 2019 and six LNG carrier newbuildings relating to our 50% owned joint venture with China LNG Shipping (Holdings) Limited (or the Yamal LNG Joint Venture) scheduled for delivery between 2018 and 2020. Including the transactions described above, we ordered another LNG newbuilding carrier and have four additional newbuilding options declarable by the end of April 2015. In total, we have nine LNG newbuildings ordered, with four additional newbuilding options. We have entered into time-charter contracts for all ~~but two~~ of ~~the ordered~~our remaining newbuildings.

~~Acquisition and Bareboat Charter-Back of an~~

LPG Carrier

Newbuildings

In February, June, and November, ~~2014,~~2016, Exmar LPG BVBA (or the Exmar LPG Joint Venture), of which we ~~acquired~~have a ~~2003-built 10,200 cubic meter (or~~~~cbm~~~~) LPG carrier, the~~~~Norgas Napa~~~~, from I.M. Skaugen SE (or~~~~Skaugen~~~~) for $27 million. We~~50% ownership interest, took delivery of the ~~vessel~~sixth, seventh, and eighth of its 12 LPG carrier newbuildings on November 13, 2014 and chartered the vessel back to Skaugen on a bareboat contract for a period of five years at a fixed-rate plus a profit share component based on actual earnings of the vessel, which is trading in Skaugen’s Norgas pool.

~~Equity Offerings~~

On July 17, 2014, we completed a public offering of 3.1 million common units (including 0.3 million common units issued upon exercise of the underwriters’ over-allotment option) at a price of $44.65 per unit, for gross proceeds of approximately $140.8 million (including our general partner’s 2% proportionate capital contribution). We used the net proceeds from the offering of approximately $140.5 million to prepay a portion of our outstanding debt under two of our revolving credit facilities, to fund our portion of the first installment payment of $95.3 million for six newbuilding LNG carriers ordered by our 50/50 joint venture with China LNG for a project located on the Yamal Peninsula in Northern Russia (or the~~Yamal LNG Project) and to fund a portion of our MEGI newbuildings’ shipyard installments.~~

During the fourth quarter in 2014, we sold an aggregate of approximately 1.2 million common units under our continuous offering program for net proceeds of $48.4 million (including our general partner’s 2% proportionate capital contribution). We received a portion of these proceeds ($6.8 million for 0.2 million common units) in January 2015.

~~Yamal LNG Project~~

~~On July 9, 2014, we, through a new 50/50 joint venture with China LNG (or the~~~~Yamal LNG Joint Venture~~~~), finalized shipbuilding~~order. The five-year charter contracts for ~~six internationally-flagged icebreaker LNG carriers for~~ the ~~Yamal LNG Project. The Yamal LNG Project is a joint venture between Russia-based Novatek OAO (60%), France-based Total S.A. (20%)~~sixth and ~~China-based China National Petroleum Corporation (or~~~~CNPC~~) (20%) and will consist of three LNG trains with a total expected capacity of 16.5 million metric tons of LNG per annum. The project is currently scheduled to start-up in early-2018. The Yamal LNG Joint Venture will build six 172,000-cubic meter ARC7 LNG carrier newbuildings to be constructed by DSME for an estimated total fully built-up cost of approximately $2.1 billion. The vessels, which will be constructed with maximum 2.1 meter icebreaking capabilities in both the forward and reverse directions, are scheduled to deliver at various times between the first quarter of 2018 and first quarter of 2020. Upon their deliveries, the six LNG carriers will each operate under fixed-rate time-charter contracts with Yamal Trade Pte. Ltd. until December 31, 2045, plus extension options. The six LNG carriers constructed for the Yamal LNG Project will transport LNG from Northern Russia to Europe and Asia. We account for our investment in the Yamal LNG Joint Venture using the equity method.

~~BG Joint Venture~~

~~On June 27, 2014, we acquired from BG International Limited (or~~BG) its ownership interest in four 174,000-cubic meter Tri-Fuel Diesel Electric LNG carrier newbuildings, which will be constructed by Hudong-Zhonghua Shipbuilding (Group) Co., Ltd. in China for an estimated total fully built-up cost to the joint venture of approximately $1.0 billion. The vessels upon delivery, scheduled for between September 2017 and January 2019, will each operate under 20-year fixed-rate time-charter contracts, plus extension options, with Methane Services Limited, a wholly-owned subsidiary of BG. As compensation for BG’s ownership interest in these four LNG carrier newbuildings, we assumed BG’s portion of the shipbuilding installments and its obligation to provide the shipbuilding supervision and crew training services for the four LNG carrier newbuildings up to their delivery date pursuant to a ship construction support agreement. We estimate that we will incur approximately $38.7 million of costs to provide these services, of which BG has agreed to pay $20.3 million. Through this transaction, we have a 30% ownership interest in two LNG carrier newbuildings, with the balance of the ownership held by China LNG and CETS Investment Management (HK) Co. Ltd. (or~~CETS~~) (an affiliate of China National Offshore Oil Corporation), and a 20% ownership interest in the remaining two LNG carrier newbuildings, with the balance of the ownership held by China LNG, CETS and BW LNG Investments Pte. Ltd. (collectively the~~BG Joint Venture~~). We account for our investment in the BG Joint Venture using the equity method. We expect to finance our pro rata equity interest in future shipyard installment payments using a portion of our available liquidity, with the balance of the total cost of the vessels financed with equity contributions by the other partners and a $787.0 million long-term debt facility of the BG Joint Venture.

~~Sale of Vessels~~

~~Compania Espanole de Petroles, S.A. (or~~~~CEPSA~~~~), the charterer and prior owner of the~~~~Algeciras Spirit~~~~and~~~~Huelva Spirit~~~~conventional vessels previously under capital lease with us, reached agreements to sell the vessels to third-parties. On redelivery of the~~~~Algeciras Spirit~~~~and~~~~Huelva Spirit~~to CEPSA, the charter contracts with us were terminated and the vessels delivered to their new owners in February 2014 and August 2014, respectively. As a result of these sales, we have recorded a restructuring charge of $2.0 million for 2014 relating to seafarer severance payments associated with these vessels.

~~Exmar LPG Fleet Renewal~~

~~We hold a 50% interest in Exmar LPG BVBA, a joint venture with Belgium-based Exmar NV, to own and charter-in~~seventh LPG carriers with ~~a primary focus on~~an international energy company based in Norway commenced in February, 2016 and August 2016, respectively. As at December 31, 2016, the ~~mid-size gas carrier segment. Four of~~ Exmar LPG ~~BVBA’s 12~~Joint Venture had four LPG ~~newbuilding carriers,~~carrier newbuildings, of which one delivered in March 2017 and the~~Waasmunster~~,~~Warinsart, Waregem,~~~~and~~~~Warisoulx~~~~delivered~~ remaining three are scheduled for delivery between ~~April 2014~~mid-2017 and ~~January 2015. As a result of these newbuilding deliveries, and as part of its fleet renewal strategy,~~early-2018. The Exmar LPG ~~BVBA sold certain~~Joint Venture has secured financing in place upon delivery of ~~its LPG carriers. The~~~~Temse~~~~was sold and delivered to its new owner in March 2014,~~~~Flanders Tenacity~~~~and~~~~Eeklo~~~~were sold and delivered to their new owners in June 2014 and~~~~Flanders Harmony~~was sold and delivered to its new owner in August 2014. Exmar LPG BVBA recognized a net gain in 2014 as a result of the sale of these vessels, in which our proportionate share was $16.9 million. In addition, the in-chartered contract for~~Berlian Ekuatorexpired in January 2014 and the vessel was delivered back to its owner.~~

each respective vessel.

Charter Contracts for MALT LNG Carriers

Two of the six LNG carriers (or MALT LNG Carriers) in our 52% joint venture with Marubeni Corporation (or the Teekay LNG-Marubeni Joint Venture), the Marib Spirit and Arwa Spirit, are currently under long-term contracts expiring in 2029 with Yemen LNG Ltd. (or YLNG), a consortium led by Total SA. Due to the political situation in Yemen, YLNG decided to temporarily close operation of its LNG plant in Yemen in 2015. As a result, the Teekay LNG-Marubeni Joint Venture agreed in December 2015 to defer a portion of the charter payments for the two LNG carriers from January 1, 2016 to December 31, 2016 and a further deferral was agreed and effective in August 2016 and in January 2017, the deferral period was extended to December 31, 2017. Once the LNG plant in Yemen resumes operations, it is intended that YLNG will repay the deferred amounts in full, plus interest over a period of time to be agreed upon. However, there is no assurance if or when the LNG plant will resume operations or if YLNG will repay the deferred amounts, and this deferral period may extend beyond 2017. Our proportionate share of the impact of the charter payment deferral for 2016 was a reduction to equity income of $21.2 million and this deferral period may extend beyond 2017. Our proportionate share of the estimated impact of the charter payment deferral for 2017 compared to original charter rates earned prior to December 31, 2015 is estimated to be a reduction to equity income ranging from $20 million to $30 million depending on any sub-chartering employment opportunities.

In ~~January~~ 2015, the Magellan Spirit, one of the MALT LNG Carriers in ~~which we have a 52% ownership interest,~~the Teekay LNG-Marubeni Joint Venture, had a grounding incident. The vessel was subsequently refloated and returned to service. We expect the cost of such refloating and related costs associated with the grounding to be covered by insurance, less an applicable deductible. The charterer ~~has~~during that time claimed that the vessel was off-hire for 59more than 30 consecutive days during the first quarter of ~~2015. In addition,~~2015, which, in the view of the charterer, ~~claimed that~~permitted the ~~off-hire time for this vessel during this period gave them the right~~charterer to terminate the charter ~~contract effective March 28, 2015, which they elected to do.~~contract. The Teekay LNG-Marubeni Joint Venture ~~has~~ disputed both the charterer’s ~~claims of the~~

aggregate off-hire ~~time for this vessel as a result of this incident~~claims as well as the charterer’s ability to terminate the charter contract, which originally would have expired in ~~September~~August 2016. The Teekay LNG-Marubeni Joint Venture has obtained legal assistance in resolving this dispute. However, if the charterer’s claim to terminate the charter contract is upheld, our 52% portion of the potential loss revenue from March 28, 2015 to September 30,In May 2016, would be $27.3 million, less any amounts received for re-chartering this vessel during this time. The impact in future periods from this incident will depend upon our ability to re-charter the vessel and the resolution of this dispute. The charter contract of another MALT LNG Carrier expired in March 2015 as originally scheduled and the Teekay LNG-Marubeni Joint Venture reached a settlement agreement with the charterer, under which the charterer paid $39.0 million to the Teekay LNG-Marubeni Joint Venture for lost revenues, of which our proportionate share was $20.3 million, which was received and included in equity income in the year ended December 31, 2016.

Equity Accounted Joint Ventures' Refinancings

On December 21, 2016, Teekay Nakilat (III) Corporation (or the RasGas 3 Joint Venture), of which we have a 40% ownership interest, completed its debt refinancing by entering into a $723 million secured term loan facility maturing in 2026 which replaced its outstanding term loan of $610 million. As a result, the RasGas 3 Joint Venture distributed $100 million in February 2017 to its shareholders, of which our proportionate share was $40 million.

On March 31, 2017, the Teekay LNG-Marubeni Joint Venture completed the refinancing of its existing $396 million debt facility by entering into a new $335 million U.S. Dollar-denominated term loan maturing in September 2019. The term loan is ~~seeking to secure employment for this~~collateralized by first-priority statutory mortgages over the Marib Spirit, Arwa Spirit, Methane Spirit and Magellan Spirit, first priority pledges or charges of all the issued shares of the respective vessel ~~as well.~~

owning subsidiaries, and guaranteed by us and Marubeni Corporation on a several basis. As part of the completed refinancing, we invested $57 million of additional equity, based on our proportionate ownership interest, into the Teekay LNG-Marubeni Joint Venture.

Important Financial and Operational Terms and Concepts

We use a variety of financial and operational terms and concepts when analyzing our performance. These include the following:

Voyage Revenues. Voyage revenues currently include revenues from charters accounted for under operating and direct financing leases. Voyage revenues are affected by hire rates and the number of calendar-ship-days a vessel operates. Voyage revenues are also affected by the mix of business between time and voyage charters. Hire rates for voyage charters are more volatile than for time charters, as they are typically tied to prevailing market rates at the time of a voyage.

Voyage Expenses. Voyage expenses are all expenses unique to a particular voyage, including any bunker fuel expenses, port fees, cargo loading and unloading expenses, canal tolls, agency fees and commissions. Voyage expenses are typically paid by the customer under charters and by us under voyage charters.

Net Voyage Revenues. Net voyage revenues represent voyage revenues less voyage expenses. Because the amount of voyage expenses we incur for a particular charter depends upon the type of the charter, we use net voyage revenues to improve the comparability between periods of reported revenues that are generated by the different types of charters. We principally use net voyage revenues, a non-GAAP financial measure, because it provides more meaningful information to us about the deployment of our vessels and their performance than voyage revenues, the most directly comparable financial measure under GAAP.

Vessel Operating Expenses. Under all types of charters and contracts for our vessels, except for bareboat charters, we are responsible for vessel operating expenses, which include crewing, ship management services, repairs and maintenance, insurance, stores, lube oils and communication expenses. The two largest components of our vessel operating expenses are crew costs and repairs and maintenance. We expect these expenses to increase as our fleet matures and to the extent that it expands.

Income from Vessel Operations. To assist us in evaluating our operations by segment, we analyze the income we receive from each segment after deducting operating expenses, but prior to the inclusion or deduction of equity income, interest expense, taxes, foreign currency and derivative gains or losses and other ~~income (expense).~~income. For more information, please read “Item 18 – Financial Statements: Note 34 – Segment Reporting.”

Dry docking. We must periodically dry dock each of our vessels for inspection, repairs and maintenance and any modifications required to comply with industry certification or governmental requirements. Generally, we dry dock each of our vessels every two and a half to five years, depending upon the type of vessel and its age. In addition, a shipping society classification intermediate survey is performed on our LNG carriers between the second and third year of a five-year dry-docking period. We capitalize a substantial portion of the costs incurred during dry docking and for the survey, and amortize those costs on a straight-line basis from the completion of a dry docking or intermediate survey over the estimated useful life of the dry dock. We expense as incurred costs for routine repairs and maintenance performed during dry docking or intermediate survey that do not improve or extend the useful lives of the assets. The number of dry dockings undertaken in a given period and the nature of the work performed determine the level of dry-docking expenditures.

Depreciation and Amortization. Our depreciation and amortization expense typically consists of the following three components:

charges related to the depreciation of the historical cost of our fleet (less an estimated residual value) over the estimated useful lives of our vessels;

charges related to the amortization of dry-docking expenditures over the useful life of the dry dock; and

charges related to the amortization of the fair value of the time-charters acquired in a 2004 acquisition of four LNG carriers (over the expected remaining terms of the charters).

Revenue Days. Revenue days are the total number of calendar days our vessels were in our possession during a period less the total number of off-hire days during the period associated with major repairs, dry dockings or special or intermediate surveys. Consequently, revenue days

represents the total number of days available for the vessel to earn revenue. Idle days, which are days when the vessel is available to earn revenue, yet is not employed, are included in revenue days. We use revenue days to explain changes in our net voyage revenues between periods.

Calendar-Ship-Days. Calendar-ship-days are equal to the total number of calendar days that our vessels were in our possession during a period. As a result, we use calendar-ship-days primarily in explaining changes in vessel operating expenses and depreciation and amortization.

Utilization. Utilization is an indicator of the use of our fleet during a given period, and is determined by dividing our revenue days by our calendar-ship-days for the period.

RESULTS OF OPERATIONS

Items You Should Consider When Evaluating Our Results of Operations

Some factors that have affected our historical financial performance and may affect our future performance are listed below:

•

~~The amount and timing of dry docking of our vessels can significantly affect our revenues between periods.~~ Our vessels are off-hire at various points of time due to scheduled and unscheduled maintenance. During 2014, 2013 and 2012, we had 140, 135 and 23 scheduled off-hire days, respectively, relating to dry docking on our vessels that are consolidated for accounting purposes. In addition, two of our consolidated vessels had unplanned off-hire of 26 days in 2014 relating to repairs. The financial impact from these periods of off-hire, if material, is explained in further detail below. Two of our consolidated vessels, are scheduled for dry docking in 2015.

•

~~The size of our fleet changes~~. Our historical results of operations reflect changes in the size and composition of our fleet due to certain vessel deliveries and sales. Please read “Liquefied Gas Segment” and “Conventional Tanker Segment” below and “Significant Developments in 2014 and Early 2015” above for further details about certain prior and future vessel deliveries and sales.

•

~~Vessel operating and other costs are facing industry-wide cost pressures~~. The shipping industry continues to experience a global manpower shortage of qualified seafarers in certain sectors due to growth in the world fleet and competition for qualified personnel. In recent years, upward pressure on manning costs has temporarily stabilized and resulted in lower wage increases than has been seen in the past. However, this situation will likely not continue in the long term. Going forward, there may be significant increases in crew compensation as vessel and officer supply dynamics continue to change.

The amount and timing of dry docking of our vessels can significantly affect our revenues between periods. Our vessels are off-hire at various times due to scheduled and unscheduled maintenance. During 2016, 2015 and 2014, we had none, 69 and 140 of scheduled off-hire days, respectively, relating to the dry docking of our vessels which are consolidated for accounting purposes. In addition, certain of our consolidated vessels had unplanned off-hire of 39 days in 2016, 14 days in 2015 and 26 days in 2014 relating to repairs and work stoppage. The financial impact from these periods of off-hire, if material, is explained in further detail below.

The size of our fleet changes. Our historical results of operations reflect changes in the size and composition of our fleet due to certain vessel deliveries and sales. Please read “Liquefied Gas Segment” and “Conventional Tanker Segment” below and “Significant Developments in 2016 and Early 2017” above for further details about certain prior and future vessel deliveries and sales.

Vessel operating and other costs are facing industry-wide cost pressures. The shipping industry continues to forecast a shortfall in qualified personnel, although weak shipping markets and slowing growth may ease officer shortages. We will continue to focus on our manning and training strategies to meet future needs, but going forward crew compensation may increase. In addition, factors such as pressure on commodity and raw material prices, as well as changes in regulatory requirements could also contribute to operating expenditure increases. We continue to take action aimed at improving operational efficiencies, and to temper the effect of inflationary and other price escalations; however increases to operational costs are still likely to occur in the future.

•

~~Our financial results are affected by fluctuations in the fair value of our derivative instruments.~~The change in fair value of our derivative instruments is included in our net income as the majority of our derivative instruments are not designated as hedges for accounting purposes. These changes may fluctuate significantly as interest rates, foreign exchange rates and spot tanker rates fluctuate relating to our interest rate swaps, cross currency swaps and to the agreement we have with Teekay Corporation relating to the time charter contract for the~~Toledo Spirit~~ Suezmax tanker. Please read “Item 18 – Financial Statements: Note 11(c) – Related Party Transactions” and “Note 12 – Derivative Instruments.” The unrealized gains or losses relating to changes in fair value of our derivative instruments do not impact our cash flows.

•

~~Our financial results are affected by fluctuations in currency exchange rates.~~ Under GAAP, all foreign currency-denominated monetary assets and liabilities (including cash and cash equivalents, restricted cash, accounts receivable, accounts payable, accrued liabilities, unearned revenue, advances from affiliates, obligations under capital lease and long-term debt) are revalued and reported based on the prevailing exchange rate at the end of the period. These foreign currency translations fluctuate based on the strength of the U.S. Dollar relative mainly to the Euro and NOK and are included in our results of operations. The translation of all foreign currency-denominated monetary assets and liabilities at each reporting date results in unrealized foreign currency exchange gains or losses but do not impact our cash flows.

•

~~Three of our Suezmax tankers and one of our LPG carriers earned revenues based partly on spot market rates.~~~~The time-charter contract for one of our Suezmax tankers, the~~~~Teide Spirit,~~ ~~and one of our LPG carriers, the~~~~Norgas Napa,~~~~contain a component providing for additional revenue to us beyond the fixed-hire rate when spot market rates exceed certain threshold amounts. The time-charter contracts for the~~~~Bermuda Spirit~~~~and~~ ~~Hamilton Spirit~~ Suezmax tankers were amended in the fourth quarter of 2012 for a period of 24 months, which ended on September 30, 2014, and during this period contained a component providing for additional revenues to us beyond the fixed-hire rate when spot market rates exceed certain threshold amounts. Accordingly, even though declining spot market rates will not result in our receiving less than the fixed-hire rate, our results of operations and cash flow from operations will be influenced, by the variable component of the charters in periods where the spot market rates exceed the threshold amounts.

Global natural gas and crude oil prices have significantly declined since mid-2014. A continuation of lower natural gas or oil prices or a further decline in natural gas or oil prices may adversely affect investment in the exploration for or development of new or existing natural gas reserves or projects and limit our growth opportunities, as well as ~~reduce~~changes in regulatory requirements could also contribute to operating expenditure increases. We continue to take action aimed at improving operational efficiencies, and to temper the effect of inflationary and other price escalations; however, increases to operational costs are still likely to occur in the future.

As at December 31, ~~2014,~~2016, our liquefied gas segment fleet, including newbuildings, included 4750 LNG carriers and 3029 LPG/Multigas carriers, in which our interests ranged from 20% to 100%. However, the table below only includes 13the 15 LNG carriers and six LPG/Multigas ~~carriers.~~carriers that are accounted for under the consolidation method of accounting, 19 of which we own and two of which we lease under capital leases. The table excludes ~~eight newbuilding~~nine LNG ~~carriers~~carrier newbuildings under construction and the following vessels accounted for under the equity method: (i)

The following table compares our liquefied gas segment’s operating results for ~~2014~~2016 and ~~2013,~~2015, and compares its net voyage revenues (which is a non-GAAP financial measure) for ~~2014~~2016 and ~~2013,~~2015, to voyage revenues, the most directly comparable GAAP financial measure. The following table also provides a summary of the changes in calendar-ship-days and revenue days for our liquefied gas segment:

(in thousands of U.S. Dollars, except revenue days,    Year Ended December 31,
calendar-ship-days and percentages)    2014 2013 % Change
Voyage revenues
   307,426 285,694 7.6
Voyage expenses
   (1,768 ) (407 ) 334.4


Net voyage revenues
305,658 285,287 7.1
Vessel operating expenses
(59,087 ) (55,459 ) 6.5
Depreciation and amortization
(71,711 ) (71,485 ) 0.3
General and administrative⁽¹⁾
(17,992 ) (13,913 ) 29.3


Income from vessel operations
156,868 144,430 8.6


Operating Data:
Revenue Days (A)
6,534 5,919 10.4
Calendar-Ship-Days (B)
6,619 5,981 10.7
Utilization (A)/(B)
98.7 % 99.0 %

partially offset by:

As at December 31, 2016, our fleet included five Suezmax-class double-hulled conventional crude oil tankers and one Handymax product tanker, three of which we own, two of which we lease under capital leases, and one vessel held for sale.

The following table compares our conventional tanker segment’s operating results for 2016 and 2015, and compares its net voyage revenues (which is a non-GAAP financial measure) for 2016 and 2015 to voyage revenues, the most directly comparable GAAP financial measure. The following table also provides a summary of the changes in calendar-ship-days and revenue days for our conventional tanker segment:

The $0.4 million decrease in our 33% investment in the four Angola LNG Carriers was primarily due to decreases in voyage revenues due to the positive impact of charter contract amendments in the second quarter of 2015 to allow for dry docking and operating costs to be passed-through to the charterer, retroactive to the beginning of the charter contract, which was partially offset by scheduled dry dockings for all four vessels in the joint venture in 2015 and higher unrealized gains on non-designated derivative instruments in 2016 as a result of a higher increase in long-term LIBOR benchmark interest rates compared to last year.

The $1.7 million decrease in equity income from our 40% investment in the RasGas 3 LNG Carriers was primarily due to the scheduled maturity of the joint venture's interest rate swaps, which resulted in lower unrealized gain on non-designated derivative instruments, which was partially offset by lower combined interest expense and realized loss on non-designated derivative instruments.

As at December 31, 2016 and 2015, we had interest rate swap agreements, excluding our swap agreements with future commencement

dates, with aggregate average net outstanding notional amounts of approximately $755 million and $819 million, respectively, with average

fixed rates of 3.8% for both years. The decreases in realized losses relating to our interest rate swaps from 2015 to 2016 was primarily due to an increase in LIBOR compared to last year, which decreased our settlement payments.

During 2016, we recognized unrealized gains on our interest rate swap and swaption agreements associated with our U.S. Dollar-denominated long-term debt. This resulted from transfers of $17.9 million of previously recognized unrealized losses to realized losses related to actual cash settlements of our interest rate swaps, partially offset by $3.7 million of unrealized losses relating to decreases in long-term forward LIBOR benchmark interest rates relative to the beginning of 2016.

During 2016, we recognized unrealized gains on our interest rate swap agreements associated with our EURO-denominated long-term debt. This resulted from transfers of $8.1 million of previously recognized unrealized losses to realized losses related to actual cash settlements of our interest rate swaps, partially offset by $6.7 million of unrealized losses relating to decreases in long-term forward EURIBOR benchmark interest rates, relative to the beginning of 2016.

During 2015, we recognized unrealized gains on our interest rate swap and swaption agreements associated with our U.S. Dollar-denominated long-term debt. This resulted from transfers of $21.0 million of previously recognized unrealized losses to realized losses related to actual cash settlements of our interest rate swaps, partially offset by $17.1 million of unrealized losses relating to decreases in long-term forward LIBOR benchmark interest rates relative to the beginning of 2015.

During 2015, we recognized unrealized gains on our interest rate swap agreements associated with our Euro-denominated long-term debt. This resulted from transfers of $7.9 million of previously recognized unrealized losses to realized losses related to actual cash settlements of our interest rate swaps, and $2.2 million of unrealized gains relating to increases in long-term forward EURIBOR benchmark interest rates relative to the beginning of 2015.

The projected forward average tanker rates in the tanker market increased at December 31, 2015 compared to the beginning of 2015, which resulted in $1.6 million of unrealized losses on our Toledo Spirit time-charter derivative.

Please see “Item 5 – Operating and Financial Review and Prospects: Critical Accounting Estimates – Valuation of Derivative Instruments,” which explains how our derivative instruments are valued, including the significant factors and uncertainties in determining the estimated fair value and why changes in these factors result in material variances in realized and unrealized gain (loss) on non-designated derivative instruments.

For 2016, foreign currency exchange gains (losses) included realized gains of $16.8 million on the repurchase of a portion our NOK bonds maturing in 2017, the transfer of $17.7 million of previously recognized unrealized losses to realized losses related to our cross-currency swaps associated with the NOK bond repurchase, unrealized gains of $11.2 million on our cross-currency swaps primarily due to appreciation of long-term NOK forward exchange rates and increases in long-term forward NIBOR benchmark interest rates relative to the beginning of 2016, and $5.4 million on the revaluation of our Euro-denominated cash, restricted cash and debt. These gains were partially offset by transfers of ($16.8) million of previously recognized unrealized gains to realized gains related to the repurchase of the NOK bonds in October 2016, ($17.7) million of realized losses related to the termination of our cross-currency swaps associated with the NOK bond repurchase, ($9.1) million realized losses on settlements of our cross currency swaps and a ($2.2) million loss on the revaluation of our NOK-denominated debt.

For 2015, foreign currency exchange gains (losses) included the revaluation of our Euro-denominated cash, restricted cash and debt of $25.6 million and the revaluation of our NOK-denominated debt of $54.7 million. These gains were partially offset by realized losses of ($7.6) million on settlements of our cross-currency swaps and unrealized losses of ($57.8) million on our cross currency swaps primarily due to depreciation of long-term NOK forward exchange rates relative to the beginning of 2015.

The following table compares our liquefied gas segment’s operating results for 2015 and 2014, and compares its net voyage revenues (which is a non-GAAP financial measure) for 2015 and 2014, to voyage revenues, the most directly comparable GAAP financial measure. The following table also provides a summary of the changes in calendar-ship-days and revenue days for our liquefied gas segment:

partially offset by:

•

~~a decrease of $2.6 million due to the~~~~Galicia Spirit~~ ~~being off-hire for 28 days in the first quarter of 2014 for a scheduled dry docking;~~

partially offset by:

The following table compares our conventional tanker segment’s operating results for ~~2014~~2015 and ~~2013,~~2014, and compares its net voyage revenues (which is a non-GAAP financial measure) for ~~2014~~2015 and ~~2013~~2014 to voyage revenues, the most directly comparable GAAP financial measure. The following table also provides a summary of the changes in calendar-ship-days and revenue days for our conventional tanker segment:

(in thousands of U.S. Dollars, except revenue days,    Year Ended December 31,
calendar-ship-days and percentages)    2014 2013 % Change
Voyage revenues
   95,502 113,582 (15.9 )
Voyage expenses
   (1,553 ) (2,450 ) (36.6 )


Net voyage revenues
93,949 111,132 (15.5 )
Vessel operating expenses
(36,721 ) (44,490 ) (17.5 )
Depreciation and amortization
(22,416 ) (26,399 ) (15.1 )
General and administrative⁽¹⁾
(5,868 ) (6,531 ) (10.2 )
Restructuring charges
(1,989 ) (1,786 ) 11.4


Income from vessel operations
26,955 31,926 (15.6 )


Operating Data:
Revenue Days (A)
3,121 3,921 (20.4 )
Calendar-Ship-Days (B)
3,202 3,994 (19.8 )
Utilization (A)/(B)
97.5 % 98.2 %

~~(1)~~



(in thousands of U.S. Dollars, except revenue days, calendar-ship-days and percentages)	Year Ended December 31,				% Change
	2015		2014		% Change
Voyage revenues	92,935		95,502		(2.7	)
Voyage expenses	(1,349	)	(1,553	)	(13.1	)
Net voyage revenues	91,586		93,949		(2.5	)
Vessel operating expenses	(30,757	)	(36,721	)	(16.2	)
Depreciation and amortization	(20,930	)	(22,416	)	(6.6	)
General and administrative expenses⁽¹⁾	(5,726	)	(5,868	)	(2.4	)
Restructuring charges	(4,001	)	(1,989	)	101.2
Income from vessel operations	30,172		26,955		11.9
Operating Data:
Revenue Days (A)	2,884		3,121		(7.6	)
Calendar-Ship-Days (B)	2,920		3,202		(8.8	)
Utilization (A)/(B)	98.8	%	97.5	%

(1)Includes direct general and administrative expenses and indirect general and administrative expenses (allocated to each segment based on estimated use of corporate resources).

