UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 _______________________________

FORM 20-F

  _______________________________

(Mark One)

¨ REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) or (g) OF THE SECURITIES EXCHANGE ACT OF 1934

OR

ý ANNUAL REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2016

OR

¨ TRANSITION REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

OR

¨ SHELL COMPANY REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Date of event requiring this shell company report

For the transition period from to

Commission file number 1- 32479

  _______________________________

TEEKAY LNG PARTNERS L.P.

(Exact name of Registrant as specified in its charter)

  _______________________________

Republic of The Marshall Islands

(Jurisdiction of incorporation or organization)

4th Floor, Belvedere Building, 69 Pitts Bay Road, Hamilton, HM 08, Bermuda

Telephone: (441) 298-2530

(Address and telephone number of principal executive offices)

Edith Robinson

4th Floor, Belvedere Building, 69 Pitts Bay Road, Hamilton, HM 08, Bermuda

Telephone: (441) 298-2530

Fax: (441) 292-3931

(Contact information for company contact person)

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

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

Securities registered, or to be registered, pursuant to Section 12(g) of the Act.

None

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act.

None

  _______________________________

Indicate the number of outstanding shares of each issuer’s classes of capital or common stock as of the close of the period covered by the annual report.

79,571,820 Common Units

5,000,000 Series A Preferred Units

Indicate by check mark whether the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities

Act.    Yes   ý    No   ¨

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

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

Indicate by check mark if the registrant (1) has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ý    No  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one):

Large Accelerated Filer ý Accelerated Filer ¨ Non-Accelerated Filer ¨ Emerging growth company ¨

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

† The term “new or revised financial accounting standard” refers to any update issued by the Financial Accounting Standards Board to its Accounting Standards Codification after April 5, 2012.

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

U.S. GAAP ý International Financial Reporting Standards as issued by the International Accounting Standards Board ¨ Other ¨

If “Other” has been checked in response to the previous question, indicate by check mark which financial statement item the registrant has elected to follow:

Item 17  ¨        Item 18   ¨

If this is an annual report, indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes  ¨        No  ý

TEEKAY LNG PARTNERS L.P.

INDEX TO REPORT ON FORM 20-F

		Page
PART I.
Item 1.	Identity of Directors, Senior Management and Advisers	4
Item 2.	Offer Statistics and Expected Timetable	4
Item 3.	Key Information	4
	Selected Financial Data	4
	Risk Factors	8
Item 4.	Information on the Partnership	26
	A. Overview, History and Development	26
	B. Operations	26
	Our Charters	26
	Liquefied Gas Segment	27
	Conventional Tanker Segment	31
	Business Strategies	31
	Safety, Management of Ship Operations and Administration	32
	Risk of Loss, Insurance and Risk Management	33
	Flag, Classification, Audits and Inspections	33
	Regulations	34
	C. Organizational Structure	39
	D. Properties	39
Item 4A.	Unresolved Staff Comments	39
Item 5.	Operating and Financial Review and Prospects	39
	Overview	39
	Significant Developments in 2016 and Early 2017	39
	Important Financial and Operational Terms and Concepts	42
	Results of Operations	43
	Year Ended December 31, 2016 versus Year Ended December 31, 2015	43
	Year Ended December 31, 2015 versus Year Ended December 31, 2014	48
	Liquidity and Cash Needs	53
	Credit Facilities	56
	Contractual Obligations and Contingencies	56
	Off-Balance Sheet Arrangements	58
	Critical Accounting Estimates	58
Item 6.	Directors, Senior Management and Employees	61
	Management of Teekay LNG Partners L.P.	61
	Directors of Teekay GP L.L.C.	61
	Our Management	62
	Annual Executive Compensation	63
	Compensation of Directors	63
	2005 Long-Term Incentive Plan	63
	Board Practices	63
	Crewing and Staff	64
	Common Unit Ownership	65
Item 7.	Major Common Unitholders and Related Party Transactions	65
	Major Common Unitholders	65
	Related Party Transactions	65
Item 8.	Financial Information	67
	A. Consolidated Financial Statements and Other Financial Information	67
	Consolidated Financial Statements and Notes	67
	Legal Proceedings	67

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	Cash Distribution Policy for Common Unitholders	67
	B. Significant Changes	68
Item 9.	The Offer and Listing	68
Item 10.	Additional Information	69
	Memorandum and Articles of Association	69
	Material Contracts	69
	Exchange Controls and Other Limitations Affecting Unitholders	72
	Taxation	72
	Marshall Islands Tax Consequences	72
	United States Tax Consequences	72
	Canadian Federal Income Tax Considerations	83
	Other Taxation	83
	Documents on Display	83
Item 11.	Quantitative and Qualitative Disclosures About Market Risk	84
Item 12.	Description of Securities Other than Equity Securities	85
PART II.
Item 13.	Defaults, Dividend Arrearages and Delinquencies	85
Item 14.	Material Modifications to the Rights of Unitholders and Use of Proceeds	85
Item 15.	Controls and Procedures	85
Item 16A.	Audit Committee Financial Expert	86
Item 16B.	Code of Ethics	86
Item 16C.	Principal Accountant Fees and Services	86
Item 16D.	Exemptions from the Listing Standards for Audit Committees	87
Item 16E.	Purchases of Units by the Issuer and Affiliated Purchasers	87
Item 16F.	Change in Registrant’s Certifying Accountant	87
Item 16G.	Corporate Governance	87
Item 16H.	Mine Safety Disclosure	87
PART III.
Item 17.	Financial Statements	87
Item 18.	Financial Statements	87
Item 19.	Exhibits	88
Signature		91

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PART I

This annual report of Teekay LNG Partners L.P. on Form 20-F for the year ended December 31, 2016 (or Annual Report) should be read in conjunction with the consolidated financial statements and accompanying notes included in this report.

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 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:

• our distribution policy and our ability to make cash distributions on our units or any increases in quarterly distributions, and the impact of cash distribution reductions on our financial position;

• our future financial condition and results of operations and our future revenues, expenses and capital expenditures, and our expected financial flexibility to pursue capital expenditures, acquisitions and other expansion opportunities;

• our liquidity needs and meeting our going concern requirements, including our anticipated funds and sources of financing for liquidity needs and the sufficiency of cash flows, and our estimation that we will have sufficient liquidity for a one-year period;

• our expected sources of funds for liquidity and working capital needs and our ability to enter into new bank financings and to refinance existing indebtedness;

• growth prospects and future trends of the markets in which we operate;

• liquefied natural gas (or LNG), liquefied petroleum gas (or LPG) and tanker market fundamentals, including the balance of supply and demand in the LNG, LPG and tanker markets and spot LNG, LPG and tanker charter rates;

• the expected lifespan of our vessels, including our expectations as to any impairment of our vessels;

• our expectations and estimates regarding future charter business, including with respect to minimum charter hire payments, revenues and our vessels’ ability to perform to specifications and maintain their hire rates in the future;

• our expectations regarding the ability of I.M. Skaugen SE (or Skaugen), Awilco LNG ASA (or Awilco), and our other customers to make charter payments to us, and the ability of our customers to fulfill purchase obligations at the end of charter contracts, including obligations relating to two of our LNG carriers completing charters with Awilco in 2017 and 2018;

• our ability to maximize the use of our vessels, including the redeployment or disposition of vessels no longer under long-term charter or whose charter contract is expiring in 2017 and 2018, specifically our 52% owned vessels, the Magellan Spirit and the Methane Spirit, our wholly-owned LNG carriers, the Torben Spirit, Arctic Spirit and Polar Spirit, and our wholly-owned Suezmax tankers, the African Spirit and European Spirit;

• the adequacy of our insurance coverage, less an applicable deductible;

• the future resumption of a LNG plant in Yemen operated by Yemen LNG Company Limited (or YLNG), the expected repayment of deferred hire amounts on our two 52% owned vessels, the Marib Spirit and Arwa Spirit, on charter to YLNG, and the expected reduction to our equity income in 2017 as a result of the charter payment deferral;

• expected purchases and deliveries of newbuilding vessels, the newbuildings’ commencement of service under charter contracts, and estimated costs for newbuilding vessels;

• expected deliveries of the LPG newbuilding vessels in Exmar LPG BVBA;

• expected financing for our joint venture with China LNG Shipping (Holdings) Limited (or the Yamal LNG Joint Venture);

• expected funding of our proportionate share of the remaining shipyard installment payments for our joint venture with China LNG, CETS Investment Management (HK) Co. Ltd. and BW LNG Investments Pte. Ltd. (or the BG Joint Venture);

• the cost of supervision and crew training in relation to the BG Joint Venture, and our expected recovery of a portion of those costs;

• the expected technical and operational capabilities of newbuildings, including the benefits of the M-type, Electronically Controlled, Gas Injection (or MEGI) twin engines in certain LNG carrier newbuildings;

• our ability to obtain financing for four of our unfinanced, wholly-owned LNG carrier newbuildings delivering in 2018 through 2019;

• our ability to maintain long-term relationships with major LNG and LPG importers and exporters and major crude oil companies;

• our ability to leverage to our advantage Teekay Corporation’s relationships and reputation in the shipping industry;

• our continued ability to enter into long-term, fixed-rate time-charters with our LNG and LPG customers;

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• our expectation of not earning revenues from voyage charters in the foreseeable future;

• obtaining LNG and LPG projects that we or Teekay Corporation bid on;

• the expected timing, amount and method of financing for our newbuilding vessels and the possible purchase of two of our leased Suezmax tankers, the Teide Spirit and the Toledo Spirit;

• our expectations regarding the schedule and performance of the receiving and regasification terminal in Bahrain, which will be owned and operated by a new joint venture, Bahrain LNG W.L.L., owned by us (30%), National Oil & Gas Authority (or Nogaholding) (30%), Gulf Investment Corporation (or GIC) (24%) and Samsung C&T (or Samsung) (16%) (or the Bahrain LNG Joint Venture), and our expectations regarding the supply, modification and charter of a floating storage unit (or FSU) vessel for the project;

• our ability to continue to obtain all permits, licenses, and certificates material to our operations;

• the impact of, and our ability to comply with, new and existing governmental regulations and maritime self-regulatory organization standards applicable to our business, including the expected cost to install ballast water treatment systems on our tankers in compliance with IMO proposals;

• the expected impact of heightened environmental and quality concerns of insurance underwriters, regulators and charterers;

• the future valuation of goodwill;

• our expectations regarding whether the UK taxing authority can successfully challenge the tax benefits available under certain of our former and current leasing arrangements, and the potential financial exposure to us if such a challenge is successful;

• our hedging activities relating to foreign exchange, interest rate and spot market risks, and the effects of fluctuations in foreign exchange, interest rate and spot market rates on our business and results of operations;

• the potential impact of new accounting guidance;

• our and Teekay Corporation’s ability to maintain good relationships with the labor unions who work with us;

• anticipated taxation of our partnership and its subsidiaries; and

• our business strategy and other plans and objectives for future operations.

Forward-looking statements involve known and unknown risks and are based upon a number of assumptions and estimates that are inherently subject to significant uncertainties and contingencies, many of which are beyond our control. Actual results may differ materially from those expressed or implied by such forward-looking statements. Important factors that could cause actual results to differ materially include, but are not limited to, those factors discussed in “Item 3 – Key Information: Risk Factors,” and other factors detailed from time to time in other reports we file with or furnish to the U.S. Securities and Exchange Commission (or the SEC).

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.

Item 1. Identity of Directors, Senior Management and Advisers

Not applicable.

Item 2.Offer Statistics and Expected Timetable

Not applicable.

Item 3.Key Information

Selected Financial Data

Set forth below is selected consolidated financial and other data of Teekay LNG Partners and its subsidiaries for the fiscal years 2012 through 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, 2016, 2015 and 2014.

Our consolidated financial statements are prepared in accordance with United States generally accepted accounting principles (or GAAP).

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(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

(1) Income from vessel operations includes write-down and loss on sale of vessels of $39.0 million and $29.4 million for the years ended December 31, 2016 and 2012, respectively.

(2) Equity income includes unrealized gains on non-designated derivative instruments, and any ineffectiveness of derivative instruments designated as hedges for accounting purposes of $7.3 million, $10.2 million, $1.6 million, $25.9 million, and $5.5 million for the years ended December 31, 2016, 2015, 2014, 2013 and 2012, respectively.

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(3) We entered into interest rate swap and swaption agreements to mitigate our interest rate risk from our floating-rate debt, leases and restricted cash. We also have entered into an agreement with Teekay Corporation relating to the Toledo Spirit time-charter contract under which Teekay Corporation pays us any amounts payable to the charterer as a result of spot rates being below the fixed rate, and we pay Teekay Corporation any amounts payable to us as a result of spot rates being in excess of the fixed rate. We have not applied hedge accounting treatment to these derivative instruments except for several interest rate swaps in certain of our equity accounted joint ventures, and as a result, changes in the fair value of our derivatives are recognized immediately into income and are presented as realized and unrealized loss on derivative instruments in the consolidated statements of income. Please see “Item 18 – Financial Statements: Note 12 – Derivative Instruments and Hedging Activities.”

(4) Substantially all of these foreign currency exchange gains and losses were unrealized. Under GAAP, 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, are revalued and reported based on the prevailing exchange rate at the end of the period. Foreign exchange gains and losses include realized and unrealized gains and losses on our cross-currency swaps. Our primary sources for the foreign currency exchange gains and losses are our Euro-denominated term loans and Norwegian Kroner-denominated (or NOK) bonds. Euro-denominated term loans totaled 208.9 million Euros ($219.7 million) at December 31, 2016, 222.7 million Euros ($241.8 million) at December 31, 2015, 235.6 million Euros ($285.0 million) at December 31, 2014, 247.6 million Euros ($340.2 million) at December 31, 2013, and 258.8 million Euros ($341.4 million) at December 31, 2012. Our NOK-denominated bonds totaled 3.5 billion NOK ($371.3 million) at December 31, 2016, 2.6 billion NOK ($294.0 million) at December 31, 2015, 1.6 billion NOK ($214.7 million) at December 31, 2014, 1.6 billion NOK ($263.5 million) at December 31, 2013, and 700.0 million NOK ($125.8 million) at December 31, 2012.

(5) Vessels and equipment consist of (a) our vessels, at cost less accumulated depreciation, (b) vessels under capital leases, at cost less accumulated depreciation and (c) advances on our newbuildings.

(6) The external charters that commenced in 2009 with The Tangguh Production Sharing Contractors and in 2013 with Awilco LNG ASA (or Awilco) 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.

(7) Net voyage revenues is a non-GAAP financial measure. Consistent with general practice in the shipping industry, we use net voyage revenues (defined as voyage revenues less voyage expenses) as a measure of equating revenues generated from voyage charters to revenues generated from time-charters, which assists us in making operating decisions about the deployment of our vessels and their performance. Under time-charters the charterer pays the voyage expenses, whereas under voyage charter contracts the ship owner pays these expenses. Some voyage expenses are fixed, and the remainder can be estimated. If we, as the ship owner, pay the voyage expenses, we typically pass the approximate amount of these expenses on to our customers by charging higher rates under the contract or billing the expenses to them. As a result, although voyage revenues from different types of contracts may vary, the net voyage revenues are comparable across the different types of contracts. We principally use net voyage revenues because it provides more meaningful information to us than voyage revenues, the most directly comparable GAAP financial measure. Net voyage revenues are also widely used by investors and analysts in the shipping industry for comparing financial performance between companies and to industry averages. The following table reconciles net voyage revenues with voyage revenues.