~~Net Voyage Revenues~~. ~~Net voyage revenues~~

partially offset by:

The ~~$25.7~~$12.7 million ~~decrease~~increase for ~~2014~~2015 in our 33% investment in the four Angola LNG Carriers was primarily due to ~~$23.6 million of~~ unrealized ~~losses~~gains on non- designated derivative instruments in ~~2014~~2015 as a result of long-term LIBOR benchmark interest rates ~~decreasing~~increasing for interest rate swaps ~~maturing in 2023 and 2024,~~ compared to unrealized ~~gains~~losses on non-designated derivative instruments ~~in the same period~~ last year, and an increase in ~~vessel~~voyage revenues upon amending the charter contract in the second quarter of 2015 to allow for drydocking and operating ~~expenses relating~~costs to ~~vessel main engine overhauls~~pass-through to the charterer, retroactive to the beginning of the charter contract.

The $1.3 million decrease for 2015 in ~~2014.~~

equity income from the two Exmar LNG Carriers, in which we have ownership interests ranging from 49% to 50%, was primarily due to higher interest expense as a result of the completion of the joint venture’s debt refinancing in 2015.

The $0.7 million increase for ~~34 days and 23 days, respectively, during 2014 for scheduled dry dockings, the off-hire of~~~~Woodside Donaldson~~for seven days in 2014 for motor repairs, an increase in vessel operating expenses due to higher overall repair expenditures in 2014, an increase in interest expenses due to higher interest margins upon completion of debt refinancing within the Teekay LNG-Marubeni Joint Venture in June and July 2013, and an increase in depreciation expenses due to dry-dock additions in 2014. These decreases were partially offset by the~~Methane Spirit~~ ~~being off-hire for 28 days for a scheduled dry docking in 2013.~~

~~The $1.8 million decrease for 2014~~2015 in our 40% investment in the RasGas 3 LNG Carriers primarily resulted from ~~a performance claim provision recorded in 2014 and higher operating expense due to timing of services and crew wage increases, partially offset by~~ lower interest expense due to principal repayments made during ~~2013~~2014 and ~~2014.~~

2015.

partially offset by:

As at December 31, ~~2014~~2015 and ~~2013,~~2014, we had interest rate swap and interest rate swaption agreements with an aggregate average net outstanding notional ~~amount~~amounts of approximately ~~$1.0~~$1.6 billion and ~~$870.4 million,~~$1.0 billion, respectively, with average fixed rates of ~~4.1%~~3.3% and ~~4.6%~~4.1%, respectively. The ~~increase~~decrease in realized losses from ~~2013~~2014 to ~~2014~~2015 relating to our interest rate swaps was primarily due to the ~~addition of six interest rate swaps in 2014, the~~ termination of interest rate swaps in December 2014 ~~formerly~~that had been held by the Teekay Nakilat Joint Venture and ~~lower~~higher short-term variable interest rates in ~~2014~~2015 compared to the same period in ~~2013.~~

2014.

During 2015, we recognized unrealized gains on our interest rate swap and swaption agreements associated with our U.S. Dollar-denominated long-term debt. This resulted from transfers of $21.0 million of previously recognized unrealized losses to realized losses related to actual cash settlements of our interest rate swaps, partially offset by $17.1 million of unrealized losses relating to decreases in long-term forward LIBOR benchmark interest rates, relative to the beginning of 2015.

During 2015, we recognized unrealized gains on our interest rate swap agreements associated with our EURO-denominated long-term debt. This resulted from transfers of $7.9 million of previously recognized unrealized losses to realized losses related to actual cash settlements of our interest rate swaps, and $2.2 million of unrealized gains relating to increases in long-term forward EURIBOR benchmark interest rates, relative to the beginning of 2015.

During 2014, we recognized unrealized losses on our interest rate swaps associated with our U.S. Dollar-denominated restricted cash deposits, which were terminated in December 2014. This resulted from transfers of $172.5 million of previously recognized unrealized gains to realized gains related to actual cash settlements of our interest rate swaps, partially offset by $90.0 million of unrealized gains relating to decreases in long-term forward LIBOR benchmark interest rates relative to the beginning of 2014.

During 2014, we recognized unrealized gains on our interest rate swaps associated with our U.S. Dollar-denominated long-term debt and capital leases. This resulted from transfers of $204.9 million of previously recognized unrealized losses to realized losses related to actual cash settlements of our interest rate swaps, partially offset by $104.0 million of unrealized losses relating to decreases in long-term forward LIBOR benchmark interest rates relative to the beginning of 2014.

During ~~2013,~~2014, we recognized unrealized losses on our interest rate ~~swaps~~swap agreements associated with our ~~U.S. Dollar-denominated restricted cash deposits.~~Euro-denominated long-term debt. This resulted from ~~$63.0~~$23.5 million of unrealized losses relating to ~~increases~~decreases in long-term forward ~~LIBOR~~EURIBOR benchmark interest rates, relative to the beginning of ~~2013, plus~~2014, partially offset by transfers of ~~$21.7 million of previously recognized unrealized gains to realized gains related to actual cash settlement of our interest rate swaps.~~

During 2013, we recognized unrealized gains on our interest rate swaps associated with our U.S. Dollar-denominated long-term debt and capital leases. This resulted from $44.0 million of unrealized gains relating to increases in long-term forward LIBOR benchmark interest rates, relative to the beginning of 2013, and transfers of $49.8$9.3 million of previously recognized unrealized losses to realized losses related to actual cash settlements of our interest rate swaps.

Long-term forward EURIBOR benchmark interest decreased during 2014 and increased during 2013, which resulted in an unrealized loss of $14.2 million and an unrealized gain of $9.7 million, respectively, from our interest rate swaps associated with our Euro-denominated long-term debt.

The projected average tanker rates in the tanker market inat December 31, 2014 increased compared to ~~2013,~~the beginning of 2014, which resulted in $6.3 million of unrealized losses on our Toledo Spirit time-charter derivative in 2014. The projected average tanker rates in 2013 decreased compared to 2012, which resulted in a $3.7 million unrealized gain on our Toledo Spirit time-charter derivative in 2013. The Toledo Spirit time-charter derivative is the agreement with Teekay Corporation under which Teekay Corporation pays us any amounts payable to the charterer of the~~Toledo Spiritas a result of spot rates being below the fixed rate, and we pay Teekay Corporation any amounts payable to us by the charterer of the~~~~Toledo Spirit~~~~as a result of spot rates being in excess of the fixed rate.~~

Please see “Item 5 – Operating and Financial Review and Prospects: Critical Accounting Estimates – Valuation of Derivative Instruments,” which explains how our derivative instruments are valued, including the significant factors and uncertainties in determining the estimated fair value and why changes in these factors result in material variances in realized and unrealized gain (loss) on non-designated derivative instruments.

For 2015, foreign currency exchange gains included the revaluation of our Euro-denominated cash, restricted cash and debt of $25.6 million and the revaluation of our NOK-denominated debt of $54.7 million. These gains were partially offset by realized losses of ($7.6) million on ~~NOK-denominated~~settlements of our cross currency swaps and ~~Euro-denominated monetary liabilities reflect a stronger U.S. Dollar against the~~unrealized losses of ($57.8) million on our cross currency swaps primarily due to depreciation of long-term NOK ~~and Euro on the date of revaluation or settlement compared~~forward exchange rates relative to ~~the rate in effect at~~ the beginning of ~~the period.~~

2015.

For 2014, foreign currency exchange ~~losses include realized losses of $2.2 million and unrealized losses of $51.8 million on our cross-currency swaps and unrealized~~ gains ~~of $48.8 million on the revaluation of our NOK-denominated debt. For 2014, foreign currency exchange losses also include~~included the revaluation of our Euro-denominated restricted cash and debt resulting in an unrealized gain of $34.3 million and revaluation of our NOK-denominated debt of $48.8 million.

~~For 2013, foreign currency exchange losses include~~ These gains were partially offset by realized losses of ~~$0.3~~($2.2) million on settlements of our cross currency swaps and unrealized losses of ~~$15.4~~($51.8) million on our cross-currency swaps and unrealized gains of $12.3 million on the revaluation of our NOK-denominated debt. For 2013, foreign currency exchange losses also include the revaluation of our Euro-denominated restricted cash, debt and capital leases resulting in an unrealized loss of $12.5 million.

~~Other Income (Expense).~~~~Other income decreased by $0.5 million for 2014 compared to 2013~~ primarily due to ~~one~~depreciation of ~~our~~long-term NOK forward exchange rates relative to the beginning of 2015.

Our business model is to employ our vessels on fixed-rate contracts primarily with ~~major oil~~large energy companies ~~with original terms typically between 10~~and their transportation subsidiaries. Prior to ~~25 years. The~~the fourth quarter of 2015, the operating cash flow generated by our vessels ~~generate~~ each quarter, excluding a reserve for maintenance capital expenditures and debt repayments, ~~are~~was generally paid out to our unitholders and General Partner as cash distributions within approximately 45 days after the end of each quarter. Global crude oil prices have significantly declined since mid-2014 and has contributed to depressed natural gas prices. Lower oil prices may negatively affect both the competitiveness of natural gas as a fuel for power generation and the market price of natural gas, to the extent that natural gas prices are benchmarked to the price of crude oil. These declines in energy prices, combined with other factors beyond our control, have adversely affected energy and master limited partnership capital markets and available sources of financing. Based on upcoming capital requirements for our committed growth projects and scheduled debt repayment obligations, coupled with relative weakness in energy and master limited partnership capital markets, we believe that it is in the best interests of our unitholders to conserve more of our internally generated cash flows to fund future growth projects and to reduce debt levels. Consequently, effective for the quarterly distribution for the fourth quarter of 2015, we reduced our quarterly cash distribution per common unit to $0.14 from $0.70.

Our liquidity needs beyond 2018 are currently expected to decline compared to 2017 to 2018, as a majority of our capital expenditures commitments relate to ~~expansion and maintenance capital expenditures and debt repayment. Expansion capital expenditures primarily represent the purchase or construction of vessels~~2017 to the extent the expenditures increase the operating capacity or revenue generated by our fleet, while maintenance capital expenditures primarily consist of dry-docking expenditures and expenditures to replace vessels in order to maintain the operating capacity or revenue generated by our fleet.2018. Our ~~primary sources of funds for our long-term liquidity needs are from cash from operations, long-term bank borrowings and other debt or equity financings, or a combination thereof. Consequently, our~~ ability to continue to expand the size of our fleet over the long-term is dependent upon our ability to generate operating cash flow, obtain long-term bank borrowings and other debt, as well as ~~raising equity.~~

our ability to raise debt or equity financing through public or private offerings.

Our revolving credit facilities and term loans are described in ~~“Item 18 –~~Item 1 - Financial Statements: Note 9 –- Long-Term Debt.” They contain covenants and other restrictions typical of debt financing secured by vessels, ~~that~~which restrict the ~~ship-owning~~vessel-owning subsidiaries from: incurring or guaranteeing indebtedness; changing ownership or organizational structure, including mergers, consolidations, liquidations and dissolutions; ~~making~~paying dividends or distributions if we are in default; making capital expenditures in excess of specified levels; making certain negative pledges and granting certain liens; selling, transferring, assigning or conveying assets; making certain loans and investments; and entering into a new ~~line~~lines of business. Certain of our revolving credit facilities and term loans require us to maintain financial covenants. If we do not meet these financial covenants, the lender may accelerate the repayment of ~~the~~our revolving credit facilities and term loans, ~~thus having~~which would have a significant impact on our short-term liquidity requirements. As at December 31, ~~2014,~~2016, we and our affiliates were in compliance with all covenants relating to our credit facilities and term loans.

As at December 31, ~~2014,~~2016, we had two facilities with an aggregate outstanding loan balance of $127.8 million that require us to maintain minimum vessel-value-to-outstanding-loan-principal-balance ratios ranging from 110% to 115%, which as at December 31, 2016 ranged from 133% to 209%. The vessel values were determined using a current market value for comparable second-hand vessels. Since vessel values can be volatile, our estimate of market value may not be indicative of either the current or future price that could be obtained if the related vessels were actually sold.

As ofat December 31, ~~2014,~~2016, we had a working capital deficit of ~~$117.9 million. The working capital deficit includes a $57.7~~$29.0 million, ~~outstanding balance on one~~which is primarily the result of $47.3 million of our ~~debt facilities that matures~~NOK bonds maturing in May 2017, and $26.0 million of current capital lease obligations relating to one Suezmax tanker under which the ~~second quarter of 2015.~~owner has the option to require us to purchase the vessels. We expect to ~~refinance this debt facility before it comes due.~~

~~We expect to~~ manage ~~the remaining portion of~~ our working capital deficit primarily with net operating cash ~~flow,~~flows, dividends from our equity accounted joint ventures, debt ~~refinancing~~refinancings and, to a lesser extent, existing undrawn revolving credit facilities. As at December 31, ~~2014,~~2016, we had undrawn ~~medium-term~~revolving credit facilities of ~~$135.6~~$243.7 million.

In addition, in January 2017, we raised in the Norwegian bond market, NOK 300 million (equivalent to approximately $36 million) in new senior unsecured bonds through an add-on to our existing NOK bonds due in October 2021 and received $40 million in cash distributions in February 2017 from the RasGas 3 Joint Venture upon completion of its debt refinancing in December 2016, which were partially offset by our additional equity investment of $57 million in the Teekay LNG-Marubeni Joint Venture upon completion of its debt refinancing in March 2017.

As described under “Item 4 – Information on the ~~Company: C.~~Partnership: B. Operations - Regulations,” passage of any climate control legislation or other regulatory initiatives that restrict emissions of greenhouse gases could have a significant financial and operational impact on our business, which we cannot predict with certainty at this time. Such regulatory measures could increase our costs related to operating and maintaining our vessels and require us to install new emission controls, acquire allowances or pay taxes related to our greenhouse gas emissions, or administer and manage a greenhouse gas emissions program. In addition, increased regulation of greenhouse gases may, in the long term, lead to reduced demand for oil and gas and reduced demand for our services.

Net cash flow from operating activities depends upon the timing and amount of dry-docking expenditures, repair and maintenance activity, the impact of vessel additions and dispositions on operating cash flows, foreign currency rates, changes in interest rates, timing of dividends received from equity accounted investments, fluctuations in working capital balances and spot market hire rates (to the extent we have vessels operating in the spot tanker market or our hire rates are partially affected by spot market rates). The number of vessel dry dockings tends to vary each period depending on the ~~vessel’s~~vessels’ maintenance schedule.

Our equity accounted joint ventures are generally required to distribute all available cash to ~~its shareholders.~~their owners. However, the timing and amount of dividends from each of our equity accounted joint ventures may not necessarily coincide with the ~~net income or~~ operating cash flow generated from each respective equity accounted joint venture. The timing and amount of dividends distributed by our equity accounted joint ventures are affected by the timing and amounts of debt repayments in the joint ventures, capital requirements of the joint ventures, as well as any cash reserves maintained in the joint ventures for operations, capital expenditures and/or as required under financing agreements.

Net cash flow used for financing activities was $84.4 million in 2015, compared to cash flow from financing activities of $100.1 million in 2014, primarily as a result of an increase in restricted cash of $30.3 million in 2015 compared to a $448.9 million decrease in restricted cash in 2014, $146.8 million lower proceeds from equity offerings, $56.2 million lower proceeds from debt financings net of scheduled repayments, prepayments and debt issuance costs, due to the completed debt refinancing in the Teekay Nakilat Joint Venture ~~refinancing its term loan that was~~in 2014, and a $15.0 million increase in cash distributions paid to our common unitholders and General Partner. These increases were partially offset by a $474.7 million decrease in prepayments of capital lease obligations due ~~in 2019 of $278.2 million, as of September 30, 2014, with a new US Dollar-denominated term loan of $450.0 million due in 2026. From time~~ to time, we refinance our loans and revolving credit facilities. During 2014, we primarily used the proceeds from the issuance of securities and long-term debt to acquire and fund our proportionate interest of newbuilding installments in the BG Joint Venture and the Yamal Joint Venture, fund the acquisition of ~~the~~~~Norgas Napa~~ in November 2014, to fund construction costs for our eight LNG newbuildings, to fund the acquisition of three LNG carriers under capital lease (of which a portion of the repayment was from the release of restricted cash deposits), and to prepay and repay outstanding debt under our revolving credit facilities. The decrease in restricted cash was used to acquire the RasGas II LNG Carriers under capital lease in the Teekay Nakilat Joint ~~Venture. During 2013, we~~Venture in 2014, and $41.1 million less dividends paid to non-controlling interest. The increase in restricted cash in 2015 primarily ~~used~~resulted from a $28.6 million increase in 2015 due to a higher margin call collateral related to our NOK cross-currency swaps, and the ~~proceeds from the issuance of securities and long-term debt~~$448.9 million decrease in 2014 primarily related to ~~fund the acquisition of our 50% interest in the Exmar LPG Carriers, to fund~~ the acquisition of the ~~Awilco~~RasGas II LNG Carriers ~~to fund construction costs for our five LNG newbuilding carriers, to provide an advance to Exmar LPG BVBA for the purpose of funding newbuildings, to prepay and repay outstanding debt~~ under ~~our revolving credit facilities, and for general partnership purposes. During 2012, we primarily used the proceeds from long-term debt to fund the acquisition of our 52% interest~~capital lease in the ~~six MALT LNG Carriers, to fund the first installment payment for two LNG newbuildings, to fund the acquisition of~~Teekay Nakilat Joint Venture funded by our ~~33% interest~~restricted cash in ~~the fourth Angola LNG Carrier, to prepay and repay outstanding debt under our revolving credit facilities and for general corporate purposes.~~

~~During the fourth quarter of 2014, we sold an aggregate of approximately 1.1 million common units under the continuous offering program (or~~~~COP~~) for net proceeds of $41.7 million. On July 17, 2014, we completed a public offering of 3.1 million common units at a price of $44.65 per unit, for net proceeds of approximately $140.5 million. On October 7, 2013, we completed a public offering of approximately 3.5 million common units at a price of $42.62 per unit, for net proceeds of $144.8 million. On July 30, 2013, we completed a direct equity placement of approximately 0.9 million common units for net proceeds of $40.8 million. On May 22, 2013, we implemented the COP and sold an aggregate of approximately 0.1 million common units during 2013 for net proceeds of $4.9 million. On September 10, 2012, we completed a public offering of approximately 4.8 million common units at a price of $38.43 per unit, for net proceeds of $182.3 million. Please read “Item 18 – Financial Statements: Note 15 – Total Capital and Net Income Per Unit.”

2014. Cash distributions paid during ~~2014~~2015 increased to $255.5 million from $240.5 million ~~from $215.4 million~~ for ~~2013. This increase was the result of:~~

2014 due to an increase in the number of common units eligible to receive ~~the~~ cash ~~distribution~~distributions from us as a result of ~~the~~ equity offerings during 2014 and ~~2013;~~2015 and

an increase in our quarterly cash distribution to $0.7000 per common unit from $0.6918 per common unit ~~from $0.6750 per unit starting with~~paid in the first quarter ~~distribution in 2014.~~

~~Cash distributions paid during 2013 increased to $215.4 million from $195.9 million for 2012. This increase was the result of:~~

~~an increase in the number~~ of ~~units eligible to receive the cash distribution as a result of the equity offerings during 2013 and 2012; and~~

2015.

~~an increase in our quarterly distribution to $0.6750 per unit from $0.6300 per unit starting with the second quarter distribution in 2012.~~

After December 31, ~~2014, a~~2016, cash ~~distribution totaling $63.6~~distributions of $11.4 million ~~was~~were declared to holders of common units with respect to the fourth quarter of ~~2014,~~2016, which was paid in February ~~2015. This~~2017. In addition, we paid cash ~~distribution reflected an increase~~dividends of $2.7 million on the preferred units in ~~our quarterly distribution to $0.7000 per unit from $0.6918 per unit.~~

January 2017.

Investing Cash ~~Flows~~Flows. Net cash flow from investing activities was $12.1 million in 2016 compared to net cash flow used for investing activities of $212.5 million in 2015. During 2016, we received $355.3 million from the sale-leaseback financing transactions completed on the Creole Spirit and Oak Spirit in February and July 2016, respectively, and we received $94.3 million in proceeds from the sales of the Bermuda Spirit and Hamilton Spirit in April 2016 and May 2016, respectively. Receipts from direct financing leases increased by $7.8 million due to the timing of payments. We contributed $120.9 million to our equity accounted joint ventures in 2016 compared to $25.9 million in 2015, primarily to fund newbuilding installments in the Yamal LNG Joint Venture and project expenditures for the Bahrain LNG project. During 2016, we used $345.8 million for capital expenditures, primarily for newbuilding installment payments and shipbuilding supervision costs for our LNG carrier newbuildings, compared to $192.0 million in 2015. During 2016, we received a $5.5 million repayment of a shareholder loan from the Exmar LPG Joint Venture, compared to $23.7 million repayment of a shareholder loan from the Exmar LPG Joint Venture during 2015. There was no change in the amount of the $34.3 million relating to a performance bond placed in 2015 on the Bahrain LNG Joint Venture project.

Net cash flow used infor investing activities decreased to ~~$271.6~~$212.5 million in ~~2014~~2015 from ~~$492.3~~$271.0 million in ~~2013.~~2014. We used cash of $192.0 million, primarily relating to newbuilding installment payments and shipbuilding supervision costs for our LNG carrier newbuildings. Restricted cash increased in 2015 by $34.3 million relating to a performance bond placed on the Bahrain LNG Joint Venture project. In addition, we used cash of $25.9 million to provide capital to our equity accounted investments primarily to prepay debt within the Teekay LNG-Marubeni Joint Venture, partially offset by a $23.7 million shareholder loan repayment to us by Exmar LPG BVBA in 2015. During 2014, we used cash of $100.2 million primarily to acquire and fund our proportionate interest of newbuilding installments in the BG Joint Venture and the Yamal LNG Joint Venture, $140.4 million relating to newbuilding installments for our ~~eight~~wholly-owned LNG carrier newbuildings, ~~equipped with the MEGI twin engines,~~ $23.1 million relating to the early termination fee on the termination of the leasing of the RasGas II LNG Carriers (which was capitalized as part of the vessels’ costs) and $21.6 million, which is net of $5.4 million owing to Skaugen, to fund our acquisition of theNorgas Napa in November 2014, and $3.8 million relating to certain vessel upgrades. During 2013, we used cash of $308.0 million to fund the acquisitions of two LNG carriers from Awilco in September and November 2013, $135.8 million to fund our 50% interest in the Exmar LPG Carriers and $58.6 million incurred for our three additional LNG newbuilding carriers ordered in July and November 2013. During 2012, we used cash of $151.0 million (including working capital contribution and acquisition costs) to fund the acquisition of our 52% interest in the six MALT LNG Carriers, $38.6 million to fund the first installment payment for two LNG newbuildings and $19.1 million for our acquisition of a 33% interest in the fourth and last Angola LNG Carrier.

Credit Facilities

Our revolving credit facilities and term loans are described in Item 18 – Financial Statements: Note 9 – Long-Term Debt. Our term loans and revolving credit facilities contain covenants and other restrictions typical of debt financing secured by vessels, including, among others, one or more of the following that restrict the ship-owning subsidiaries from:

incurring or guaranteeing indebtedness;

changing ownership or structure, including mergers, consolidations, liquidations and dissolutions;

making dividends or distributions if we are in default;

making capital expenditures in excess of specified levels;

making certain negative pledges and granting certain liens;

selling, transferring, assigning or conveying assets;

making certain loans and investments; and

entering into a new line of business.

Certain loan agreements require (a) that minimum levels of tangible net worth and aggregate liquidity be maintained, (b) that we maintain certain ratios of vessel values as it relates to the relevant outstanding loan principal balance, (c) that we do not exceed a maximum amount of leverage and (d) ~~one~~certain of our subsidiaries to maintain restricted cash deposits. ~~We have one facility~~As at December 31, 2016, we had two facilities with an aggregate outstanding loan balance of $127.8 million that ~~requires~~require us to maintain aminimum vessel-value-to-outstanding-loan-principal-balance ~~ratio of~~ratios ranging from 110% to 115%, which as at December 31, ~~2014, was 158%~~2016 ranged from 133% to 209%. The vessel ~~value is~~values were determined using ~~reference to~~a current market value for comparable second-hand ~~market comparables or using a depreciated replacement cost approach.~~vessels. Since vessel values can be volatile, our ~~estimates~~estimate of market value may not be indicative of either the current or future ~~prices~~price that could be obtained if ~~we sold any of~~ the ~~vessels.~~related vessel was actually sold. Our ship-owning subsidiaries may not, among other things, pay dividends or distributions if they are in default under their term loans or revolving credit facilities. One of our term loans is guaranteed by Teekay Corporation and contains covenants that require Teekay Corporation to maintain the greater of a minimum liquidity (cash and cash equivalents) of at least $50.0 million and 5.0% of Teekay Corporation’s total consolidated debt which has recourse to Teekay Corporation. As at December 31, ~~2014,~~2016, we and our affiliates were in compliance with all covenants relating to our credit facilities and capital leases.

Contractual Obligations and Contingencies

The following table summarizes our contractual obligations as at December 31, ~~2014:~~

      2016    2018
      and    and    Beyond
   Total    2015    2017    2019    2019
   (in millions of U.S. Dollars)
U.S. Dollar-Denominated Obligations:

Long-term debt⁽¹⁾
   1,424.4    141.6    175.8    570.2    536.8
Commitments under capital leases⁽²⁾
   73.7    7.8    38.6    27.3    —
Commitments under operating leases⁽³⁾
   343.7    24.1    48.2    48.2    223.2
Newbuilding installments/shipbuilding supervision⁽⁴⁾
   2,462.7    188.9    1,092.9    979.8    201.1










Total U.S. Dollar-denominated obligations
4,304.5 362.4 1,355.5 1,625.5 961.1










Euro-Denominated Obligations:⁽⁵⁾

Long-term debt⁽⁶⁾
285.0 15.6 34.6 153.7 81.1










Total Euro-denominated obligations
285.0 15.6 34.6 153.7 81.1










Norwegian Kroner-Denominated Obligations:⁽⁵⁾

Long-term debt⁽⁷⁾
214.7 —   93.9 120.8 —










Total Norwegian Kroner-Denominated obligations
214.7 —   93.9 120.8 —










Totals
4,804.2 378.0 1,484.0 1,900.0 1,042.2

2016:



	Total	2017	2018	2019	2020	2021	Beyond 2021
	(in millions of U.S. Dollars)
U.S. Dollar-Denominated Obligations:
Long-term debt:⁽¹⁾
Scheduled repayments	460.5	102.2	81.4	53.2	52.7	31.1	139.9
Repayments at maturity	753.0	25.0	409.4	20.4	—	142.9	155.3
Commitments under capital leases⁽²⁾	536.3	61.0	57.3	30.1	30.1	30.1	327.7
Commitments under operating leases⁽³⁾	295.5	24.1	24.1	24.1	24.1	24.1	175.0
Newbuilding installments/shipbuilding supervision⁽⁴⁾	2,876.9	1,050.0	1,067.2	561.1	198.6	—	—
Total U.S. Dollar-denominated obligations	4,922.2	1,262.3	1,639.4	688.9	305.5	228.2	797.9
Euro-Denominated Obligations:⁽⁵⁾
Long-term debt⁽⁶⁾	219.7	15.6	124.8	8.9	9.6	10.3	50.5
Total Euro-denominated obligations	219.7	15.6	124.8	8.9	9.6	10.3	50.5
Norwegian Kroner-Denominated Obligations:⁽⁵⁾
Long-term debt⁽⁷⁾	371.3	47.3	104.2	—	115.7	104.1	—
Total Norwegian Kroner-Denominated obligations	371.3	47.3	104.2	—	115.7	104.1	—
Totals	5,513.2	1,325.2	1,868.4	697.8	430.8	342.6	848.4

~~(1)~~

1.

Excludes expected interest payments of ~~$23.3~~$28.8 million ~~(2015)~~(2017), ~~$42.2~~$20.8 million ~~(2016~~(2018), $13.6 million (2019), $12.5 million (2020), $10.2 million (2021) and ~~2017), $24.6 million (2018 and 2019) and $38.6~~$29.8 million (beyond ~~2019)~~2021). Expected interest payments are based on the existing interest rates (fixed-rate loans) and LIBOR at December 31, ~~2014,~~2016, plus margins on debt that has been drawn that ~~ranged~~ranges up to 2.80% (variable-rate loans). The expected interest payments do not reflect the effect of related interest rate swaps or swaptions that we have used as an economic hedge offor certain of our variable-rate debt.

In addition, the above table does not reflect scheduled debt repayments in our equity accounted joint ventures.

Upon the completion of the Teekay-LNG Marubeni Joint Venture’s debt refinancing in March 2017, we invested $57.2 million of additional equity into the Teekay-LNG Marubeni Joint Venture through a $44.2 million payment in March 2017 and a $13.0 million payment in April 2017, which is not reflected in the table above.

~~(2)~~

2.

Includes, in addition to lease payments, amounts we may be or are required to pay to purchase the leased vessels at the end of their respective lease terms. ~~The~~For two of our four capital lease obligations, the lessor has the option to sell ~~these vessels~~two Suezmax tankers under capital lease to us at any time during the remaining lease ~~term;~~terms; however, in this table we have assumed the lessor will not exercise its right to sell the ~~vessels~~two Suezmax tankers to us until after the lease term ~~expire,~~expires, which is during the years 2017 toand 2018. The purchase price for any ~~vessel~~Suezmax tanker we are required to purchase would be based on the unamortized portion of the vessel construction financing costs for the vessels, which are included in the table above. We expect to satisfy any such purchase price by assuming the existing vessel financing, although we may be required to obtain separate debt or equity financing to complete any purchases if the lenders do not consent to our assuming the financing obligations. Please read “Item 1 –- Financial Statements: Note ~~4 –~~5 - Leases and Restricted ~~Cash.”~~

Cash”.

~~(3)~~
3.	We have corresponding leases whereby we are the lessor and expect to receive ~~an aggregate of~~ approximately ~~$303.7~~$260.3 million ~~for~~under these leases from ~~2015~~2017 to 2029. ~~Please read “Item 18 – Financial Statements: Note 4 – Leases and Restricted Cash.”~~

~~(4)~~

~~Between~~

4.

As of December ~~2012 and December 2014,~~31, 2016, we ~~entered into~~have agreements for the construction of ~~eight~~nine wholly-owned LNG ~~newbuildings. The~~carrier newbuildings, for which the estimated remaining ~~cost~~costs for these newbuildings totaled ~~$1,445.4 million as of December 31, 2014,~~$1.5 billion, including estimated interest and construction supervision fees.