(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

(8) EBITDA and Adjusted EBITDA are non-GAAP financial measures. EBITDA represents net income before interest, taxes, depreciation and amortization. Adjusted EBITDA represents EBITDA before restructuring charges, net of reimbursement, write-down and loss on sale of vessels, foreign currency exchange (gain) loss, amortization of in-process contracts included in voyage revenues net of offsetting vessel operating expenses, unrealized (gain) loss on non-designated derivative instruments, realized loss on interest rate swaps and Adjustments to Equity Income. EBITDA and Adjusted EBITDA are used as a supplemental financial measure by management and by external users of our financial statements, such as investors, as discussed below:

• Financial and operating performance. EBITDA and Adjusted EBITDA assist our management and investors by increasing the comparability of our fundamental performance from period to period and against the fundamental performance of other companies in our industry that provide EBITDA and Adjusted EBITDA information. This increased comparability is achieved by excluding the potentially disparate effects between periods or companies of interest expense, taxes, depreciation or amortization, amortization of in-process revenue contracts and realized and unrealized loss on derivative instruments relating to interest rate swaps, interest rate swaptions, and cross-currency swaps, which items are affected by various and possibly changing financing methods, capital structure and historical cost basis and which items may significantly affect net income between periods. We believe that including EBITDA and Adjusted EBITDA as financial and operating measures benefits investors in (a) selecting between investing in us and other investment alternatives and (b) monitoring our ongoing financial and operational strength and health in assessing whether to continue to hold our common and preferred units.

• Liquidity. EBITDA and Adjusted EBITDA allow us to assess the ability of assets to generate cash sufficient to service debt, pay distributions and undertake capital expenditures. By eliminating the cash flow effect resulting from our existing capitalization and other items such as dry-docking expenditures, working capital changes and foreign currency exchange gains and losses, EBITDA and Adjusted EBITDA provides a consistent measure of our ability to generate cash over the long term. Management uses this information as a significant factor in determining (a) our proper capitalization (including assessing how much debt to incur and whether changes to the capitalization should be made) and (b) whether to undertake material capital expenditures and how to finance them, all in light of our cash distribution policy. Use of EBITDA and Adjusted EBITDA as liquidity measures also permits investors to assess the fundamental ability of our business to generate cash sufficient to meet cash needs, including distributions on our common and preferred units.

Neither EBITDA nor Adjusted EBITDA should be considered as an alternative to net income, cash flow from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. EBITDA and Adjusted EBITDA exclude some, but not all, items that affect net income and income from vessel operations and these measures may vary among other companies. Therefore, EBITDA and Adjusted EBITDA as presented in this Annual Report may not be comparable to similarly titled measures of other companies.

The following table reconciles our historical consolidated EBITDA and Adjusted EBITDA to net income, the most directly comparable GAAP financial measure, and our historical consolidated Adjusted EBITDA to net operating cash flow, the most directly comparable GAAP financial measure.

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(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
Reconciliation of “EBITDA” and “Adjusted EBITDA” to “Net income”:
Net income	157,965		217,510		218,927		213,315		139,142
Depreciation and amortization	95,542		92,253		94,127		97,884		100,474
Interest expense, net of interest income	56,261		40,758		57,362		52,731		50,709
Income tax expense	973		2,722		7,567		5,156		625
EBITDA	310,741		353,243		377,983		369,086		290,950
Restructuring charges, net of reimbursement	—		—		1,989		1,786		—
Write-down and loss on sale of vessels	38,976		—		—		—		29,367
Foreign currency exchange (gain) loss	(5,335	)	(13,943	)	(28,401	)	15,832		8,244
Amortization of in-process contracts included in voyage revenues, net of offsetting vessel operating expenses	(1,113	)	(1,113	)	(1,113	)	(1,113	)	(649	)
Unrealized (gain) loss on non-designated derivative instruments	(19,433	)	(12,375	)	2,096		(22,568	)	(6,900	)
Realized loss on interest rate swaps	25,940		28,968		41,725		38,089		37,427
Adjustments to Equity Accounted EBITDA(12)(13)	95,565		87,683		74,675		59,906		54,594
Adjusted EBITDA	445,341		442,463		468,954		461,018		413,033
Reconciliation of “Adjusted EBITDA” to “Net operating cash flow”:
Net operating cash flow	166,492		239,729		191,097		183,532		192,013
Expenditures for dry docking	12,686		10,357		13,471		27,203		7,493
Interest expense, net of interest income	56,261		40,758		57,362		52,731		50,709
Income tax expense	973		2,722		7,567		5,156		625
Change in operating assets and liabilities	20,669		34,187		(18,822	)	(10,078	)	7,307
Equity income from joint ventures	62,307		84,171		115,478		123,282		78,866
Dividends received from equity accounted joint ventures	(31,113	)	(97,146	)	(11,005	)	(13,738	)	(14,700	)
Restructuring charges, net of reimbursement	—		—		1,989		1,786		—
Realized loss on interest rate swaps	25,940		28,968		41,725		38,089		37,427
Realized loss (gain) on cross-currency swaps recorded in foreign currency exchange (gain) loss	26,774		7,640		2,222		338		(257	)
Adjustments to Equity Accounted EBITDA(12)(13)	95,565		87,683		74,675		59,906		54,594
Other, net	8,787		3,394		(6,805	)	(7,189	)	(1,044	)
Adjusted EBITDA	445,341		442,463		468,954		461,018		413,033

(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.

(10) Equity accounted vessels include (i) six LNG carriers (or the MALT LNG Carriers) relating to theTeekay LNG-Marubeni Joint Venture from 2012, (ii) four LNG carriers (or the RasGas 3 LNG Carriers) relating to our joint venture with QGTC Nakilat (1643-6) Holdings Corporation from 2008, (iii) four LNG carriers relating to the Angola Project (or the Angola LNG Carriers) in our joint venture with Mitsui & Co. Ltd. and NYK Energy Transport (Atlantic) Ltd. from 2011, (iv) two LNG carriers (or the Exmar LNG Carriers) relating our LNG joint venture with Exmar NV (or Exmar) and (v) 19, 16, and 15 LPG carriers (or the Exmar LPG Carriers) from 2016, 2015, and 2014, respectively, relating to our LPG joint venture with Exmar. The figures in the selected financial data for our equity accounted vessels are at 100% and not based on our ownership percentages.

(11) For 2016, the number of vessels indicated do not include nine LNG carriers newbuildings in our consolidated liquefied gas fleet and 14 LNG and LPG carriers newbuildings in our equity accounted liquefied gas fleet.

(12) Adjusted Equity Accounted EBITDA is a non-GAAP financial measure. Adjusted Equity Accounted EBITDA represents equity income after Adjustments to Equity Income. Adjustments to Equity Income consist of depreciation and amortization, interest expense net of interest income, income tax expense (recovery), amortization of in-process revenue contracts, foreign currency exchange loss (gain), write-down and loss (gain) on sales of vessels, unrealized gain on non-designated derivative instruments and realized loss on interest rate swaps, in each case related to our equity accounted entities, on the basis of our ownership percentages of such entities. Neither Adjusted Equity Accounted EBITDA nor Adjustments to Equity Accounted EBITDA should be considered as an alternative to equity income or any other measure of financial performance or liquidity presented in accordance with GAAP. Adjustments to Equity Accounted EBITDA exclude some, but not all, items that affect equity income and these measures may vary among other companies. Therefore, Adjustments to Equity Accounted EBITDA as presented in this Annual Report may not be comparable to similarly titled measures of the other companies. When using Adjusted EBITDA as a measure of liquidity, it should be noted that this measure includes the Adjusted EBITDA from our equity accounted for investments. We do not have control over the operations, nor do we have any legal claim to the revenue and expenses of our equity accounted for investments. Consequently, the cash flow generated by our equity accounted for investments, as measured by Adjusted Equity Accounted EBITDA, may not be available for use by us in the period generated.

(13) Adjustments relating to equity income from our equity accounted joint ventures are as follows:

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(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
Reconciliation of “Adjusted Equity Accounted EBITDA” to “Equity Income”:
Equity Income	62,307		84,171		115,478		123,282		78,866
Depreciation and amortization	52,095		48,702		45,885		45,664		25,589
Interest expense, net of interest income	39,849		37,376		36,916		35,110		26,622
Income tax expense (recovery)	352		315		(155	)	163		87
Amortization of in-process revenue contracts	(5,482	)	(7,153	)	(8,295	)	(14,173	)	(11,083	)
Foreign currency exchange loss (gain)	125		(527	)	(441	)	149		(18	)
Write-down and loss (gain) on sales of vessels	4,861		1,228		(16,923	)	—		—
Unrealized gain on non-designated derivative instruments	(6,963	)	(10,945	)	(1,563	)	(26,432	)	(5,549	)
Realized loss on interest rate swaps	10,728		18,687		19,251		19,425		18,946
Adjustments to Equity Accounted EBITDA	95,565		87,683		74,675		59,906		54,594
Adjusted Equity Accounted EBITDA	157,872		171,854		190,153		183,188		133,460

RISK FACTORS

Some of the following risks relate principally to the industry in which we operate and to our business in general. Other risks relate principally to the securities market and to ownership of our common or preferred units. The occurrence of any of the events described in this section could materially and adversely affect our business, financial condition, operating results and ability to pay distributions on, and the trading price of, our common and preferred units.

We may not have sufficient cash from operations to enable us to pay the current levels of quarterly distributions on our common and preferred units following the establishment of cash reserves and payment of fees and expenses.

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 rates we obtain from our charters;

• the expiration of charter contracts;

• the charterers options to terminate charter contracts or repurchase vessels;

• the level of our operating costs, such as the cost of crews and insurance;

• the continued availability of LNG and LPG production, liquefaction and regasification facilities;

• the number of unscheduled off-hire days for our fleet and the timing of, and number of days required for, scheduled dry docking of our vessels;

• delays in the delivery of newbuildings and the beginning of payments under charters relating to those vessels;

• prevailing global and regional economic and political conditions;

• currency exchange rate fluctuations;

• the effect of governmental regulations and maritime self-regulatory organization standards on the conduct of our business; and

• limitation of obtaining cash distributions from joint venture entities due to similar restrictions within the joint venture entities.

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

• the level of capital expenditures we make, including for maintaining vessels, building new vessels, acquiring existing vessels and complying with regulations;

• our debt service requirements and restrictions on distributions contained in our debt instruments;

• fluctuations in our working capital needs;

• our ability to make working capital borrowings, including to pay distributions to unitholders; and

• the amount of any cash reserves, including reserves for future capital expenditures, anticipated future credit needs and other matters, established by Teekay GP L.L.C., our general partner (or our General Partner) in its discretion.

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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 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 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.

Our ability to repay or refinance our debt obligations and to fund our capital expenditures will depend on certain financial, business and other factors, many of which are beyond our control. To the extent we are able to finance these obligations and expenditures with cash from operations or by issuing debt or equity securities, our ability to make cash distributions may be diminished or our financial leverage may increase or our unitholders may be diluted. Our business may be adversely affected if we need to access other sources of funding.

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:

• restructuring our debt;

• seeking additional debt or equity capital;

• selling assets;

• further reducing distributions;

• reducing, delaying or cancelling our business activities, acquisitions, investments or capital expenditures; or

• seeking bankruptcy protection.

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 have limited current liquidity.

As at December 31, 2016, we had total liquidity of $369.8 million, consisting of $126.1 million of cash and cash equivalents and $243.7 million of undrawn borrowings under our revolving credit facilities, subject to limitations in the credit facilities.  Our primary near-term liquidity needs include payment of our quarterly distributions, including distributions on our common units and Series A Preferred Units, operating expenses, dry-docking expenditures, debt service costs, scheduled repayments of long-term debt, committed capital expenditures and the funding of

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general working capital requirements. We expect to manage our near-term liquidity needs from cash flows from operations, proceeds from new debt financings and refinancings, proceeds from equity offerings, and dividends from our equity accounted joint ventures, however, there can be no assurance that any such funding will be available to us on acceptable terms, if at all.

We make substantial capital expenditures to maintain the operating capacity of our fleet, which reduce our cash available for distribution. In addition, each quarter our General Partner is required to deduct estimated maintenance capital expenditures from operating surplus, which may result in less cash available to unitholders than if actual maintenance capital expenditures were deducted.

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:

• the cost of labor and materials;

• customer requirements;

• increases in the size of our fleet;

• governmental regulations and maritime self-regulatory organization standards relating to safety, security or the environment; and

• competitive standards.

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 will be required to make substantial capital expenditures to expand the size of our fleet and generally will be required to make significant installment payments for acquisitions of newbuilding vessels prior to their delivery and generation of revenue.

We make substantial capital expenditures to increase the size of our fleet. Please read “Item 5 – Operating and Financial Review and Prospects,” for additional information about our newbuilding acquisitions. As at December 31, 2016, we have 19 LNG carrier newbuildings scheduled for delivery between 2017 and 2020, and four LPG carrier newbuildings scheduled for delivery between 2017 and 2018. We may also be obligated to purchase two of our leased Suezmax tankers, the Teide Spirit and Toledo Spirit, upon the charterer’s option, which may occur in 2018 and have an aggregate purchase price of approximately $58.2 million at December 31, 2016.

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.

Our substantial capital expenditures may reduce our cash available for distribution to our unitholders. Funding of any capital expenditures with debt may significantly increase our interest expense and financial leverage, and 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 to unitholders.

A shipowner is typically 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 substantial debt levels may limit our flexibility in obtaining additional financing, refinancing credit facilities upon maturity, pursuing other business opportunities and paying distributions.

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As at December 31, 2016, our consolidated debt, capital lease obligations and advances from affiliates totaled $2.2 billion and we had the capacity to borrow an additional $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 obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;

• we will need a substantial portion of our cash flow to make principal and interest payments on our debt, reducing the funds that would otherwise be available for operations, future business opportunities and distributions to unitholders;

• our debt level may make us more vulnerable than our competitors with less debt to competitive pressures or a downturn in our industry or the economy generally; and

• our debt level may limit our flexibility in responding to changing business and economic conditions.

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, seeking to restructure or refinance our debt, 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.

Financing agreements containing operating and financial restrictions may restrict our business and financing activities.

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:

• incur or guarantee indebtedness;

• change ownership or structure, including mergers, consolidations, liquidations and dissolutions;

• make dividends or distributions when in default of the relevant loans;

• make certain negative pledges and grant certain liens;

• sell, transfer, assign or convey assets;

• make certain investments; and

• enter into new lines of business.

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 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.

Restrictions in our debt agreements may prevent us from paying distributions.

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

• failure to pay any principal, interest, fees, expenses or other amounts when due;

• failure to notify the lenders of any material oil spill or discharge of hazardous material, or of any action or claim related thereto;

• breach or lapse of any insurance with respect to vessels securing the facility;

• breach of certain financial covenants;

• failure to observe any other agreement, security instrument, obligation or covenant beyond specified cure periods in certain cases;

• default under other indebtedness;

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• bankruptcy or insolvency events;

• failure of any representation or warranty to be materially correct;

• a change of control, as defined in the applicable agreement; and

• a material adverse effect, as defined in the applicable agreement.

We derive a substantial majority of our revenues from a limited number of customers, and the loss of any customer, charter or vessel, or any adjustment to our charter contracts could result in a significant loss of revenues and cash flow.

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 4 – Segment Reporting.”

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

• the customer fails to make charter payments because of its financial inability, disagreements with us or otherwise;

• we agree to reduce the charter payments due to us under a charter because of the customer’s inability to continue making the original payments;

• the customer exercises certain rights to terminate the charter, purchase or cause the sale of the vessel or, under some of our charters, convert the time-charter to a bareboat charter (some of which rights are exercisable at any time);

• the customer terminates the charter because we fail to deliver the vessel within a fixed period of time, the vessel is lost or damaged beyond repair, there are serious deficiencies in the vessel or prolonged periods of off-hire, or we default under the charter; or

• under some of our time-charters, the customer terminates the charter because of the termination of the charterer’s sales agreement or a prolonged force majeure event affecting the customer, including damage to or destruction of relevant facilities, war or political unrest preventing us from performing services for that customer.

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 to unitholders.

We depend on Teekay Corporation and certain of our joint venture partners to assist us in operating our business and competing in our markets.

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 various services including, in the case of operating subsidiaries, 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 fail to perform these services satisfactorily or if Teekay Corporation or certain of our joint venture partners 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 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:

• renew existing charters upon their expiration;

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• obtain new charters;

• successfully interact with shipyards during periods of shipyard construction constraints;

• obtain financing on commercially acceptable terms; or

• maintain satisfactory relationships with our employees and suppliers.

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 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.

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

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:

• a reduction in exploration for or development of new natural gas reserves or projects, or the delay or cancelation of existing projects as energy companies lower their capital expenditures budgets, which may reduce our growth opportunities;

• a reduction in 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;

• lower demand for vessels of the types we own and operate, which may reduce available charter rates and revenue to us upon redeployment of our vessels following expiration or termination of existing contracts or upon the initial chartering of vessels, or which may result in extended periods of our vessels being idle between contracts;

• customers potentially seeking to renegotiate or terminate existing vessel contracts, or failing to extend or renew contracts upon expiration, or seeking to negotiate cancelable contracts;

• the inability or refusal of customers to make charter payments to us, including purchase obligations at the end of, or the early termination of, charter contracts with Awilco relating to two of our LNG carriers due in 2017 and 2018, due to financial constraints or otherwise; or

• declines in vessel values, which may result in losses to us upon vessel sales or impairment charges against our earnings.

Our growth depends on continued growth in demand for LNG and LPG shipping.

Our growth strategy focuses on 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:

• increases in the cost of natural gas derived from LNG relative to the cost of natural gas generally;

• increase in the cost of LPG relative to the cost of naphtha and other competing petrochemicals;

• increases in the production of natural gas in areas linked by pipelines to consuming areas, the extension of existing, or the development of new, pipeline systems in markets we may serve, or the conversion of existing non-natural gas pipelines to natural gas pipelines in those markets;

• decreases in the consumption of natural gas due to increases in its price relative to other energy sources or other factors making consumption of natural gas less attractive;

• additional sources of natural gas, including shale gas;

• availability of alternative energy sources; and

• negative global or regional economic or political conditions, particularly in LNG and LPG consuming regions, which could reduce energy consumption or its growth.

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.

Changes in the oil markets could result in decreased demand for our conventional vessels and services in the future.

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 tankers business, financial condition and results of operations.

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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.

Changes in the LPG markets could result in decreased demand for our LPG vessels operating in the spot market.

We have several LPG carriers that operate in the LPG spot market and are either owned or chartered-in by Exmar LPG BVBA (or the Exmar LPG Joint Venture), a joint venture entity formed pursuant to a joint venture agreement made in February 2013 between us and Belgium-based Exmar to own and charter-in LPG carriers with a primary focus on the mid-size gas carrier segment. The charters in the spot market operate for short durations and are priced on a current, or “spot,” market rate. The LPG spot market is highly volatile and fluctuates based upon the many conditions and events that affect the price, production and transport of LPG, including competition from alternative energy sources and negative global or regional economic or political conditions. Any adverse changes in the LPG markets may impact our ability to enter into economically beneficial charters when our LPG carriers complete their existing short-term charters in the LPG spot market, which may reduce vessel earnings and impact our operating results.

Future adverse economic conditions, including disruptions in the global credit markets, could adversely affect our business, financial condition, and results of operations.

Economic downturns and financial crises in the global markets could produce illiquidity in the capital markets, market volatility, increased exposure to interest rate and credit risks and reduced access to capital markets. If global financial markets and economic conditions significantly deteriorate in the future, we may face restricted access to the capital markets or bank lending, which may make it more difficult and costly to fund future growth. Decreased access to such resources could have a material adverse effect on our business, financial condition and results of operations.

Future adverse economic conditions or other developments may affect our customers’ ability to charter our vessels and pay for our services and may adversely affect our business and results of operations.

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.

Growth of the LNG market may be limited by infrastructure constraints and community environmental group resistance to new LNG infrastructure over concerns about the environment, safety and terrorism.

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:

• increases in interest rates or other events that may affect the availability of sufficient financing for LNG projects on commercially reasonable terms;

• decreases in the price of LNG, which might decrease the expected returns relating to investments in LNG projects;

• the inability of project owners or operators to obtain governmental approvals to construct or operate LNG facilities;

• local community resistance to proposed or existing LNG facilities based on safety, environmental or security concerns;

• any significant explosion, spill or similar incident involving an LNG facility or LNG carrier; and

• labor or political unrest affecting existing or proposed areas of LNG production.

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 to unitholders.

Our growth depends on our ability to expand relationships with existing customers and obtain new customers, for which we will face substantial competition.

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:

• shipping industry relationships and reputation for customer service and safety;

• shipping experience and quality of ship operations (including cost effectiveness);

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• quality and experience of seafaring crew;

• the ability to finance carriers at competitive rates and financial stability generally;

• relationships with shipyards and the ability to get suitable berths;

• construction management experience, including the ability to obtain on-time delivery of new vessels according to customer specifications;

• willingness to accept operational risks pursuant to the charter, such as allowing termination of the charter for force majeure events; and

• competitiveness of the bid in terms of overall price.

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 to unitholders.

Delays in deliveries of newbuildings or in conversions or upgrades of existing vessels could harm our operating results and lead to the termination of related charters.

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:

• quality or engineering problems;

• changes in governmental regulations or maritime self-regulatory organization standards;

• work stoppages or other labor disturbances at the shipyard;

• bankruptcy or other financial crisis of the shipbuilder;

• a backlog of orders at the shipyard;

• political or economic disturbances where our vessels are being or may be built;

• weather interference or catastrophic event, such as a major earthquake or fire;

• our requests for changes to the original vessel specifications;

• shortages of or delays in the receipt of necessary construction materials, such as steel;

• our inability to finance the purchase or construction of the vessels; or

• our inability to obtain requisite permits or approvals.

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 to unitholders.

We may be unable to recharter vessels at attractive rates, which may lead to reduced revenues and profitability.

Our ability to recharter our LNG and LPG carriers upon the expiration or termination of their current time charters and the charter rates payable under any renewal or replacement charters, including the 10-month charter contract plus one-year option for the Torben Spirit which commenced in March 2017, our wholly-owned LNG carriers, the Arctic Spirit and Polar Spirit whose charter contract ends with Teekay Corporation in April 2018, and our 52% owned vessels, the Magellan Spirit and Methane Spirit, which are currently trading in the spot market, will depend upon, among other things, the then current states of the LNG and LPG carrier markets. If charter rates are low when existing time charters expire, we may be required to recharter our vessels at reduced rates or even possibly at a rate whereby we incur a loss, which would harm our results of operations. Alternatively, we may determine to leave such vessels off-charter. The size of the current orderbooks for LNG carriers and LPG carriers is expected to result in the increase in the size of the world LNG and LPG fleets over the next few years. An over-supply of vessel capacity, combined with stability or any decline in the demand for LNG or LPG carriers, may result in a reduction of charter hire rates.

We may have more difficulty entering into long-term, fixed-rate LNG time-charters if an active short-term, medium-term or spot LNG shipping market develops.

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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 2016, they accounted for approximately 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.

Over time vessel values may fluctuate substantially, which could adversely affect our operating results.

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

• prevailing economic conditions in natural gas, oil and energy markets;

• a substantial or extended decline in demand for natural gas, LNG, LPG or oil;

• competition from more technologically advanced vessels;

• increases in the supply of vessel capacity; and

• the cost of retrofitting or modifying existing vessels, as a result of technological advances in vessel design or equipment, changes in applicable environmental or other regulation or standards, or otherwise.

Vessel values may decline from existing levels. If the operation of a vessel is not profitable, or if we cannot re-deploy a vessel at attractive rates upon termination of its contract, rather than continue to incur costs to maintain and finance 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.

Increased technological innovation in vessel design or equipment could reduce our charter hire rates and the value of our vessels.

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 may be unable to perform as per specifications on our new engine designs.

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

We or our joint venture partners may be unable to deliver or operate a FSU or a LNG receiving and regasification terminal.

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.

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-

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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 may be unable to make or realize expected benefits from acquisitions, and implementing our growth strategy through acquisitions may harm our business, financial condition and operating results.

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:

• fail to realize anticipated benefits, such as new customer relationships, cost-savings or cash flow enhancements;

• be unable to hire, train or retain qualified shore and seafaring personnel to manage and operate our growing business and fleet;

• decrease our liquidity by using a significant portion of our available cash or borrowing capacity to finance acquisitions;

• significantly increase our interest expense or financial leverage if we incur additional debt to finance acquisitions;

• incur or assume unanticipated liabilities, losses or costs associated with the business or vessels acquired; or

• incur other significant charges, such as impairment of goodwill or other intangible assets, asset devaluation or restructuring charges.

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.

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:

• marine disasters;

• bad weather or natural disasters;

• mechanical failures;

• grounding, fire, explosions and collisions;

• piracy;

• human error; and

• war and terrorism.

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

• death or injury to persons, loss of property or environmental damage;

• delays in the delivery of cargo;

• loss of revenues from or termination of charter contracts;

• governmental fines, penalties or restrictions on conducting business;

• higher insurance rates; and

• damage to our reputation and customer relationships generally.

Any of these results could have a material adverse effect on our business, financial condition and operating results. In addition, any damage to, or environmental contamination involving, oil production facilities serviced could suspend that service and result in loss of revenues.

Our insurance may be insufficient to cover losses that may occur to our property or result from our operations.

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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.

Our and many of our customers’ substantial operations outside the United States expose us and them to political, governmental and economic instability, which could harm our operations.

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.

Two vessels owned by the Teekay LNG-Marubeni Joint Venture, the Marib Spirit and Arwa Spirit, are currently under long-term contracts expiring in 2029 with 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 deferred 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. 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.

Terrorist attacks, piracy, increased hostilities, political change or war could lead to further economic instability, increased costs and disruption of our business.

Terrorist attacks, piracy, the current conflicts in the Middle East, 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 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 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 a LNG or LPG facility or LNG or

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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 on ocean-going vessels continue to be a risk, which could adversely affect our business.

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 continues to be a significant risk of piracy 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 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.

The ARC7 Ice-Class LNG carrier newbuildings for the Yamal LNG Project are customized vessels and our financial condition, results of operations and ability to make distributions on our common and preferred units could be substantially affected if the Yamal LNG Project is not completed.

On July 9, 2014, we entered into a 50/50 joint venture with China LNG (or the Yamal LNG Joint Venture) and ordered six internationally-flagged icebreaker LNG carriers for a project located on the Yamal Peninsula in Northern Russia (or the Yamal LNG Project). The Yamal LNG Project is a joint venture between Russia-based Novatek OAO (50.1%), France-based Total S.A. (20%), China-based China National Petroleum Corporation (20%) and Silk Road Fund (9.9%).

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:

• failure to achieve expected operating results;

• changes in demand for LNG;

• adverse changes in Russian regulations or governmental policy relating to the project or the export of LNG;

• technical challenges of completing and operating the complex project, particularly in extreme Arctic conditions;

• labor disputes; and

• environmental regulations or potential claims.

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 to unitholders.

Sanctions against key participants in the Yamal LNG Project could impede completion or performance of the Yamal LNG Project, which could have a material adverse effect on us.

The U.S. Treasury Department’s Office of Foreign Assets Control (or OFAC) placed Russia-based Novatek OAO (or Novatek), a 50.1% owner of the Yamal LNG Project, on the Sectoral Sanctions Identifications List. OFAC also previously imposed sanctions on an investor in Novatek and these sanctions also remain in effect. The restrictions on Novatek prohibit U.S. persons (and their subsidiaries) from participating in debt financing transactions of greater than 90 days maturity with Novatek and, by virtue of Novatek’s 50.1% ownership interest, the Yamal LNG Project. The European Union also imposed certain sanctions on Russia. These sanctions require a European Union license or authorization before a party can provide certain technologies or technical assistance, financing, financial assistance, or brokering with regard to these technologies. However, the technologies being currently sanctioned by the EU appear to focus on oil exploration projects, not gas projects. Future sanctions may prohibit the Yamal LNG Joint Venture from performing under its contracts with the Yamal LNG Project, which could have a material adverse effect on our financial condition, results of operations and ability to make distributions on our common and preferred units. We believe that we are in compliance with all applicable sanctions laws and regulations and intend to maintain such compliance.

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Neither the Yamal LNG Joint Venture nor our joint venture partner may be able to obtain financing for the six LNG ARC7 Ice-Class carrier newbuildings for the Yamal LNG Project.

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.

Failure of the Yamal LNG Project to achieve expected results could lead to a default under the time-charter contracts by the charter party.

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.

We assume credit risk by entering into agreements with unrated entities.

Some of our vessels are chartered to unrated entities and 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.

The marine energy transportation industry is subject to substantial environmental and other regulations, which may significantly limit our operations or increase our expenses.

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: B. Operations - Regulations.”

Exposure to currency exchange rate fluctuations will result in fluctuations in our cash flows and operating results.

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 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, are revalued and reported based on the prevailing exchange rate at the end

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of the period. This revaluation historically has caused us to report significant non-monetary foreign currency exchange gains or losses each period. The primary source for these gains and losses is our Euro-denominated term loans and our Norwegian Kroner-denominated (or NOK) bonds. We incur interest expense on our NOK bonds and we have entered into cross-currency swaps to economically hedge the foreign exchange risk on the principal and interest payments of our NOK bonds. If the Norwegian Kroner depreciates relative to the U.S. Dollar beyond a certain threshold, we are required to place cash collateral with our swap providers.

Many of our seafaring employees are covered by collective bargaining agreements and the failure to renew those agreements or any future labor agreements may disrupt our operations and adversely affect our cash flows.

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 to unitholders.

Teekay Corporation and certain of our joint venture partners may be unable to attract and retain qualified, skilled employees or crew necessary to operate our business, or may have to pay substantially increased costs for its employees and crew.

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.

Due to our lack of diversification, adverse developments in our LNG, LPG or oil marine transportation businesses could reduce our ability to make distributions to our unitholders.

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.

Teekay Corporation and its affiliates may engage in competition with us.

Teekay Corporation and its affiliates, including Teekay Offshore Partners L.P. (or Teekay Offshore), may engage in competition with us. Pursuant to an omnibus agreement between Teekay Corporation, Teekay Offshore, us and other related parties, Teekay Corporation, Teekay Offshore and their respective controlled affiliates (other than us and our subsidiaries) generally have agreed not to own, operate or charter LNG carriers without the consent of our General Partner. The omnibus agreement, however, allows Teekay Corporation, Teekay Offshore or any of such controlled affiliates to:

• acquire LNG carriers and related time-charters as part of a business if a majority of the value of the total assets or business acquired is not attributable to the LNG carriers and time-charters, as determined in good faith by the board of directors of Teekay Corporation or 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; or

• own, operate and charter LNG carriers that relate to a bid or award for an LNG project that Teekay Corporation or any of its subsidiaries 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 a project and other projects that would have been subject to the offer rights set forth in the omnibus agreement but were not completed.

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:

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• acquire, operate or charter 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;

• acquire up to a 9.9% equity ownership, voting or profit participation interest in any publicly traded company that owns or operates LNG carriers; and

• provide ship management services relating to LNG carriers.

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 to unitholders.

Our General Partner and its other affiliates own a controlling interest in us and have conflicts of interest and limited fiduciary duties, which may permit them to favor their own interests to those of unitholders.