We have secured $857.1 million of financing related to the commitments for five of the LNG carrier newbuildings included in the table above.

As part of the acquisition of an ownership interest in the BG Joint Venture, we agreed to assume ~~BG’s~~Shell’s obligation to provide shipbuilding supervision and crew training services for the four LNG carrier newbuildings and to fund our proportionate share of the remaining newbuilding installments. The estimated remaining costs for the shipbuilding supervision and crew training services and our proportionate share of newbuilding installments ~~net~~totaled $195.6 million as of ~~the secured financing within the joint venture for the LNG carrier newbuildings, totaled $89.4 million.~~December 31, 2016. However, as part of this agreement with ~~BG,~~Shell, we expect to recover ~~approximately $20.3~~$10.9 million of the shipbuilding supervision and crew training costs from Shell between 2017 and 2019 and the BG ~~between 2015 and 2019.~~

Joint Venture has secured financing of $137.1 million based on our proportionate share of the remaining newbuilding installments as of December 31, 2016.

In July 2014, the Yamal LNG Joint Venture, in which we have a 50% ownership interest, entered into agreements for the construction of six LNG carrier newbuildings. As at December 31, ~~2014,~~2016, our 50% share of the estimated remaining ~~cost~~costs for these six newbuildings totaled ~~$928.0~~$883.0 million. The Yamal LNG Joint Venture intends to secure debt financing for ~~70%~~approximately 80% of the estimated fully built-up cost of the six newbuildings, which is estimated to ~~80%~~be $2.1 billion.

The Bahrain LNG Joint Venture, in which we have a 30% ownership interest, is developing an LNG receiving and regasification terminal in Bahrain. The project will be owned and operated under a 20-year agreement commencing in early-2019 with an estimated fully-built up cost of approximately $960.0 million. As at December 31, 2016, our 30% share of the estimated remaining costs is $224.1 million. The Bahrain LNG Joint Venture has secured debt financing for approximately 75% of the fully built-up cost of the ~~six newbuildings.~~

LNG receiving and regasification terminal in Bahrain.

The table above ~~excludes nine~~includes our proportionate share of the newbuilding costs for four LPG ~~carriers~~carrier newbuildings scheduled for delivery between ~~early-2015~~2017 and 2018 in the ~~joint venture between~~ Exmar ~~and us.~~LPG Joint Venture. As at December 31, ~~2014,~~2016, our 50% share of the estimated remaining ~~cost~~costs for these ~~nine~~four newbuildings totaled ~~$190.2~~$77.5 million, including estimated interest and construction supervision fees.

The Exmar LPG Joint Venture has secured financing for the four LPG carrier newbuildings.

~~(5)~~
5.	Euro-denominated and NOK-denominated obligations are presented in U.S. Dollars and have been converted using the prevailing exchange rate as of December 31, ~~2014.~~ 2016.

~~(6)~~

6.

Excludes expected interest payments of ~~$4.3~~$2.5 million ~~(2015)~~(2017), ~~$7.9~~$1.3 million ~~(2016~~(2018), $0.2 million (2019), $0.2 million (2020), $0.2 million (2021) and ~~2017), $2.7 million (2018 and 2019) and $1.4~~$0.2 million (beyond ~~2019)~~2021). Expected interest payments are based on EURIBOR at December 31, ~~2014,~~2016, plus margins that ~~ranged~~range up to 2.25%, as well as the prevailing U.S. Dollar/Euro exchange rate as of December 31, ~~2014.~~2016. The expected interest payments do not reflect the effect of related interest rate swaps that we have used as an economic hedge of certain of our variable-rate debt.

~~(7)~~
7. Excludes expected interest payments of ~~$13.7~~$15.5 million ~~(2015)~~(2017), ~~$23.0~~$16.8 million ~~(2016~~(2018), $12.9 million (2019), $10.2 million (2020), and ~~2017) and $4.8~~$3.7 million ~~(2018 and 2019)~~(2021). Expected interest payments are based on NIBOR at December 31, ~~2014,~~2016, plus margins that range up to ~~5.25%~~6.00%, as well as the prevailing U.S. Dollar/NOK exchange rate as of December 31, ~~2014.~~2016. The expected interest payments do not reflect the effect of the related cross-currency ~~swap~~swaps that we have used as an economic hedge of our foreign exchange and interest rate exposure associated with our NOK-denominated long-term debt.

Off-Balance Sheet Arrangements

We have no off-balance sheet ~~arrangements.~~arrangements that have or are reasonably likely to have, a current or future material effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources. The details of our equity accounted investments are shown in Item 18 – Financial Statements: Note 56 – Equity ~~Method~~Accounted Investments.

Critical Accounting Estimates

We prepare our consolidated financial statements in accordance with GAAP, which ~~require~~requires us to make estimates in the application of our accounting policies based on our best assumptions, judgments and opinions. On a regular basis, management reviews the accounting policies, assumptions, estimates and judgments to ensure that our consolidated financial statements are presented fairly and in accordance with GAAP. However, because future events and their effects cannot be determined with certainty, actual results could differ from our assumptions and estimates, and such differences could be material. Accounting estimates and assumptions discussed in this section are those that we consider to be the most critical to an understanding of our financial statements, because they inherently involve significant judgments and uncertainties. For a further description of our material accounting policies, please read “Item 18 – Financial Statements: Note 1 – Summary of Significant Accounting Policies.”

Vessel Lives and Impairment

Description.The carrying value of each of our vessels represents its original cost at the time of delivery or purchase less depreciation and impairment charges. We depreciate the original cost, less an estimated residual value, of our vessels on a straight-line basis over each vessel’s estimated useful life. The carrying values of our vessels may not represent their market value at any point in time because the market prices of second-hand vessels tend to fluctuate with changes in charter rates and the cost of newbuildings. Both charter rates and newbuilding costs tend to be cyclical in nature.

We review vessels and equipment for impairment whenever events or circumstances indicate the carrying value of an asset, including the carrying value of the charter contract, if any, under which the vessel is employed, may not be recoverable. This occurs when the asset’s carrying value is greater than the future undiscounted cash flows the asset is expected to generate over its remaining useful life. For a vessel under charter, the discounted cash flows from that vessel may exceed its market value, as market values may assume the vessel is not employed on an existing charter. If the estimated future undiscounted cash flows of an asset ~~exceeds~~exceed the asset’s carrying value, no impairment is recognized even though the fair value of the asset may be lower than its carrying value. If the estimated future undiscounted cash flows of an asset is less than the asset’s carrying value and the fair value of the asset is less than its carrying value, the asset is written down to its fair value. Fair value is calculated as the net present value of estimated future cash flows, which, in certain circumstances, will approximate the estimated market value of the vessel.

Our business model is to employ our vessels on fixed-rate contracts with large energy companies and their transportation subsidiaries. These contracts generally have original terms between 10five to 25 years in length. Consequently, while the market value of a vessel may decline below its carrying value, the carrying value of a vessel may still be recoverable based on the future undiscounted cash flows the vessel is expected to obtain from servicing its existing contract and future contracts.

The following table presents by segment the aggregate market values and carrying values of certain of our vessels that we have determined have a market value that is less than their carrying value as of December 31, ~~2014.~~2016. Specifically, the following table reflects all such vessels, except those operating on contracts where the remaining term is significant and the estimated future undiscounted cash flows relating to such contracts are sufficiently greater than the carrying value of the vessels such that we consider it unlikely an impairment would be recognized in the following year. Consequently, the vessels included in the following table generally include those vessels near the end of existing charters or other operational contracts. While the market values of these vessels are below their carrying values, no impairment has been recognized on any of these vessels as the estimated future undiscounted cash flows relating to such vessels are greater than their carrying values.

We would consider the vessels reflected in the following table to be at a higher risk of future impairment. The estimated future undiscounted cash flows of the vessels reflected in the following table are significantly greater than their respective carrying values. Consequently, in these cases the following table would not necessarily represent vessels that would likely be impaired in the next 12 months, and the recognition of an impairment in the future for those vessels may primarily depend upon our deciding to dispose of the vessel instead of continuing to operate it. In deciding whether to dispose of a vessel, we determine whether it is economically preferable to sell the vessel or continue to operate it. This assessment includes an estimate of the net proceeds expected to be received if the vessel is sold in its existing condition compared to

the present value of the vessel’s estimated future revenue, net of operating costs. Such estimates are based on the terms of the existing charter, charter market outlook and estimated operating costs, given a vessel’s type, condition and age. In addition, we typically do not dispose of a vessel that is servicing an existing customer contract.

      Market Values⁽¹⁾    Carrying Values
(in thousands of U.S. Dollars, except number of vessels)    Number of Vessels    $    $
Reportable Segment

Conventional Tanker Segment⁽²⁾
   4    170,392    184,432



(in thousands of U.S. Dollars, except number of vessels) Reportable Segment ___________________________________	Number of Vessels	Market Values⁽¹⁾ $	Carrying Values $
Liquefied Gas Segment⁽²⁾	8	244,462	341,851
Conventional Tanker Segment⁽²⁾	3	58,276	88,246
Total	11	302,738	430,097


(1)	Market values are determined using reference to second-hand market comparable values as at December 31, ~~2014.~~2016. Since vessel values can be volatile, our estimates of market value may not be indicative of either the current or future prices we could obtain if we sold any of the vessels.


(2)	Undiscounted cash flows are significantly greater than the carrying values.

Judgments and Uncertainties.Depreciation is calculated using an estimated useful life of 25 years for conventional tankers, 30 years for LPG Carriers and 35 years for LNG carriers, commencing at the date the vessel was originally delivered from the shipyard. However, the actual life of a vessel may be different than the estimated useful life, with a shorter actual useful life resulting in an increase in the quarterly depreciation and potentially resulting in an impairment loss. The estimated useful life of our vessels takes into account design life, commercial considerations and regulatory restrictions. Our estimates of future cash flows involve assumptions about future charter rates, vessel utilization, operating expenses, dry-docking expenditures, vessel residual values and the remaining estimated life of our vessels. Our estimated charter rates are based on rates under existing vessel contracts and market rates at which we expect we can re-charter our vessels. Our estimates of vessel utilization, including estimated off-hire time, are based on historical experience. Our estimates of operating expenses and dry-docking expenditures are based on historical operating and dry-docking costs and our expectations of future inflation and operating requirements. Vessel residual values are a product of a vessel’s lightweight tonnage and an estimated scrap rate. The remaining estimated lives of our vessels used in our estimates of future cash flows are consistent with those used in the calculation of depreciation.

Certain assumptions relating to our estimates of future cash flows are more predictable by their nature in our historical experience, including estimated revenue under existing contract terms, on-going operating costs and remaining vessel life. Certain assumptions relating to our estimates of future cash flows require more discretion and are inherently less predictable, such as future charter rates beyond the firm period of existing contracts and vessel residual values, due to factors such as the volatility in vessel charter rates and vessel values. We believe that the assumptions used to estimate future cash flows of our vessels are reasonable at the time they are made. We can make no assurances, however, as to whether our estimates of future cash flows, particularly future vessel charter rates or vessel values, will be accurate.

Effect if Actual Results Differ fromAssumptions.If we conclude that a vessel or equipment is impaired, we recognize a loss in an amount equal to the excess of the carrying value of the asset over its fair value at the date of impairment. The written-down amount becomes the new lower cost basis and will result in a lower annual depreciation expense than for periods before the vessel impairment.

Dry-docking Life

Description. We capitalize a portion of the costs we incur during dry docking and for an intermediate survey and amortize those costs on a straight-line basis over the useful life of the dry dock. We expense costs related to routine repairs and maintenance incurred during dry docking that do not improve operating efficiency or extend the useful lives of the assets.

Judgments and Uncertainties. Amortization of capitalized dry-dock expenditures requires us to estimate the period of the next dry docking and useful life of dry-dock expenditures. While we typically dry dock each vessel every five years and have a shipping society classification intermediate survey performed on our LNG and LPG carriers between the second and third year of the five-year dry-docking period, we may dry dock the vessels at an earlier date, with a shorter life resulting in an increase in the amortization.

Effect if Actual Results Differ from Assumptions. If we change our estimate of the next dry-dock date for a vessel, we will adjust our annual amortization of dry-docking expenditures. Amortization expense of capitalized dry-dock expenditures for 2016, 2015, and 2014 ~~2013 and 2012~~ were ~~$14.8~~$11.5 million, ~~$13.4~~$10.1 million, and ~~$13.1~~$14.8 million, respectively. As at December 31, ~~2014, 2013~~2016, 2015, and ~~2012,~~2014, our capitalized dry-dock expenditures ~~were $13.5~~were$13.9 million, ~~$27.2~~$10.4 million, and ~~$7.5~~$13.5 million, respectively. A one-year reduction in the estimated useful lives of capitalized dry-dock expenditures would result in an increase in our current annual amortization by approximately ~~$3.0~~$2.8 million.

Goodwill and Intangible Assets

Description. We allocate the cost of acquired companies, including acquisitions of equity accounted investments, to the identifiable tangible and intangible assets and liabilities acquired, with the remaining amount being classified as goodwill. Certain intangible assets, such as time-charter contracts, are being amortized over time. Our future operating performance will be affected by the amortization of intangible assets and potential impairment charges related to goodwill and intangibles. Accordingly, the allocation of purchase price to intangible assets and goodwill may significantly affect our future operating results.

Goodwill is not amortized, but reviewed for impairment at the reporting unit level on an annual basis or more frequently if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit to below its carrying value. When goodwill is

reviewed for impairment, we may elect to assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount, including goodwill. Alternatively, we may bypass this step and use a fair value approach to identify potential goodwill impairment and, when necessary, measure the amount of impairment. The Partnership uses a discounted cash flow model to determine the fair value of reporting units, unless there is a readily determinable fair market value. Intangible assets are assessed for impairment when and if impairment indicators exist. An impairment loss is recognized if the carrying amount of an intangible asset is not recoverable and its carrying amount exceeds its fair value.

Judgments and Uncertainties. The allocation of the purchase price of acquired companies to intangible assets and goodwill requires management to make significant estimates and assumptions, including estimates of future cash flows expected to be generated by the acquired assets and the appropriate discount rate to value these cash flows. In addition, the process of evaluating the potential impairment of goodwill and intangible assets is highly subjective and requires significant judgment at many points during the analysis. The fair value of our reporting units was estimated based on discounted expected future cash flows using a weighted-average cost of capital rate. The estimates and assumptions regarding expected cash flows and the discount rate require considerable judgment and are based upon existing contracts, historical experience, financial forecasts and industry trends and conditions.

At December 31, ~~2014,~~2016, we had one reporting unit with goodwill attributable to it. As of the date of this filing, we do not believe that there is a reasonable possibility that the goodwill attributable to this reporting unit might be impaired within the next year. However, certain factors that impact this assessment are inherently difficult to forecast and as such we cannot provide any assurances that an impairment will or will not occur in the future. An assessment for impairment involves a number of assumptions and estimates that are based on factors that are beyond our control. These are discussed in more detail in ~~the following section entitled in~~ Part I – Forward-Looking Statements.

Amortization expense of intangible assets for each of the years 2016, 2015, and 2014 ~~2013 and 2012~~ was ~~$9.2~~$8.9 million, ~~$13.1~~$8.9 million, and ~~$11.0~~$9.2 million, respectively. If actual results are not consistent with our estimates used to value our intangible assets, we may be exposed to an impairment charge and a decrease in the annual amortization expense of our intangible assets.

Valuation of Derivative Instruments

Description. Our risk management policies permit the use of derivative financial instruments to manage interest rate risk, foreign exchange risk and spot tanker market risk. Changes in fair value of derivative financial instruments that are not designated as cash flow hedges for accounting purposes are recognized in earnings.

Judgments and Uncertainties.A substantial majority of the fair value of our derivative instruments and the change in fair value of our derivative instruments from period to period result from our use of interest rate swap agreements. The fair value of our ~~interest rate swap agreements~~derivative instruments is the estimated amount that we would receive or pay to terminate the agreements at the reporting date, taking into account current interest rates and the current credit worthiness of both us and the swap counterparties. The estimated amount is the present value of estimated future cash flows, being equal to the difference between the benchmark interest rate and the fixed rate in the interest rate swap agreement, multiplied by the notional principal amount of the interest rate swap agreement at each interest reset date.

The fair value of our interest and ~~currency~~cross-currency swap agreements at the end of each period are most significantly affected by the interest rate implied by the benchmark interest yield curve, including its relative steepness, and forward foreign exchange rates. Interest rates and foreign exchange rates have experienced significant volatility in recent years in both the short and long term. While the fair value of our interest and ~~currency~~cross-currency swap agreements are typically more sensitive to changes in short-term rates, significant changes in the long-term benchmark interest and foreign exchange rates also materially impact our interest and ~~currency~~cross-currency swap agreements.

The fair value of our interest and ~~currency~~cross-currency swap agreements are also affected by changes in our specific credit risk included in the discount factor. We discount our interest rate swap agreements with reference to the credit default swap spreads of similarly rated global industrial companies and by considering any underlying collateral. The process of determining credit worthiness requires significant judgment in determining which source of credit risk information most closely matches our risk profile.

The benchmark interest rate yield curve and our specific credit risk are expected to vary over the life of the interest rate swap agreements. The larger the notional amount of the interest rate swap agreements outstanding and the longer the remaining duration of the interest rate swap agreements, the larger the impact of any variability in these factors will be on the fair value of our interest rate swaps. We economically hedge the interest rate exposure on a significant amount of our long-term debt and for long durations. As such, we have historically experienced, and we expect to continue to experience, material variations in the period-to-period fair value of our derivative instruments.

The fair value of our derivative instrument relating to the agreement between us and Teekay Corporation for the Toledo Spirit time-charter contract is the estimated amount that we would receive or pay to terminate the agreement at the reporting date. This amount is estimated using the present value of our projected future spot market tanker rates, which has been derived from current spot market rates and long-term historical average rates.

Effect if Actual Results Differ fromAssumptions.Although we measure the fair value of our derivative instruments utilizing the inputs and assumptions described above, if we were to terminate the agreements at the reporting date, the amount we would pay or receive to terminate the derivative instruments may differ from our estimate of fair value. If the estimated fair value differs from the actual termination amount, an adjustment to the carrying amount of the applicable derivative asset or liability would be recognized in earnings for the current period. Such adjustments could be material. See “Item 18 – Financial Statements: Note 12 – Derivative ~~Instruments”~~Instruments and Hedging Activities” for the effects on the change in fair value of our derivative instruments on our consolidated statements of income and statements of comprehensive income.

Taxes

Description. We record a valuation allowance to reduce our deferred tax assets to the amount that is more likely than not to be realized.

Judgments and Uncertainties. The future realization of deferred tax assets depends on the existence of sufficient taxable income of the appropriate character in either the carryback or carryforward period. This analysis requires, among other things, the use of estimates and projections in determining future reversals of temporary differences, forecasts of future profitability and evaluating potential tax-planning strategies.

Effect if Actual Results Differ from Assumptions.If we determined that we were able to realize a net deferred tax asset in the future, in excess of the net recorded amount, an adjustment to the deferred tax assets would typically increase our net income ~~(or decrease our loss)~~ in the period such determination was made. Likewise, if we determined that we were not able to realize all or a part of our deferred tax asset in the future, an adjustment to the deferred tax assets would typically decrease our net income ~~(or increase our loss)~~ in the period such determination was made. As at December 31, ~~2014,~~2016, we had arecorded valuation ~~allowance~~allowances of ~~$58.4~~$41.1 million ~~(2013~~(2015 – ~~$73.1~~$53.2 million).

Item 6. Directors, Senior Management and Employees

~~Item 6. Directors, Senior Management and Employees~~

Management of Teekay LNG Partners L.P.

Teekay GP L.L.C., our General Partner, manages our operations and activities. Unitholders are not entitled to elect the directors of our General Partner or directly or indirectly participate in our management or operation.

Our General Partner owes a fiduciary duty to our unitholders. Our General Partner is liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are expressly nonrecourse to it. Whenever possible, our General Partner intends to cause us to incur indebtedness or other obligations that are nonrecourse to it.

The directors of our General Partner oversee our operations. ~~The day-to-day affairs of our business are managed by the officers of~~Effective February 1, 2017, our General Partner has a Corporate Secretary but does not have any other officers. Instead, the Partnership and ~~key employees~~our wholly-owned subsidiary, Teekay LNG Operating L.L.C. (or Opco), have entered into a services agreement with Teekay Gas Group Ltd. (or the Service Provider), a subsidiary of ~~certain of our operating subsidiaries.~~Opco. Employees of certain subsidiaries of Teekay Corporation provide ~~assistance~~various services to us ~~and~~including in the case of our operating subsidiaries, ~~pursuant to~~substantially all of their managerial, operational and administrative services ~~agreements.~~and other technical and advisory services, and in the case of the Partnership, various administrative services. Please read “Item 7 – Major Unitholders and Related Party Transactions.”

The Chief Executive Officer and Chief Financial Officer of our General Partner, Peter Evensen, allocates his time between managing our business and affairs and the business and affairs of Teekay Corporation and its subsidiaries Teekay Offshore (NYSE: TOO) and Teekay Tankers Ltd. (NYSE: TNK) (or~~Teekay Tankers~~). Mr. Evensen is the President and Chief Executive Officer of Teekay Corporation. He also holds the roles of Chief Executive Officer and Chief Financial Officer of Teekay Offshore’s general partner, Teekay Offshore GP L.L.C. The amount of time Mr. Evensen allocates between our business and the businesses of Teekay Corporation and Teekay Offshore varies from time to time depending on various circumstances and needs of the businesses, such as the relative levels of strategic activities of the businesses. We believe Mr. Evensen devotes sufficient time to our business and affairs as is necessary for their proper conduct.

~~Officers of our General Partner and those~~

Those individuals providing services to us or our subsidiaries may face a conflict regarding the allocation of their time between our business and the other business interests of Teekay Corporation or its affiliates. ~~Our General Partner seeks~~The various services agreements require the service providers to ~~cause its officers to devote as much time to~~provide the ~~management~~services diligently and in a commercially reasonable manner.

Directors of ~~our business and affairs as is necessary for the proper conduct of our business and affairs.~~

~~Directors and Executive Officers~~

Teekay GP L.L.C.

The following table provides information about the directors ~~and executive officers~~as at the date of our ~~General Partner and of our operating subsidiary Teekay Shipping Spain SL.~~Annual Report. Directors are elected for one-year terms. The business address of each of our directors ~~and executive officers~~ listed below is c/o 4^th4th Floor, Belvedere Building, 69 Pitts Bay Road, Hamilton, HM 08, Bermuda. ~~The business address of our key employee of Teekay Shipping Spain SL. is Musgo Street 5 – 28023, Madrid, Spain.~~ Ages of the individuals are as of December 31, ~~2014.~~

2016.



Name	Age	Position
Ida Jane Hinkley	66	Chairperson^(1)(2)(3)
Beverlee F. Park	54	Director^(1)(2)(3)
Vincent Lok	48	Director
C. Sean Day	67	Director⁽³⁾
Joseph E. McKechnie	58	Director^(1)(2)(3)


~~C. Sean Day~~ (1)		65		~~Chairman~~ Member of Audit Committee.


~~Peter Evensen~~ (2)		56		~~Chief Executive Officer, Chief Financial Officer and Director~~ Member of Conflicts Committee.


~~Beverlee F. Park~~	52	~~Director since March 11, 2014~~^(1)(3)(4)

~~Kenneth Hvid~~	46	~~Director~~

~~Ida Jane Hinkley~~	64	~~Director~~^(1)(2)(3)

~~Joseph E. McKechnie~~	56	~~Director~~⁽²⁾

~~George Watson~~	67	~~Director~~^(1)(2)(3)

~~Andres Luna~~	58	~~Managing Director, Teekay Shipping Spain SL~~

~~(1)~~

~~Member of Audit Committee.~~

~~(2)~~

~~Member of Conflicts Committee.~~

(3)	Member of Corporate Governance Committee.

~~(4)~~

Ms. Beverlee F. Park joined the Board of Directors, Corporate Governance Committee and assumed the role as Chair of the Audit Committee on March 11, 2014, replacing Mr. Robert E. Boyd, who retired from the Board of Directors on the same day.

Certain biographical information about each of these individuals is set forth below:

~~C. Sean Day~~~~has served~~

Ida Jane Hinkley serves as ~~Chairman~~Chair of Teekay GP L.L.C. since it was formed in November 2004. Mr. Day has also served as Chairman of the Board for Teekay Corporation since September 1999, Teekay Offshore GP L.L.C. since it was formed in August 2006. He served as a Chairman of Teekay Tankers Ltd. from October 2007 until June 2013. From 1989 to 1999, he was President and Chief Executive Officer of Navios Corporation, a large bulk shipping company based in Stamford, Connecticut. Prior to this, Mr. Day held a number of senior management positions in the shipping and finance industry. He is currently serving as a Director of Kirby Corporation and Chairman of Compass Diversified Holdings. Mr. Day is engaged as a consultant to Kattegat Limited, the parent company of Teekay’s largest shareholder, to oversee its investments, including that in the Teekay group of companies.

~~Peter Evensen~~has served as ~~Chief Executive Officer and Chief Financial Officer of Teekay GP L.L.C.~~director since it was formed in November 2004 and as a Director since January 2005. He has also served as Chief Executive Officer, Chief Financial Officer, and a Director of Teekay Offshore GP L.L.C., since it was formed in August 2006. He served as a Director of Teekay Tankers from October 2007 until June 2013. Effective April 1, 2011, he assumed the position of President and Chief Executive Officer of Teekay Corporation and also became a Director of Teekay Corporation. Mr. Evensen joined Teekay Corporation in May 2003 as Senior Vice President, Treasurer and Chief Financial Officer. He was appointed Executive Vice President and Chief Strategy Officer of Teekay Corporation in 2006. Mr. Evensen has over 30 years’ experience in banking and shipping finance. Prior to joining Teekay Corporation, Mr. Evensen was Managing Director and Head of Global Shipping at J.P. Morgan Securities Inc., and worked in other senior positions for its predecessor firms. His international industry experience includes positions in New York, London and Oslo.

~~Beverlee F. Park~~joined the Board of Teekay GP L.L.C. on March 11, 2014. From 2000 to 2013, Ms. Park served as Chief Operating Officer, Interim Chief Executive Officer, and Executive Vice President and Chief Financial Officer at TimberWest, the largest private forest land owner in Western Canada. During this time, Ms. Park also served as President and Chief Operating Officer, Couverdon Real Estate, a division of TimberWest. From 2003 to 2010, Ms. Park served as Board Member, Audit Committee Chair of BC Transmission Corp., the entity responsible for the operation and maintenance of 18,000km of electrical transmission in British Columbia and 300 substations. Previously, Ms. Park was employed by BC Hydro, British Columbia’s electricity, transmission and distribution utility company, in a range of senior financial roles and by KPMG. Ms. Park is currently a Board member of InTransit BC and of Silver Standard Resources Inc., serving as a member of the company’s Audit Committee and Safety and Sustainability Committee.

~~Kenneth Hvid~~has served as a Director of Teekay GP L.L.C. since April 1, 2011. Since April 2011, he has also served as Chief Strategy Officer and Executive Vice President of Teekay Corporation and as a Director of Teekay Offshore GP L.L.C. He joined Teekay Corporation in October 2000 and was responsible for leading its global procurement activities until he was promoted in 2004 to Senior Vice President, Teekay Gas Services. During this time, Mr. Hvid was involved in leading Teekay Corporation through its entry and growth in the LNG business. He held this position until the beginning of 2006, when he was appointed President of the Teekay Shuttle and Offshore division of Teekay Corporation. In this role, he is responsible for Teekay Corporation’s global shuttle tanker business as well as initiatives in the floating storage and offtake business and related offshore activities. Mr. Hvid has 26 years of global shipping experience, 12 of which were spent with A.P. Moller in Copenhagen, San Francisco and Hong Kong. In 2007 Mr. Hvid joined the Board or Directors of Gard P&I (Bermuda) Ltd.

~~Ida Jane Hinkley~~~~has served as a Director of Teekay GP L.L.C. since January~~ 2005. From 1998 to 2001, she served as Managing Director of Navion Shipping AS, a shipping company at that time affiliated with the Norwegian state-owned oil company Statoil ASA (and subsequently acquired by Teekay Corporation’s in 2003). From 1980 to 1997, Ms. Hinkley was employed by the Gotaas-Larsen Shipping Corporation, an international provider of marine transportation services for crude oil and gas (including LNG), serving as its Chief Financial Officer from 1988 to 1992 and its Managing Director from 1993 to 1997. She currently serves as a non-executive director on the Board of Premier Oil plc, a London Stock Exchange listed oil exploration and production company and as a non-executive director of Vesuvius plc, a

London Stock Exchange listed engineering company. From 2007 to 2008 she served as a non-executive director on the Board of Revus Energy ASA, a Norwegian listed oil company.

~~Joseph E. McKechnie~~

Beverlee F. Park joined the Board of Teekay GP L.L.C. in March 2014. From 2000 to 2013, Ms. Park served as COO, Interim CEO, and EVP/CFO at TimberWest, the largest private forest land owner in Western Canada. During this time, Ms. Park also served as President and COO, Couverdon Real Estate, a division of TimberWest. From 2003 to 2010, Ms. Park served as Board Member, Audit Committee Chair of BC Transmission Corp., the entity responsible for the operation and maintenance of 18,000km of electrical transmission in British Columbia and 300 substations. Previously, Ms. Park was employed by BC Hydro, British Columbia’s electricity, transmission and distribution utility company, in a range of senior financial roles and by KPMG. Ms. Park is currently a Board member of TransAlta Corporation, serving as a member of the Audit and Risk Committee and the Human Resources Committee, InTransit BC, serving as Chair of the Audit Committee, and of Silver Standard Resources Inc., serving as a member of the company’s Audit Committee and Safety and Sustainability Committee. She was appointed to the University of British Columbia’s Board of Governors in February 2016.

Vincent Lokjoined the board of Teekay GP L.L.C. in June 2015. Mr. Lok has served as Teekay Corporation’s Executive Vice President and Chief Financial Officer since 2007. He has held a number of finance and accounting positions with Teekay, including Controller from 1997 until his promotions to the positions of Vice President, Finance in 2002, Senior Vice President and Treasurer in 2004, and Senior Vice President and Chief Financial Officer in 2006. Mr. Lok has also served as the Chief Financial Officer of Teekay Tankers Ltd. since 2007. Prior to joining Teekay, Mr. Lok worked as a Chartered Accountant with Deloitte & Touche LLP. Mr. Lok is also a Chartered Financial Analyst.