Teekay Corporation, which owns and controls our General Partner, indirectly owns our 2% general partner interest and as at December 31, 2016 owned 31.7% of our common units. Although our General Partner has a fiduciary duty to manage us in 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:

• neither our partnership agreement nor any other agreement requires our General Partner or Teekay Corporation to pursue a business strategy that favors us or utilizes our assets, and Teekay Corporation’s officers and directors have a fiduciary duty to make decisions in the best interests of the shareholders of Teekay Corporation, which may be contrary to our interests;

• executive officers of Teekay Gas Group Ltd., our newly formed subsidiary, and two of the directors of our General Partner also currently serve as officers or directors of Teekay Corporation;

• our General Partner is allowed to take into account the interests of parties other than us, such as Teekay Corporation, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders;

• our General Partner has limited its liability and reduced its fiduciary duties under the laws of The Marshall Islands, while also restricting the remedies available to our unitholders, and as a result of purchasing units, unitholders are treated as having agreed to the modified standard of fiduciary duties and to certain actions that may be taken by our General Partner, all as set forth in our partnership agreement;

• our General Partner determines the amount and timing of our asset purchases and sales, capital expenditures, borrowings, issuances of additional partnership securities and reserves, each of which can affect the amount of cash that is available for distribution to our unitholders;

• in some instances, our General Partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make incentive distributions to affiliates to Teekay Corporation;

• our General Partner determines which costs incurred by it and its affiliates are reimbursable by us;

• our partnership agreement does not restrict our General Partner from causing us to pay it or its affiliates for any services rendered to us on terms that are fair and reasonable or entering into additional contractual arrangements with any of these entities on our behalf;

• our General Partner controls the enforcement of obligations owed to us by it and its affiliates; and

• our General Partner decides whether to retain separate counsel, accountants or others to perform services for us.

The fiduciary duties of the officers and directors of our General Partner may conflict with those of the officers and directors of Teekay Corporation.

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.

Certain of our lease arrangements contain provisions whereby we have provided a tax indemnification to third parties, which may result in increased lease payments or termination of favorable lease arrangements.

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 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

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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 (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.

We own a 70% interest in Teekay Nakilat Corporation (or Teekay Nakilat Joint Venture) that was the lessee under three separate 30-year capital lease arrangements with a third party for three LNG carriers (or the RasGas II LNG Carriers). Under the terms of the leasing arrangements for the RasGas II LNG Carriers, the lessor claimed tax depreciation on the capital expenditures it incurred to acquire these vessels. As is typical in these leasing arrangements, tax and change of law risks were assumed by the lessee, in this case the Teekay Nakilat Joint Venture. Lease payments under the lease arrangements were based on certain tax and financial assumptions at the commencement of the leases and subsequently adjusted to maintain the lessor’s agreed after-tax margin. On December 22, 2014, the Teekay Nakilat Joint Venture terminated the leasing of the RasGas II LNG Carriers. However, the Teekay Nakilat Joint Venture remains obligated to the lessor to maintain the lessor’s agreed after-tax margin from the commencement of the lease to the lease termination date and placed $6.8 million on deposit with the lessor as security against any future claims.

The UK taxing authority (or HMRC) has been challenging the use of similar lease structures in the UK courts. One of those challenges was eventually decided in favour of HMRC (Lloyds Bank Equipment Leasing No. 1 or LEL1), with the lessor and lessee choosing not to appeal further. The LEL1 tax case concluded that capital allowances were not available to the lessor. On the basis of this conclusion, HMRC is now asking lessees on other leases, including the Teekay Nakilat Joint Venture, to accept that capital allowances are not available to the lessor. The Teekay Nakilat Joint Venture does not accept this contention and has informed HMRC of this position. It is not known at this time whether the Teekay Nakilat Joint Venture would eventually prevail in court. If the former lessor of the RasGas II LNG Carriers were to lose on a similar claim from HMRC, our 70% share of the Teekay Nakilat Joint Venture's potential exposure is estimated to be approximately $60 million. Such estimate is primarily based on information received from the lessor.

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 have with the three RasGas II LNG Carriers.

Our joint venture arrangements impose obligations upon us but limit our control of the joint ventures, which may affect our ability to achieve our joint venture objectives.

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.

TAX RISKS

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.

United States unitholders will be required to pay U.S. taxes on their share of our income even if they do not receive any cash distributions from us.

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. 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.

Because distributions may reduce a common unitholder’s tax basis in our common units, common unitholders may realize greater gain on the disposition of their common units than they otherwise may expect, and common unitholders may have a tax gain even if the price they receive is less than their original cost.

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

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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 after-tax benefit of an investment in the common units may be reduced if we are not treated as a partnership for U.S. federal income tax purposes.

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:

• The ratio of taxable income to distributions with respect to common units would be expected to increase because items would not be allocated to account for any differences between the fair market value and the basis of our assets at the time our common units are issued.

• Common unitholders may recognize income or gain on any change in our status from a partnership to a corporation that occurs while they hold common units.

• We would not be permitted to adjust the tax basis of a secondary market purchaser in our assets under Section 743(b) of the Code. As a result, a person who purchases common units from a common unitholder in the secondary market may realize materially more taxable income each year with respect to the units. This could reduce the value of common unitholders’ common units.

• Common unitholders would not be entitled to claim any credit against their U.S. federal income tax liability for non-U.S. income tax liabilities incurred by us.

• As to the U.S. source portion of our income attributable to transportation that begins or ends (but not both) in the United States, we will be subject to U.S. tax on such income on a gross basis (that is, without any allowance for deductions) at a rate of 4 percent. The imposition of this tax would have a negative effect on our business and would result in decreased cash available for distribution to common unitholders.

• We also may be considered a passive foreign investment company (or PFIC) for U.S. federal income tax purposes. U.S. shareholders of a PFIC are subject to an adverse U.S. federal income tax regime with respect to the income derived by the PFIC, the distributions they receive from the PFIC, and the gain, if any, they derive from the sale or other disposition of their interests in the PFIC.

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

The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes or differing interpretations, possibly on a retroactive basis.

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.

If the IRS contests the U.S. federal income tax positions we take, the value of our units could be adversely affected and the costs of any such contest will reduce cash available for distribution to unitholders. The procedures for assessing and collecting taxes due with respect to partnerships for taxable years beginning after December 31, 2017, have been altered in a manner that could substantially reduce cash available for distribution to unitholders.

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.

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The IRS may challenge the manner in which we prorate our items of income, gain, loss and deduction between transferors and transferees of our common units and, if successful, we may be required to change the allocation of items of income, gain, loss and deduction among our common unitholders.

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.

U.S. tax-exempt entities and non-U.S. persons face unique U.S. tax issues from owning units that may result in adverse U.S. tax consequences to them.

Investments in units by U.S. tax-exempt entities, including individual retirement accounts (known as IRAs), other 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."

The sale or exchange of 50 percent or more of our capital or profits interests in any 12-month period will result in the termination of our partnership for U.S. federal income tax purposes.

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.”

Teekay Corporation owns less than 50 percent of our outstanding equity interests, which could cause certain of our subsidiaries and us to be subject to additional tax.

Certain of our subsidiaries are and have been classified as corporations for U.S. federal income tax purposes. As such, these subsidiaries would be subject to U.S. federal income tax on the U.S. source portion of our income attributable to transportation that begins or ends (but not both) in the United States if they fail to qualify for an exemption from U.S. federal income tax (the Section 883 Exemption). Teekay Corporation indirectly owns less than 50 percent of certain of our subsidiaries’ and our outstanding equity interests. Consequently, we expect these subsidiaries failed to qualify for the Section 883 Exemption in 2016 and that Teekay LNG Holdco L.L.C., our sole remaining regarded corporate subsidiary as of January 1, 2016, failed to qualify for the Section 883 Exemption in 2016 and will fail to so qualify in 2017 and subsequent tax years. Any resulting imposition of U.S. federal income taxes will result in decreased cash available for distribution to unitholders. Please read “Item 10 – Additional Information: Taxation – United States Tax Consequences –Taxation of Our Subsidiary Corporations.”

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 and that any resulting imposition of U.S. federal income taxes would result in decreased cash available for distribution to unitholders.

The IRS may challenge the manner in which we value our assets in determining the amount of income, gain, loss and deduction allocable to the common unitholders and to the General Partner and certain other tax positions, which could adversely affect the value of the common units.

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 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 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.

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Unitholders may be subject to income tax in one or more non-U.S. countries, including Canada, as a result of owning our units if, under the laws of any such country, we are considered to be carrying on business there. Such laws may require unitholders to file a tax return with, and pay taxes to, those countries. Any foreign taxes imposed on us or any of our subsidiaries will reduce our cash available for distribution to unitholders.

Unitholders may be subject to tax in one or more countries, including Canada, as a result of owning our units if, under the laws of any such country, we are considered to be carrying on business there. If unitholders are subject to tax in any such country, 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 unitholders on account of any withholding obligations imposed upon us by that country in respect of such allocation to unitholders. The United States may not allow a tax credit for any foreign income taxes that unitholders directly or indirectly incur. Any foreign taxes imposed on us or any of our subsidiaries will reduce our cash available for unitholders.

Item 4.Information on the Partnership

A. Overview, History and Development

Overview and History

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 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 2016 and Early 2017.”

As of December 31, 2016, our fleet, excluding newbuildings, consisted of 31 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), 25 LPG carriers (including the 19 Exmar LPG Carriers that are accounted for under the equity method), five Suezmax-class crude oil tankers, and one Handymax product tanker, all of which are double-hulled. Our fleet is relatively young and has an average age of approximately nine years for our LNG carriers, approximately nine years for our LPG carriers and approximately 12 years for our conventional tankers (Suezmax and Handymax), compared to world averages of 11, 15 and nine years, respectively, as of December 31, 2016.

Our fleets of LNG and LPG carriers currently have approximately 4.9 million and 0.8 million cubic meters of total capacity, respectively. The aggregate capacity of our conventional tanker fleet is approximately 0.8 million deadweight tonnes (or dwt).

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 offices at 4th Floor, Belvedere Building, 69 Pitts Bay Road, Hamilton, HM 08, Bermuda. Our telephone number at such address is (441) 298-2530.

B. Operations

Our Charters

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 fixed-rate contracts with major energy and utility companies and Teekay Corporation. As of December 31, 2016, the average remaining term for these contracts, including assets under construction, is approximately 13 years for our LNG carriers and regasification terminal, approximately five years for our LPG carriers and approximately 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.

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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.

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 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.

Liquefied Gas Segment

LNG Carriers

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.

LNG carriers transport LNG internationally between liquefaction facilities and import terminals. After natural gas is transported by pipeline from production fields to a liquefaction facility, it is supercooled to a temperature of approximately negative 260 degrees Fahrenheit. This process reduces its volume to approximately 1/600th of its volume in a gaseous state. The reduced volume facilitates economical storage and transportation by ship over long distances, enabling countries with limited natural gas reserves or limited access to long-distance transmission pipelines to import natural gas. LNG carriers include a sophisticated containment system that holds the LNG and provides insulation to reduce the amount of LNG that boils off naturally. The natural boil off is either used as fuel to power the engines on the ship or it can be reliquefied and put back into the tanks. LNG is transported overseas in specially built tanks in double-hulled ships to a receiving terminal, where it is offloaded and stored in insulated tanks. In regasification facilities at the receiving terminal, the LNG is returned to its gaseous state (or regasified) and then shipped by pipeline for distribution to natural gas customers.

With the exception of the Arctic Spirit and Polar Spirit, which are the only two ships in the world that utilize the Ishikawajima Harima Heavy Industries Self Supporting Prismatic Tank IMO Type B (or IHI SPB) independent tank technology, our fleet makes use of one of the Gaz Transport and Technigaz (or GTT) membrane containment systems. The GTT membrane systems are used in the majority of LNG tankers now being constructed. New LNG carriers generally have an expected lifespan of approximately 35 to 40 years. Unlike the oil tanker industry, there are currently no regulations that require the phase-out from trading of LNG carriers after they reach a certain age. As at December 31, 2016, our LNG carriers, excluding newbuilding vessels, had an average age of approximately nine years, compared to the world LNG carrier fleet average age of approximately 11 years. In addition, as at that date, there were approximately 472 vessels in the world LNG fleet and approximately 133 additional LNG carriers under construction or on order for delivery through 2020.

The following table provides additional information about our LNG carriers as of December 31, 2016, excluding our 19 newbuildings scheduled for delivery between 2017 and 2020 in which our ownership interests range from 20% to 100%, of which one LNG carrier newbuilding was delivered in February 2017:

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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)
Al Marrouna	149,539	2006	70	%		Ras Laffan Liquefied Natural Gas Company Ltd.	Oct. 2026(4)
Al Areesh	148,786	2007	70	%		Ras Laffan Liquefied Natural Gas Company Ltd.	Jan. 2027(4)
Al Daayen	148,853	2007	70	%		Ras Laffan Liquefied Natural Gas Company Ltd.	Apr. 2027(4)
Tangguh Hiri	151,885	2008	69	%		The Tangguh Production Sharing Contractors	Jan. 2029
Tangguh Sago	155,000	2009	69	%		The Tangguh Production 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)
Creole Spirit	173,000	2016	100% – Capital lease			Cheniere Marketing, LLC	Feb. 2021(6)
Oak Spirit	173,000	2016	100% – Capital lease			Cheniere Marketing, LLC	Aug. 2021(6)
Equity Accounted
Al Huwaila	214,176	2008	40	%	(8)	Ras Laffan Liquefied Natural Gas Company Ltd.	Apr. 2033(2)
Al Kharsaah	214,198	2008	40	%	(8)	Ras Laffan Liquefied Natural Gas Company Ltd.	Apr. 2033(2)
Al Shamal	213,536	2008	40	%	(8)	Ras Laffan Liquefied Natural Gas Company Ltd.	May 2033(2)
Al Khuwair	213,101	2008	40	%	(8)	Ras Laffan Liquefied Natural Gas Company Ltd.	Jun. 2033(2)
Excelsior	138,087	2005	50	%	(9)	Excelerate Energy LP	Jan. 2025(2)
Excalibur	138,034	2002	49	%	(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(7)
Magellan Spirit	165,700	2009	52	%	(11)	Spot market	-
Marib Spirit	165,500	2008	52	%	(11)	Yemen LNG Company Limited(12)	Mar. 2029(7)
Arwa Spirit	165,500	2008	52	%	(11)	Yemen LNG Company Limited(12)	Apr. 2029(7)
Methane Spirit	165,500	2008	52	%	(11)	Spot market	-
Woodside Donaldson	165,500	2009	52	%	(11)	Pluto LNG Party Limited	Jun. 2026(13)
	4,899,079

(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.

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(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 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.

(7) The charterer has three options to extend the term for one, five and five additional years, respectively.

(8) The RasGas 3 LNG Carriers are accounted for under the equity method.

(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) 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 the status of this charter contract.

(13)The charterer has four options to extend the term for an additional five years each.

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 2016, 2015 and 2014.

	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) Shell Spain LNG S.A.U. acquired the charter contracts from Repsol YPF, S.A in March 2014. The voyage revenues in 2014 consisted of the voyage revenues from both customers relating to the same charter contracts.

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 Carriers

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.

As of December 31, 2016, our LPG carriers had an average age of approximately nine years, compared to the world LPG carrier fleet average age of approximately 15 years. As of that date, the worldwide LPG tanker fleet consisted of approximately 1,410 vessels and approximately 114 additional LPG vessels were on order for delivery through 2019. LPG carriers range in size from approximately 100 to approximately 87,000 cubic meters. Approximately 45% of the vessels in the worldwide fleet are less than 5,000 cubic meters in size. New LPG carriers generally have an expected lifespan of approximately 30 to 35 years.

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, 2016, and excludes our 50% ownership interest in four newbuildings scheduled for delivery between 2017 and 2018 of which one LPG carrier newbuilding was delivered in March 2017:

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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 SE(1)	Mar. 2024
Norgas Cathinka	10,000	2009	99%	Bareboat	I.M. Skaguen SE(1)	Oct. 2024
Norgas Camilla	10,000	2011	99%	Bareboat	I.M. Skaguen SE(1)	Sep. 2026
Norgas Unikum	12,000	2011	99%	Bareboat	I.M. Skaguen SE(1)	Jun. 2026
Bahrain Vision	12,000	2011	99%	Bareboat	I.M. Skaguen SE(1)	Oct. 2026
Norgas Napa	10,200	2003	99%	Bareboat	I.M. Skaguen SE(1)	Nov. 2019
Equity Accounted
Brugge Venture(2)	35,418	1997	50%	Time charter	An international fertilizer company	Jan. 2017
Temse	12,030	1995	50% – Capital lease	Time charter	An international fertilizer company	Mar. 2017
Libramont	38,455	2006	50%	Time charter	An international fertilizer company	Jun. 2026
Sombeke	38,447	2006	50%	Time charter	An international fertilizer company	Jul. 2027
Touraine	39,270	1996	50%	Spot	Spot market	—
Bastogne	35,229	2002	50%	Spot	Spot market	—
Courcheville	28,006	1989	50%	Time charter	An international energy company	Mar. 2017
Eupen	38,961	1999	50%	Time charter	An international mining company	Dec. 2018
Brussels	35,454	1997	50%	Time charter	An international fertilizer company	Dec. 2017
Antwerpen	35,223	2005	50% – In-chartered	Time charter	An international energy company	Oct. 2017
BW Tokyo	83,270	2009	50% – In-chartered	Spot	Spot market	—
Waregem	38,189	2014	50%	Time charter	An international trading company	Jan. 2020
Warinsart	38,213	2014	50%	Time charter	An international energy company	Nov. 2017
Waasmunster	38,245	2014	50%	Spot	Spot market	—
Warisoulx	38,000	2015	50%	Time charter	An international trading company	Jun. 2018
Kaprijke	38,000	2015	50%	Time charter	An international fertilizer company	Jan. 2026
Knokke	38,000	2016	50%	Time charter	An international energy company	Apr. 2021
Kontich	38,000	2016	50%	Time charter	An international energy company	Aug. 2021
Kortrijk	38,000	2016	50%	Time charter	An international trading company	Nov. 2018
	788,610

(1) 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 the status of these charter contracts.

(2) The Brugge Venture was sold on January 10, 2017.

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

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Conventional Tanker Segment

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, 2016, the world tanker fleet included 468 conventional Suezmax tankers, representing approximately 14% of worldwide oil tanker capacity, excluding tankers under 10,000 dwt.

As of December 31, 2016, our conventional tankers had an average age of approximately 12 years, compared to the average age for the world conventional tanker fleet of approximately nine years. New conventional tankers generally have an expected lifespan of approximately 25 to 30 years, based on estimated hull fatigue life.

The following table provides additional information about our conventional oil tankers as of December 31, 2016:

Tanker(1)	Capacity	Delivery	Our Ownership	Charterer	Expiration of Charter
	(dwt)
Operating Conventional tankers:
Teide Spirit	149,999	2004	100% – Capital lease (2)	CEPSA	Oct. 2017(3)
Toledo Spirit	159,342	2005	100% – Capital lease (2)	CEPSA	Jul. 2018(3)
European Spirit	151,849	2003	100%	ConocoPhillips Shipping LLC	Sep. 2017(4)
African Spirit	151,736	2003	100%	ConocoPhillips Shipping LLC	Nov. 2017(4)
Asian Spirit(5)	151,693	2004	100%	ConocoPhillips Shipping LLC	Jan. 2017(4)
Alexander Spirit	40,083	2007	100%	Caltex Australian Petroleum Pty Ltd.	Sep. 2019
	804,702

(1) The conventional tankers listed in the table are all Suezmax tankers, with the exception of the Alexander Spirit, which is a Handymax tanker.

(2) We are the lessee under a capital lease arrangement and may be required to purchase the vessel after the end of the lease terms for a fixed price. Please read “Item 18 - Financial Statements: Note 5 – Leases and Restricted Cash.”

(3) Compania Espanole de Petroleos, S.A. (or CEPSA) has the right to terminate the time-charter 13 years after the original delivery date without penalty. The expiration date presented in the table assumes the termination at the end of year 13 of the charter contract; however, if the charterer does not exercise its annual termination rights, from the end of year 13 onward, the charter contract could extend to 20 years after the original delivery date.

(4) The term of the time-charter is 12 years from the original delivery date, which may be extended at the customer’s option for up to an additional six years. In addition, the customer has the right to terminate the time-charter upon notice and payment of a cancellation fee. Either party also may require the sale of the vessel to a third party at any time, subject to the other party’s right of first refusal to purchase the vessel.

(5) The Asian Spirit was sold on March 21, 2017.

No conventional tanker customer accounted for 10% or more of our consolidated voyage revenues during 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.

Business Strategies

Our primary long-term business objective is to increase distributable cash flow per 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

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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.

We intend to achieve our long-term business objective, as stated above, by executing the following strategies:

• Provide superior customer service by maintaining high reliability, safety, environmental and quality standards. LNG and LPG project operators seek LNG and LPG transportation partners that have a reputation for high reliability, safety, environmental and quality standards. We seek to leverage our own and Teekay Corporation’s operational expertise to create a sustainable competitive advantage with consistent delivery of superior customer service.

• Expand our LNG and LPG business globally. We seek to capitalize on opportunities emerging from the global expansion of the LNG and LPG sectors by selectively targeting:

• projects which involve medium-to long-term, fixed-rate charters;

• cost-effective LNG and LPG newbuilding contracts;

• joint ventures and partnerships with companies that may provide increased access to opportunities in attractive LNG and LPG importing and exporting geographic regions;

• strategic vessel and business acquisitions; and

• specialized projects in adjacent areas of the business, including floating storage and regasification units (or FSRUs).

Safety, Management of Ship Operations and Administration

Teekay Corporation, through its subsidiaries, assists us in managing our ship operations, other than the vessels owned or chartered-in by our joint ventures with Exmar, which are commercially and technically managed by Exmar, and two of the Angola LNG Carriers, which are commercially and technically managed by NYK Energy Transport (Atlantic) Ltd. Safety and environmental compliance are our top operational priorities. We operate our vessels in a manner intended to protect the safety and health of the employees, the general public and the environment. We seek to manage the risks inherent in our business and are committed to eliminating incidents that threaten the safety and integrity of our vessels, such as groundings, fires, collisions and petroleum spills. In 2007, Teekay Corporation introduced a behavior-based safety program called “Safety in Action” to further enhance the safety culture in our fleet. We are also committed to reducing our emissions and waste generation. In 2008, Teekay Corporation introduced the Quality Assurance and Training Officers (or QATO) program to conduct rigorous internal audits of our processes and provide the seafarers with onboard training. In 2010, Teekay Corporation introduced a training program for our employees titled “Operational Leadership, The Journey” which sets out Teekay Corporation's operational expectations, the responsibilities of individual employees and our commitment to empowering our employees to work safely and live Teekay Corporation’s vision through a positive and responsible attitude.

Key performance indicators facilitate regular monitoring of our operational performance. Targets are set on an annual basis to drive continuous improvement, and indicators are reviewed monthly to determine if remedial action is necessary to reach the targets.

Teekay Corporation has achieved certification under the standards reflected in International Standards Organization’s (or ISO) 9001 for Quality Assurance, ISO 14001 for Environment Management Systems, Occupational Health and Safety Advisory Services 18001 for Occupational Health and Safety, and the IMO’s International Management Code for the Safe Operation of Ships and Pollution Prevention (or ISM Code) on a fully integrated basis. As part of Teekay Corporation’s compliance with the ISM Code, all of our vessels’ safety management certificates are maintained through ongoing internal audits performed by our certified internal auditors and intermediate external audits performed by the classification society DNV-GL. Subject to satisfactory completion of these internal and external audits, certification is valid for five years.

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 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. Vessel management services are provided by subsidiaries of Teekay Corporation, located in various offices around the world. These include critical vessel management functions such as:

• 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 and projects during construction of newbuildings and conversions;

• insurance; and

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• 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 are 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.

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 because 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. (or IACS): Bureau Veritas (or BV), Lloyd’s Register of Shipping, the American Bureau of 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.

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 two 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;

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• machinery and equipment is being maintained to give reliable service;

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

• 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.

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 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 (or CLC). 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 (or SOLAS), including amendments to SOLAS implementing the International Ship and Port Facility Security Code (or ISPS), 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 (the IGC 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 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, which takes account of

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advances in science and technology, was adopted by the IMO’s Maritime Safety Committee (or MSC) on May 22, 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 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 "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.

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 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 USCG have issued Type Approval (or TA) for the following ballast water treatment systems (or BWTS):

•Alfa Laval;

•Ocean Saver; and

•Optimarin.

We expect the USCG will issue more TAs for BWTS in the future. Plans have been set for the decoupling of IOPP surveys with Harmonised System of Survey and Certification for vessels planning to drydock in 2018 with approval from the Flag and Classification Society. We estimate that the installation of 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 (or MEPC) adopted the environmental provisions of the Polar Code and associated amendments to MARPOL. The Polar Code 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:

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• 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 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, 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 a Directive requiring the use of low sulfur fuel. 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. Since January 1, 2014, the California Air Resources Board has required vessels to burn fuel with 0.1% sulfur content or less within 24 nautical miles 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, 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 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 0.1% sulfur marine gas oil (or LSMGO). Since January 1, 2015, the applicable sulfur content limits in the North Sea, the Baltic Sea and the English Channel ECAs have been 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 (or HFO), 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

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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 Ship Recycling Regulation (1257/2013) (or the EU Ship Recycling Regulation) entered into force on December 30, 2013. It aims to prevent, reduce and minimize accidents, injuries and other negative effects on human health and the environment when ships are recycled and the hazardous waste they contain is removed. The legislation applies to all ships flying the flag of an EU country and 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 (such as asbestos, lead or 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 the 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. The EU Ship Recycling Regulation is to apply 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, 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 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 (or OPA 90) and the Comprehensive Environmental Response, Compensation and Liability Act (or CERCLA). 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 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 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 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.

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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 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 (or EPA) 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 the Kyoto 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” (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,

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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 the inclusion of shipping in the 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 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 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.

C. Organizational Structure

Our sole 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 subsidiaries as at December 31, 2016.

D. Properties

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

Item 4A. Unresolved Staff Comments

Not applicable.

Item 5. Operating and Financial Review and Prospects

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

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 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 2016 AND EARLY 2017

Bahrain LNG Joint Venture

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On November 15, 2016, the 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

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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 20% interest in two LNG carrier newbuildings and a 30% interest in another two LNG carrier newbuildings (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 have entered into time-charter contracts for all of our remaining newbuildings.

LPG Carrier Newbuildings

In February, June, and November, 2016, Exmar LPG BVBA (or the Exmar LPG Joint Venture), of which we have a 50% ownership interest, took delivery of the sixth, seventh, and eighth of its 12 LPG carrier newbuildings on order. The five-year charter contracts for the sixth and seventh LPG carriers with an international energy company based in Norway commenced in February, 2016 and August 2016, respectively. As at December 31, 2016, the Exmar LPG Joint Venture had four LPG carrier newbuildings, of which one delivered in March 2017 and the remaining three are scheduled for delivery between mid-2017 and early-2018. The Exmar LPG Joint Venture has secured financing in place upon delivery of 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 2015, the Magellan Spirit, one of the MALT LNG Carriers in the Teekay LNG-Marubeni Joint Venture, had a grounding incident. The charterer during that time claimed that the vessel was off-hire for more than 30 consecutive days during the first quarter of 2015, which, in the view of the charterer, permitted the charterer to terminate the charter contract. The Teekay LNG-Marubeni Joint Venture disputed both the charterer’s

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aggregate off-hire claims as well as the charterer’s ability to terminate the charter contract, which originally would have expired in August 2016. In May 2016, 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 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 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. For more information, please read “Item 18 – Financial Statements: Note 4 – 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

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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 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, interest rate swaptions, 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 11c – Related Party Transactions” and “Note 12 – Derivative Instruments and Hedging Activities.” 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, 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 consolidated Suezmax tankers, one of our consolidated LPG carriers and certain of our LNG and LPG carriers in our equity accounted joint ventures 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 these charters 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 would not result in our receiving less than the fixed-hire rate, our results of operations and cash flow from operations would be influenced by the variable component of the charters in periods where the spot market rates exceed the threshold amounts. Two of our 52%-owned LNG carriers in the Teekay LNG-Marubeni Joint Venture, the Magellan Spirit and Methane Spirit, and certain of our LPG carriers in our 50%-owned Exmar LPG Joint Venture are trading in the spot market.

Year Ended December 31, 2016 versus Year Ended December 31, 2015

Liquefied Gas Segment

As at December 31, 2016, our liquefied gas segment fleet, including newbuildings, included 50 LNG carriers and 29 LPG/Multigas carriers, in which our interests ranged from 20% to 100%. However, the table below only includes the 15 LNG carriers and six LPG/Multigas 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 nine LNG carrier newbuildings under construction and the following vessels accounted for under the equity method: (i)

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the six MALT LNG Carriers in which we have a 52% ownership interest, (ii) four LNG carriers relating to the Angola LNG project (or the Angola LNG Carriers) in which we have a 33% ownership interest, (iii) four LNG carriers relating to our joint venture with QGTC Nakilat (1643-6) Holdings Corporation (or the RasGas 3 LNG Carriers) in which we have a 40% ownership interest, (iv) four LNG carrier newbuildings in the BG Joint Venture in which we have a 30% ownership interest in two LNG carrier newbuildings and a 20% ownership interest in the other two LNG carrier newbuildings, (v) six LNG carrier newbuildings relating to the Yamal LNG Joint Venture in which we have a 50% ownership interest, (vi) two LNG carriers in which we have ownership interests ranging from 49% to 50% with Exmar (or the Exmar LNG Carriers), (vii) 19 LPG carriers and four LPG carrier newbuildings (or the Exmar LPG Carriers) relating to our 50/50 joint venture with Exmar, and (viii) the assets for the development of an LNG receiving and regasification terminal in Bahrain in which we have a 30% ownership interest (or the Bahrain LNG Joint Venture). The comparison of the results from vessels accounted for under the equity method are described below under Other Operating Results – Equity Income.

The following table compares our liquefied gas 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 liquefied gas segment:

(in thousands of U.S. Dollars, except revenue days, calendar-ship-days and percentages)	Year Ended December 31,				% Change
	2016		2015
Voyage revenues	336,530		305,056		10.3
Voyage (expenses) recoveries	(449	)	203		321.2
Net voyage revenues	336,081		305,259		10.1
Vessel operating expenses	(66,087	)	(63,344	)	4.3
Depreciation and amortization	(80,084	)	(71,323	)	12.3
General and administrative expenses(1)	(15,310	)	(19,392	)	(21.0	)
Income from vessel operations	174,600		151,200		15.5
Operating Data:
Revenue Days (A)	7,374		6,888		7.1
Calendar-Ship-Days (B)	7,440		6,935		7.3
Utilization (A)/(B)	99.1	%	99.3	%

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

Our liquefied gas segment’s total calendar-ship-days increased by 7.3% to 7,440 days in 2016 from 6,935 days in 2015, as a result of the deliveries to us of the Creole Spirit and Oak Spirit on February 18, 2016 and July 19, 2016, respectively. During 2016, one of our consolidated vessels in this segment was off-hire for a scheduled in-water survey, the Creole Spirit was off-hire for 32 days for repairs covered under warranty, and the Creole Spirit and Oak Spirit's time-charter contracts commenced in February and August 2016, respectively, compared to one consolidated vessel in this segment being off-hire for 47 days in 2015. As a result, our utilization decreased to99.1% for 2016, compared to 99.3% in 2015.