C. Sean Day served as Chairman of Teekay GP L.L.C. since it was formed in November 2004 until June 2015 and continues to serve as a Director. Mr. Day has also served as Chairman of the Board for Teekay Corporation since September 1999 and for Teekay Offshore GP L.L.C., the general partner of Teekay Offshore, since it was formed in August 2006. He will resign as Chairman of those two entities effective June 15, 2017 but intends to continue on as a director of each. He served as a Chairman of Teekay Tankers Ltd. from October 2007 until June 2013. From 1989 to 1999, he was President and Chief Executive Officer of Navios Corporation, a large bulk shipping company based in Stamford, Connecticut. Prior to this, Mr. Day held a number of senior management positions in the shipping and finance industry. He is currently serving as a Director of Kirby Corporation and Chairman of Compass Diversified Holdings. Mr. Day is engaged as a consultant to Kattegat Limited, the parent company of Teekay’s largest shareholder, to oversee its investments, including that in the Teekay group of companies.

Joseph E. McKechnie joined the board of Teekay GP L.L.C. in February ~~19,~~ 2013. Mr. McKechnie is a retired United States Coast Guard Officer, having served for more than 23 years, many of which focused on marine safety and security with an emphasis on LNG. In 2000 he joined Tractebel LNG North America (formerly Cabot LNG) in Boston, Massachusetts as the Vice President of Shipping, where he oversaw the LNG shipping operations for the Port of Boston. From 2006 to 2011, Mr. McKechnie was transferred to London and then Paris to continue his work with SUEZ, (the parent company of Tractebel) and ultimately GDF-SUEZ, as the Senior Vice President of Shipping, and Deputy Head of the Shipping Department. He is a former member of the board of directors of Society of International Gas Tankers and Terminal Operators, and Gaz-Ocean, the GDF-SUEZ Owned LNG vessel operating company. In 2011, he left GDF-SUEZ following the successful merger of GDF and SUEZ, and ultimately formed J.E. McKechnie ~~LLC~~L.L.C. in early 2011.

~~George Watson~~

Our Management

Our General Partner has a Corporate Secretary but does not have any other officers. On February 1, 2017, the Partnership and its wholly-owned subsidiary, Opco, entered into a service agreement with the Service Provider, a subsidiary of Opco. The following table provides certain information about the senior management team that is principally responsible for our operations and their positions in the Service Provider as at the date of this Annual Report. The business address of each of the executive officers of the Service Provider and the Corporate Secretary of our General Partner listed below is c/o 4th Floor, Belvedere Building, 69 Pitts Bay Road, Hamilton, HM 08, Bermuda.



Name	Age	Position
Mark Kremin	46	President and Chief Executive Officer, Teekay Gas Group Ltd. - effective February 1, 2017
Brody Speers	33	Chief Financial Officer, Teekay Gas Group Ltd. - effective February 1, 2017
Edith Robinson	52	Corporate Secretary, Teekay GP L.L.C.; Corporate Secretary, Teekay Gas Group Ltd. - effective February 1, 2017

Mark Kremin was appointed President and CEO of Service Provider on February 1, 2017. He was appointed President of Teekay Gas Services in 2015 having acted as its Vice President since 2006. Mr. Kremin has over 20 years of experience in shipping. In 2000, he joined Teekay Corporation as in-house counsel. He subsequently held commercial roles within Teekay Gas Services. He represents us on the boards of joint ventures with partners in Asia, Europe and the Middle East. Prior to joining Teekay Corporation, he was an attorney in an admiralty law firm in Manhattan. Prior to attending law school in New York City, he worked for a leading owner and operator of container ships.

Brody Speers was appointed Chief Financial Officer of Service Provider on February 1, 2017. He joined Teekay Corporation in 2008 and has served in progressive financial positions including roles in Teekay Corporation’s Strategic Development and Finance departments. In 2013, he was promoted to Director, Finance, and to Vice President, Finance on February 1, 2017. He has had responsibility for completing financings for the Teekay Group, with a focus on financings for us. He represents us on the boards of joint ventures with partners in Asia, Europe and the Middle East. Prior to joining Teekay, Mr. Speers worked as a ~~Director~~Chartered Professional Accountant for an accounting firm in Vancouver, Canada. Mr. Speers is also a Chartered Business Valuator.

Edith Robinson was appointed as the Corporate Secretary of Teekay GP L.L.C. ~~since January 2005. He~~, the general partner of Teekay LNG Partners L.P., in September 2014 and also currently serves as ~~Executive Chairman~~an Associate General Counsel for Teekay Corporation. Ms. Robinson joined Teekay Corporation in 2014. She was appointed Corporate Secretary of ~~Critical Control Solutions Inc. (formerly WNS Emergent), a provider of information control applications for the energy sector. He held the position of CEO of Critical Control from 2002~~Teekay Gas Group Ltd. on February 1, 2017. Prior to 2007. From February 2000 to July 2002, he served as Executive Chairman at VerticalBuilder.com Inc. Mr. Watson served as President and Chief Executive Officer of TransCanada Pipelines Ltd. from 1993 to 1999 and as its Chief Financial Officer from 1990 to 1993.

~~Andres Luna~~~~has~~joining Teekay Corporation, Ms. Robinson served as the ~~Managing Director~~General Counsel for a utility group in Bermuda. She has over twenty years of ~~Teekay Shipping Spain SL since April 2004. Mr. Luna joined Alta Shipping, S.A., a former affiliate company of Naviera F. Tapias S.A.,~~legal experience and is qualified to practice law in ~~September 1992~~Bermuda, Ontario Canada, and England. Ms. Robinson has an MBA from Cornell University in addition to her legal qualifications.

Annual Executive Compensation

During 2016 and until his resignation on January 31, 2017, Peter Evensen served as its General Manager until he was appointed Commercial General Manager of Naviera F. Tapias S.A. in December 1999. He also served as Chief Executive Officer of Naviera F. Tapias S.A. from July 2000 until its acquisition by Teekay Corporation in April 2004, when it was renamed Teekay Shipping Spain. Mr. Luna’s responsibilities with Teekay Spain have included business development, newbuilding contracting, project management, development of its LNG business and the renewal of its tanker fleet. He has been in the shipping business since his graduation as a naval architect from Madrid University in 1981.

~~Annual Executive Compensation~~

~~Because the~~our Chief Executive Officer and Chief Financial ~~Officer of our General Partner, Peter~~Officer. Because Mr. Evensen iswas an employee of Teekay Corporation, his compensation (other than any awards under the long-term incentive plan described below) iswas set and paid by Teekay Corporation, and we ~~reimburse~~reimbursed Teekay Corporation for time he ~~spends~~spent on partnership matters. ~~In addition, Michael Balaski was the Vice President of our~~Our General Partner ~~from December 2011 until his resignation on August 20, 2014. His compensation was set~~did not appoint any executive officers to replace Mr. Evensen. Instead, the Partnership entered into a service agreement pursuant to which the Service Provider (an indirect subsidiary of the Partnership) provides the Partnership and ~~paid by our General Partner,~~Opco (a wholly-owned subsidiary of the Partnership) and ~~we reimbursed our General Partner for time he spent on our partnership matters.~~ its subsidiaries with the services of its CEO, Mark Kremin and its CFO, Brody Speers.

During ~~2014,~~2016, the aggregate amount for which we reimbursed Teekay Corporation for compensation expenses of the ~~officers~~former Chief Executive Officer and Chief Financial Officer of the General Partner, ~~incurred on our behalf and for compensation earned~~excluding any long-term incentive plan awards issued directly by the ~~executive officer of Teekay Spain listed above~~Partnership as described below, was ~~approximately $2.4~~$2.0 million. The amounts were paid ~~primarily~~ in U.S. ~~Dollars or in Euros, but are reported here in U.S. Dollars using an exchange rate 1.33 U.S. Dollar for each Euro, the exchange rate on December 31, 2014.~~Dollars. Teekay Corporation’s annual bonus plan, in which ~~each~~the former CEO and CFO of the ~~Officers participates,~~General Partner participated, considers both company performance and team ~~performance and individual performance (through comparison to established targets).~~

performance.

Compensation of Directors

Officers of our General Partner or Teekay Corporation who also serve as directors of our General Partner do not receive additional compensation for their service as directors. During ~~2014,~~2016, each non-management director received compensation for attending meetings of the Board of Directors, as well as committee meetings. Non-management directors received a director fee of $50,000 ~~for the year~~ and common units with a value of approximately $70,000 for the 2016 year. The Chairman received an additional annual fee of $37,500 and common units with a value of approximately $87,500. In addition, members of the audit, conflicts and governance committees each received a committee fee of $5,000 for the 2016 year, and the chairs of the audit, ~~committee,~~ conflicts ~~committee~~ and governance ~~committee~~committees each received an additional ~~fees~~fee of $12,000, ~~$12,000, and $10,000, respectively,~~ for serving in that role. Each director is fully indemnified by us for actions associated with being a director to the extent permitted under Marshall Islands law.

During ~~2014,~~2016, the five non-management directors received, in the aggregate, ~~$367,750~~$368,500 in cash fees for their services as directors, plus reimbursement of their out-of-pocket expenses. In March ~~2014,~~2016, our ~~general partner’s~~General Partner’s Board of Directors granted to the five non-management directors an aggregate of ~~9,521~~32,723 common units.

2005 Long-Term Incentive Plan

Our General Partner adopted the Teekay LNG Partners L.P. 2005 Long-Term Incentive Plan for employees and directors of and consultants to our General Partner and employees and directors of and consultants to its affiliates, who perform services for us. The plan provides for the award of restricted units, phantom units, unit options, unit appreciation rights and other unit or cash-based awards. In ~~2014,~~2016, the General Partner awarded ~~31,961~~132,582 restricted units to the Teekay employees who provide services to our business. The restricted units vest evenly over a ~~three year~~three-year period from the grant date.

Board Practices

Teekay GP L.L.C., our General Partner, ~~manages~~is responsible for the management of our operations and activities. Unitholders are not entitled to elect the directors of our General Partner or directly or indirectly participate in our management or operation.

Our General Partner’s board of directors (orthe Board) currently consists of ~~seven~~five members. Directors are appointed to serve until their successors are appointed or until they resign or are removed.

There are no service contracts between us and any of our directors providing for benefits upon termination of their employment or service.

The Board has the following three committees: Audit Committee, Conflicts Committee, and Corporate Governance Committee. The membership of these committees and the function of each of the committees are described below. Each of the committees is currently comprised of independent members and operates under a written charter adopted by the Board. The committee charters for the Audit Committee, the Conflicts Committee and the Corporate Governance Committee are available under “Investors – Teekay LNG Partners L.P. –- Governance” from the home page of our web site at www.teekay.com. During ~~2014,~~2016, the Board held ~~seven~~five meetings. ~~Directors~~Each director attended all Board meetings, ~~except for two board~~with the exception of one director who did not attend one Board meeting. The members ~~who between them missed four meetings.~~of the Audit Committee, ~~members~~Conflicts Committee and Corporate Governance Committee attended all meetings, ~~except for~~with the exception of one ~~member~~director who ~~missed~~did not attend two Audit Committee meetings, one ~~meeting.~~ Conflicts Committee ~~members attended all applicable meetings.~~meeting and one Corporate Governance Committee ~~members attended all committee meetings, except for one member who missed one~~ meeting.

Audit Committee. The Audit Committee of our General Partner is composed of at least three directors, each of whom must meet the independence standards of the New York Stock Exchange (orNYSE) and the SEC. This committee is comprised of directors Beverlee F. Park

(Chair), Ida Jane Hinkley, and ~~George Watson.~~Joseph E. McKechnie. All members of the committee are financially literate and the Board has determined that Ms. Park qualifies as the audit committee financial expert.

The Audit Committee assists the Board in fulfilling its responsibilities for general oversight of:

the integrity of our consolidated financial statements;

our compliance with legal and regulatory requirements;

the independent auditors’ qualifications and independence; and

the performance of our internal audit function and independent auditors.

Conflicts Committee. The Conflicts Committee of our General Partner is comprised of ~~George Watson~~Beverlee F. Park (Chair), Joseph E. McKechnie and Ida Jane Hinkley. The members of the Conflicts Committee may not be officers or employees of our General Partner or directors, officers or employees of its affiliates, and must meet the heightened NYSE and SEC director independence standards applicable to audit committee membership and certain other requirements.

The Conflicts Committee:

reviews specific matters that the Board believes may involve conflicts of interest; and

determines if the resolution of the conflict of interest is fair and reasonable to us.

Any matters approved by the Conflicts Committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners, and not a breach by our General Partner of any duties it may owe us or our ~~unit holders.~~unitholders. The Board is not obligated to seek approval of the Conflicts Committee on any matter, and may determine the resolution of any conflict of interest itself.

Corporate Governance Committee. The Corporate Governance Committee of our General Partner is composed of at least two directors, a majority of whom must meet the director independence standards established by the NYSE. This committee is currently comprised of directors Joseph E. McKechnie (Chair), C. Sean Day, Ida Jane Hinkley, ~~(Chair),~~and Beverlee F. ~~Park and George Watson.~~

Park.

The Corporate Governance Committee:

oversees the operation and effectiveness of the Board and its corporate governance;

develops and recommends to the Board corporate governance principles and policies applicable to us and our General Partner and monitors compliance with these principles and policies and recommends to the Board appropriate changes; and

oversees director compensation and the long-term incentive plan described above.

Crewing and Staff

As of December 31, ~~2014,~~2016, approximately ~~1,628~~1,700 seagoing staff served on our consolidated and equity accounted for vessels that were managed by subsidiaries of Teekay Corporation and approximately 11nine staff served on shore in technical, commercial and administrative roles in various countries, compared to approximately ~~1,400~~1,800 seagoing staff and 1511 on shore staff as of December 31, ~~2013~~2015 and approximately ~~1,370~~1,600 seagoing staff and 1511 on shore staff as of December 31, ~~2012.~~2014. Certain subsidiaries of Teekay Corporation employ the crews, who serve on the vessels pursuant to agreements with the subsidiaries, and Teekay Corporation subsidiaries also provide on-shore advisory, operational and administrative support to our operating subsidiaries pursuant to service agreements. Please read “Item 7 – Major Unitholders and Related Party Transactions.”

We regard attracting and retaining motivated seagoing personnel as a top priority. Like Teekay Corporation, we offer our seafarers competitive employment packages and comprehensive benefits and opportunities for personal and career development, which relates to a philosophy of promoting internally.

Teekay Corporation has entered into a Collective Bargaining Agreement with the Philippine Seafarers’ Union, an affiliate of the International Transport Workers’ Federation (orITF), and a Special Agreement with ITF London, which cover substantially all of the officers and seamen that operate our Bahamian-flagged vessels. Our Spanish officers and seamen for our Spanish-flagged vessels are covered by two different collective bargaining agreements (one for Suezmax tankers and one for LNG carriers) with Spain’s Union General de Trabajadores and Comisiones Obreras, and the Filipino crewmembers employed on our Spanish-flagged LNG and Suezmax tankers are covered by the Collective Bargaining Agreement with the Philippine Seafarer’s Union. We believe Teekay Corporation’s and our relationships with these labor unions are good.

Our commitment to training is fundamental to the development of the highest caliber of seafarers for our marine operations. Teekay Corporation has agreed to allow our personnel to participate in its training programs. Teekay Corporation’s cadet training approach is designed to balance academic learning with hands-on training at sea. Teekay Corporation has relationships with training institutions in Canada, Croatia, India, Latvia, Norway, Philippines, Turkey and the United Kingdom. After receiving formal instruction at one of these institutions, our cadets’ training continues on board on one of our vessels. Teekay Corporation also has a career development plan that we follow, which was designed to ensure a continuous flow of qualified officers who are trained on its vessels and familiarized with its operational standards, systems and policies. We

believe that high-quality crewing and training policies will play an increasingly important role in distinguishing larger independent shipping companies that have in-house or affiliate capabilities from smaller companies that must rely on outside ship managers and crewing agents on the basis of customer service and safety. As such, we have a LNG training facility in Glasgow that serves this purpose.

Common Unit Ownership

The following table sets forth certain information regarding beneficial ownership, as of December 31, ~~2014,~~2016, of our common units by all directors ~~and officers~~ of our General ~~Partner, and an executive officer of Teekay Spain as a group.~~Partner. The information is not necessarily indicative of beneficial ownership for any other purpose. Under SEC rules, a person or entity beneficially owns any units that the person has the right to acquire as of March 1, ~~2015~~2017 (60 days after December 31, ~~2014)~~2016) through the exercise of any unit option or other right. Unless otherwise indicated, each person has sole voting and investment power (or shares such powers with his or her spouse) with respect to the common units set forth in the following table. Information for all persons listed below is based on information delivered to us.

Identity of Person or Group
   Common Units
Owned    Percentage of
Common Units
Owned⁽³⁾
All directors and officers as a group (8 persons)^{(1) (2)}
   128,306       0.16 %

(1)

Excludes units owned by Teekay Corporation which controls us and on the board of which serve the directors of our General Partner, C. Sean Day ~~Peter Evensen~~ and ~~Kenneth Hvid. Peter Evensen~~Vincent Lok. Mr. Lok is also the ~~Chief~~ Executive ~~Officer of Teekay Corporation, the Chief Executive Officer~~Vice President and Chief Financial Officer of Teekay Offshore GP L.L.C., and a director of Teekay GP L.L.C. and Teekay Offshore GP L.L.C. Kenneth Hvid is a director of Teekay GP L.L.C. and Teekay Offshore GP L.L.C. Mr. Hvid is also Chief Strategy Officer and Executive Vice President of Teekay Corporation. Please read “Item 7 – Major Unitholders and Related Party ~~Transactions~~Transactions" for more detail.”


(2)	Each director, executive officer and key employee beneficially owns less than 1% of the outstanding common units. Under SEC rules, a person beneficially owns any units as to which the person has or shares voting or investment power.


(3)	Excludes the 2% general partner interest held by our General Partner, a wholly owned subsidiary of Teekay Corporation.

Item 7. Major Common Unitholders and Related Party Transactions

Major Common Unitholders

The following table sets forth information regarding beneficial ownership, as of December 31, ~~2014,~~2016, of our common units by each person we know to beneficially own more than 5% of the outstanding common units. The number of units beneficially owned by each person is determined under SEC rules and the information is not necessarily indicative of beneficial ownership for any other purpose. Under SEC rules a person beneficially owns any units as to which the person has or shares voting or investment power. In addition, a person beneficially owns any units that the person or entity has the right to acquire as of March 1, ~~2015~~2017 (60 days after December 31, ~~2014)~~2016) through the exercise of any unit option or other right. Unless otherwise indicated, each unitholder listed below has sole voting and investment power with respect to the units set forth in the following table.

   Common
Units Owned    Percentage of
Common Units
Owned⁽¹⁾
Identity of Person or Group

Teekay Corporation⁽¹⁾
   25,208,274       32.2 %
Neuberger Berman LLC⁽²⁾
   9,010,446       11.5 %
Oppenheimer Funds, Inc.⁽³⁾
   7,375,160       9.4 %



Identity of Person or Group	Common Units Owned	Percentage of Common Units Owned ⁽¹⁾
Teekay Corporation⁽¹⁾	25,208,274	31.7	%
FMR LLC⁽²⁾	7,957,182	10.0	%
Neuberger Berman Group LLC⁽³⁾	6,642,979	8.4	%
OppenheimerFunds, Inc.⁽⁴⁾	4,906,417	6.2	%


(1)	Excludes the 2% general partner interest held by our General Partner, a wholly owned subsidiary of Teekay Corporation.

(2)

~~Includes shared~~FMR LLC has the sole dispositive power, but does not have voting power as to ~~8,747,346 units and shared dispositive power as to 9,010,446~~these units. Both Neuberger Berman Group LLC and Neuberger Berman LLC have shared dispositive power. Neuberger Berman, LLC and Neuberger Berman Management LLC serve as a sub-advisor and investment manager, respectively, of Neuberger Berman Group LLC’s various registered mutual funds which hold such units. The holdings belonging to clients of Neuberger Berman Trust Co N.A., Neuberger Berman Trust Co of Delaware N.A., NB Alternatives Advisers LLC, Neuberger Berman Fixed Income LLC and NB Alternative Investment Management LLC, affiliates of Neuberger Berman LLC, are also aggregated to comprise the holdings referenced herein. This information is based on the Schedule ~~13G/A~~13G filed by this group with the SEC on ~~February 9, 2015.~~

October 11, 2016.


(3)	~~Includes~~Neuberger Berman Group LLC and Neuberger Berman Investment Advisors LLC each have shared voting power as to 6,385,625 common units and shared dispositive power as to ~~7,375,160~~6,642,979 common units. This information is based on the Schedule 13G/A filed by this group with the SEC on February ~~10, 2015.~~ 15, 2017.

(4) OppenheimerFunds, Inc., an investment advisor, has shared voting power and shared dispositive power as to 4,906,417 common units. This information is based on the Schedule 13G/A filed by this group with the SEC on February 6, 2017.

Teekay Corporation has the same voting rights with respect to common units it owns as our other common unitholders. We are controlled by Teekay Corporation. We are not aware of any arrangements, the operation of which may at a subsequent date result in a change in control of us.

Related Party Transactions


a)	We have entered into an amended and restated omnibus agreement with Teekay Corporation, our General Partner, our operating company, Teekay LNG Operating L.L.C., Teekay Offshore and related parties. The following discussion describes certain provisions of the omnibus agreement.

Noncompetition. Under the omnibus agreement, Teekay Corporation and Teekay Offshore have agreed, and have caused their controlled affiliates (other than us) to agree, not to own, operate or charter LNG carriers. This restriction does not prevent Teekay Corporation, Teekay Offshore or any of their controlled affiliates (other than us) from, among other things:

acquiring LNG carriers and related time-charters as part of a business and operating or chartering those vessels if a majority of the value of the total assets or business acquired is not attributable to the LNG carriers and related time-charters, as determined in good faith by the board of directors of Teekay Corporation or the ~~conflict~~conflicts committee of the board of directors of Teekay Offshore’s general partner; however, if at any time Teekay Corporation or Teekay Offshore completes such an acquisition, it must offer to sell the LNG carriers and related time-charters to us for their fair market value plus any additional tax or other similar costs to Teekay Corporation or Teekay Offshore that would be required to transfer the LNG carriers and time-charters to us separately from the acquired business;

owning, operating or chartering LNG carriers that relate to a bid or award for a proposed LNG project that Teekay Corporation or any of its subsidiaries has submitted or hereafter submits or receives; however, at least 180 days prior to the scheduled delivery date of any such LNG carrier, Teekay Corporation must offer to sell the LNG carrier and related time-charter to us, with the vessel valued at its “fully-built-up cost,” which represents the aggregate expenditures incurred (or to be incurred prior to delivery to us) by Teekay Corporation to acquire or construct and bring such LNG carrier to the condition and location necessary for our intended use, plus a reasonable allocation of overhead costs related to the development of such project and other projects that would have been subject to the offer rights set forth in the omnibus agreement but were not completed; or

acquiring, operating or chartering LNG carriers if our General Partner has previously advised Teekay Corporation or Teekay Offshore that the board of directors of our General Partner has elected, with the approval of its conflicts committee, not to cause us or our subsidiaries to acquire or operate the carriers.

In addition, under the omnibus agreement we have agreed not to own, operate or charter crude oil tankers or the following “offshore vessels” – dynamically positioned shuttle tankers, floating storage and off-take units or floating production, storage and off-loading units, in each case that are subject to contracts with a remaining duration of at least three years, excluding extension options. This restriction does not apply to any of the conventional tankers in our current fleet, and the ownership, operation or chartering of any oil tankers that replace any of those oil tankers in connection with certain events. In addition, the restriction does not prevent us from, among other things:

acquiring oil tankers or offshore vessels and any related time-charters or contracts of affreightment as part of a business and operating or chartering those vessels, if a majority of the value of the total assets or business acquired is not attributable to the oil tankers and offshore vessels and any related charters or contracts of affreightment, as determined by the conflicts committee of our General Partner’s board of directors; however, if at any time we complete such an acquisition, we are required to promptly offer to sell to Teekay Corporation the oil tankers and time-charters or to Teekay Offshore the offshore vessels and time-charters or contracts of affreightment for fair market value plus any additional tax or other similar costs to us that would be required to transfer the vessels and contracts to Teekay Corporation or Teekay Offshore separately from the acquired business; or

acquiring, operating or chartering oil tankers or offshore vessels if Teekay Corporation or Teekay Offshore, respectively, has previously advised our General Partner that it has elected not to acquire or operate those vessels.

Rights of First Offer on Suezmax Tankers, LNG Carriers and Offshore Vessels.Under the omnibus agreement, we have granted to Teekay Corporation and Teekay Offshore a 30-day right of first offer on any proposed (a) sale, transfer or other disposition of any of our conventional tankers, in the case of Teekay Corporation, or certain offshore vessels in the case of Teekay Offshore, or (b) re-chartering of any of our conventional tankers or offshore vessels pursuant to a time-charter or contract of affreightment with a term of at least three years if the existing charter expires or is terminated early. Likewise, each of Teekay Corporation and Teekay Offshore has granted a similar right of first offer to us for any LNG carriers it might own. These rights of first offer do not apply to certain transactions.

b)

C. Sean Day iswas the Chairman of our General Partner, Teekay GP L.L.C. Hesince it was formed in November 2004 until June 2015 and continues to serve as a director. Mr. Day also isserves as the Chairman of Teekay Corporation and Teekay Offshore GP L.L.C. (the general partner of Teekay Offshore Partners L.P., a publicly held partnership controlled by Teekay Corporation). He ~~served~~will be resigning as Chairman of those two entities effective June 15, 2017 but continuing as a ~~Chairman~~director of ~~Teekay Tankers Ltd., a publicly held corporation controlled by Teekay Corporation, from 2007 to June 2013.~~

each entity.

Peter Evensen is the Chief Executive Officer and Chief Financial Officer and a director of Teekay GP L.L.C. and the Chief Executive Officer, Chief Financial Officer and a director of Teekay Offshore GP L.L.C. Mr. Evensen is alsowas the President and Chief Executive Officer of Teekay Corporation, the Chief Executive Officer and ~~a director of Teekay Corporation.~~

~~Kenneth Hvid, a director of Teekay GP L.L.C., is also Executive Vice President,~~ Chief ~~Strategy~~Financial Officer ~~of Teekay Corporation and a director~~ of Teekay Offshore GP L.L.C.

and Teekay GP L.L.C., and a Director of Teekay Corporation, Teekay GP L.L.C., Teekay Offshore GP L.L.C. and Teekay Tankers Ltd. through January 31, 2017.

Because Mr. Evensen iswas an employee of a subsidiary of Teekay Corporation, ~~or another of its subsidiaries,~~ his compensation (other than any awards under ~~our~~the long-term incentive plan) iswas set and paid by the Teekay Corporation ~~or such other applicable~~ subsidiary. Pursuant to our partnership agreement, we have agreed to reimburse Teekay Corporation ~~or its applicable subsidiary~~ for time spent by Mr. Evensen on our ~~management matters~~partnership matters.

Vincent Lok joined the board of Teekay GP L.L.C. as ~~our Chief~~a director in June 2015. Mr. Lok is also Executive ~~Officer~~Vice President and Chief Financial ~~Officer.~~

Officer of Teekay Corporation and the Chief Financial Officer of Teekay Tankers Ltd.

On February 1, 2017, the Partnership and its wholly-owned subsidiary, Opco, entered into a service agreement with the Service Provider, a management services company that is a subsidiary of Opco. The Service Provider provides services using persons employed by various subsidiaries of Teekay Corporation, including the services of Mark Kremin, the President and CEO of Service Provider, and Brody Speers, the CFO of Service Provider. In addition, we have entered into various service agreements with certain direct and indirect subsidiaries of Teekay Corporation pursuant to which those subsidiaries provide to us various services including, in the case of the operating subsidiaries, substantially all of their managerial, operational and administrative services (including vessel maintenance, crewing, crew training, purchasing, shipyard supervision, insurance and financial services) and other technical and advisory services, and in the case of Teekay LNG Partners L.P., various administrative services. Because Mr. Kremin and Mr. Speers and the other persons providing services to the Partnership and its subsidiaries are employees of various subsidiaries of Teekay Corporation, their compensation (other than any awards under the long-term incentive plan) is set and paid by the Teekay Corporation subsidiary that employs them. Pursuant to our agreements with Teekay Corporation and its subsidiaries, we have agreed to reimburse Teekay Corporation for time spent by such persons on providing services to the Partnership and our subsidiaries.

Please read “Item 18. – Financial Statements: Note 11 – Related Party Transactions” for a description of our various related-party transactions.

Item 8. Financial Information

~~Item 8. Financial Information~~


A.	Consolidated Financial Statements and Other Financial Information

~~A. Consolidated Financial Statements and Other Financial Information~~

Consolidated Financial Statements and Notes

Please see “Item 18 – Financial Statements” below for additional information required to be disclosed under this Item.

Legal Proceedings

From time to time we have been, and expect to continue to be, subject to legal proceedings and claims in the ordinary course of our business, principally personal injury and property casualty claims. These claims, even if lacking merit, could result in the expenditure of significant financial and managerial resources. We are not aware of any legal proceedings or claims that we believe will have, individually or in the aggregate, a material adverse effect on ~~us.~~

us, other than those set forth in "Item 18. - Financial Statements: Note 13c - Commitments and Contingencies".

Cash Distribution Policy

for Common Unitholders

Rationale for Our Cash Distribution Policy

Our ~~partnership agreement requires us to distribute all of our available cash (as defined in our partnership agreement) within approximately 45 days after the end of each quarter. This~~general cash distribution policy reflects a basic judgment that our common unitholders are better served by our distributing our cash available after expenses and reserves rather than our retaining it. ~~Because~~However, commencing with our distribution on common units relating to the fourth quarter of 2015, we ~~believe~~significantly reduced the amount of our quarterly per common unit cash distributions. Global crude oil prices have significantly declined since mid-2014 and has contributed to depressed natural gas prices. These declines in energy prices, combined with other factors beyond our control, have adversely affected energy and master limited partnership capital markets and available sources of financing. Based on upcoming capital requirements for our committed growth projects and scheduled debt repayment obligations, coupled with relative weakness in energy and master limited partnership capital markets, the board of directors of our General Partner believes it is in the best interests of our unitholders to conserve more of our internally generated cash flows to fund these projects and to reduce debt levels. As a result, in December 2015, we ~~will generally finance any capital investments from external financing sources,~~reduced our quarterly distributions on our common units. This reduction in the amount of common unit distributions to establish cash reserves for these purposes is consistent with our cash distribution policy and the terms of our partnership agreement, which requires that we ~~believe that our investors are best served by our distributing~~distribute all of our ~~available cash.~~

Available Cash within approximately 45 days after the end of each quarter.

Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy

There is no guarantee that common unitholders will receive quarterly distributions from us. Our distribution policy is subject to certain restrictions and may be changed at any time, including:

Our ~~distribution policy~~common unitholders have no contractual or other legal right to receive distributions other than the obligation under our partnership agreement to distribute Available Cash on a quarterly basis, which is subject to restrictions on distributions under our credit agreements. Specifically, our credit agreements contain material financial tests and covenants that we must satisfy. Should we be unable to satisfy these restrictions under our credit agreements, we would be prohibited from making cash distributions to unitholders notwithstanding our stated cash distribution policy.

~~The board of directors of~~ our General ~~Partner has the authority~~Partner’s broad discretion to establish reserves (including, among others, reserves for ~~the prudent conduct~~future capital expenditures and our anticipated future credit needs) and other limitations (including as required by law, credit facilities or other agreements or obligations).

While our partnership agreement requires us to distribute all of our ~~business and for future~~Available Cash, our partnership agreement, including provisions requiring us to make cash distributions ~~to our unitholders, and~~contained therein, may be amended with the ~~establishment~~approval of ~~those reserves could result in~~ a ~~reduction in cash distributions to unitholders from levels we anticipate pursuant to our stated distribution policy.~~

majority of the outstanding common units.

Even if our cash distribution policy is not modified or revoked, the amount of distributions we pay under our cash distribution policy and the decision to make any distribution is determined by the board of directors of our General Partner, taking into consideration the terms of our partnership agreement.

Under Section 51 of ~~the~~The Marshall Islands Limited Partnership Act, we may not make a distribution to unitholders ifto the extent that at the time of the distribution, ~~would cause~~after giving effect to the distribution, all of our liabilities, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specified property of ours, exceed the fair value of our ~~assets.~~

assets, except that the fair value of property that is subject to a liability for which the recourse of creditors is limited shall be included in our assets only to the extent that the fair value of that property exceeds that liability.

We may lack sufficient cash to pay distributions to our unitholders due to decreases in net revenues or increases in our ~~general and administrative~~operating expenses, principal and interest payments on ~~our~~ outstanding debt, tax expenses, ~~the issuance of additional units (which would require the payment of distributions on those units),~~ working capital requirements, ~~and~~maintenance capital expenditures or anticipated cash needs.

~~While~~Our distribution policy may be affected by restrictions on distributions under our ~~partnership agreement requires us~~credit facility agreements, which contain material financial tests and covenants that must be satisfied and complied with. Should we be unable to ~~distribute all of~~satisfy these restrictions included in our ~~available~~credit agreements or if we are otherwise in default under our credit agreements, we would be prohibited from making cash distributions, which would materially hinder our ~~partnership agreement, including provisions requiring us~~ability to make cash distributions ~~may be amended. Our partnership agreement can be amended with the approval~~to unitholders, notwithstanding our stated cash distribution policy.

If we make distributions out of ~~a majority of the outstanding common units, voting~~capital surplus, as ~~a class (including common units held by affiliates of our General Partner).~~

~~Minimum Quarterly Distribution~~

~~Common unitholders~~opposed to operating surplus (as such terms are ~~entitled under~~defined in our partnership ~~agreement to receive~~agreement), those distributions will constitute a ~~minimum quarterly distribution~~return of ~~$0.4125 per unit, or $1.6500 per year, to the extent we have sufficient cash from our operations after establishment of cash reserves~~capital and payment of fees and expenses, including payments to our General Partner. Our General Partner has the authority to determine the amount of our available cash for any quarter. This determination must be madewill result in ~~good faith. There is no guarantee that we will pay~~a reduction in the minimum quarterly distribution onand the ~~common units in any quarter, and~~target distribution levels under our partnership agreement. We do not anticipate that we will ~~be prohibited from making~~make any distributions ~~to unitholders if it would cause an event of default, or an event of default exists, under our credit agreements.~~

Our cash distributions were $0.6300 per unit in 2011, increased to $0.6750 per unit effective for the second quarter of 2012, increased to $0.6918 effective for the first quarter of 2014 and further increased to $0.7000 effective for the first quarter of 2015.

from capital surplus.

Incentive distribution rights represent the right to receive an increasing percentage of quarterly distributions of ~~available cash~~Available Cash from operating surplus (as defined in our partnership agreement) after the minimum quarterly distribution to our common unitholders and the target distribution levels have been achieved. Our General Partner currently holds the incentive distribution rights, but may transfer these rights separately from its general partner interest, subject to restrictions in our partnership agreement.

The following table illustrates the percentage allocations of the additional ~~available cash~~Available Cash from operating surplus among the common unitholders and our General Partner up to the various target distribution levels. The amounts set forth under “Marginal Percentage Interest in Distributions’’ are the percentage interests of the common unitholders and our General Partner in any ~~available cash~~Available Cash from operating surplus we distribute up to and including the corresponding amount in the column ~~“ Quarterly~~“Quarterly Distribution Target Amount,’’ until ~~available cash~~Available Cash from operating surplus we distribute reaches the next target distribution level, if any. The percentage interests shown for the common unitholders and our General Partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests shown for our General Partner include its 2%2.0% general partner interest and assume the General Partner has contributed any capital necessary to maintain its 2.0% general partner interest and has not transferred the incentive distribution rights.

Quarterly Distribution Target Amount
   Marginal Percentage Interest In Distributions
   (per unit)    Unitholders General Partner
Minimum Quarterly Distribution
   $0.4125    98% 2%
First Target Distribution
   Up to $0.4625    98% 2%
Second Target Distribution
   Above $0.4625 up to $0.5375    85% 15%
Third Target Distribution
   Above $0.5375 up to $0.6500    75% 25%
Thereafter
   Above $0.6500    50% 50%

During 2016, cash distributions were below $0.4625 per common unit and, consequently, the assumed distribution of net income was based on the limited partners' and General Partner’s ownership percentage for the purposes of the net income per common unit calculation. During 2015 and 2014, cash distributions exceeded $0.4625 per unit and, consequently, the assumed distribution of net income resulted in the use of the increasing percentages to calculate the General Partner’s interest in net income for the purposes of the net income per common unit calculation.

Please read “Item 18 – Financial Statements: Note 19 – Subsequent Events.”

Our common units are listed on the NYSE under the symbol “TGP”. The following table sets forth the high and low prices for our common units on the NYSE for each of the periods indicated.

Years Ended      Dec. 31,
2014      Dec. 31,
2013      Dec. 31,
2012      Dec. 31,
2011      Dec. 31,
2010
High
     $47.49      $45.42      $42.26      $41.50      $38.25
Low
     33.02      37.73      33.00      28.61      19.75

Quarters Ended    Mar. 31,
2015    Dec. 31,
2014    Sept. 30,
2014    June 30,
2014    Mar. 31,
2014    Dec. 31,
2013    Sept. 30,
2013    June 30,
2013    Mar. 31,
2013
High
   $ 43.38    $ 43.86    $ 47.49    $ 46.69    $ 42.92    $ 44.96    $ 45.42    $ 45.06    $ 42.60
Low
   34.13    33.02    40.40    41.35    39.03    38.17    41.18    38.32    37.73

Months Ended      Mar. 31,
2015      Feb. 28,
2015      Jan. 31,
2015      Dec. 31,
2014      Nov. 30,
2014      Oct. 31,
2014
High
     $ 37.70      $ 39.47      $ 43.38      $ 43.66      $ 39.78      $ 43.86
Low
     34.13      36.32      37.10      34.62      35.82      33.02

Our Series A Preferred Units are listed on the NYSE under the symbol “TGPPA”. The following table sets forth the high and low prices for our Series A Preferred Units on the NYSE for each of the periods indicated.

The information required to be disclosed under Item 10B is incorporated by reference to our Registration Statement on Form 8-A/A filed with the SEC on ~~September 29, 2006.~~

May 13, 2011 and our Registration Statement on Form 8/A filed with the SEC on October 5, 2016.

The following is a summary of each material contract, other than material contracts entered into in the ordinary course of business, to which we or any of our subsidiaries is a party, for the two years immediately preceding the date of this Annual Report, each of which is included in the list of exhibits in Item 19:

We are not aware of any governmental laws, decrees or regulations, including foreign exchange controls, in the Republic of The Marshall Islands that restrict the export or import of capital, or that affect the remittance of dividends, interest or other payments to ~~non-resident~~ holders of our ~~securities.~~

securities that are non-resident and not citizens.

We are not aware of any limitations on the right of non-resident or foreign owners to hold or vote our securities imposed by the laws of the Republic of The Marshall Islands or our partnership agreement.

This discussion is limited to unitholders who hold their ~~common~~ units as capital assets for tax purposes. This discussion does not address all tax considerations that may be important to a particular unitholder in light of the unitholder’s circumstances, or to certain categories of unitholders that may be subject to special tax rules, such as:

If a partnership (including any entity or arrangement treated as a partnership for U.S. federal income tax purposes) holds our ~~common~~ units, the tax treatment of a partner generally will depend upon the status of the partner and the activities of the partnership. ~~Partner~~Partners in partnerships holding our ~~common~~ units should consult their ~~own~~ tax advisors to determine the appropriate tax treatment of the partnership’s ownership of our ~~common~~ units.

This discussion does not address any U.S. estate tax considerations or tax considerations arising under the laws of any state, local or non-U.S. jurisdiction. Each unitholder is urged to consult its ~~own~~ tax advisor regarding the U.S. federal, state, local and other tax consequences of the ownership or disposition of our ~~common~~ units.

For U.S. federal income tax purposes, a partnership is not a taxable entity, and although it may be subject to withholding taxes on behalf of its partners under certain circumstances, a partnership itself incurs no U.S. federal income tax liability. Instead, each partner of a partnership is required to take into account ~~his~~its share of items of income, gain, loss, deduction and credit of the partnership in computing ~~his~~its U.S. federal

income tax liability, regardless of whether cash distributions are made to ~~him~~it by the partnership. Distributions by a partnership to a partner generally are not taxable unless the amount of cash distributed exceeds the partner’s adjusted tax basis in ~~his~~its partnership interest.

Section 7704 of the Code provides that a publicly traded ~~partnerships~~partnership generally will be treated as a ~~corporations~~corporation for U.S. federal income tax purposes. However, an exception, referred to as the “Qualifying Income Exception,” exists with respect to a publicly traded ~~partnerships~~partnership whose “qualifying income” represents 90 percent or more of its gross income for every taxable year. Qualifying income includes income and gains derived from the transportation and storage of crude oil, natural gas and products thereof, including liquefied natural gas. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of qualifying income, including stock. We have received a ruling from the ~~Internal Revenue Service (or~~IRS) that we requested in connection with our initial public offering that the income we derive from transporting LNG and crude oil pursuant to time charters existing at the time of our initial public offering is qualifying income within the meaning of Section 7704. Furthermore, on January 24, 2017, The U.S. Treasury Department and the IRS published in the Federal Register final regulations effective as of January 19, 2017 which, among other things, provide that income derived from the transportation of LNG, crude oil and products derived therefrom pursuant to time charters is qualifying income. However, the impact on the final regulations of a regulatory freeze imposed by the incoming administration in a January 20, 2017 White House memorandum is not immediately clear. Should the final regulations be withdrawn or otherwise deemed inapplicable, we would need to continue to rely on the ruling that we received from the IRS. A ruling from the IRS, while generally binding on the IRS, may under certain circumstances be revoked or modified by the IRS retroactively.

We estimate that less than 5 percent of our current income is not qualifying income and therefore we believe that we will be treated as a partnership for U.S. federal income tax purposes. However, this estimate could change from time to time for various reasons. Because we have not received an IRS ruling or an opinion of counsel that any (1) income we derive from transporting crude oil, natural gas and products thereof, including LNG, pursuant to bareboat charters or (2) income or gain we recognize from foreign currency transactions, is qualifying income, we currently are not treating income from those sources as ~~non-qualifying~~qualifying income. Under some circumstances, such as a significant change in foreign currency rates, the percentage of income or gain from foreign currency transactions in relation to our total gross income could be substantial. We do not expect income or gains from these sources and other income or gains that are not qualifying income to constitute 10 percent or more of our gross income for U.S. federal income tax purposes. However, it is possible that the operation of certain of our vessels pursuant to bareboat charters could, in the future, cause our non-qualifying income to constitute 10 percent or more of our future gross income if such vessels were held in a pass-through structure. In order to preserve our status as a partnership for U.S. federal income tax purposes, we have received a ruling from the IRS that effectively allows us to conduct our bareboat charter operations in a subsidiary corporation.

The treatment of unitholders described in this section applies only to unitholders treated as partners in us for U.S. federal income tax purposes. ~~Unitholders~~Common unitholders who have been properly admitted as limited partners of Teekay LNG Partners L.P. will be treated as partners in us for U.S. federal income tax purposes. In addition, ~~assignees~~although there is no direct controlling authority with respect to our Series A preferred units, we will treat Series A preferred unitholders who have been properly admitted as limited partners of ~~common~~Teekay LNG Partners L.P. as partners for U.S. federal income tax purposes and the discussion in this Annual Report assumes that the Series A preferred units will be treated as partnership interests. Other U.S. tax consequences would result in the event that the Series A preferred units are treated as indebtedness for U.S. federal income tax purposes.

Assignees of units who have executed and delivered transfer applications, and are awaiting admission as limited partners and unitholders whose ~~common~~ units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of their ~~common~~ units will be treated as partners in us for U.S. federal income tax purposes.

The status of assignees of ~~common~~ units who are entitled to execute and deliver transfer applications and thereby become entitled to direct the exercise of attendant rights, but who fail to execute and deliver transfer applications, is unclear. In addition, a purchaser or other transferee of ~~common~~ units who does not execute and deliver a transfer application may not receive some U.S. federal income tax information or reports furnished to record holders of ~~common~~ units, unless the ~~common~~ units are held in a nominee or street name account and the nominee or broker has executed and delivered a transfer application for those ~~common~~ units.

Under certain circumstances, a beneficial owner of ~~common~~ units whose units have been loaned to another may lose ~~his~~its status as a partner with respect to those units for U.S. federal income tax purposes.

In general, a person who is not a partner in a partnership for U.S. federal income tax purposes is not required or permitted to report any share of the partnership’s income, gain, deductions or losses for such purposes, and any cash distributions received by such a person from the partnership therefore may be fully taxable as ordinary income. ~~Unitholders~~Common unitholders not described here and Series A preferred unitholders are urged to consult their ~~own~~ tax advisors with respect to their status as partners in us for U.S. federal income tax purposes.

Gain, Loss, Deduction and Credit,” we do not expect to allocate any income, gain, loss, deduction or credit in respect of the Series A preferred units except in limited circumstances.

In addition, certain U.S. unitholders who are individuals, estates or trusts currently are required to pay an additional 3.8 percent tax on, among other things, the income allocated to them. Unitholders should consult their tax advisors regarding the effect, if any, of this tax on their ownership of our ~~common~~ units.

We will treat distributions on the Series A preferred units (including the distribution of any accumulated and previously unpaid distributions upon our liquidation) as guaranteed payments for the use of capital that generally will be taxable to Series A preferred unitholders as ordinary income and will be deductible by us. Distributions on the Series A preferred units will accrue and be paid quarterly to Series A preferred unitholders who hold their Series A preferred units on the last day of each calendar quarter. However, it is not entirely certain that this treatment would be respected by the IRS. Consequently, it is possible that a Series A preferred unitholder could recognize taxable income from the accrual of a guaranteed payment even in the absence of a contemporaneous distribution. Series A preferred unitholders should consult their tax advisors as to the amount and timing of taxable income with respect to their Series A preferred units.

Certain U.S. Series A preferred unitholders who are individuals, estates or trusts currently are required to pay an additional 3.8 percent tax on, among other things, guaranteed payments for the use of capital. Series A preferred unitholders should consult their tax advisors regarding the effect, if any, of this tax on their ownership of our Series A preferred units.

A Series A preferred unitholder will not be allocated any of our nonrecourse liabilities and distributions made by us, to the extent treated as guaranteed payments, will not affect a Series A preferred unitholder’s tax basis. Accordingly, except in certain limited situations, as discussed below under “—Allocation of Income, Gain, Loss, Deduction and Credit,” a Series A preferred unitholder’s tax basis with respect to Series A preferred units is not expected to change. The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all of those interests. Series A preferred unitholders who also own common units should consult their tax advisors with respect to determining the tax basis in their units.

The passive loss limitations generally provide that individuals, estates, trusts and some closely-held corporations and personal service corporations can deduct losses from a passive activity only to the extent of the taxpayer’s income from the same passive activity. Passive activities generally are corporate or partnership activities in which the taxpayer does not materially participate. The passive loss limitations are applied separately with respect to each publicly traded partnership. Consequently, any passive losses we generate only will be available

to offset our passive income generated in the future and will not be available to offset income from other passive activities or investments, including our investments or investments in other publicly traded partnerships, or salary or active business income. Passive losses that are not deductible because they exceed a unitholder’s share of income we generate may be deducted in full when heit disposes of ~~his~~its entire investment in us in a fully taxable transaction with an unrelated party. The passive activity loss rules are applied after other applicable limitations on deductions, including the at risk rules and the basis limitation.

Dual consolidated loss restrictions also may apply to limit the deductibility by a corporate unitholder of losses we incur. Corporate unitholders are urged to consult their own tax advisors regarding the applicability and effect to them of dual consolidated loss restrictions.

Series A preferred unitholders will be allocated loss to the extent of their positive capital accounts only after the capital accounts of the general partner and the common unitholders have been reduced to zero. In general, the capital account with respect to a Series A preferred unit will be equal to the liquidation preference of the Series A preferred unit, or $25.00, without regard to the price paid for such units, but will have an initial tax basis with respect to the Series A preferred unit equal to the price paid for such unit. To the extent the purchase price paid for a Series A preferred unit exceeds the liquidation preference of such unit, we will have income that will be allocated to our general partner and the holders of units other the Series A preferred units in accordance with their percentage interest. In the event that a Series A preferred unitholder is allocated net loss with respect to a taxable year, such Series A preferred unitholder will be allocated items of income and gain in the earliest succeeding taxable year or years in which there are items of income and gain to the extent necessary to restore its capital account with respect to each Series A preferred unit to equal the liquidation preference. Except as specifically provided in this paragraph, we do not expect to allocated any income or loss in respect of our Series A preferred units.

Specified items of our income, gain, loss and deduction will be allocated to account for any difference between the tax basis and fair market value of any property held by the partnership immediately prior to an offering of ~~common~~ units, referred to in this discussion as “Adjusted Property.” The effect of these allocations to a unitholder purchasing ~~common~~ units in an offering essentially will be the same as if the tax basis of our assets were equal to their fair market value at the time of the offering. In addition, items of recapture income will be allocated to the extent possible to the partner who was allocated the deduction giving rise to the treatment of that gain as recapture income in order to minimize the recognition of ordinary income by some unitholders. Finally, although we do not expect that our operations will result in the creation of negative capital accounts, if negative capital accounts nevertheless result, items of our income and gain will be allocated in an amount and manner to eliminate the negative balance as quickly as possible.

An allocation of items of our income, gain, loss, deduction or credit, other than an allocation required by the Code to eliminate the difference between a partner’s “book” capital account, which is credited with the fair market value of Adjusted Property, and “tax” capital account, which is credited with the tax basis of Adjusted Property, referred to in this discussion as the “Book-Tax Disparity,” generally will be given effect for U.S. federal income tax purposes in determining a partner’s share of an item of income, gain, loss, deduction or credit only if the allocation has substantial economic effect. In any other case, a partner’s share of an item will be determined on the basis of ~~his~~its interest in us, which will be determined by taking into account all the facts and circumstances, including:

A unitholder’s taxable income or loss with respect to a ~~common~~ unit each year will depend upon a number of factors, including (1) the nature and fair market value of our assets at the time the holder acquired the ~~common~~ unit, (2) whether we issue additional units or we engage in certain other transactions and (3) the manner in which our items of income, gain, loss, deduction and credit are allocated among our partners. For this

purpose, we determine the value of our assets and the relative amounts of our items of income, gain, loss, deduction and credit allocable to our unitholders and our ~~general partner~~General Partner as holder of the incentive distribution rights by reference to the value of our interests, including the incentive distribution rights. The IRS may challenge any valuation determinations that we make, particularly as to the incentive distribution rights, for which there is no public market. Moreover, the IRS could challenge certain other aspects of the manner in which we determine the relative allocations made to our unitholders and to the ~~general partner~~General Partner as holder of our incentive distribution rights. A successful IRS challenge to our valuation or allocation methods could increase the amount of net taxable income and gain realized by a unitholder with respect to a ~~common~~ unit.

In general, a purchaser’s common basis is depreciated or amortized according to the existing method utilized by us. A positive Section 743(b) adjustment to that basis generally is depreciated or amortized in the same manner as property of the same type that has been newly placed in service by us. A negative Section 743(b) adjustment to that basis generally is recovered over the remaining useful life of the partnership’s recovery property.

The calculations involved in the Section 743(b) adjustment are complex and will be made on the basis of assumptions as to the value of our assets and in accordance with the Code and applicable Treasury Regulations. We cannot assure you that the determinations we make will not be successfully challenged by the IRS and that the deductions resulting from them will not be reduced or disallowed altogether. Should the IRS require a different basis adjustment to be made, and should, in our judgment, the expense of compliance exceed the benefit of the election, we may seek consent from the IRS to revoke our Section 754 election. If such consent is given, a subsequent purchaser of units may be allocated more income than heit would have been allocated had the election not been revoked.

Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to ensure that any applicable brokerage account agreements prohibit their brokers from borrowing their units.

To the extent allowable, we may elect to use the depreciation and cost recovery methods that will result in the largest deductions being taken in the earliest years after assets are placed in service. Property we subsequently acquire or construct may be depreciated using any method permitted by the Code.

If we dispose of depreciable property by sale, foreclosure or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation previously deducted and the nature of the property, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a unitholder who has taken cost recovery or depreciation deductions with respect to property we own likely will be required to recapture some or all of those deductions as ordinary income upon a sale of ~~his~~its interest in us.

The U.S. federal income tax consequences of the ownership and disposition of units will depend in part on our estimates of the relative fair market values, and the tax bases, of our assets at the time (a) the unitholder acquired ~~his common~~its unit, (b) we issue additional units or (c) we engage in certain other transactions. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and

amount of items of income, gain, loss, deductions or credits previously reported by unitholders might change, and unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

Prior distributions from us in excess of cumulative net taxable income for a common unit that decreased a common unitholder’s tax basis in that common unit will, in effect, become taxable income if the common unit is sold at a price greater than the common unitholder’s tax basis in that common unit, even if the price received is less than ~~his~~its original cost. Except as noted below, gain or loss recognized by a unitholder on the sale or exchange of a unit generally will be taxable as capital gain or loss. Capital gain recognized by an individual on the sale of units held more than one year generally will be taxed at preferential tax rates.

Capital loss may offset capital gains and, in the case of an individual, up to $3,000 of ordinary income per year.

A portion of a common unitholder’s amount realized may be allocable to “unrealized receivables” or to “inventory items” we own. The term “unrealized receivables” includes potential recapture items, including depreciation and amortization recapture. A common unitholder will recognize ordinary income or loss to the extent of the difference between the portion of the common unitholder’s amount realized allocable to unrealized receivables or inventory items and the common unitholder’s share of our basis in such receivables or inventory items. Ordinary income attributable to unrealized receivables, inventory items and depreciation or amortization recapture may exceed net taxable gain realized upon the sale of a common unit and may be recognized even if a net taxable loss is realized on the sale of a common unit. Thus, a common unitholder may recognize both ordinary income and a capital loss upon a sale of common units. ~~Net capital losses~~Because Series A preferred unitholders generally ~~may only~~are not expected to be ~~used~~allocated a share of our items of depreciation, depletion or amortization, it is not anticipated that Series A preferred unitholders would be required to ~~offset capital gains. An exception permits individuals to offset up to $3,000~~recharacterize any portion of ~~net capital losses against~~their gain as ordinary income ~~in any given year.~~

as a result of these rules. However, it is uncertain as to whether a portion of their gain may be required to be recharacterized as ordinary income to the extent that it represents the accrued but unpaid portion of the guaranteed payment to be paid on the next distribution date.

The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an “equitable apportionment” method. Treasury Regulations under Section 1223 of the Code allow a selling unitholder who can identify ~~common~~ units transferred with an ascertainable holding period to elect to use the actual holding period of the ~~common~~ units transferred. Thus, according to the ruling, a ~~common~~ unitholder will be unable to select high or low basis ~~common~~ units to sell as would be the case with corporate stock, but, according to the Treasury Regulations, may designate specific ~~common~~ units sold for purposes of determining the holding period of units transferred. A unitholder electing to use the actual holding period of ~~common~~ units transferred must consistently use that identification method for all subsequent sales or exchanges of ~~common~~ units. A unitholder considering the purchase of additional units or a sale of ~~common~~ units purchased in separate transactions is urged to consult ~~his~~its tax advisor as to the possible consequences of this ruling and application of the Treasury Regulations.

In addition, certain U.S. unitholders who are individuals, estates or trusts are required to pay an additional 3.8 percent tax on, among other things, capital gain from the sale or other disposition of their units. Unitholders should consult their tax advisors regarding the effect, if any, of this tax on their ownership of our ~~common~~ units.

generally is required to notify us in writing of that acquisition within 30 days after the purchase, unless a broker or nominee will satisfy such requirement. We are required to notify the IRS of any such transfers of units and to furnish specified information to the transferor and transferee. Failure to notify us of a transfer of units may lead to the imposition of substantial penalties.

Subject to detailed limitations set forth in the Code, a unitholder may elect to claim a credit against ~~his~~its liability for U.S. federal income tax for ~~his~~its share of foreign income taxes (and certain foreign taxes imposed in lieu of a tax based upon income) paid by us. Income allocated to unitholders ~~likely~~generally will constitute foreign source income falling in the passive foreign tax credit category for purposes of the U.S. foreign tax credit limitation. The rules relating to the determination of the foreign tax credit are complex and unitholders are urged to consult their ~~own~~ tax advisors to determine whether or to what extent they would be entitled to such credit. A unitholder who does not elect to claim foreign tax credits may instead claim a deduction for ~~his~~its share of foreign taxes paid by us.

Investments in units by employee benefit plans, other tax-exempt organizations and non-U.S. persons, including nonresident aliens of the United States, non-U.S. corporations and non-U.S. trusts and estates (collectively,non-U.S. ~~unitholders~~)unitholders) raise issues unique to those investors and, as described below, may result in substantially adverse tax consequences to them.

We may be required to withhold U.S. federal income tax, computed at the highest statutory rate, from cash distributions to non-U.S. unitholders with respect to their shares of our income that is U.S. effectively connected income. Our transportation income generally should not be treated as U.S. effectively connected income unless we have a fixed place of business in the United States and substantially all of such transportation income is attributable to either regularly scheduled transportation or, in the case of income derived from bareboat charters, is attributable to the fixed place of business in the United States. While we do not expect to have any regularly scheduled transportation or a fixed place of business in the United States, there can be no guarantee that this will not change. Under a ruling of the IRS, a portion of any gain recognized on the sale or other disposition of a unit by a non-U.S. unitholder may be treated as U.S. effectively connected income to the extent we have a fixed place of business in the United States and a sale of our assets would have given rise to U.S. effectively connected income. If we were to earn any U.S. effectively connected income, we believe a non-U.S. unitholder (including a non-U.S. Series A preferred unitholder) would be treated as being engaged in such business and would be required to file a U.S. federal income tax return to report ~~his~~its U.S. effectively

connected income (including ~~his~~its share of any such income earned by us) and to pay U.S. federal income tax, or claim a credit or refund for tax withheld on such income. Further, unless an exemption applies, a non-U.S. corporation investing in units may be subject to a branch profits tax, at a 30 percent rate or lower rate prescribed by a treaty, with respect to its U.S. effectively connected income.

Non-U.S. unitholders must apply for and obtain a U.S. taxpayer identification number in order to file U.S. federal income tax returns and must provide that identification number to us for purposes of any U.S. federal income tax information returns we may be required to file. Non-U.S. unitholders are encouraged to consult with their ~~own~~ tax advisors regarding the U.S. federal, state, local and other tax consequences of an investment in units and any filing requirements related thereto.

We intend to furnish to each unitholder, within 90 days after the close of each calendar year, specific U.S. federal income tax information, including a document in the form of IRS Form 1065, Schedule K-1, which sets forth ~~his~~its share of our items of income, gain, loss, deductions and credits as computed for U.S. federal income tax purposes and, with respect to a Series A preferred unitholder, the amount of the Series A preferred unitholder’s guaranteed payments, for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine each unitholder’s share of such items of income, gain, loss, deduction and credit. We cannot assure you that those positions will yield a result that conforms to the requirements of the Code, Treasury Regulations or administrative interpretations of the IRS. We cannot assure unitholders that the IRS will not successfully contend that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the units.

We will be obligated to file U.S. federal income tax information returns with the IRS for any year in which we earn any U.S. source income or U.S. effectively connected income. In the event we were obligated to file a U.S. federal income tax information return but failed to do so, unitholders would not be entitled to claim any deductions, losses or credits for U.S. federal income tax purposes relating to us. Consequently, we may file U.S. federal income tax information returns for any given year. The IRS may audit any such information returns that we file. Adjustments resulting from an IRS audit of our return may require each unitholder to adjust a prior year’s tax liability, and may result in an audit of ~~his~~its return. Any audit of a unitholder’s return could result in adjustments not related to our returns as well as those related to our returns. Any IRS audit relating to our items of income, gain, loss, deduction or credit for years in which we are not required to file and do not file a U.S. federal income tax information return would be conducted at the partner-level, and each unitholder may be subject to separate audit proceedings relating to such items.

For years in which we file or are required to file U.S. federal income tax information returns, we will be treated as a separate entity for purposes of any U.S. federal income tax audits, as well as for purposes of judicial review of administrative adjustments by the IRS and tax settlement proceedings. For such years, the tax treatment of partnership items of income, gain, loss, deduction and credit will be determined in a partnership proceeding rather than in separate proceedings with the partners. The Code requires that one partner be designated as the “Tax Matters Partner” for these purposes. The partnership agreement names Teekay GP L.L.C. as our Tax Matters Partner.