Net Voyage Revenues. Net voyage revenues increased during 2016 compared to 2015, primarily as a result of:

•an increase of $22.4 million as a result of the Creole Spirit charter contract commencing in February 2016;

•an increase of $12.7 million as a result of the Oak Spirit charter contract commencing in August 2016;

•an increase of $2.2 million due to the Polar Spirit being off-hire for 47 days in 2015 for a scheduled dry docking; and

• an increase of $2.1 million relating to amortization of in-process contracts recognized into revenue with respect to our shipbuilding and site supervision contract associated with the four LNG newbuilding carriers in the BG Joint Venture (however, we had a corresponding increase in vessel operating expenses);

partially offset by:

• a decrease of $4.5 million due to uncertainty of collection for outstanding hire receivable relating to our six LPG carriers on charter to Skaugen in the fourth quarter of 2016; and

• a decrease of $2.0 million for our Spanish LNG carriers primarily due to a performance claim related to the Hispania Spirit recorded in the fourth quarter of 2016 and the Catalunya Spirit being off-hire for six days in the first quarter of 2016 for a scheduled in-water survey.

Vessel Operating Expenses. Vessel operating expenses increased during 2016 compared to 2015, primarily as a result of:

• an increase of $3.9 million due to the delivery of the Creole Spirit in February 2016;

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• an increase of $2.5 million due to the delivery of the Oak Spirit in July 2016; and

• an increase of $2.1 million in relation to our agreement to provide shipbuilding and site supervision costs associated with the four LNG newbuilding carriers in the BG Joint Venture;

partially offset by:

• a decrease of $3.8 million due to the charterer, Teekay Corporation, not being able to find employment for the Arctic Spirit and Polar Spirit for a significant portion of 2016, which permitted us to operate the vessels with a reduced average number of crew on board and reduce the amount of repair and maintenance activities performed; and

• a decrease of $1.3 million relating to crew training costs for our LNG carrier newbuildings as a result of the deliveries of the Creole Spirit and Oak Spirit in 2016.

Depreciation and Amortization. Depreciation and amortization increased by $8.8 million in 2016 compared to 2015 primarily due to the deliveries of the Creole Spirit and Oak Spirit in February and July 2016, respectively.

Conventional Tanker Segment

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:

(in thousands of U.S. Dollars, except revenue days, calendar-ship-days and percentages)	Year Ended December 31,				% Change
	2016		2015
Voyage revenues	59,914		92,935		(35.5	)
Voyage expenses	(1,207	)	(1,349	)	(10.5	)
Net voyage revenues	58,707		91,586		(35.9	)
Vessel operating expenses	(22,503	)	(30,757	)	(26.8	)
Depreciation and amortization	(15,458	)	(20,930	)	(26.1	)
General and administrative expenses(1)	(3,189	)	(5,726	)	(44.3	)
Write-down and loss on sale of vessels	(38,976	)	—		100.0
Restructuring charges	—		(4,001	)	(100.0	)
(Loss) income from vessel operations	(21,419	)	30,172		(171.0	)
Operating Data:
Revenue Days (A)	2,439		2,884		(15.4	)
Calendar-Ship-Days (B)	2,439		2,920		(16.5	)
Utilization (A)/(B)	100.0	%	98.8	%

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

Our conventional tanker segment's total calendar ship days decreased by 16.5% to 2,439 days in 2016 from 2,920 days in 2015 primarily as a result of the sales of the Bermuda Spirit and Hamilton Spirit in April 2016 and May 2016, respectively. During 2016, none of our vessels in this segment were off-hire for scheduled dry dockings, compared to two of our vessels in this segment being off-hire for a total of 24 days for scheduled dry dockings and another vessel being off-hire for 12 days relating to a crew work stoppage during 2015. As a result, our utilization increased to 100.0% in 2016 compared to 98.8% in 2015.

Net Voyage Revenues. Net voyage revenues decreased during 2016 compared to 2015, primarily as a result of:

• a decrease of $14.2 million due to the sales of the Bermuda Spirit and Hamilton Spirit in April 2016 and May 2016, respectively;

• a decrease of $4.4 million due to lower revenues earned by the Teide Spirit relating to the profit-sharing agreement between us and CEPSA;

• a decrease of $4.2 million in pass-through vessel operating expenses due to the change in crew nationality on board the Alexander Spirit in September 2015 (however, we had a corresponding decrease in vessel operating expenses);

• a decrease of $4.0 million due to our recovery during 2015 of crew restructuring charges in that amount from the charterer of the Alexander Spirit, who had requested we change the crew nationality on board the vessel (however, because we had a corresponding increase in our restructuring charges, this increase in revenue did not affect our cash flow or net income);

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• a decrease of $3.6 million relating to the European Spirit, African Spirit and Asian Spirit upon the charterer exercising its one-year extension options in September 2015, November 2015 and January 2016, respectively, at lower charter rates than the original charter rates; and

• a decrease of $2.8 million due to lower revenues earned by the Toledo Spirit in 2016 relating to the profit-sharing agreement between us and CEPSA (however, we had a corresponding decrease in our realized loss on our associated derivative contract with Teekay Corporation; therefore, this decrease and future increases or decreases related to this agreement did not and will not affect our cash flow or net income).

Vessel Operating Expenses. Vessel operating expenses decreased during 2016 compared to 2015 primarily as a result of:

• a decrease of $4.2 million in crew wages due to the change in crew nationality on board the Alexander Spirit in September 2015; and

•a decrease of $3.6 million due to the sales of the Bermuda Spirit and Hamilton Spirit in April 2016 and May 2016, respectively.

Depreciation and Amortization. Depreciation and amortization decreased by $5.5 million during 2016 compared to 2015, primarily as a result of Centrofin exercising its purchase options on the Bermuda Spirit and Hamilton Spirit in February 2016 and March 2016, respectively, and our subsequent sales of these vessels.

Write-down and loss on sale of vessels. During 2016, we incurred a loss on sale of vessels of $27.4 million upon Centrofin exercising its purchase options on the Bermuda Spirit and Hamilton Spirit in February 2016 and March 2016, respectively. In addition, we incurred a loss of $11.5 million when we agreed to sell the Asian Spirit in November 2016. This vessel was classified as held for sale at December 31, 2016.

Restructuring Charges. The restructuring charges of $4.0 million for 2015 related to seafarer severance payments made as a result of the request by the charterer to change the crew nationality on board the Alexander Spirit (however, we had a corresponding increase in our net voyage revenues as the charterer is responsible for all the severance payments; therefore, this increase in restructuring expense did not affect our cash flow or net income).

Other Operating Results

General and Administrative Expenses. General and administrative expenses decreased to $18.5 million for 2016, from $25.1 million for 2015, primarily due to reimbursement from the Bahrain Joint Venture in 2016 of our proportionate share of certain costs we paid, including pre-operation, engineering and financing-related expenses, upon the joint venture securing debt financing in the fourth quarter of 2016. A reduced amount of business development activities in 2016 also contributed to the decrease in general and administrative expenses.

Equity Income. Equity income decreased to $62.3 million for 2016, from $84.2 million for 2015, as set forth in the table below:

(in thousands of U.S. Dollars)	Year Ended December 31,
	Angola LNG Carriers		Exmar LNG Carriers		Exmar LPG Carriers		MALT LNG Carriers		RasGas 3 LNG Carriers		Other		Total Equity Income
2016	15,713		9,038		13,674		4,503		19,817		(438	)	62,307
2015	16,144		9,332		32,733		4,620		21,527		(185	)	84,171
Difference	(431	)	(294	)	(19,059	)	(117	)	(1,710	)	(253	)	(21,864	)

The $0.4 milliondecrease 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.

Equity income from our 50% ownership interest in Exmar LPG BVBA decreased by $19.1 million primarily due to: more vessels trading in the spot market in 2016 compared to higher fixed rates earned in 2015; the redelivery of the in-chartered vessel Odin back to its owner in November 2015; and the write-down of the Brugge Venture recorded in the fourth quarter of 2016, which was sold in January 2017. These decreases were partially offset by the deliveries to the joint venture of four LPG carrier newbuildings between September 2015 and November 2016.

The slight decrease in equity income from our 52% investment in the MALT LNG Carriers was primarily due to the deferral during 2016 (and which will continue through 2017) of a significant portion of the charter payments for the Marib Spirit and Arwa Spirit LNG carriers chartered to support the LNG plant in Yemen, and a lower charter rate on the redeployment of the Methane Spirit after its original time-charter contract expired in March 2015. These decreases were partially offset by the settlement payment awarded to us in 2016 for the disputed contract termination relating to the Magellan Spirit, and unscheduled off-hire relating to the Woodside Donaldson to repair a damaged propulsion motor in January 2015.

The $1.7 milliondecrease 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.

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Interest Expense. Interest expense increased to $58.8 million for 2016, from $43.3 million for 2015. Interest expense primarily reflects interest incurred on our long-term debt and capital lease obligations. This increase was primarily the result of:

• an increase of $8.0 million relating to interest incurred on the capital lease obligation for the Creole Spirit commencing upon its delivery in February 2016;

• an increase of $4.1 million relating to interest incurred on the capital lease obligation for the Oak Spirit commencing upon its delivery in July 2016; and

• a net increase of $3.3 million due to the combined effect of an increase in LIBOR on our floating-rate debt, and lower principal balances due to debt repayments during 2016 and 2015.

Realized and Unrealized Loss on Non-Designated Derivative Instruments. Net realized and unrealized losses on non-designated derivative instruments decreased to $7.2 million for 2016, from $20.0 million for 2015 as set forth in the table below.

(in thousands of U.S. Dollars)	Year Ended December 31,
	2016						2015
	Realized gains (losses)		Unrealized gains (losses)		Total		Realized gains (losses)		Unrealized gains (losses)		Total
Interest rate swap agreements	(25,940	)	15,627		(10,313	)	(28,968	)	14,768		(14,200	)
Interest rate swaption agreements	—		(164	)	(164	)	—		(783	)	(783	)
Toledo Spirit time-charter derivative	(654	)	3,970		3,316		(3,429	)	(1,610	)	(5,039	)
	(26,594	)	19,433		(7,161	)	(32,397	)	12,375		(20,022	)

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.

The projected forward average tanker rates in the tanker market decreased at December 31, 2016 compared to the beginning of 2016, which resulted in $4.0 million of unrealized gains on our Toledo Spirit time-charter derivative. 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 Spirit as 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.

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.

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Foreign Currency Exchange Gains. Foreign currency exchange gains were $5.3 million and $13.9 million for 2016 and 2015, respectively. These foreign currency exchange gains are due primarily to the relevant period-end revaluation of our NOK-denominated debt and our Euro-denominated term loans for financial reporting purposes into U.S. Dollars, net of the realized and unrealized gains and losses on our cross-currency swaps. Gains on NOK-denominated and Euro-denominated monetary liabilities reflect a stronger U.S. Dollar against the NOK and Euro on the date of revaluation or settlement compared to the rate in effect at the beginning of the period. Losses on NOK-denominated and Euro-denominated monetary liabilities reflect a weaker U.S. Dollar against the NOK and Euro on the date of revaluation or settlement compared to the rate in effect at the beginning of the period.

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.

Income Tax Expense. Income tax expense decreased to $(1.0) million for 2016, from $(2.7) million for 2015, primarily as a result of additional income taxes in 2015 from the termination of capital lease obligations and refinancing in the Teekay Nakilat Joint Venture.

Other Comprehensive Income (Loss) (or OCI). OCI was $2.8 million in 2016 compared to $(0.6) million in 2015, due to changes in the valuation of interest rate swaps accounted for using hedge accounting within the consolidated Teekay Nakilat Joint Venture and certain of our equity accounted joint ventures. During 2016, we recognized unrealized gains on our interest rate swaps accounted for using hedge accounting relating to increases in long-term forward LIBOR benchmark interest rates, relative to the beginning of 2016. During 2015, we recognized unrealized losses on our interest rate swaps accounted for using hedge accounting relating to decreases in long-term forward LIBOR benchmark interest rates, relative to the beginning of 2015.

Year Ended December 31, 2015 versus Year Ended December 31, 2014

Liquefied Gas Segment

As at December 31, 2015, our liquefied gas segment fleet, including newbuildings, included 50 LNG carriers and 29 LPG/Multigas carriers, in which our interests ranged from 20% to 100%. However, the table below only includes 13 LNG carriers and six LPG/Multigas carriers. The table excludes 11 LNG carrier newbuildings under construction and the following vessels accounted for under the equity method: (i) the six MALT LNG Carriers in which we have a 52% ownership interest, (ii) the four Angola LNG Carriers in which we have a 33% ownership interest, (iii) the four RasGas 3 LNG Carriers in which we have a 40% ownership interest, (iv) four LNG carrier newbuildings in the BG Joint Venture in which we have a 30% ownership interest in two LNG carrier newbuildings and a 20% ownership interest in the other two LNG carrier newbuildings, (v) six LNG carrier newbuildings relating to the Yamal LNG Joint Venture in which we have a 50% ownership interest, (vi) the two Exmar LNG Carriers in which we have ownership interests ranging from 49% to 50% and (vii) 16 LPG carriers and seven LPG carrier newbuildings (or the Exmar LPG Carriers) relating to our 50/50 joint venture with Exmar. The comparison of the results from vessels accounted for under the equity method are described below under Other Operating Results – Equity Income.

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:

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(in thousands of U.S. Dollars, except revenue days, calendar-ship-days and percentages)	Year Ended December 31,				% Change
	2015		2014
Voyage revenues	305,056		307,426		(0.8	)
Voyage recoveries (expenses)	203		(1,768	)	(111.5	)
Net voyage revenues	305,259		305,658		(0.1	)
Vessel operating expenses	(63,344	)	(59,087	)	7.2
Depreciation and amortization	(71,323	)	(71,711	)	(0.5	)
General and administrative expenses(1)	(19,392	)	(17,992	)	7.8
Income from vessel operations	151,200		156,868		(3.6	)
Operating Data:
Revenue Days (A)	6,888		6,534		5.4
Calendar-Ship-Days (B)	6,935		6,619		4.8
Utilization (A)/(B)	99.3	%	98.7	%

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

Our liquefied gas segment’s total calendar-ship-days increased by 5% to 6,935 days in 2015 from 6,619 days in 2014, as a result of the acquisition and delivery of the Norgas Napa on November 13, 2014. During 2015, the Polar Spirit was off-hire for 47 days for a scheduled dry docking, compared to the Galicia Spirit, Madrid Spirit and Polar Spirit being off-hire for 28, 24 and 6 days, respectively, for scheduled dry dockings and an in-water survey in 2014. As a result, our utilization increased to 99.3% for 2015, compared to 98.7% for 2014.

Net Voyage Revenues. Net voyage revenues decreased during 2015 compared to 2014, primarily as a result of:

• a decrease of $10.6 million due to the effect on our Euro-denominated revenues from the depreciation of the Euro against the U.S. Dollar compared to 2014;

• a decrease of $2.4 million due to the Polar Spirit being off-hire for 47 days in 2015 for a scheduled dry docking, partially offset by the Polar Spirit being off-hire for six days in 2014 for a scheduled in-water survey and a further eight days of unscheduled off-hire in 2014 for repairs;

• a decrease of $1.2 million due to operating expense flow-through adjustments under our charter provisions for the Tangguh Hiri and Tangguh Sago relating to timing of main engine overhauls (however, we had a corresponding decrease in vessel operating expenses); and

• a decrease of $0.7 million due to a performance claim on the Madrid Spirit in 2015;

partially offset by:

• an increase of $4.8 million relating to amortization of in-process contracts recognized into revenue with respect to our shipbuilding and site supervision contract associated with the four LNG newbuilding carriers in the BG Joint Venture (however, we had a corresponding increase in vessel operating expenses);

• an increase of $3.2 million as a result of the acquisition and delivery of the Norgas Napa in November 2014;

• an increase of $2.6 million due to the Galicia Spirit being off-hire for 28 days in 2014 for a scheduled dry docking;

• an increase of $2.4 million relating to 18 days of unscheduled off-hire in 2014 due to repairs required for one of our LNG carriers; and

• an increase of $1.9 million due to the Madrid Spirit being off-hire for 24 days in 2014 for a scheduled dry docking.