The Tax Matters Partner will make some U.S. federal tax elections on our behalf and on behalf of unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items reported in the information returns we file. The Tax Matters Partner may bind a unitholder with less than a 1 percent profits interest in us to a settlement with the IRS with respect to these items unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1 percent interest in profits or by any group of unitholders having in the aggregate at least a 5 percent interest in profits. However, only one action for judicial review will go forward, and each unitholder with an interest in the outcome may participate.

For taxable years beginning after December 31, 2017, the procedures for auditing large partnerships and for assessing and collecting taxes due (including applicable penalties and interest) as a result of an audit have been altered. Unless we are eligible to (and choose to) elect to issue revised schedules K-1 to our partners with respect to an audited and adjusted return, the IRS may assess and collect taxes (including

any applicable penalties and interest) directly from us in the year in which the audit is completed under the new rules. If we are required to pay taxes, penalties and interest as the result of audit adjustments, cash available for distribution to our unitholders may be substantially reduced. In addition, because payment would be due for the taxable year in which the audit is completed, unitholders during that taxable year would bear the expense of the adjustment even if they were not unitholders during the audited taxable year. Pursuant to this new legislation, we will designate a person (our General Partner) to act as the partnership representative who shall have the sole authority to act on behalf of the partnership with respect to dealings with the IRS under these new audit procedures.

A unitholder must file a statement with the IRS identifying the treatment of any item on ~~his~~its U.S. federal income tax return that is not consistent with the treatment of the item on an information return that we file. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial ~~penalties~~

penalties.

A U.S. person who either contributes more than $100,000 to us (when added to the value of any other property contributed to us by such person or a related person during the previous 12 months) or following a contribution owns, directly, indirectly or by attribution from certain related persons, at least a 10 percent interest in us, is required to file IRS Form 8865 with ~~his~~its U.S. federal income tax return for the year of the contribution to report the contribution and provide certain details about himself and certain related persons, us and any persons that own a 10 percent or greater direct interest in us. We will provide each unitholder with the necessary information about us and those persons who own a 10 percent or greater direct interest in us along with the Schedule K-1 information described previously.

In addition to the foregoing, a U.S. person who directly owns at least a 10 percent interest in us may be required to make additional disclosures on IRS Form 8865 in the event such person acquires, disposes or has ~~his~~its interest in us substantially increased or reduced. Further, a U.S. person who directly, indirectly or by attribution from certain related persons, owns at least a 10 percent interest in us may be required to make additional disclosures on IRS Form 8865 in the event such person, when considered together with any other U.S. persons who own at least a 10 percent interest in us, owns a greater than 50 percent interest in us. For these purposes, an “interest” in us generally is defined to include an interest in our capital or profits or an interest in our deductions or losses.

Significant penalties may apply for failing to satisfy IRS Form 8865 filing requirements and thus common unitholders are advised to contact their tax advisors to determine the application of these filing requirements under their own circumstances.

In addition, individual citizens or residents of the United States who hold certain specified foreign financial assets, including units in a foreign partnership not held in an account maintained by a financial institution, with an aggregate value in excess of $50,000, on the last day of a taxable year, or $75,000 at any time during that taxable year, may be required to report such assets on IRS Form 8938 with their U.S. federal income tax return for that taxable year. Penalties apply for failure to properly complete and file IRS Form 8938. Investors are encouraged to consult with your tax advisor regarding the potential application of this disclosure requirement.

An additional tax equal to 20 percent of the amount of any portion of an underpayment of U.S. federal income tax attributable to one or more specified causes, including negligence or disregard of rules or regulations and substantial understatements of income tax, is imposed by the Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for that portion and that the taxpayer acted in good faith regarding that portion.

A substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10 percent of the tax required to be shown on the return for the taxable year or $5,000. The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return:

More stringent rules, including additional penalties and extended statutes of limitations, may apply as a result of our participation in “listed transactions” or “reportable transactions with a significant tax avoidance purpose.” While we do not anticipate participating in such transactions, if any item of income, gain, loss, deduction or credit included in the distributive shares of unitholders for a given year might result in an “understatement” of income relating to such a transaction, we will disclose the pertinent facts on a U.S. federal income tax information return for such year. In such event, we also will make a reasonable effort to furnish sufficient information for unitholders to make adequate disclosure on their returns and to take other actions as may be appropriate to permit unitholders to avoid liability for penalties.

If we fail to meet the Qualifying Income Exception described above with respect to our classification as a partnership for U.S. federal income tax purposes, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery, we will be treated as a non-U.S. corporation for U.S. federal income tax purposes. If previously treated as a partnership, our change in status would be deemed to have been effected by our transfer of all of our assets, subject to liabilities, to a newly formed non-U.S. corporation, in return for stock in that corporation, and then our distribution of that stock to our unitholders and other owners in liquidation of their interests in us. Unitholders that are U.S. persons would be required to file IRS Form 926 to report these deemed transfers and any other transfers they made to us while we were treated as a corporation and may be required to recognize income or gain for U.S. federal income tax purposes

to the extent of certain prior deductions or losses and other items. Substantial penalties may apply for failure to satisfy these reporting requirements, unless the person otherwise required to report shows such failure was due to reasonable cause and not willful neglect.

In the event we were treated as a corporation, we do not believe that we would be able to qualify for the Section 883 Exemption and therefore our U.S. Source International Transportation Income would not be exempt from U.S. federal income taxation.

~~The 4 Percent Gross~~

Any income that we earn that is treated as Effectively Connected Income would be subject to U.S. federal corporate income tax (the highest statutory rate currently is ~~35.0 percent), unless the Section 883 Exemption (as discussed above) applied. The 4 percent U.S. federal income tax described above is inapplicable to Effectively Connected Income.~~

~~Unless the Section 883 Exemption applied,~~35%) and a ~~30 percent~~30% branch profits tax imposed under Section 884 of the ~~Code also would apply to our earnings that result from Effectively Connected Income, and~~Code. In addition, a branch interest tax could be imposed on certain interest paid or deemed paid by ~~us.~~

us if we were classified as a corporation.

On the sale of a vessel that has produced Effectively Connected Income, we ~~could~~generally would be subject to the net basis ~~corporate income tax~~ and ~~to the 30 percent~~ branch profits ~~tax~~taxes with respect to our gain ~~not in excess~~recognized up to the amount of certain prior deductions for depreciation that reduced Effectively Connected Income. Otherwise, we would not ~~expect to~~ be subject to U.S. federal income tax with respect to ~~the remainder of any~~ gain realized on sale of a vessel, ~~because it is expected that any~~provided the sale ~~of a vessel will be structured so that it~~ is considered to occur outside of the United States under U.S. federal income tax principles.

A non-U.S. entity treated as a corporation for U.S. federal income tax purposes will be a ~~passive foreign investment company (or~~PFIC) in any taxable year in which, after taking into account the income and assets of the corporation and certain subsidiaries pursuant to a “look through” rule, either (i) at least ~~75 percent~~75% of its gross income is “passive” income or (ii) at least ~~50 percent~~50% of the average value of its assets is attributable to assets that produce or are held for the production of passive income. For purposes of these tests, “passive income” includes dividends, interest, ~~and~~ gains from the sale or exchange of investment property and rents and royalties other than rents and royalties that are received from unrelated parties in connection with the active conduct of a trade or business. ~~For purposes of these tests,~~By contrast, income derived from the performance of services does not constitute “passive income.”

~~Based~~

There are legal uncertainties involved in determining whether the income derived from our time-chartering activities would constitute rental income or income derived from the performance of services, including legal uncertainties arising from the decision in Tidewater Inc. v. United States. 565 F.3d 299 (5th Cir. 2009), which held that income derived from certain time-chartering activities should be treated as rental income rather than services income for purposes of a foreign sales corporation provision of the Code. However, the IRS stated in an Action on Decision (AOD 2010-01) that it disagrees with, and will not acquiesce to, the way that the rental versus services framework was applied to the facts in the Tidewater decision, and in its discussion stated that the time charters at issue in Tidewater would be treated as producing services income for PFIC purposes. The IRS’s statement with respect to Tidewater cannot be relied upon or otherwise cited as precedent by taxpayers. Consequently, in the absence of any binding legal authority specifically relating to the statutory provisions governing PFICs, there can be no assurance that the IRS or a court would not follow the Tidewater decision in interpreting the PFIC provisions under the Code. Nevertheless, based on our current assets and operations, we ~~do not~~ believe that we would not now be ~~considered to be~~nor would have ever been a PFIC even if we were treated as a corporation. No assurance can be given, however, that the IRS would accept this position or that we would not constitute a PFIC for any future taxable year if we were treated as a corporation and there were to be changes in our assets, income or operations. ~~In addition, the decision of the United States Court of Appeals for the Fifth Circuit in~~~~Tidewater Inc. v. United States.~~ 565 F.3d 299 (5th Cir. 2009) held that income derived from certain time chartering activities should be treated as rental income rather than services income for purposes of a foreign sales corporation provision of the Code. However, the IRS stated in an Action on Decision (AOD 2010-001) that it disagrees with, and will not acquiesce to, the way that the rental versus services framework was applied to the facts in the~~Tidewater~~ ~~decision, and in its discussion stated that the time charters at issue in~~~~Tidewater~~ ~~would be treated as producing services income for PFIC purposes. The IRS’s statement with respect to~~~~Tidewater~~ cannot be relied upon or otherwise cited as precedent by taxpayers. Consequently, in the absence of any binding legal authority specifically relating to the statutory provisions governing PFICs, there can be no assurance that the IRS or a court would not follow the~~Tidewater~~ ~~decision in interpreting the PFIC provisions under the Code. Nevertheless, based on our current assets and operations~~,~~we believe that we would not now be nor would have ever been a PFIC even if we were treated as a corporation.~~

If we were to be treated as a PFIC for any taxable year during which a unitholder owns units, a U.S. unitholder generally would be subject to special rules (regardless of whether we continue thereafter to be a PFIC) resulting in increased tax liability with respect to (1) any “excess distribution” (i.e., the portion of any distributions received by a unitholder on our common units in a taxable year in excess of 125 percent of the average annual distributions received by the unitholder in the three preceding taxable years or, if shorter, the unitholder’s holding period for the units) and (2) any gain realized upon the sale or other disposition of units. Under these rules:

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~~the excess distribution or gain will be allocated ratably over the unitholder’s aggregate holding period for the common units;~~

In addition, for each year during which a U.S. unitholder holds units, we were treated as a PFIC, and the total value of all PFIC stock that such U.S. unitholder directly or indirectly owns exceeds certain thresholds, such unitholder would be required to file IRS Form 8621 with its annual U.S. federal income tax return to report its ownership of our units.

Our subsidiary Teekay LNG Holdco L.L.C. is wholly-owned by a U.S. partnership and has been classified as a corporation for U.S. federal income tax purposes and is subject to U.S. federal income tax based on the rules applicable to foreign corporations described above under “Possible Classification as a Corporation — Taxation of Operating Income,” including, but not limited to, the ~~4 percent~~4% gross basis tax or the net basis tax if the Section 883 Exemption does not apply. We believe that the Section 883 Exemption would apply to our corporate subsidiary only to the extent that it would apply to us if we were to be treated as a corporation. As such, we believe that the Section 883 Exemption did not apply for ~~2014~~2016 and ~~would~~will not apply in 2017 or subsequent years and therefore, the ~~4 percent~~4% gross basis tax applied to our subsidiary corporation in ~~2014~~2016 and will apply to our subsidiary corporation in 2017 and subsequent years. In this regard, we estimate that we will be subject to approximately $100,000 or less of U.S. federal income tax in ~~2015~~2017 and in each subsequent year based on the amount of U.S. Source

International Transportation Income our corporate subsidiary earned for ~~2014~~2016 and its expected U.S. Source International Transportation Income for ~~2015~~2017 and subsequent years. The amount of such tax for which it would be liable for any year will depend upon the amount of income earned from voyages into or out of the United States in such year, which, however, is not within its complete control.

In past years, certain other of our subsidiaries were classified as corporations for U.S. federal income tax purposes. We have and will continue to take the position that these subsidiaries, to the extent they were owned by our U.S. partnership, should also have been treated as CFCs rather than PFICs. Moreover, we have and will continue to take the position that these subsidiaries were not PFICs at any time prior to being owned by our U.S. partnership. No assurance can be given, however, that the IRS, or a court of law, will accept this position or would not follow theTidewater decision in interpreting the PFIC provisions under the Code (as discussed above).

Teekay LNG Partners L.P. is considered to be a partnership under Canadian federal income tax law and therefore not a taxable entity for Canadian income tax purposes. A U.S. Resident Holder will not be liable to tax under the Canada Tax Act on any income or gains allocated by usTeekay LNG Partners L.P. to the U.S. Resident Holder in respect of such U.S. Resident Holder’s ~~common~~ units, provided that for purposes of the Canada-U.S. Treaty, (a) ~~we do~~Teekay LNG Partners L.P. does not carry on business through a permanent establishment in Canada and (b) such U.S. Resident Holder does not hold such ~~common~~ units in connection with a business carried on by such U.S. Resident Holder through a permanent establishment in Canada.

A U.S. Resident Holder will not be liable to tax under the Canada Tax Act on any income or gain from the sale, redemption or other disposition of such U.S. Resident Holder’s ~~common~~ units, provided that, for purposes of the Canada-U.S. Treaty, such ~~common~~ units do not, and did not at any time in the twelve-month period preceding the date of disposition, form part of the business property of a permanent establishment in Canada of such U.S. Resident Holder.

We believe that ~~our~~the activities and affairs of Teekay LNG Partners L.P. are conducted in such a manner that ~~we are~~Teekay LNG Partners L.P. is not carrying on business in Canada and that U.S. Resident Holders should not be considered to be carrying on business in Canada for purposes of the Canada Tax Act or the Canada-U.S. Treaty solely by reason of the acquisition, holding, disposition or redemption of ~~common~~ units. We intend that this is and continues to be the case, notwithstanding that Teekay Shipping Limited (a subsidiary of Teekay Corporation that is ~~resident~~a non-resident of Canada) and ~~based in Bermuda) provides~~Service Provider (an indirect subsidiary of Teekay LNG Partners L.P. that is a non-resident of Canada) provide certain services to Teekay LNG Partners L.P. and ~~obtains~~obtain some or all such services under subcontracts with Canadian service providers. If the arrangements we have entered into result in ~~our~~Teekay LNG Partners L.P. being considered to carry on business in Canada for purposes of the Canada Tax Act, U.S. Resident Holders would be considered to be carrying on business in Canada and may be required to file Canadian tax returns and would be subject to taxation in Canada on any income from such business that is considered to be attributable to a permanent establishment in Canada for purposes of the Canada-U.S. ~~Treaty~~

Treaty.

Although we do not intend to do so, there can be no assurance that the manner in which we carry on our activities will not change from time to time as circumstances dictate or warrant in a manner that may cause U.S. Resident Holders to be carrying on business in Canada for purposes of the Canada Tax Act. Further, the relevant Canadian federal income tax law may change by legislation or judicial interpretation and the Canadian taxing authorities may take a different view than we have of the current law.

We and our subsidiaries are subject to taxation in certain non-U.S. jurisdictions because we or our subsidiaries are either organized, or conduct business or operations, in such ~~jurisdictions. We intend that our business and the business of our subsidiaries will~~jurisdictions, but we do not expect any such tax to be ~~conducted and operated in a manner that minimizes taxes imposed upon us and our subsidiaries.~~material. However, we cannot assure this result as tax laws in these or other jurisdictions may change or we may enter into new business transactions relating to such jurisdictions, which could affect our tax liability. Please read “Item 18 – Financial Statements: Note 10 – Income Tax.”

We are exposed to the impact of interest rate changes primarily through our borrowings that require us to make interest payments based on LIBOR, EURIBOR or NIBOR. Significant increases in interest rates could adversely affect our operating margins, results of operations and our ability to service our debt. From time to time, we use interest rate swaps to reduce our exposure to market risk from changes in interest rates. The principal objective of these contracts is to minimize the risks and costs associated with our floating-rate debt.

We are exposed to credit loss in the event of non-performance by the counterparties to the interest rate swap agreements. In order to minimize counterparty risk, we only enter into derivative transactions with counterparties that are rated A- or better by Standard & Poor’s or A3 or better by Moody’s at the time of the transactions. In addition, to the extent practical, interest rate swaps are entered into with different counterparties to reduce concentration risk.

The table below provides information about our financial instruments at December 31, ~~2014,~~2016, that are sensitive to changes in interest rates. For long-term debt and capital lease obligations, the table presents principal payments and related weighted-average interest rates by expected maturity dates. For interest rate swaps, the table presents notional amounts and weighted-average interest rates by expected contractual maturity dates.

The expected contractual maturity dates do not reflect potential prepayments of long-term debt and capital lease obligations as well as the potential exercise of early termination options for certain of our interest rate swaps.

Our functional currency is U.S. Dollars because primarily all of our revenues and most of our operating costs are in U.S. Dollars. Our results of operations are affected by fluctuations in currency exchange rates. The volatility in our financial results due to currency exchange rate fluctuations is attributed primarily to foreign currency revenues and expenses, our Euro-denominated loans and restricted cash deposits and our NOK-denominated bonds. A portion of our voyage revenues are denominated in Euros. A portion of our vessel operating expenses and general and administrative expenses are denominated in Euros, which is primarily a function of the nationality of our crew and administrative staff. We have Euro-denominated interest expense and Euro-denominated interest income related to our Euro-denominated loans of ~~235.6~~208.9 million Euros ($~~285.0~~219.7 million) and Euro-denominated restricted cash deposits of ~~15.1~~18.3 million Euros ($~~18.3~~19.2 million), respectively, as at December 31, ~~2014.~~2016. We also incur NOK-denominated interest expense on our NOK-denominated bonds; however, we entered into cross-currency swaps and pursuant to these swaps we receive the principal amount in NOK on the maturity date of the swap, in exchange for payment of a fixed U.S. Dollar amount. In addition, the cross-currency swaps exchange a receipt of floating interest in NOK based on NIBOR plus a margin for a payment of U.S. Dollar fixed interest. The purpose of the cross-currency swaps is to economically hedge the foreign currency exposure on the payment of interest and principal of our NOK bonds due in 2017 through ~~2018,~~2021, and to economically hedge the interest rate exposure. We have not designated, for accounting purposes, these cross-currency swaps as cash flow hedges of ~~its~~the NOK-denominated bonds due in 2017 through ~~2018.~~2021. Please read “Item 18 – Financial Statements: Note 12 – Derivative ~~Instruments.~~Instruments and Hedging Activities.” At December 31, ~~2014,~~2016, the fair value of the cross-currency swaps derivative liabilities was ~~$70.4~~$99.8 million and the change from December ~~2013~~2015 to the reporting period has been reported in foreign currency exchange gain ~~(loss).~~in the consolidated statements of income. As a result, fluctuations in the Euro and NOK relative to the U.S. Dollar have caused, and are likely to continue to cause, fluctuations in our reported voyage revenues, vessel operating expenses, general and administrative expenses, interest expense, interest income, realized and unrealized loss on non-designated derivative instruments and foreign currency exchange ~~gain (loss).~~

gain.

Not applicable.

None.

Not applicable.

We maintain disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities and Exchange Act of 1934, as amended (or theExchange ~~Act~~)Act)) that are designed to ensure that (i) information required to be disclosed in our reports that are filed or submitted under the Exchange Act, are recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms, and (ii) information required to be disclosed by us in the reports we file or submit under the Exchange Act is accumulated and communicated to our management, including the principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

We conducted an evaluation of our disclosure controls and procedures under the supervision and with the participation of the Chief Executive Officer and Chief Financial ~~Officer.~~Officer of Service Provider. Based on the evaluation, the Chief Executive Officer and Chief Financial Officer of Service Provider concluded that our disclosure controls and procedures are effective as of December 31, ~~2014.~~

2016.

The Chief Executive Officer and Chief Financial Officer of Service Provider do not expect that our disclosure controls or internal controls will prevent all ~~error~~errors and all fraud. Although our disclosure controls and procedures were designed to provide reasonable assurance of achieving their objectives, a control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within us have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based partly on certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions.

Our management is responsible for establishing and maintaining for us adequate internal controls over financial reporting.

Our internal controls are designed to provide reasonable assurance as to the reliability of our financial reporting and the preparation and presentation of the consolidated financial statements for external purposes in accordance with accounting principles generally accepted in the United States. Our internal controls over financial reporting include those policies and procedures that: 1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets; 2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of the financial statements in accordance with U.S. generally accepted accounting principles, and that our receipts and expenditures are being made in accordance with authorizations of management and the directors; and 3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our consolidated financial statements.

We conducted an evaluation of the effectiveness of our internal control over financial reporting based upon the framework in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. This evaluation included review of the documentation of controls, evaluation of the design effectiveness of controls, testing of the operating effectiveness of controls and a conclusion on this evaluation.

Because of its inherent limitations, internal controls over financial reporting may not prevent or detect misstatements even when determined to be effective and can only provide reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies and procedures may deteriorate. Based on the evaluation, management has determined that the internal control over financial reporting was effective as of December 31, ~~2014.~~

2016.

Our independent auditors, KPMG LLP, an independent registered public accounting firm, has audited the accompanying consolidated financial statements and our internal control over financial reporting. Their attestation report on the effectiveness of our internal control over financial reporting can be found on page F-2 of this Annual Report.

There were no changes in our internal controls that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting (as defined in Rule 13a – 15 (f) under the Exchange Act) that occurred during the year ended December 31, ~~2014.~~

2016.

The Board of Directors of our General Partner has determined that director ~~Robert E. Boyd qualified, and~~ Ms. Beverlee F. Park ~~who replaced Mr. Boyd when he retired from the Board of Directors of our General Partner on March 11, 2014,~~ qualifies as an audit committee financial expert and is independent under applicable NYSE and SEC standards.

Our principal accountant for ~~2014~~2016 and ~~2013~~2015 was KPMG LLP, Chartered Professional Accountants. The following table shows the fees we paid or accrued for audit and audit-related services provided by KPMG LLP for ~~2014~~2016 and ~~2013.~~

Fees(in thousands of U.S. Dollars)    2014    2013
   $    $
Audit Fees⁽¹⁾
   729    837
Audit-Related Fees⁽²⁾
   3    10
Other⁽³⁾
   —      50




Total
732 897

2015.

No fees for tax services were provided to the Partnership by the auditor during the term of their appointments in ~~2014~~2016 and ~~2013.~~

2015.

The Audit Committee of our General Partner’s Board of Directors has the authority to pre-approve permissible audit, audit-related and non-audit services not prohibited by law to be performed by our independent auditors and associated fees. Engagements for proposed services either may be separately pre-approved by the Audit Committee or entered into pursuant to detailed pre-approval policies and procedures established by the Audit Committee, as long as the Audit Committee is informed on a timely basis of any engagement entered into on that basis. The Audit Committee pre-approved all engagements and fees paid to our principal accountant in ~~2014~~2016 and in ~~2013.~~

2015.

Not applicable.

There are no other significant ways in which our corporate governance practices differ from those followed by domestic companies under the listing requirements of the New York Stock Exchange.

Not applicable.

The following financial statements, together with the related reports of KPMG LLP, Independent Registered Public Accounting Firm are filed as part of this Annual Report:

All schedules for which provision is made in the applicable accounting regulations of the SEC are not required, are inapplicable or have been disclosed in the Notes to the Consolidated Financial Statements and therefore have been omitted.

The following exhibits are filed as part of this Annual Report:

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Significant intercompany balances and transactions have been eliminated upon consolidation. In addition, certain of the comparative figures ~~as at December 31, 2013~~ have been reclassified to conform to the presentation adopted in the current period relating to in-process revenue contracts of $1.1 million and $3.7 million reclassified from unearned revenue and other long-term liabilities, respectively, to current portion of in-process contracts and in-process contracts, respectively,certain operating activities in the ~~Partnership’s~~Partnership's consolidated ~~balance sheets.~~

statements of cash flows and certain of the summarized financial information in Note 6c.

The consolidated financial statements are stated in U.S. Dollars and the functional currency of the Partnership and its subsidiaries is the U.S. Dollar. Transactions involving other currencies during the year are converted into U.S. Dollars using the exchange rates in effect at the time of the transactions. At the balance sheet date, monetary assets and liabilities that are denominated in currencies other than the U.S. Dollar are translated to reflect the year-end exchange rates. Resulting gains or losses are reflected separately in the accompanying consolidated statements of income.

The lease element of time-charters and bareboat charters accounted for as operating leases are recognized by the Partnership on a straight-line basis daily over the term of the charter as the applicable vessel operates under the charter. The lease element of the Partnership’s time-charters that are accounted for as direct financing leases are reflected on the balance sheets as net investments in direct financing leases. The lease element is recognized over the lease term using the effective interest rate method and is included in voyage revenues. The Partnership recognizes revenues from the non-lease element of time-charter contracts ~~daily~~ as services are performed. The Partnership does not recognize revenues during days that the vessel is off-hire.

Voyage expenses are all expenses unique to a particular voyage, including bunker fuel expenses, port fees, cargo loading and unloading expenses, canal tolls, agency fees and commissions. Vessel operating expenses include crewing, ship management services, repairs and maintenance, insurance, stores, lube oils and communication expenses. Voyage expenses and vessel operating expenses are recognized when incurred.

The Partnership classifies all highly-liquid investments with a maturity date of three months or less when purchased as cash and cash equivalents.

Accounts receivable are recorded at the invoiced amount and do not bear interest. The allowance for doubtful accounts is the Partnership’s best estimate of the amount of probable credit losses in existing accounts receivable. The Partnership determines the allowance based on historical write-off experience and customer economic data. The Partnership reviews the allowance for doubtful accounts regularly and past due balances are reviewed for collectability. Account balances are charged against the allowance when the Partnership believes that the receivable will not be recovered.

~~TEEKAY LNG PARTNERS L.P. AND SUBSIDIARIES~~

~~NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS~~

~~(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)~~

All pre-delivery costs incurred during the construction of newbuildings, including interest and supervision and technical costs, are capitalized. The acquisition cost and all costs incurred to restore used vessels purchased by the Partnership to the standards required to properly service the Partnership’s customers are capitalized.

Vessel capital modifications include the addition of new equipment or can encompass various modifications to the vessel which are aimed at improving or increasing the operational efficiency and functionality of the asset. This type of expenditure is amortized over the estimated useful life of the modification. Expenditures covering recurring routine repairs and maintenance are expensed as incurred.

Interest costs capitalized to vessels and equipment for the years ended December 31, 2016, 2015 and 2014 ~~2013~~aggregated $9.9 million, $8.2 million and ~~2012 aggregated~~ $3.1 million, ~~$1.3 million and $24 thousand,~~ respectively.

Gains on vessels sold and leased back under capital leases are deferred and amortized over the remaining estimated useful life of the vessel. Losses on vessels sold and leased back under capital leases are recognized immediately to the extent that the fair value of the vessel at the time of sale-leaseback is less than its book value.

Generally, the Partnership dry docks each of its vessels every five years. In addition, a shipping society classification intermediate survey is performed on the Partnership’s LNG and LPG carriers between the second and third year of the five-year dry-docking ~~period.~~cycle. The Partnership capitalizes certain costs incurred during dry docking and for the survey and amortizes those costs on a straight-line basis from the completion of a dry docking or intermediate survey over the estimated useful life of the dry dock. The Partnership includes in capitalized dry docking those costs incurred as part of the dry docking to meet regulatory requirements, or expenditures that either add economic life to the vessel, increase the vessel’s earning capacity or improve the vessel’s operating efficiency. The Partnership expenses costs related to routine repairs and maintenance performed during dry docking that do not improve operating efficiency or extend the useful lives of the assets.

~~Dry-docking activity for~~

The following table summarizes the ~~three years ended~~change in the Partnership’s capitalized dry docking costs, from January 1, 2014 to December 31, ~~2014, 2013 and 2012 is summarized as follows:~~

   Year Ended December 31,
   2014    2013    2012
   $    $    $
Balance at January 1,
   40,328    28,821    34,449
Cost incurred for dry docking
   13,471    27,203    7,493
Sales of vessels (note 4)
   (5,327 )    (2,285 )    —
Dry-dock amortization
   (14,837 )    (13,411 )    (13,121 )






Balance at December 31,
33,635 40,328 28,821

2016:

Vessels and equipment that are “held and used” are assessed for impairment when events or circumstances indicate the carrying amount of the asset may not be recoverable. If the asset’s net carrying value exceeds the net undiscounted cash flows expected to be generated over its remaining useful life, the carrying amount of the asset is reduced to its estimated fair value. The estimated fair value for the Partnership’s impaired vessels is determined using discounted cash flows or appraised values. In cases where an active second hand sale and purchase market does not exist, the Partnership uses a discounted cash flow approach to estimate the fair value of an impaired vessel. In cases where an active second hand sale and purchase market exists, an appraised value is generally the amount the Partnership would expect to receive if it were to sell the vessel. Such appraisal is normally completed by the Partnership.

Vessels and equipment that are held for sale are measured at the lower of their carrying amount or fair value less costs to sell and are not depreciated while classified as held for sale. Interest and other expenses attributable to vessels and equipment classified as held for sale, or to their related liabilities, continue to be recognized as incurred.

Gains on vessels sold and leased back under capital leases are deferred and amortized over the remaining term of the capital lease. Losses on vessels sold and leased back under capital leases are recognized immediately when the fair value of the vessel at the time of sale and lease-back is less than its book value. In such case, the Partnership would recognize a loss in the amount by which book value exceeds fair value.

The Partnership’s investments in certain joint ventures are accounted for using the equity method of accounting. Under the equity method of accounting, investments are stated at initial cost and are adjusted for subsequent additional investments and the Partnership’s proportionate share of earnings or losses and distributions. In addition, the Partnership’s advances to equity accounted joint ventures are recorded at cost. The Partnership evaluates its investment in and advances to equity accounted joint ventures for impairment when events or circumstances indicate that the carrying value of such investments may have experienced an other-than-temporary decline in value below its carrying value. If the estimated fair value is less than the carrying value, the carrying value is written down to its estimated fair value and the resulting impairment is recorded in the Partnership’s consolidated statements of income.