Vessel Operating Expenses. Vessel operating expenses increased during 2015 compared to 2014, primarily as a result of:

• an increase of $4.8 million in relation to our agreement to provide shipbuilding and site supervision costs associated with the four LNG newbuilding carriers in the BG Joint Venture;

• an increase of $1.6 million in ship management fees for our LNG carriers compared to 2014; and

• an increase of $0.6 million relating to costs to train our crew for two LNG carrier newbuildings that are expected to deliver in the first half of 2016;

partially offset by:

• a decrease of $1.3 million in crew wages due to favorable foreign exchange impacts on crew wages denominated in foreign currencies relating to certain of our LNG carriers; and

• a decrease of $1.2 million as a result of timing of main engine overhauls on the Tangguh Hiri and Tangguh Sago.

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Conventional Tanker Segment

As at December 31, 2015, our fleet included seven Suezmax-class double-hulled conventional crude oil tankers and one Handymax product tanker, six of which we owned and two of which we leased under capital leases. All of our conventional tankers operate under fixed-rate charters. The Bermuda Spirit’s and Hamilton Spirit’s time-charter contracts were amended in the fourth quarter of 2012 to reduce the daily hire rate on each by $12,000 per day through September 30, 2014. However, during this renegotiated period, Suezmax tanker spot rates exceeded the renegotiated charter rate, and the charterer paid us the excess amount up to a maximum of the original charter rate, as specified in the amended charter contracts. The impact of the change in hire rates is not fully reflected in the table below as the change in the lease payments is being recognized on a straight-line basis over the term of the lease.

In addition, CEPSA, the charterer and owner of our conventional vessels under capital lease, sold the Algeciras Spirit in February 2014 and the Huelva Spirit in August 2014, and on redelivery of the vessels to CEPSA, the charter contracts with us were terminated. Upon sale of the vessels, we were not required to pay the balance of the capital lease obligations, as the vessels under capital lease were returned to the owner and the capital lease obligations were concurrently extinguished. When the vessels were sold to a third party, we were subject to seafarer severance related costs.

The following table compares our conventional tanker 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 conventional tanker segment:

(in thousands of U.S. Dollars, except revenue days, calendar-ship-days and percentages)	Year Ended December 31,				% Change
	2015		2014
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).

Our conventional segment’s total calendar-ship-days decreased by 9% to 2,920 days in 2015 from 3,202 days in 2014, as a result of the sales of the Algeciras Spirit and Huelva Spirit in February 2014 and August 2014, respectively. During 2015, the Toledo Spirit was off-hire for 22 days for a scheduled dry docking, compared to the Bermuda Spirit, Hamilton Spirit and Teide Spirit being off-hire for 27, 24 and 31 days, respectively, for scheduled dry dockings in 2014. As a result, our utilization increased to 98.8% for 2015, compared to 97.5% for 2014.

Net Voyage Revenues. Net voyage revenues decreased during 2015 compared to 2014, primarily as a result of:

• a decrease of $7.9 million due to the sales of the Algeciras Spirit and Huelva Spirit in February 2014 and August 2014, respectively;

• a decrease of $3.0 million due to higher revenues recognized in the same periods last year by the Bermuda Spirit and Hamilton Spirit relating to an agreement between us and the charterer that ended in September 2014, which resulted in us recognizing additional revenues in 2014 when Suezmax tanker spot rates exceeded a certain amount;

• a decrease of $1.0 million in flow-through operating expenses due to the change in crew nationality on board the Alexander Spirit in September 2015 (however, we had a corresponding decrease in vessel operating expenses);

• a decrease of $0.9 million due to the Alexander Spirit being off-hire for 12 days in the third quarter of 2015 due to a crew work stoppage and as a result of the depreciation of the Australian Dollar (or AUD) against the U.S. Dollar compared to 2014, affecting our AUD-denominated revenues;

• a decrease of $0.6 million due to the Toledo Spirit being off-hire for 22 days for a scheduled dry docking in 2015; and

• a decrease of $0.6 million due to lower revenues from the European Spirit and Asian Spirit upon the charterer exercising its one-year option in September and November 2015, respectively, with the option rate being lower than the original charter rate;

partially offset by:

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• an increase of $4.0 million due to our recovery during 2015 of crew restructuring charges from the charterer of the Alexander Spirit, who had requested we change the crew nationality on board the vessel, which resulted in seafarer severance payments (however, as we had a corresponding increase in our restructuring charges, this increase in revenue did not affect our cash flow or net income);

• an increase of $3.7 million due to higher revenues earned by the Teide Spirit in 2015 relating to the agreement between us and CEPSA;

• an increase of $2.6 million due to higher revenues earned by the Toledo Spirit in 2015 relating to the agreement between us and CEPSA (however, we had a corresponding increase in our realized loss on our associated derivative contract with Teekay Corporation; therefore, this increase and future increases or decreases related to this agreement did not and will not affect our cash flow or net income);

• an increase of $0.9 million due to the Teide Spirit being off-hire for 31 days for a scheduled dry docking in 2014; and

• an increase of $0.7 million due to the Bermuda Spirit being off-hire for 27 days in 2014 and the Hamilton Spirit being off-hire for 24 days in 2014 for scheduled dry dockings.

Vessel Operating Expenses. Vessel operating expenses decreased during 2015 compared to 2014 primarily as a result of:

• a decrease of $3.0 million due to the sales of the Algeciras Spirit and Huelva Spirit in February 2014 and August 2014, respectively;

• a decrease of $1.6 million in crew wages due to favorable foreign exchange impacts on crew wages denominated in foreign currencies; and

• a decrease of $1.0 million in crew wages due to the change in crew nationality on board the Alexander Spirit in September 2015.

Depreciation and Amortization. Depreciation and amortization decreased by $1.5 million during 2015 compared to 2014, as a result of the sales of the Algeciras Spirit and Huelva Spirit in February 2014 and August 2014, respectively.

Restructuring Charges. The restructuring charges of $4.0 million for 2015 related to seafarer severance payments made as a result of the request by the charterer to change the crew nationality on board the Alexander Spirit (however, we had a corresponding increase in our net voyage revenues as the charterer is responsible for all the severance payments; therefore, this increase in restructuring expense did not affect our cash flow or net income). The restructuring charges of $2.0 million for 2014 related to the seafarer severance payments upon CEPSA’s sale of our vessel under capital lease, the Huelva Spirit, in August 2014.

Other Operating Results

General and Administrative Expenses. General and administrative expenses increased to $25.1 million for 2015, from $23.9 million for 2014, primarily due to a greater amount of business development, commercial activities, and legal and tax services provided to us by Teekay Corporation to support our growth, and higher advisory fees incurred to support our business development and commercial activities.

Equity Income. Equity income decreased to $84.2 million for 2015, from $115.5 million for 2014, as set forth in the table below:

(in thousands of U.S. Dollars)	Year Ended December 31,
	Angola LNG Carriers	Exmar LNG Carriers		Exmar LPG Carriers		MALT LNG Carriers		RasGas 3 LNG Carriers	Other		Total Equity Income
2015	16,144	9,332		32,733		4,620		21,527	(185	)	84,171
2014	3,472	10,651		44,114		36,805		20,806	(370	)	115,478
Difference	12,672	(1,319	)	(11,381	)	(32,185	)	721	185		(31,307	)

The $12.7 million increase for 2015 in our 33% investment in the four Angola LNG Carriers was primarily due to unrealized gains on non- designated derivative instruments in 2015 as a result of long-term LIBOR benchmark interest rates increasing for interest rate swaps compared to unrealized losses on non-designated derivative instruments last year, and an increase in voyage revenues upon amending the charter contract in the second quarter of 2015 to allow for drydocking and operating costs to pass-through to the charterer, retroactive to the beginning of the charter contract.

The $1.3 million decrease for 2015 in 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 $11.4 million decrease for 2015 in equity income from our 50% ownership interest in Exmar LPG BVBA was primarily due to the gains on the sales of the Flanders Tenacity, Eeklo and Flanders Harmony, which were sold during the second and third quarters of 2014, a loss on sale of the Temse (formerly Kemira Gas) in 2015, redelivery of the in-chartered vessel Odin back to its owner in November 2015, and hedge ineffectiveness of interest rate swaps in 2015. These decreases were partially offset by higher contracted charter rates from five LPG carrier newbuildings which delivered from September 2014 to September 2015, net of four disposed of LPG carriers during 2014, and a loss on the sale of the Temse in the first quarter of 2014.

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The $32.2 million decrease for 2015 in our 52% investment in the MALT LNG Carriers was primarily due to fewer revenue days compared to 2014 as a result of the disputed termination of the charter contract and unscheduled off-hire days relating to a grounding incident for the Magellan Spirit in the first quarter of 2015, the scheduled expiration of the charter contract for the Methane Spirit in March 2015 and the unscheduled off-hire days relating to the Woodside Donaldson to repair a damaged propulsion motor in January 2015.

The $0.7 million increase for 2015 in our 40% investment in the RasGas 3 LNG Carriers primarily resulted from lower interest expense due to principal repayments made during 2014 and 2015.

Interest Expense. Interest expense decreased to $43.3 million for 2015, from $60.4 million for 2014. Interest expense primarily reflects interest incurred on our long-term debt and capital lease obligations. This decrease was primarily the result of:

• a decrease of $5.1 million due to an increase in capitalized interest as a result of our exercising three newbuildings options with Daewoo Shipbuilding & Marine Engineering Co. (or DSME) in December 2014, and entering into an additional newbuilding agreement with DSME in February 2015 and two additional newbuilding agreements with HHI in June 2015;

• a decrease of $3.6 million due to a lower interest rate on debt facilities and elimination of interest on capital lease obligations relating to our LNG carriers in the Teekay Nakilat Joint Venture upon debt refinancing and termination of capital lease obligations in December 2014;

• a decrease of $3.1 million relating to accelerated amortization of Teekay Nakilat Joint Venture’s deferred debt issuance cost upon completion of its debt refinancing in December 2014;

• a decrease of $2.6 million due to lower interest on capital lease obligations associated with the sales of the Algeciras Spirit and Huelva Spirit conventional tankers in February 2014 and August 2014, respectively;

• a decrease $2.6 million relating to capitalized interest on the advances we made to the Yamal LNG Joint Venture in July 2014 to fund our proportionate share of the joint venture’s newbuilding installments; and

• a decrease of $1.7 million due to the impact of a decrease in EURIBOR and depreciation of the Euro against the U.S. Dollar on our Euro-denominated debt facilities;

partially offset by:

• an increase of $0.8 million relating to a new debt facility used to fund the delivery of the Wilpride in April 2014.

Realized and Unrealized Loss on Non-DesignatedDerivative Instruments. Net realized and unrealized losses on non-designated derivative instruments decreased to $20.0 million for 2015, from $44.7 million for 2014 as set forth in the table below.

(in thousands of U.S. Dollars)	Year Ended December 31,
	2015						2014
	Realized gains (losses)		Unrealized gains (losses)		Total		Realized gains (losses)		Unrealized gains (losses)		Total
Interest rate swap agreements	(28,968	)	14,768		(14,200	)	(39,406	)	4,204		(35,202	)
Interest rate swaption agreements	—		(783	)	(783	)	—		—		—
Interest rate swap agreements termination	—		—		—		(2,319	)	—		(2,319	)
Toledo Spirit time-charter derivative	(3,429	)	(1,610	)	(5,039	)	(861	)	(6,300	)	(7,161	)
	(32,397	)	12,375		(20,022	)	(42,586	)	(2,096	)	(44,682	)

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

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. 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

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Spirit as 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.

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 2014, we recognized unrealized losses on our interest rate swap agreements associated with our Euro-denominated long-term debt. This resulted from $23.5 million of unrealized losses relating to decreases in long-term forward EURIBOR benchmark interest rates, relative to the beginning of 2014, partially offset by transfers of $9.3 million of previously recognized unrealized losses to realized losses related to actual cash settlements of our interest rate swaps.

The projected average tanker rates in the tanker market at December 31, 2014 increased compared to the beginning of 2014, which resulted in $6.3 million of unrealized losses on our Toledo Spirit time-charter derivative in 2014.

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.

Foreign Currency Exchange Gains. Foreign currency exchange gains were $13.9 million and $28.4 million for 2015 and 2014, respectively. These foreign currency exchange gains, substantially all of which were unrealized, are due primarily to the relevant period-end revaluation of our NOK-denominated debt and our Euro-denominated term loans for financial reporting purposes into U.S. Dollars, net of the realized and unrealized gains and losses on our cross-currency swaps. Gains on NOK-denominated and Euro-denominated monetary liabilities reflect a stronger U.S. Dollar against the NOK and Euro on the date of revaluation or settlement compared to the rate in effect at the beginning of the period. Losses on NOK-denominated and Euro-denominated monetary liabilities reflect a weaker U.S. Dollar against the NOK and Euro on the date of revaluation or settlement compared to the rate in effect at the beginning of the period.

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 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.

For 2014, foreign currency exchange gains 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. These gains were partially offset by realized losses of ($2.2) million on settlements of our cross currency swaps and unrealized losses of ($51.8) million on our cross-currency swaps primarily due to depreciation of long-term NOK forward exchange rates relative to the beginning of 2015.

Other Income. Other income increased by $0.7 million for 2015 compared to 2014 primarily due to amortization of additional guarantee liabilities in 2015 relating to our guarantees of Exmar LNG Joint Venture’s and Exmar LPG Joint Venture’s debt upon refinancing in 2015.

Income Tax Expense. Income tax expense decreased to $2.7 million for 2015, from $7.6 million for 2014, primarily as a result of higher income taxes in 2014 from the termination of capital lease obligations and refinancing in the Teekay Nakilat Joint Venture.

Other Comprehensive Income (Loss). OCI decreased to a loss of ($0.6) million for 2015, from a loss of ($1.5) million for 2014, due to lower unrealized losses on the valuation of interest rate swaps accounted for using hedge accounting within the equity accounted Teekay LNG-Marubeni Joint Venture, Exmar LNG Joint Venture, and Exmar LPG Joint Venture.

Liquidity and Cash Needs

Our business model is to employ our vessels on fixed-rate contracts primarily with large energy companies and their transportation subsidiaries. Prior to the fourth quarter of 2015, the operating cash flow generated by our vessels each quarter, excluding a reserve for maintenance capital expenditures and debt repayments, 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.

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Our primary liquidity needs for 2017 through 2018 include payment of our quarterly distributions, including distributions on our common units and Series A Preferred Units, operating expenses, dry-docking expenditures, debt service costs, scheduled repayments of long-term debt, bank debt maturities, committed capital expenditures and the funding of general working capital requirements. We anticipate that our primary sources of funds for our short-term liquidity needs will be cash flows from operations, proceeds from debt financings, proceeds from equity offerings, and dividends from our equity accounted joint ventures. For 2017 through 2018, we expect that our existing liquidity, combined with the cash flow we expect to generate from our operations and receive as dividends from our equity accounted joint ventures will be sufficient to finance a portion of our liquidity needs, including the equity portion of our committed capital expenditures. Our remaining liquidity needs include the requirement to secure debt financing for an adequate portion of our committed capital expenditures, to refinance our loan facilities maturing in 2017 to 2018 and our NOK-denominated bonds due in 2018, to possibly fund the potential exposure relating to the lease arrangements that the Teekay Nakilat Joint Venture had previously entered into (please read “Item 1 - Financial Statements: Note 13c - Commitments and Contingencies"). We already have committed debt financing in place for the following vessels and projects: three of our LNG carriers under construction that will be chartered to a wholly-owned subsidiary of Royal Dutch Shell PLC; the Torben Spirit, which was delivered to us on February 28, 2017 and chartered out to a major energy company; the vessels under construction in the BG Joint Venture and the Exmar LPG Joint Venture; and the assets of the Bahrain LNG Joint Venture formed for the development of an LNG receiving and regasification terminal in Bahrain. We are actively seeking debt financings for our other five wholly-owned LNG carriers under construction, the six LNG carriers under construction for the Yamal LNG Joint Venture and for the other requirements described above.