~~TEEKAY LNG PARTNERS L.P. AND SUBSIDIARIES~~

~~NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS~~

~~(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)~~

Debt issuance costs, including fees, commissions and legal expenses, are presented as ~~other assets and~~a direct reduction from the carrying amount of the debt liability with the exception if debt issuance costs are not attributable to a specific debt liability or the debt issuance costs exceed the carrying value of the related debt liability, the debt issuance costs are deferred and presented as other assets in the Partnership's consolidated balance sheets. Debt issuance costs are amortized on an effective interest rate method over the term of the relevant loan. Amortization of debt issuance costs is included in interest expense.

Goodwill is not amortized, but reviewed for impairment at the reporting unit level on an annual basis or more frequently if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. When goodwill is reviewed for impairment, the Partnership may elect to assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount, including goodwill. Alternatively, the Partnership may bypass this step and use a fair value approach to identify potential goodwill impairment and, when necessary, measure the amount of impairment. The Partnership uses a discounted cash flow model to determine the fair value of reporting units, unless there is a readily determinable fair market value. Intangible assets are assessed for impairment when and if impairment indicators exist. An impairment loss is recognized if the carrying amount of an intangible asset is not recoverable and its carrying amount exceeds its fair value.

The Partnership’s finite life intangible assets consist of acquired time-charter contracts and are amortized on a straight-line basis over the remaining term of the time-charters. Finite life intangible assets are assessed for impairment when events or circumstances indicate that the carrying value may not be recoverable.

All derivative instruments are initially recorded at fair value as either assets or liabilities in the accompanying consolidated balance sheet and subsequently remeasured to fair value, regardless of the purpose or intent for holding the derivative. The method of recognizing the resulting gain or loss is dependent on whether the derivative contract is designed to hedge a specific risk and whether the contract qualifies for hedge accounting. At December 31, 2014, the Partnership has not applied hedge accounting to its derivative instruments, except for one interest rate swap in its equity accounted joint venture between the Partnership and Marubeni Corporation (or the~~Teekay LNG-Marubeni Joint Venture) (see note 5).~~

When a derivative is designated as a cash flow hedge, the Partnership formally documents the relationship between the derivative and the hedged item. This documentation includes the strategy and risk management objective for undertaking the hedge and the method that will be used to assess the effectiveness of the hedge. Any hedge ineffectiveness is recognized immediately in earnings, as are any gains and losses on the derivative that are excluded from the assessment of hedge effectiveness. The Partnership does not apply hedge accounting if it is determined that the hedge was not effective or will no longer be effective, the derivative was sold or exercised, or the hedged item was sold, repaid or no longer possible of occurring.

For derivative financial instruments designated and qualifying as cash flow hedges, changes in the fair value of the effective portion of the derivative financial instruments are initially recorded as a component of accumulated other comprehensive income (loss) in total equity. In the periods when the hedged items affect earnings, the associated fair value changes on the hedging derivatives are transferred from total equity to the corresponding earnings line item in the consolidated statements of income. The ineffective portion of the change in fair value of the derivative financial instruments is immediately recognized in earnings in the consolidated statements of income. If a cash flow hedge is terminated and the originally hedged item is still considered possible of occurring, the gains and losses initially recognized in total equity remain there until the hedged item impacts earnings, at which point they are transferred to the corresponding earnings line item (e.g. interest expense) in the consolidated statements of income. If the hedged items are no longer possible of occurring, amounts recognized in total equity are immediately transferred to the earnings item in the consolidated statements of income.

The Partnership grants restricted unit awards as incentive-based compensation under the Teekay LNG Partners L.P. 2005 Long-Term Incentive Plan to certain of the Partnership’s employees and to certain employees of Teekay Corporation’s subsidiaries that provide services to the Partnership and its subsidiaries. The Partnership measures the cost of such awards using the grant date fair value of the award and recognizes that cost, net of estimated forfeitures, over the requisite service period. The requisite service period consists of the period from the grant date of the award to the earlier of the date of vesting or the date the recipient becomes eligible for retirement. For unit-based compensation awards subject to graded vesting, the Partnership calculates the value for the award as if it was one single award with one expected life and amortizes the calculated expense for the entire award on a straight-line basis over the requisite service period. The compensation cost of the Partnership’s unit-based compensation awards are reflected in general and administrative expenses in the Partnership’s consolidated statements of income.

these two vessels are registered in the Canary Islands Special Ship Registry. Consequently, the Partnership is allowed a credit, equal to 90% of the tax payable on income from the commercial operation of these vessels, against the tax otherwise payable. This effectively results in an income tax rate of approximately 3%2.5% on income from the operation of these two Spanish-flagged vessels.

The Partnership recognizes the benefits of uncertain tax positions when it is more-likely-than-not that a tax position taken or expected to be taken in a tax return will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. If a tax position meets the more-likely-than-not recognition threshold, it is measured to determine the amount of benefit to recognize in the financial statements. The Partnership recognizes interest and penalties related to uncertain tax positions in income tax expense in the Partnership’s consolidated statements of income.

~~TEEKAY LNG PARTNERS L.P. AND SUBSIDIARIES~~

~~NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS~~

~~(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)~~

Guarantees issued by the Partnership, excluding those that are guaranteeing its own performance, are recognized at fair value at the time the guarantees are issued and are presented in the Partnership’s consolidated balance sheets as other long-term liabilities. The liability recognized on issuance is amortized to other income ~~(expense)~~ on the Partnership’s consolidated statements of income ~~as the Partnership’s risk from the guarantees declines~~ over the term of the guarantee. If it becomes probable that the Partnership will have to perform under a guarantee, the Partnership will recognize an additional liability if the amount of the loss can be reasonably estimated.

The following table contains the changes in the balance of the Partnership’s only component of accumulated other comprehensive income (loss) ~~income~~ for the periods presented:

losses and requires consideration of a broader range of reasonable and supportable information to inform credit loss estimates. This update

is effective for the Partnership January 1, 2020, with a modified-retrospective approach. The Partnership is currently evaluating the effect of

adopting this new guidance.

equity method investees in the statement of cash flows. This update is effective for the Partnership January 1, 2018, with a retrospective

approach. The Partnership is currently evaluating the effect of adopting this new guidance.

The following methods and assumptions were used to estimate the fair value of each class of financial instrument:

The Partnership categorizes the fair value estimates by a fair value hierarchy based on the inputs used to measure fair value. The fair value hierarchy has three levels based on the reliability of the inputs used to determine fair value as follows:

~~Level 1. Observable inputs such as quoted prices in active markets;~~

~~Level 2. Inputs, other than the quoted prices in active markets, that are observable either directly or indirectly; and~~

~~Level 3. Unobservable inputs in which there is little or no market data, which require the reporting entity to develop its own assumptions.~~

The following table includes the estimated fair value and carrying value of those assets and liabilities that are measured at fair value on a recurring and non-recurring basis, as well as the estimated fair value of the Partnership’s financial instruments that are not accounted for at a fair value on a recurring basis.

The following table contains a summary of the Partnership’s loan receivables and other financing receivables by type of borrower and the method by which the Partnership monitors the credit quality of its financing receivables on a quarterly basis.

   December 31,    December 31,
Credit Quality    2014    2013
Class of Financing Receivable
Indicator Grade    $    $
Direct financing leases
Payment activity Performing    682,495    699,695
Other receivables:

Long-term receivable and accrued revenue included in other assets (note 5b)
Payment activity Performing    27,266    8,095
Advances to equity accounted joint ventures(notes 6b and 6c)
Other internal metrics Performing    181,514    85,135
Advances to joint venture partner (note 6a)
Other internal metrics Settled    —      14,364




891,275 807,289

The Partnership has two reportable segments, its liquefied gas segment and its conventional tanker segment. The Partnership’s liquefied gas segment consists of LNG carriers, LPG carriers and ~~LPG/Multigas~~multigas carriers, which can carry both LNG and LPG, which generally operate under long-term, fixed-rate charters to international energy companies and Teekay Corporation (see Note 11a). As at December 31, ~~2014,~~2016, the Partnership’s liquefied gas segment consisted of 4750 LNG carriers and LNG carrier newbuildings (including 2026 LNG carriers and LNG carrier newbuildings included in joint ventures that are accounted for under the equity method), and 3029 LPG/Multigas carriers and LPG carrier newbuildings (including 2423 LPG carriers and LPG carrier newbuildings included in a joint venture that is accounted for under the equity method). ~~The~~As at December 31, 2016, the Partnership’s conventional tanker segment consisted of ~~seven~~five Suezmax-class crude oil tankers and one Handymax product ~~tanker which generally operate under long-term, fixed-rate time-charter contracts to international energy and shipping companies.~~tanker. Segment results are evaluated based on income from vessel operations. The accounting policies applied to the reportable segments are the same as those used in the preparation of the Partnership’s consolidated financial statements.

The following table presents voyage revenues and percentage of consolidated voyage revenues for the Partnership’s ~~top~~ customers who accounted for 10% or more of the Partnership's consolidated voyage revenues during any of the periods presented.

The following tables include results for these segments for the years presented in these financial statements.

   Year Ended December 31, 2014
   Conventional
   Liquefied Gas Tanker
   Segment Segment Total
   $ $ $
Voyage revenues
   307,426 95,502 402,928
Voyage expenses
   (1,768 ) (1,553 ) (3,321 )
Vessel operating expenses
   (59,087 ) (36,721 ) (95,808 )
Depreciation and amortization
   (71,711 ) (22,416 ) (94,127 )
General and administrative⁽ⁱ⁾
   (17,992 ) (5,868 ) (23,860 )
Restructuring charge
   —   (1,989 ) (1,989 )


Income from vessel operations
156,868 26,955 183,823


Equity income
115,478 —   115,478
Investment in and advances to equity accounted joint ventures
891,478 —   891,478
Total assets at December 31, 2014
3,395,759 381,838 3,777,597
Expenditures for vessels and equipment
(193,669 ) (586 ) (194,255 )
Expenditures for dry docking
(8,127 ) (5,344 ) (13,471 )


   Year Ended December 31, 2013
   Conventional
   Liquefied Gas Tanker
   Segment Segment Total
   $ $ $
Voyage revenues
   285,694 113,582 399,276
Voyage expenses
   (407 ) (2,450 ) (2,857 )
Vessel operating expenses
   (55,459 ) (44,490 ) (99,949 )
Depreciation and amortization
   (71,485 ) (26,399 ) (97,884 )
General and administrative⁽ⁱ⁾
   (13,913 ) (6,531 ) (20,444 )
Restructuring charge
   —   (1,786 ) (1,786 )


Income from vessel operations
144,430 31,926 176,356


Equity income
123,282 —   123,282
Investment in and advances to equity accounted joint ventures
671,789 —   671,789
Total assets at December 31, 2013
3,591,693 456,186 4,047,879
Expenditures for vessels and equipment
(469,463 ) (750 ) (470,213 )
Expenditures for dry docking
(21,090 ) (6,113 ) (27,203 )


   Year Ended December 31, 2012
   Conventional
   Liquefied Gas Tanker
   Segment Segment Total
   $ $ $
Voyage revenues
   278,511 114,389 392,900
Voyage expenses
   (66 ) (1,706 ) (1,772 )
Vessel operating expenses
   (50,124 ) (44,412 ) (94,536 )
Depreciation and amortization
   (69,064 ) (31,410 ) (100,474 )
General and administrative⁽ⁱ⁾
   (13,224 ) (5,736 ) (18,960 )
Write down of vessels
   —   (29,367 ) (29,367 )


Income from vessel operations
146,033 1,758 147,791


Equity income
78,866 —   78,866
Expenditures for vessels and equipment
(39,366 ) (528 ) (39,894 )
Expenditures for dry docking
(6,054 ) (1,439 ) (7,493 )

A reconciliation of total segment assets presented in the consolidated balance sheets is as follows:

   December 31,    December 31,
   2014    2013
   $    $
Total assets of the liquefied gas segment
   3,395,759    3,591,693
Total assets of the conventional tanker segment
   381,838    456,186
Unallocated:

Cash and cash equivalents
   159,639    139,481
Accounts receivable and prepaid expenses
   15,240    25,600
Advances to affiliates
   11,942    6,634




Consolidated total assets
3,964,418 4,219,594

The amounts in the table below assume the owner will not exercise its options to require the Partnership to purchase either of the two remaining vessels from the owner, but rather it assumes the owner will cancel the charter contracts when the cancellation right is first exercisable (in October 2017 and July 2018, respectively), and sell the ~~vessel~~vessels to a third party, upon which the remaining lease ~~obligation~~obligations will be extinguished.

At the inception of these leases, the weighted-average interest rate implicit in these leases was 5.5%. These capital leases are variable-rate capital leases. However, any change in the lease payments resulting from changes in interest rates is offset by a corresponding change in the charter hire payments received by the Partnership.

~~TEEKAY LNG PARTNERS L.P. AND SUBSIDIARIES~~

~~NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS~~

~~(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)~~

As at December 31, ~~2014,~~2016, the remaining commitments under the two capital leases for Suezmax tankers, including the related purchase obligations, ~~for the two Suezmax tankers,~~ approximated ~~$73.7~~$58.2 million, including imputed interest of ~~$10.2~~$3.6 million, repayable from ~~2015~~2017 through 2018, as indicated below:

Year
   Commitment
2015
   $ 7,790
2016
   $ 7,673
2017
   $ 30,953
2018
   $ 27,296

The Partnership’s capital leases relating to its Suezmax tankers do not contain financial or restrictive covenants other than those relating to operation and maintenance of the vessels.

The Partnership maintains restricted cash deposits relating to certain term loans, collateral for cross-currency swaps, project tenders, leasing arrangements (see Note 13c) and amounts received from charterers to be used only for dry-docking expenditures and emergency repairs, which cash totaled ~~$39.2~~$117.0 million and ~~$21.7~~$111.5 million as at December 31, ~~2014~~2016 and ~~2013,~~2015, respectively.

As at December 31, ~~2014,~~2016, the total estimated future minimum rental payments to be received and paid under the lease contracts are as follows:

Year
   Head Lease
Receipts⁽ⁱ⁾    Sublease
Payments^(i)(ii)




2015
$ 22,188    $ 24,113
2016
$ 21,242    $ 24,113
2017
$ 21,242    $ 24,113
2018
$ 21,242    $ 24,113
2019
$ 21,242    $ 24,113
Thereafter
$ 196,579    $ 223,185




Total
$ 303,735    $ 343,750

As at December 31, ~~2014,~~2016, estimated minimum lease payments to be received by the Partnership under the Tangguh LNG Carrier leases in each of the next five succeeding fiscal years ~~were~~are approximately $39.1 million per year from ~~2015~~2017 through ~~2019.~~2021. Both leases are scheduled to end in 2029. In addition, estimated minimum lease payments in the next ~~four~~two years to be received by the Partnership under the Awilco LNG Carrier leases are approximately ~~$32.8 million (2015), $35.9 million (2016), $165.0~~$162.0 million (2017) and $134.6 million (2018).

As at December 31, ~~2014,~~2016, the minimum scheduled future revenues ~~in the next five years~~ to be received by the Partnership in each of the next five years for the lease and non-lease elements under charters that were accounted for as operating leases are approximately ~~$324.1 million (2015), $300.8 million (2016), $299.8~~$349.2 million (2017), ~~$258.1~~$372.2 million (2018), $404.0 million (2019), $393.3 million (2020), and ~~$243.4~~$353.5 million ~~(2019)~~(2021). Minimum scheduled future revenues do not include revenue generated from new contracts entered into after December 31, ~~2014,~~2016, revenue from ~~undelivered~~ vessels in the Partnership’s equity accounted investments, revenue from unexercised option periods of contracts that existed on December 31, ~~2014,~~2016, or variable or contingent revenues. Therefore, the minimum scheduled future revenues should not be construed to reflect total charter hire revenues for any of ~~the~~these five years.

As at December 31, ~~2014, the interest accrued on these advances was $1.0 million (December 31, 2013 – $0.4 million). Both the advances~~2016 and ~~the accrued interest on these advances are included in investment and advances to equity accounted joint ventures in~~2015, intangible assets consisted of acquired time-charter contracts with a weighted-average amortization period of 20.7 years. The carrying amount of intangible assets for the Partnership’s ~~consolidated balance sheet.~~

c) The Partnership has a 50% interest in the Yamal LNG Joint Venture (see Note 5a). As of December 31, 2014, the Partnership had advances of $95.3 million (December 31, 2013 – nil) to the Yamal LNG Joint Venture. The advances bear interest at LIBOR plus 3.0% compounded semi-annually. As of December 31, 2014, the interest accrued on these advances was $1.0 million (December 31, 2013 – nil).

liquefied gas segment is as follows:

Amortization expense associated with intangible assets ~~consisted of time-charter contracts with a weighted-average amortization period of 18.1 years. The carrying amount of intangible assets for the Partnership’s reportable segments is as follows:~~

   December 31, 2014    December 31, 2013
      Conventional          Conventional
   Liquefied Gas    Tanker       Liquefied Gas    Tanker
   Segment    Segment    Total    Segment    Segment    Total
   $    $    $    $    $    $
Gross carrying amount
   179,813    6,797    186,610    179,813    6,797    186,610
Accumulated amortization
   (92,167 )    (6,797 )    (98,964 )    (83,311 )    (6,454 )    (89,765 )












Net carrying amount
87,646 —   87,646 96,502 343 96,845

~~Amortization expense of intangible assets were $9.2~~was $8.9 million, ~~$13.1~~$8.9 million and ~~$11.0~~$9.2 million for the years ended December 31, ~~2014, 2013~~2016, 2015 and ~~2012,~~2014, respectively. Amortization ofexpense associated with intangible assets ~~in the next five years are~~is expected to be approximately $8.9 million per ~~year. In addition, as a result~~year in each of the ~~sales of the~~~~Algeciras Spirit~~~~and~~~~Huelva Spirit~~ ~~in 2014 (see Note 4) and the~~~~Tenerife Spirit~~ ~~in 2013, the Partnership’s intangible assets relating to these three conventional tankers were fully amortized in 2013 and 2014.~~

next five years.

The carrying amount of goodwill as at each of December 31, ~~2014~~2016 and ~~2013~~2015 for the Partnership’s liquefied gas segment was $35.6 million. In ~~2014~~2016 and ~~2013,~~2015, the Partnership conducted its annual goodwill impairment review of its liquefied gas segment and concluded that no impairment had occurred.

As at December 31, ~~2014,~~2016, the Partnership had three revolving credit facilities available of which two credit facilities are long-term and one is current. ~~These~~The three credit facilities, as at such date, provided for ~~aggregate~~ borrowings of up to ~~$393.3~~$451.9 million (December 31, 2015 – $459.2 million), of which ~~$135.6~~$243.7 million (December 31, 2015 – $130.0 million) was undrawn. Interest payments are based on LIBOR plus ~~margins.~~margins, which ranged from 0.55% to 1.25%. The amount available under the three revolving credit facilities reduces by ~~$84.1 million (2015), $27.3 million (2016), $28.2~~$198.2 million (2017) and $253.7 million (2018). ~~All the~~The revolving credit facilities may be used by the Partnership to fund general partnership purposes and to fund cash distributions. The Partnership is required to repay all borrowings used to fund cash distributions within 12 months of their being drawn, from a source other than further borrowings. ~~The~~One of the revolving credit facilities is unsecured while the other two revolving credit facilities are collateralized by first-priority mortgages granted on ~~seven~~four of the Partnership’s vessels, together with other related security, and include a guarantee from the Partnership or its subsidiaries of all outstanding amounts.

At

The Partnership has two Euro-denominated term loans outstanding, which as at December 31, ~~2014,~~2016, totaled ~~235.6~~208.9 million Euros ($~~285.0~~219.7 million). Interest payments are based on EURIBOR plus margins, which ranged from 0.60% to 2.25% as ofat December 31, ~~2014,~~2016, and the loans require monthly interest and principal payments. The term loans have varying maturities through 2023. The term loans are collateralized by first-priority mortgages on two vessels to which the loans relate, together with certain other related security and are guaranteed by the Partnership and one of its subsidiaries.

The weighted-average effective interest rate for the Partnership’s long-term debt outstanding at December 31, ~~2014~~2016 and December 31, ~~2013 was 2.19%~~2015 were 3.03% and ~~2.48%~~2.33%, respectively. ~~This rate does~~These rates do not reflect the effect of related interest rate swaps that the Partnership has used to economically hedge certain of its floating-rate debt (see Note 12). At December 31, ~~2014,~~2016, the margins on the Partnership’s outstanding revolving credit facilities and term loans ranged from 0.30% to 2.80%.

All Euro-denominated term loans and NOK-denominated bonds are revalued at the end of each period using the then-prevailing U.S. Dollar exchange rate. Due primarily to the revaluation of the Partnership’s NOK-denominated bonds, the Partnership’s Euro-denominated term loans ~~capital leases~~ and restricted cash, the repayment of the Partnership's NOK-denominated bonds and the termination of the associated cross-currency swaps, and the change in the valuation of the Partnership’s cross-currency ~~swap,~~swaps, the Partnership incurred foreign exchange gains ~~(losses)~~ of $5.3 million, $13.9 million, and $28.4 million ~~($15.8) million and ($8.2) million, of which these amounts were primarily unrealized,~~ for the years ended December 31, 2016, 2015 and 2014, ~~2013 and 2012,~~ respectively.

The aggregate annual long-term debt principal repayments required subsequent to December 31, ~~2014~~2016 are ~~$157.2 million (2015), $102.3 million (2016), $202.0~~$190.1 million (2017), ~~$773.6~~$719.8 million (2018), ~~$71.1~~$82.5 million (2019), $178.0 million (2020), $288.4 million (2021) and ~~$617.9~~$345.7 million (thereafter).

The Partnership and a subsidiary of Teekay Corporation are borrowers under one of the loan arrangements and are joint and severally liable for the obligations to the lender. Obligations resulting from long-term debt joint and several liability arrangements are measured at the sum of the amount the Partnership agreed to pay, on the basis of its arrangement among the co-obligor, and any additional amount the Partnership expects to pay on behalf of the co-obligor. This loan arrangement matures in 2021 and as of December 31, 2014 had an outstanding balance of $188.4 million, of which $95.6 million was the Partnership’s share. Teekay Corporation has indemnified the Partnership in respect of any losses and expenses arising from any breach by the co-obligor of the terms and conditions of the loan facility.

Certain loan agreements require that (a) the Partnership maintains minimum levels of tangible net worth and aggregate liquidity, (b) the Partnership ~~maintains~~maintain certain ratios of vessel values ~~as it relates~~related to the relevant outstanding loan principal balance, (c) the Partnership not exceed a maximum amount of leverage, and (d) ~~two~~certain of the Partnership’s subsidiaries maintains restricted cash deposits. ~~The~~As at December 31, 2016, the Partnership ~~has one facility~~had two facilities with an aggregate outstanding loan balance of $127.8 million that ~~requires us~~require it to maintain aminimum vessel-value-to-outstanding-loan-principal-balance ~~ratio of~~ratios ranging from 110% to 115%, which as at December 31, ~~2014, was 158%~~2016 ranged from 133% to 209%. The vessel ~~value was~~values were determined using ~~reference to~~ second-hand market comparables or using a depreciated replacement cost approach. Since vessel values can be volatile, the Partnership’s estimates of market value may not be indicative of either the current or future prices that could be obtained if the Partnership sold any of the vessels. The Partnership’s ship-owning subsidiaries may not, among other things, pay dividends or distributions if the ~~Partnership is~~Partnership's subsidiaries are in default under ~~its~~their term loans or revolving credit facilities. One of the Partnership’s term loans is guaranteed by Teekay Corporation and contains covenants that require Teekay Corporation to maintain the greater of a minimum liquidity (cash and cash equivalents) of at least $50.0 million and 5.0% of Teekay Corporation’s total consolidated debt which has recourse to Teekay Corporation. As at December 31, ~~2014,~~2016, the Partnership ~~and Teekay Corporation and their affiliates were~~was in compliance with all covenants relating to the Partnership’s credit facilities and term loans.

The components of the provision for income taxes were as follows:

   Year Ended    Year Ended    Year Ended
   December 31,    December 31,    December 31,
   2014    2013    2012
   $    $    $
Current
   (5,212 )    (1,482 )    (1,652 )
Deferred
   (2,355 )    (3,674 )    1,027






Income tax expense
(7,567 ) (5,156 ) (625 )

~~TEEKAY LNG PARTNERS L.P. AND SUBSIDIARIES~~

~~NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS~~

~~(all tabular amounts stated in thousands of U.S. Dollars, except unit and per unit data or unless otherwise indicated)~~

The Partnership operates in countries that have differing tax laws and rates. Consequently, a consolidated weighted average tax rate will vary from year to year according to the source of earnings or losses by country and the change in applicable tax rates. Reconciliations of the tax charge related to the relevant year at the applicable statutory income tax rates and the actual tax charge related to the relevant year are as follows:

   Year Ended    Year Ended    Year Ended
   December 31,    December 31,    December 31,
   2014    2013    2012
   $    $    $
Net income before income tax expenses
   226,494    218,471    139,767
Net income not subject to taxes
   (81,604 )    (131,529 )    (148,118 )






Net income (loss) subject to taxes
144,890 86,942 (8,351 )






At applicable statutory tax rates
Amount computed using the standard rate of corporate tax
(33,083 ) (16,476 ) (731 )
Adjustments to valuation allowance and uncertain tax position
14,851 12,830 3,352
Permanent and currency differences
11,507 1,576 2,069
Change in tax rate
(842 ) (3,086 ) (5,315 )






Tax expense charge related to the current year
(7,567 ) (5,156 ) (625 )

The significant components of the Partnership’s deferred tax assets (liabilities) ~~included in other assets~~ were as follows:

   Year Ended    Year Ended
   December 31,    December 31,
   2014    2013
   $    $
Derivative instruments
   8,647    21,757
Taxation loss carryforwards and disallowed finance costs
   48,440    52,804
Vessels and equipment
   3,602    3,190
Capitalized interest
   (2,261 )    (2,342 )




58,428 75,409
Valuation allowance
(58,428 ) (73,054 )




Net deferred tax assets
—   2,355

The Partnership recognizes interest and penalties related to uncertain tax positions in income tax expense. The tax years ~~2009~~2007 through ~~2014~~2016 currently remain open to examination by the major tax jurisdictions to which the Partnership is subject.

The Partnership uses derivative instruments in accordance with its overall risk management policy. ~~The Partnership has not designated derivative instruments described within this note as hedges for accounting purposes.~~

From 2013 through 2016, concurrently with the issuance of NOK ~~700 million and NOK 900 million, respectively,~~3.5 billion of senior unsecured bonds (see Note 9), during that time, the Partnership entered into cross-currency swaps, and pursuant to these swaps, the Partnership receives the principal amount in NOK on maturity dates of the swaps in exchange for payments of a fixed U.S. Dollar amount. In addition, the cross-currency swaps exchange a receipt of floating interest in NOK based on NIBOR plus a margin for a payment of U.S. Dollar fixed interest. The purpose of the cross-currency swaps is to economically hedge the foreign currency exposure on the payment of interest and principal of the Partnership’s NOK-denominated bonds due in 2017, 2018, 2020 and ~~2018,~~2021, and to economically hedge the interest rate exposure. The following table reflects information relating to the cross-currency swaps as at December 31, ~~2014.~~

Principal
Amount
NOK
   Principal
Amount
$
Floating Rate Receivable
Reference
Rate
   Margin Fixed Rate
Payable Fair Value /
Carrying
Amount of
(Liability)
$    Remaining
Term (Years)
Weighted-
Average
700,000    125,000    NIBOR    5.25 % 6.88 % (35,766 )    2.3
900,000    150,000    NIBOR    4.35 % 6.43 % (34,620 )    3.7



(70,386 )

2016.

The Partnership enters into interest rate swaps which exchange a receipt of floating interest for a payment of fixed interest to reduce the Partnership’s exposure to interest rate variability on certain of its outstanding floating-rate debt. As at December 31, ~~2014,~~2016, the Partnership was committed to the following interest rate swap agreements:

         Fair Value /
         Carrying Weighted-
         Amount of Average    Fixed
   Interest    Principal    Assets Remaining    Interest
   Rate    Amount    (Liability) Term    Rate
   Index    $    $ (years)    (%)⁽ⁱ⁾
LIBOR-Based Debt:

U.S. Dollar-denominated interest rate swaps
   LIBOR    90,000    (11,549 ) 3.7    4.9
U.S. Dollar-denominated interest rate swaps
   LIBOR    100,000    (10,255 ) 2.0    5.3
U.S. Dollar-denominated interest rate swaps⁽ⁱⁱ⁾
   LIBOR    181,250    (38,674 ) 14.0    5.2
U.S. Dollar-denominated interest rate swaps⁽ⁱⁱ⁾
   LIBOR    74,979    (3,530 ) 6.6    2.8
U.S. Dollar-denominated interest rate swaps⁽ⁱⁱⁱ⁾
   LIBOR    320,000    (8,516 ) 1.3    2.9
U.S. Dollar-denominated interest rate swaps^(iv)
   LIBOR    125,667    (1,224 ) 4.0    1.7
EURIBOR-Based Debt:

Euro-denominated interest rate swaps^(v)
   EURIBOR    284,993    (45,810 ) 6.0    3.1



(119,558 )

As at December 31, ~~2014,~~2016, the Partnership had multiple interest rate swaps, interest rate swaptions, and cross-currency swaps with the same counterparty that are subject to the same master agreement. Each of these master agreements provide for the net settlement of all swaps subject to that master agreement through a single payment in the event of default or termination of any one swap. The fair value of these ~~interest rate swaps~~derivative instruments are presented on a gross basis in the Partnership’s consolidated balance sheets. As at December 31, ~~2014,~~2016, these interest rate swaps, interest rate swaptions, and cross-currency swaps had an aggregate fair value assets of $4.2 million and an aggregate fair value liability ~~amount~~ of ~~$162.6~~$173.6 million. As at December 31, ~~2014,~~2016, the Partnership had ~~$16.2~~$37.8 million (December 31, 2015 – $44.8 million) on deposit as security for swap liabilities under certain master agreements. The deposit is presented in restricted cash – current and – long-term on the Partnership’s consolidated balance sheets.

The Partnership is exposed to credit loss in the event of non-performance by the counterparties to the interest rate swap agreements. In order to minimize counterparty risk, the Partnership only enters into derivative transactions with counterparties that are rated ~~A- or better~~investment grade by Standard & Poor’s or A3 or better by Moody’s at the time of the transactions. In addition, to the extent practical, interest rate swaps are entered into with different counterparties to reduce concentration risk.

The following table presents the location and fair value amounts of derivative instruments, segregated by type of contract, on the Partnership’s consolidated balance sheets.

   Accounts          Accrued
   receivable/    Current       liabilities/ Current
   Advances    portion of       Advances portion of
   to    derivative    Derivative    from derivative Derivative
   affiliates    assets    assets    affiliates liabilities liabilities
As at December 31, 2014

Interest rate swap agreements
   —      —      441    (7,486 ) (52,356 ) (60,157 )
Cross-currency swap agreement
   —      —      —      (544 ) (4,922 ) (64,920 )
Toledo Spirit time-charter derivative
   —      —      —      (637 ) (400 ) (1,100 )








—   —   441 (8,667 ) (57,678 ) (126,177 )








As at December 31, 2013
Interest rate swap agreements
4,608 17,044 59,467 (10,960 ) (75,615 ) (114,187 )
Cross-currency swap agreement
—   —   —   (155 ) (1,365 ) (16,716 )
Toledo Spirit time-charter derivative
1,544 1,400 3,400 —   —   —








6,152 18,444 62,867 (11,115 ) (76,980 ) (130,903 )

Unrealized and realized gains (losses) ~~gains~~ relating to cross-currency swap agreements are recognized in earnings and reported in foreign currency exchange gain ~~(loss)~~ in the Partnership’s consolidated statements of income. The effect of the gain (loss) on these derivatives on the Partnership's consolidated statements of income is as follows:

Significant rights of the Partnership’s limited partners include the following:

The General Partner is entitled to incentive distributions if the amount the Partnership distributes to common unitholders with respect to any quarter exceeds specified target levels shown below:

Quarterly Distribution Target Amount (per unit)
   Unitholders General Partner
Minimum quarterly distribution of $0.4125
   98 % 2 %
Up to $0.4625
   98 % 2 %
Above $0.4625 up to $0.5375
   85 % 15 %
Above $0.5375 up to $0.6500
   75 % 25 %
Above $0.6500
   50 % 50 %

During 2016, the quarterly cash distributions were below $0.4625 per common unit and, consequently, the assumed distribution of net income was based on the limited partners' and General Partner’s ownership percentage for the purposes of the net income per common unit calculation. During 2015 and 2014, quarterly cash distributions exceeded $0.4625 per common unit and, consequently, the assumed distribution of net income resulted in the use of the increasing percentages to calculate the General Partner’s interest in net income for the purposes of the net income per common unit calculation.

For more information on the increasing percentages to calculate the General Partner’s interest in net income, please refer to the Partnership’s Annual Report on Form 20-F for the year ended December 31, 2016.

In the event of a liquidation, all property and cash in excess of that required to discharge all liabilities and liquidation amounts on the Series A Preferred Units will be distributed to the common unitholders and the General Partner in proportion to their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of the Partnership’s assets in liquidation in accordance with the partnership agreement.

Limited partners' interest in net income per common unit is determined by dividing net income, after deducting the amount of net income attributable to the non-controlling ~~interest and~~interests, the General Partner’s interest and the distributions on the Series A Preferred Units by the weighted-average number of common units outstanding during the period.

The distributions payable on the Series A Preferred Units (which were issued on October 5, 2016) for the year ended December 31, 2016 were $2.7 million (December 31, 2015 and 2014 – nil).

The General Partner’s and common unitholders’ interests in net income are calculated as if all net income was distributed according to the terms of the Partnership’s partnership agreement, regardless of whether those earnings would or could be distributed. The partnership agreement does not provide for the distribution of net income; rather, it provides for the distribution of available cash, which is a contractually defined term that generally means all cash on hand at the end of each quarter after establishment of cash reserves determined by the Partnership’s board of directors to provide for the proper conduct of the Partnership’s business, including reserves for maintenance and replacement capital expenditure and anticipated credit needs. In addition, the General Partner is entitled to incentive distributions if the amount the Partnership distributes to common unitholders with respect to any quarter exceeds specified target levels. Unlike available cash, net income is affected by non-cash items, such as depreciation and amortization, unrealized gains or losses on non-designated derivative instruments and foreign currency translation gains (losses).

Pursuant to the Partnership agreement, allocations to partners are made on a quarterly basis.

The following table summarizes the issuances of common and preferred units over the three years ending December 31, 2016:

In March ~~2014,~~2016, a total of ~~9,521~~32,723 common units, with an aggregate value of $0.4 million, were granted to the non-management directors of the General Partner as part of their annual compensation for ~~2014.~~2016. These common units were fully vested upon grant. During ~~2013~~2015 and ~~2012,~~2014, the Partnership awarded ~~7,362~~10,447 and ~~1,263~~9,521 common units, respectively, as compensation to non-management directors. The awards were fully vested in March ~~2013~~2015 and March ~~2012,~~2014, respectively. The compensation to the non-management directors is included in general and administrative expenses on the Partnership’s consolidated statements of income.

The Partnership grants restricted ~~unit-based compensation~~unit awards as incentive-based compensation under the Teekay LNG Partners L.P. 2005 Long-Term Incentive Plan to certain of the Partnership’s employees and to certain employees of Teekay Corporation’s subsidiaries that provide services to the Partnership. The Partnership measures the cost of such awards using the grant date fair value of the award and recognizes that cost, net of estimated forfeitures, over the requisite service period. The requisite service period consists of the period from the grant date of the award to the earlier of the date of vesting or the date the recipient becomes eligible for retirement. For unit-based compensation awards subject to graded vesting, the Partnership calculates the value for the award as if it was one single award with one expected life and amortizes the calculated expense for the entire award on a straight-line basis over the requisite service period. The compensation cost of the Partnership’s unit-based compensation awards are reflected in general and administrative expenses in the Partnership’s consolidated statements of income.

During March ~~2014~~2016, 2015 and ~~2013,~~2014, the Partnership granted ~~restricted unit-based compensation with respect to~~132,582, 32,054 and 31,961 ~~and 36,878~~restricted units, respectively, with grant date fair values of ~~$1.3~~$1.5 million, $1.1 million and ~~$1.5~~$1.3 million, respectively, to certain of the Partnership’s employees and to certain employees of Teekay Corporation’s subsidiaries who provide services to the Partnership, based on the Partnership’s closing common unit price on the grant date. Each ~~award represents the specified number~~restricted unit is equal in value to one of the ~~Partnership’s~~Partnership's common units plus reinvested distributions from the grant date to the vesting date. The ~~awards~~restricted units vest equally over three years from the grant date. Any portion of ana restricted unit award that is not vested on the date of a recipient’s termination of service is ~~cancelled,~~canceled, unless their termination arises as a result of the recipient’s retirement, and in this case, the restricted unit award will continue to vest in accordance with the vesting schedule. Upon vesting, the value of the restricted unit awards ~~are~~is paid to each recipient in the form of ~~units.~~common units, net of withholding tax. During the years ended December 31, ~~2014, 2013~~2016, 2015 and ~~2012,~~2014, the Partnership recorded an expense of ~~$1.0~~$1.3 million, ~~$1.0~~$1.2 million, and ~~nil,~~$1.0 million, respectively, related to the restricted units.



Large Accelerated Filer	ý	Accelerated Filer	¨	Non-Accelerated Filer	¨	Emerging growth company	¨



U.S. GAAPx	ý	International Financial Reporting Standards as issued by the International Accounting Standards Board¨	¨	Other	¨


(in thousands of U.S. Dollars, except per unit and fleet data)	Year Ended December 31, 2010 $			Year Ended December 31, 2011 $			Year Ended December 31, 2012 $			Year Ended December 31, 2013 $			Year Ended December 31, 2014 $
Income Statement Data:
Voyage revenues		374,502			380,469			392,900			399,276			402,928
Total operating expenses⁽¹⁾⁽²⁾		(195,542	)		(206,966	)		(245,109	)		(222,920	)		(219,105	)

Income from vessel operations		178,960			173,503			147,791			176,356			183,823

Equity income⁽³⁾		8,043			20,584			78,866			123,282			115,478
Interest expense		(49,019	)		(49,880	)		(54,211	)		(55,703	)		(60,414	)
Interest income		7,190			6,687			3,502			2,972			3,052
Realized and unrealized loss on derivative
instruments⁽⁴⁾		(78,720	)		(63,030	)		(29,620	)		(14,000	)		(44,682	)
Foreign currency exchange gain (loss)⁽⁵⁾		27,545			10,310			(8,244	)		(15,832	)		28,401
Other income (expense)		615			(37	)		1,683			1,396			836
Income tax expense		(1,670	)		(781	)		(625	)		(5,156	)		(7,567	)

Net income		92,944			97,356			139,142			213,315			218,927

Non-controlling and other interest in net income		14,216			18,982			36,740			37,438			44,676
Limited partners’ interest in net income		78,728			78,374			102,402			175,877			174,251
Limited partners’ interest in net income per:
Common unit (basic and diluted)		1.46			1.33			1.54			2.48			2.30
Cash distributions declared per unit		2.3700			2.5200			2.6550			2.7000			2.7672
Balance Sheet Data(at end of period):
Cash and cash equivalents		81,055			93,627			113,577			139,481			159,639
Restricted cash⁽⁶⁾		572,138			495,634			528,589			497,298			45,997
Vessels and equipment⁽⁷⁾		2,019,576			2,021,125			1,949,640			1,922,662			1,989,230
Investment in and advances to equity accounted
joint ventures		172,898			191,448			409,735			671,789			891,478
Net investments in direct financing leases⁽⁸⁾		415,695			409,541			403,386			699,695			682,495
Total assets⁽⁶⁾		3,547,395			3,588,734			3,785,446			4,219,594			3,964,418
Total debt and capital lease obligations⁽⁶⁾		2,137,249			1,962,278			2,050,927			2,375,836			1,987,674
Partners’ equity		896,200			1,113,467			1,212,980			1,390,790			1,537,752
Total equity		913,323			1,139,709			1,254,274			1,443,784			1,547,371
Common units outstanding		55,106,100			64,857,900			69,683,763			74,196,294			78,353,354
Other Financial Data:
Net voyage revenues⁽⁹⁾		372,460			379,082			391,128			396,419			399,607
EBITDA⁽¹⁰⁾		226,284			233,743			290,950			369,086			377,983
Adjusted EBITDA⁽¹⁰⁾		297,508			320,929			413,033			461,018			468,954
Capital expenditures:
Expenditures for vessels and equipment		26,652			64,685			39,894			470,213			194,255
Liquefied Gas Fleet Data:
Consolidated:
Calendar-ship-days⁽¹¹⁾		5,051			5,126			5,856			5,981			6,619
Average age of our fleet (in years at end of period)		5.3			5.8			6.6			6.7			7.9
Vessels at end of period⁽¹³⁾		13			16			16			18			19
Equity Accounted:⁽¹²⁾
Calendar-ship-days⁽¹¹⁾		1,576			2,469			5,481			11,059			11,338
Average age of our fleet (in years at end of period)		3.5			3.0			3.4			9.4			8.0
Vessels at end of period⁽¹³⁾		6			9			16			32			31
Conventional Fleet Data:
Calendar-ship-days⁽¹¹⁾		4,015			4,015			4,026			3,994			3,202
Average age of our fleet (in years at end of period)		6.1			6.9			7.9			8.5			8.5
Vessels at end of period		11			11			11			10			8



(in thousands of U.S. Dollars, except per unit and fleet data)	Year Ended December 31, 2016 $		Year Ended December 31, 2015 $		Year Ended December 31, 2014 $		Year Ended December 31, 2013 $		Year Ended December 31, 2012 $
Income Statement Data:
Voyage revenues	396,444		397,991		402,928		399,276		392,900
Income from vessel operations ⁽¹⁾	153,181		181,372		183,823		176,356		147,791
Equity income⁽²⁾	62,307		84,171		115,478		123,282		78,866
Interest expense	(58,844	)	(43,259	)	(60,414	)	(55,703	)	(54,211	)
Interest income	2,583		2,501		3,052		2,972		3,502
Realized and unrealized loss on non-designated derivative instruments⁽³⁾	(7,161	)	(20,022	)	(44,682	)	(14,000	)	(29,620	)
Foreign currency exchange gain (loss)⁽⁴⁾	5,335		13,943		28,401		(15,832	)	(8,244	)
Other income	1,537		1,526		836		1,396		1,683
Income tax expense	(973	)	(2,722	)	(7,567	)	(5,156	)	(625	)
Net income	157,965		217,510		218,927		213,315		139,142
Non-controlling and other interests in net income	22,988		42,903		44,676		37,438		36,740
Limited partners’ interest in net income	134,977		174,607		174,251		175,877		102,402
Limited partners’ interest in net income per:
Common unit - basic	1.70		2.21		2.30		2.48		1.54
Common unit - diluted	1.69		2.21		2.30		2.48		1.54
Cash distributions declared per common unit	0.5600		2.8000		2.7672		2.7000		2.6550
Balance Sheet Data (at end of period):
Cash and cash equivalents	126,146		102,481		159,639		139,481		113,577
Restricted cash	117,027		111,519		45,997		497,298		528,589
Vessels and equipment⁽⁵⁾	2,215,983		2,108,160		1,989,230		1,922,662		1,949,640
Investment in and advances to equity accounted joint ventures	1,037,726		883,731		891,478		671,789		409,735
Net investments in direct financing leases⁽⁶⁾	643,008		666,658		682,495		699,695		403,386
Total assets	4,315,474		4,052,980		3,947,275		4,203,143		3,769,649
Total debt and capital lease obligations	2,184,065		2,058,336		1,970,531		2,359,385		2,035,130
Partners’ equity	1,738,506		1,519,062		1,537,752		1,390,790		1,212,980
Total equity	1,777,412		1,543,679		1,547,371		1,443,784		1,254,274
Common units outstanding	79,571,820		79,551,012		78,353,354		74,196,294		69,683,763
Preferred units outstanding	5,000,000		—		—		—		—
Other Financial Data:
Net voyage revenues⁽⁷⁾	394,788		396,845		399,607		396,419		391,128
EBITDA⁽⁸⁾	310,741		353,243		377,983		369,086		290,950
Adjusted EBITDA⁽⁸⁾	445,341		442,463		468,954		461,018		413,033
Capital expenditures:
Expenditures for vessels and equipment	344,987		191,969		194,255		470,213		39,894
Liquefied Gas Fleet Data:
Consolidated:
Calendar-ship-days⁽⁹⁾	7,440		6,935		6,619		5,981		5,856
Average age of our fleet (in years at end of year)	9.0		8.9		7.9		6.7		6.6
Vessels at end of year⁽¹¹⁾	21		19		19		18		16
Equity Accounted:⁽¹⁰⁾
Calendar-ship-days⁽⁹⁾	12,285		11,720		11,338		11,059		5,481
Average age of our fleet (in years at end of year)	8.7		8.5		8.0		9.4		3.4
Vessels at end of year⁽¹¹⁾	35		32		31		32		16
Conventional Fleet Data:
Calendar-ship-days⁽⁹⁾	2,439		2,920		3,202		3,994		4,026
Average age of our fleet (in years at end of year)	11.7		9.5		8.5		8.5		7.9
Vessels at end of year	6		8		8		10		11


(in thousands of U.S. Dollars)	Year Ended December 31, 2010			Year Ended December 31, 2011			Year Ended December 31, 2012			Year Ended December 31, 2013			Year Ended December 31, 2014
Reconciliation of “EBITDA” and “Adjusted EBITDA” to “Net income”:
Net income		92,944			97,356			139,142			213,315			218,927
Depreciation and amortization		89,841			92,413			100,474			97,884			94,127
Interest expense, net of interest income		41,829			43,193			50,709			52,731			57,362
Income tax expense		1,670			781			625			5,156			7,567

EBITDA		226,284			233,743			290,950			369,086			377,983

Restructuring charge		175			—			—			1,786			1,989
Write down of vessels		—			—			29,367			—			—
Foreign currency exchange (gain) loss		(27,545	)		(10,310	)		8,244			15,832			(28,401	)
Gain on sale of vessel		(4,340	)		—			—			—			—
Amortization of in-process revenue contracts included in
voyage revenues		(494	)		(494	)		(649	)		(1,113	)		(1,113	)
Unrealized loss (gain) on derivative instruments		34,306			277			(6,900	)		(22,568	)		2,096
Realized loss on interest rate swaps		42,495			62,660			37,427			38,089			41,725
Adjustments to Equity-Accounted EBITDA⁽¹⁴⁾		26,627			35,053			54,594			59,906			74,675

Adjusted EBITDA		297,508			320,929			413,033			461,018			468,954

Reconciliation of “Adjusted EBITDA” to “Net operating cash flow”:
Net operating cash flow		174,970			122,046			192,013			183,532			191,097
Expenditures for dry docking		12,727			19,638			7,493			27,203			13,471
Interest expense, net of interest income		41,829			43,193			50,709			52,731			57,362
Income tax expense		1,670			781			625			5,156			7,567
Change in operating assets and liabilities		(6,657	)		33,458			7,307			(10,078	)		(18,822	)
Equity income from joint ventures		8,043			20,584			78,866			123,282			115,478
Restructuring charge		175			—			—			1,786			1,989
Realized loss on interest rate swaps		42,495			62,660			37,427			38,089			41,725
Dividends received from equity accounted joint ventures		—			(15,340	)		(14,700	)		(13,738	)		(11,005	)
Adjustments to Equity-Accounted EBITDA⁽¹⁴⁾		26,627			35,053			54,594			59,906			74,675
Other, net		(4,371	)		(1,144	)		(1,301	)		(6,851	)		(4,583	)

Adjusted EBITDA		297,508			320,929			413,033			461,018			468,954



¨	REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) or (g) OF THE SECURITIES EXCHANGE ACT OF 1934

x

ý	ANNUAL REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934



¨	TRANSITION REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934



¨	SHELL COMPANY REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934



Title of each class		Name of each exchange on which registered
Common Units		New York Stock Exchange
Series A Preferred Units		New York Stock Exchange



		Page
PART I.		*~~Page~~*
~~PART I.~~

Item 1.		Identity of Directors, Senior Management and ~~Advisors~~Advisers			4
Item 2.		Offer Statistics and Expected Timetable			4
Item 3.		Key Information	4
		4
		Selected Financial Data	4
		4
		Risk Factors			9	8
Item 4.		Information on the Partnership	26
		24
		A. Overview, History and Development	26
		24
		B. Operations	26
		24
		Our Charters	26
		24
		Liquefied Gas Segment	27
		25
		Conventional Tanker Segment	31
		29
		Business Strategies	31
		29
		Safety, Management of Ship Operations and Administration	32
		30
		Risk of Loss, Insurance and Risk Management	33
		31
		Flag, Classification, Audits and Inspections	33
	Regulations	31	34
	C. Organizational Structure	39
	~~C. Regulations~~			32
		D. Properties			35	39
		~~E. Organizational Structure~~			35
Item 4A.		Unresolved Staff Comments			35	39
Item 5.		Operating and Financial Review and Prospects	39
	Overview	36	39
		~~General~~			36
		Significant Developments in ~~2014~~2016 and Early ~~2015~~2017	39
		36
		Important Financial and Operational Terms and Concepts	42
		37
		Results of Operations	43
		38
		Year Ended December 31, ~~2014~~2016 versus Year Ended December 31, ~~2013~~2015	43
		39
		Year Ended December 31, ~~2013~~2015 versus Year Ended December 31, ~~2012~~2014	48
		43
		Liquidity and Cash Needs	53
		48
		Credit Facilities	56
		49
		Contractual Obligations and Contingencies	56
		51
		Off-Balance Sheet Arrangements	58
		52
		Critical Accounting Estimates			52	58
Item 6.		Directors, Senior Management and Employees	61
		54
		Management of Teekay LNG Partners L.P.	61
	Directors of Teekay GP L.L.C.	54	61
	Our Management	62
	~~Directors and Executive Officers~~			55
		Annual Executive Compensation	63
		56
		Compensation of Directors	63
		56
		2005 Long-Term Incentive Plan	63
		57
		Board Practices	63
		57
		Crewing and Staff	64
	Common Unit Ownership	58	65
		~~Unit Ownership~~			58
Item 7.		Major Common Unitholders and Related Party Transactions	65
	Major Common Unitholders	58	65
		~~Major Unitholders~~			58


		Related Party Transactions		59	65
Item 8.		Financial Information	67
	60
		A. Consolidated Financial Statements and Other Financial Information	67
	60
		Consolidated Financial Statements and Notes	67
	60 Legal Proceedings	67


		~~Legal Proceedings~~
	60
		Cash Distribution Policy for Common Unitholders	67
	60
		B. Significant Changes		61	68
Item 9.		The Offer and Listing		61	68
Item 10.		Additional Information	69
	62
		Memorandum and Articles of Association	69
	62
		Material Contracts	69
	62
		Exchange Controls and Other Limitations Affecting Unitholders	72
	64 Taxation	72
		~~Taxation~~		64
		Marshall Islands Tax Consequences	72
	64
		United States Tax Consequences	72
	64
		Canadian Federal Income Tax Considerations	83
	73
		Other Taxation	83
	74
		Documents on Display		74	83
Item 11.		Quantitative and Qualitative Disclosures About Market Risk		74	84
Item 12.		Description of Securities Other than Equity Securities	85
	76

PART II.

Item 13.		Defaults, Dividend Arrearages and Delinquencies		76	85
Item 14.		Material Modifications to the Rights of Unitholders and Use of Proceeds		76	85
Item 15.		Controls and Procedures		76	85
Item 16A.		Audit Committee Financial Expert		76	86
Item 16B.		Code of Ethics		77	86
Item 16C.		Principal Accountant Fees and Services		77	86
Item 16D.		Exemptions from the Listing Standards for Audit Committees		77	87
Item 16E.		Purchases of Units by the Issuer and Affiliated Purchasers		77	87
Item 16F.		Change in Registrant’s Certifying Accountant	87
Item 16G.	Corporate Governance	87
Item 16H.	Mine Safety Disclosure	87
	77
~~Item 16G.~~		~~Corporate Governance~~PART III.		77
Item ~~16H.~~ 17.	Financial Statements	~~Mine Safety Disclosure~~87
Item 18.	Financial Statements	87
Item 19.	Exhibits	88
Signature		77

~~PART III.~~91

~~Item 17.~~		~~Financial Statements~~		78
~~Item 18.~~		~~Financial Statements~~		78
~~Item 19.~~		~~Exhibits~~		78
~~Signature~~				81


(2)	~~Total operating expenses include vessel operating expenses, which include crewing, ship management services, repairs and maintenance, insurance, stores, lube oils and communication expenses.~~

~~(8)~~
(6)	The external charters that commenced in 2009 with The Tangguh Production Sharing Contractors and in 2013 with Awilco LNG ASA (orAwilco) have been accounted for as direct financing leases. As a result, the two LNG vessels chartered to The Tangguh Production Sharing Contractors and the two LNG vessels chartered to Awilco are not included as part of vessels and equipment.


	Year Ended December 31,			Year Ended December 31,			Year Ended December 31,			Year Ended December 31,			Year Ended December 31,
(in thousands of U.S. Dollars)	2010			2011			2012			2013			2014
Voyage revenues		374,502			380,469			392,900			399,276			402,928
Voyage expenses		(2,042	)		(1,387	)		(1,772	)		(2,857	)		(3,321	)

Net voyage revenues		372,460			379,082			391,128			396,419			399,607



(in thousands of U.S. Dollars)	Year Ended December 31, 2016		Year Ended December 31, 2015		Year Ended December 31, 2014		Year Ended December 31, 2013		Year Ended December 31, 2012
Voyage revenues	396,444		397,991		402,928		399,276		392,900
Voyage expenses	(1,656	)	(1,146	)	(3,321	)	(2,857	)	(1,772	)
Net voyage revenues	394,788		396,845		399,607		396,419		391,128

~~(11)~~
(9)	Calendar-ship-days are equal to the aggregate number of calendar days in a period that our vessels were in our possession during that ~~period (including three vessels deemed to be in our possession for accounting purposes as a result of the impact of the Dropdown Predecessor prior to our actual acquisition of such vessels).~~ period.

~~(13)~~
(11)	For ~~2014,~~2016, the number of vessels indicated do not include ~~eight~~nine LNG ~~newbuilding~~ carriers newbuildings in our consolidated liquefied gas fleet and 1914 LNG and LPG ~~newbuilding~~ carriers newbuildings in our equity accounted liquefied gas fleet.


(13)	Adjustments relating to equity income from our equity accounted joint ventures are as follows:

~~Item 4.~~	~~Information on the Partnership~~
A.	Overview, History and Development


Vessel	Capacity		Delivery	Our Ownership			Charterer	Expiration of Charter⁽¹⁾
	(cubic meters)
*Operating LNG carriers:*

Consolidated
Hispania Spirit		137,814	2002		100	%	Shell Spain LNG S.A.U.	Sep. 2022⁽²⁾
Catalunya Spirit		135,423	2003		100	%	Gas Natural SDG	Aug. 2023⁽²⁾
Galicia Spirit		137,814	2004		100	%	Uniòn Fenosa Gas	Jun. 2029⁽³⁾
Madrid Spirit		135,423	2004		100	%	Shell Spain LNG S.A.U.	Dec. 2024⁽²⁾
							Ras Laffan Liquefied
Al Marrouna		149,539	2006		70	%	Natural Gas Company Ltd.	Oct. 2026⁽⁴⁾
							Ras Laffan Liquefied
Al Areesh		148,786	2007		70	%	Natural Gas Company Ltd.	Jan. 2027⁽⁴⁾
							Ras Laffan Liquefied
Al Daayen		148,853	2007		70	%	Natural Gas Company Ltd.	Apr. 2027⁽⁴⁾
							The Tangguh Production
Tangguh Hiri		151,885	2008		69	%	Sharing Contractors	Jan. 2029
							The Tangguh Production
Tangguh Sago		155,000	2009		69	%	Sharing Contractors	May 2029
Arctic Spirit		87,305	1993		99	%	Teekay Corporation	Apr. 2018⁽⁴⁾
Polar Spirit		87,305	1993		99	%	Teekay Corporation	Apr. 2018⁽⁴⁾
Wilforce		155,900	2013		99	%	Awilco LNG ASA	Sep. 2018⁽⁵⁾
Wilpride		155,900	2013		99	%	Awilco LNG ASA	Nov. 2017⁽⁵⁾

Equity Accounted
							Ras Laffan Liquefied
Al Huwaila		214,176	2008		40	%⁽⁸⁾	Natural Gas Company Ltd.	Apr. 2033⁽²⁾
							Ras Laffan Liquefied
Al Kharsaah		214,198	2008		40	%⁽⁸⁾	Natural Gas Company Ltd.	Apr. 2033⁽²⁾
							Ras Laffan Liquefied
Al Shamal		213,536	2008		40	%⁽⁸⁾	Natural Gas Company Ltd.	May 2033⁽²⁾
							Ras Laffan Liquefied
Al Khuwair		213,101	2008		40	%⁽⁸⁾	Natural Gas Company Ltd.	Jun. 2033⁽²⁾
Excelsior		138,087	2005		50	%⁽⁹⁾	Excelerate Energy LP	Jan. 2025⁽²⁾
Excalibur		138,034	2002		50	%⁽⁹⁾	Excelerate Energy LP	Mar. 2022
Soyo		160,400	2011		33	%⁽¹⁰⁾	Angola LNG Supply Services LLC	Aug. 2031⁽²⁾
Malanje		160,400	2011		33	%⁽¹⁰⁾	Angola LNG Supply Services LLC	Sep. 2031⁽²⁾
Lobito		160,400	2011		33	%⁽¹⁰⁾	Angola LNG Supply Services LLC	Oct. 2031⁽²⁾
Cubal		160,400	2012		33	%⁽¹⁰⁾	Angola LNG Supply Services LLC	Jan. 2032⁽²⁾
Meridian Spirit		165,700	2010		52	%⁽¹¹⁾	Total E&P Norge AS Mansel Limited	Nov. 2030⁽⁶⁾
Magellan Spirit		165,700	2009		52	%⁽¹¹⁾	Vitol S.A.	Sep. 2016⁽¹³⁾
Marib Spirit		165,500	2008		52	%⁽¹¹⁾	Yemen LNG Company Limited	Mar. 2029⁽⁶⁾
Arwa Spirit		165,500	2008		52	%⁽¹¹⁾	Yemen LNG Company Limited	Apr. 2029⁽⁶⁾
Methane Spirit		165,500	2008		52	%⁽¹¹⁾	BP Shipping Limited	Mar. 2015⁽⁷⁾
Woodside Donaldson		165,500	2009		52	%⁽¹¹⁾	Pluto LNG Party Limited	Jun. 2026⁽¹²⁾

Total Capacity:		4,553,079


(1)	Each of our time-charters are subject to certain termination and purchase provisions.


(2)	The charterer has two options to extend the term for an additional five years each.


(3)	The charterer has one option to extend the term for an additional five years.


(4)	The charterer has three options to extend the term for an additional five years each.


(5)	The charterer has an option to extend the term for one additional year and at the end of the charter period the charterer has an obligation to ~~repurchase~~purchase each vessel at a fixed price.


(6)	We are the lessee under capital lease arrangement and will be required to purchase the vessel after the end of the lease terms for a fixed price.


(9)	The Exmar LNG Carriers are accounted for under the equity method.


(10)	The Angola LNG Carriers are accounted for under the equity method.


(11)	The MALT LNG Carriers are accounted for under the equity method.


(12)	~~The charterer has four options~~ Please see "Item 5 – Operating and Financial Review and Prospects: Management's Discussion and Analysis of Financial Condition and Results of Operations – Significant Developments in 2016 and early 2017" relating to ~~extend~~ the ~~term for an additional five years each.~~



	Year Ended December 31,
	2016		2015		2014
Ras Laffan Liquefied Natural Gas Company Ltd.	18	%	18	%	17	%
Shell Spain LNG S.A.U. ⁽¹⁾	12	%	12	%	13	%
The Tangguh Production Sharing Contractors	11	%	11	%	11	%


(1)	~~In March 2014,~~ Shell Spain LNG S.A.U. acquired the charter contracts from Repsol YPF, ~~S.A.~~S.A in March 2014. The voyage revenues in 2014 consisted of the voyage revenues from both customers relating to the same charter ~~contract; voyage revenues in 2013 and 2012 were only from Repsol YPF, S.A.~~ contracts.


(1)	~~“CoA” refers~~ Please see "Item 5 – Operating and Financial Review and Prospects: Management's Discussion and Analysis of Financial Condition and Results of Operations – Significant Developments in 2016 and early 2017" relating to ~~contracts~~the status of ~~affreightment.~~ these charter contracts.

Identity of Person or Group

Common Units
Owned

Percentage of
Common Units
Owned ⁽³⁾

All directors and officers of Teekay GP L.L.C. as a group (6 persons) ^{(1) (2)}