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 2017 to 2018. 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 our ability to raise debt or equity financing through public or private offerings.

Our revolving credit facilities and term loans are described in Item 1 - Financial Statements: Note 9 - Long-Term Debt. They contain covenants and other restrictions typical of debt financing secured by vessels, which restrict the vessel-owning subsidiaries from: incurring or guaranteeing indebtedness; changing ownership or organizational structure, including mergers, consolidations, liquidations and dissolutions; 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 new 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 our revolving credit facilities and term loans, which would have a significant impact on our short-term liquidity requirements. As at December 31, 2016, we and our affiliates were in compliance with all covenants relating to our credit facilities and term loans. As at December 31, 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 at December 31, 2016, our consolidated cash and cash equivalents were $126.1 million, compared to $102.5 million at December 31, 2015. Our total liquidity, which consists of cash, cash equivalents and undrawn credit facilities, was $369.8 million as at December 31, 2016, compared to $232.5 million as at December 31, 2015. The increase in total consolidated liquidity was primarily due to proceeds of $355.3 million from our sale-leaseback financing transactions in February 2016 and July 2016 relating to the Creole Spirit and Oak Spirit, respectively, proceeds from the issuance of our Series A Preferred Units in October 2016 and the issuance of our NOK bonds net of buyback, in October 2016, and reduced quarterly distributions in 2016.

As at December 31, 2016, we had a working capital deficit of $29.0 million, which is primarily the result of $47.3 million of our NOK bonds maturing in May 2017, and $26.0 million of current capital lease obligations relating to one Suezmax tanker under which the owner has the option to require us to purchase the vessels. We expect to manage our working capital deficit primarily with net operating cash flows, dividends from our equity accounted joint ventures, debt refinancings and, to a lesser extent, existing undrawn revolving credit facilities. As at December 31, 2016, we had undrawn revolving credit facilities of $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 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.

Cash Flows. The following table summarizes our cash flow for the periods presented:

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(in thousands of U.S. Dollars)	Year Ended December 31,
	2016		2015		2014
Net cash flow from operating activities	166,492		239,729		191,097
Net cash flow (used for) from financing activities	(154,925	)	(84,357	)	100,069
Net cash flow from (used for) investing activities	12,098		(212,530	)	(271,008	)

Operating Cash Flows. Net cash flow from operating activities decreased to $166.5 million in 2016 from $239.7 million in 2015, primarily due to a lower aggregate amount of dividends received from our equity accounted joint ventures, the sales of the Bermuda Spirit and Hamilton Spirit in April 2016 and May 2016, respectively, an increase in restricted cash relating to operating activities, reduced revenues in the fourth quarter of 2016 for uncollected hire invoices relating to our six LPG carriers on charter to Skaugen, lower revenues earned by the Teide Spirit relating to the profit-sharing agreement between us and CEPSA, and lower charter rates on the European Spirit, African Spirit and Asian Spirit. These decreases were partially offset by the commencement of charter contracts for the Creole Spirit and Oak Spirit in February 2016 and August 2016, respectively, fewer off-hire days relating to scheduled dry dockings during 2016, the timing of collection and payments owing from and to our affiliates, and one additional calendar day in 2016.

Net cash flow from operating activities increased to $239.7 million in 2015 from $191.1 million in 2014 primarily due to a greater aggregate amount of dividends received from our equity accounted joint ventures, the acquisition of the Norgas Napa in November 2014, upfront hire payments received relating to our six LPG carriers chartered out to Skaugen, higher charter rates received from the Bermuda Spirit and Hamilton Spirit relating to an agreement between us and the charterer that ended in October 2014, a lower number of off-hire days relating to scheduled dry dockings during 2015 compared to 2014, and 18 days of unscheduled off-hire during the first quarter of 2014 due to repairs required for one of our LNG carriers. These increases were partially offset by the sales of the Algeciras Spirit and Huelva Spirit conventional tankers in February 2014 and August 2014, respectively, and the timing of payments to affiliates.

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 vessels’ maintenance schedule.

Our equity accounted joint ventures are generally required to distribute all available cash to their owners. However, the timing and amount of dividends from each of our equity accounted joint ventures may not necessarily coincide with the 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.

Financing Cash Flows. Net cash flow used for financing activities increased to $154.9 million in 2016 from $84.4 million in 2015 primarily as a result of a $563.3 million increase in scheduled repayments and prepayments of long-term debt in 2016 (primarily due to prepayments of revolving credit facilities, repurchase of a portion of our NOK bonds, and payments of term loans associated with the sales of the Bermuda Spirit and Hamilton Spirit in April 2016 and May 2016, respectively), and a $17.2 million increase in capital lease repayments due to the sale-leaseback financing transactions completed on the Creole Spirit and Oak Spirit in February 2016 and July 2016, respectively. These increases in cash flows used for financing activities were partially offset by a $210.1 million decrease in cash distributions paid to our common unitholders and General Partner due to the decrease in our quarterly distribution to $0.14 per common unit from $0.70 per common unit, higher net proceeds from the issuance of long-term debt of $181.3 million primarily relating to the issuance of NOK bonds in October 2016, $85.3 million higher proceeds from equity offerings due to the issuance of preferred units in 2016, and a decrease in restricted cash of $4.7 million for 2016 compared to a $30.3 million increase in restricted cash in 2015, primarily due to changes in the amount of margin call collateral related to our NOK cross-currency swaps.

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 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 to the acquisition of the RasGas II LNG Carriers under capital lease in the Teekay Nakilat Joint Venture in 2014, and $41.1 million less dividends paid to non-controlling interest. The increase in restricted cash in 2015 primarily 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 $448.9 million decrease in 2014 primarily related to the acquisition of the RasGas II LNG Carriers under capital lease in the Teekay Nakilat Joint Venture funded by our restricted cash in 2014. Cash distributions paid during 2015 increased to $255.5 million from $240.5 million for 2014 due to an increase in the number of common units eligible to receive cash distributions from us as a result of equity offerings during 2014 and 2015 and an increase in our quarterly cash distribution to $0.7000 per common unit from $0.6918 per common unit paid in the first quarter of 2015.

After December 31, 2016, cash distributions of $11.4 million were declared to holders of common units with respect to the fourth quarter of 2016, which was paid in February 2017. In addition, we paid cash dividends of $2.7 million on the preferred units in January 2017.

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Investing Cash 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 for investing activities decreased to $212.5 million in 2015 from $271.0 million in 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 wholly-owned LNG carrier newbuildings, $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 the Norgas Napa in November 2014, and $3.8 million relating to certain vessel upgrades.

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) certain of our subsidiaries to maintain restricted cash deposits. As at December 31, 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 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. As at December 31, 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, 2016:

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	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. Excludes expected interest payments of $28.8 million (2017), $20.8 million (2018), $13.6 million (2019), $12.5 million (2020), $10.2 million (2021) and $29.8 million (beyond 2021). Expected interest payments are based on the existing interest rates (fixed-rate loans) and LIBOR at December 31, 2016, plus margins on debt that has been drawn that 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 for 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. 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. For two of our four capital lease obligations, the lessor has the option to sell two Suezmax tankers under capital lease to us at any time during the remaining lease terms; however, in this table we have assumed the lessor will not exercise its right to sell the two Suezmax tankers to us until after the lease term expires, which is during the years 2017 and 2018. The purchase price for any 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 5 - Leases and Restricted Cash”.

3. We have corresponding leases whereby we are the lessor and expect to receive approximately $260.3 million under these leases from 2017 to 2029.

4. As of December 31, 2016, we have agreements for the construction of nine wholly-owned LNG carrier newbuildings, for which the estimated remaining costs for these newbuildings totaled $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 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 totaled $195.6 million as of December 31, 2016. However, as part of this agreement with Shell, we expect to recover $10.9 million of the shipbuilding supervision and crew training costs from Shell between 2017 and 2019 and the BG 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, 2016, our 50% share of the estimated remaining costs for these six newbuildings totaled $883.0 million. The Yamal LNG Joint Venture intends to secure debt financing for approximately 80% of the estimated fully built-up cost of the six newbuildings, which is estimated to 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 LNG receiving and regasification terminal in Bahrain.

The table above includes our proportionate share of the newbuilding costs for four LPG carrier newbuildings scheduled for delivery between 2017 and 2018 in the Exmar LPG Joint Venture. As at December 31, 2016, our 50% share of the estimated remaining costs for these four newbuildings totaled $77.5 million, including estimated interest and construction supervision fees. The Exmar LPG Joint Venture has secured financing for the four LPG carrier newbuildings.

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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, 2016.

6. Excludes expected interest payments of $2.5 million (2017), $1.3 million (2018), $0.2 million (2019), $0.2 million (2020), $0.2 million (2021) and $0.2 million (beyond 2021). Expected interest payments are based on EURIBOR at December 31, 2016, plus margins that range up to 2.25%, as well as the prevailing U.S. Dollar/Euro exchange rate as of December 31, 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. Excludes expected interest payments of $15.5 million (2017), $16.8 million (2018), $12.9 million (2019), $10.2 million (2020), and $3.7 million (2021). Expected interest payments are based on NIBOR at December 31, 2016, plus margins that range up to 6.00%, as well as the prevailing U.S. Dollar/NOK exchange rate as of December 31, 2016. The expected interest payments do not reflect the effect of the related cross-currency 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 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 6 – Equity Accounted Investments.

Critical Accounting Estimates

We prepare our consolidated financial statements in accordance with GAAP, which 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 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 five 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, 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

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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.

(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, 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 were $11.5 million, $10.1 million, and $14.8 million, respectively. As at December 31, 2016, 2015, and 2014, our capitalized dry-dock expenditures were$13.9 million, $10.4 million, and $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 $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

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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, 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 Part I – Forward-Looking Statements.

Amortization expense of intangible assets for each of the years 2016, 2015, and 2014 was $8.9 million, $8.9 million, and $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 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 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 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 cross-currency swap agreements.

The fair value of our interest and 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 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.

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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 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 in the period such determination was made. As at December 31, 2016, we had recorded valuation allowances of $41.1 million (2015 – $53.2 million).

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. Effective February 1, 2017, our General Partner has a Corporate Secretary but does not have any other officers. Instead, the Partnership and 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 Opco. Employees of certain subsidiaries of Teekay Corporation provide various services to us including in the case of our operating subsidiaries, substantially all of their managerial, operational and administrative services 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.”

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. The various services agreements require the service providers to provide the services diligently and in a commercially reasonable manner.

Directors of Teekay GP L.L.C.

The following table provides information about the directors as at the date of our Annual Report. Directors are elected for one-year terms. The business address of each of our directors listed below is c/o 4th Floor, Belvedere Building, 69 Pitts Bay Road, Hamilton, HM 08, Bermuda. Ages of the individuals are as of December 31, 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)

(1) Member of Audit Committee.

(2) Member of Conflicts Committee.

(3) Member of Corporate Governance Committee.

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

Ida Jane Hinkley serves as Chair of Teekay GP L.L.C. and has served as director since 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

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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.

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 Lok joined 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 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 L.L.C. in early 2011.

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 Chartered Professional Accountant for an accounting firm in Vancouver, Canada. Mr. Speers is also a Chartered Business Valuator.

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Edith Robinson was appointed as the Corporate Secretary of Teekay GP L.L.C., the general partner of Teekay LNG Partners L.P., in September 2014 and also currently serves as an Associate General Counsel for Teekay Corporation. Ms. Robinson joined Teekay Corporation in 2014. She was appointed Corporate Secretary of Teekay Gas Group Ltd. on February 1, 2017. Prior to joining Teekay Corporation, Ms. Robinson served as the General Counsel for a utility group in Bermuda. She has over twenty years of legal experience and is qualified to practice law in 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 our Chief Executive Officer and Chief Financial Officer. Because Mr. Evensen was an employee of Teekay Corporation, his compensation (other than any awards under the long-term incentive plan described below) was set and paid by Teekay Corporation, and we reimbursed Teekay Corporation for time he spent on partnership matters. Our General Partner 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 Opco (a wholly-owned subsidiary of the Partnership) and its subsidiaries with the services of its CEO, Mark Kremin and its CFO, Brody Speers.

During 2016, the aggregate amount for which we reimbursed Teekay Corporation for compensation expenses of the former Chief Executive Officer and Chief Financial Officer of the General Partner, excluding any long-term incentive plan awards issued directly by the Partnership as described below, was $2.0 million. The amounts were paid in U.S. Dollars. Teekay Corporation’s annual bonus plan, in which the former CEO and CFO of the General Partner participated, considers both company performance and team 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 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 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, conflicts and governance committees each received an additional fee of $12,000, 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 2016, the five non-management directors received, in the aggregate, $368,500 in cash fees for their services as directors, plus reimbursement of their out-of-pocket expenses. In March 2016, our General Partner’s Board of Directors granted to the five non-management directors an aggregate of 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 2016, the General Partner awarded 132,582 restricted units to the Teekay employees who provide services to our business. The restricted units vest evenly over a three-year period from the grant date.

Board Practices

Teekay GP L.L.C., our General Partner, 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 (or the Board) currently consists of 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 2016, the Board held five meetings. Each director attended all Board meetings, with the exception of one director who did not attend one Board meeting. The members of the Audit Committee, Conflicts Committee and Corporate Governance Committee attended all meetings, with the exception of one director who did not attend two Audit Committee meetings, one Conflicts Committee meeting and one Corporate Governance Committee 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 (or NYSE) and the SEC. This committee is comprised of directors Beverlee F. Park

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(Chair), Ida Jane Hinkley, and 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 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 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, and Beverlee F. 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, 2016, approximately 1,700 seagoing staff served on our consolidated and equity accounted for vessels that were managed by subsidiaries of Teekay Corporation and approximately nine staff served on shore in technical, commercial and administrative roles in various countries, compared to approximately 1,800 seagoing staff and 11 on shore staff as of December 31, 2015 and approximately 1,600 seagoing staff and 11 on shore staff as of December 31, 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 (or ITF), 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 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

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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, 2016, of our common units by all directors of our General 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, 2017 (60 days after December 31, 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 of Teekay GP L.L.C. as a group (6 persons) (1) (2)	108,847	0.14	%

(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 and Vincent Lok. Mr. Lok is also the Executive Vice President and Chief Financial Officer of Teekay Corporation. Please read “Item 7 – Major Unitholders and Related Party 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, 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, 2017 (60 days after December 31, 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.

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) FMR LLC has the sole dispositive power, but does not have voting power as to these units. This information is based on the Schedule 13G filed by this group with the SEC on October 11, 2016.

(3) 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 6,642,979 common units. This information is based on the Schedule 13G/A filed by this group with the SEC on February 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

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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 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 was the Chairman of our General Partner, Teekay GP L.L.C. since it was formed in November 2004 until June 2015 and continues to serve as a director. Mr. Day also serves 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 will be resigning as Chairman of those two entities effective June 15, 2017 but continuing as a director of each entity.

Peter Evensen was the President and Chief Executive Officer of Teekay Corporation, the Chief Executive Officer and Chief Financial Officer 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 was an employee of a subsidiary of Teekay Corporation, his compensation (other than any awards under the long-term incentive plan) was set and paid by the Teekay Corporation subsidiary. Pursuant to our partnership agreement, we have agreed to reimburse Teekay Corporation for time spent by Mr. Evensen on our partnership matters.

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

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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

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, 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 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. However, commencing with our distribution on common units relating to the fourth quarter of 2015, we 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 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 distribute all of our 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 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 our General Partner’s broad discretion to establish reserves (including, among others, reserves for 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 Available Cash, our partnership agreement, including provisions requiring us to make cash distributions contained therein, may be amended with the approval of a 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.

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• Under Section 51 of The Marshall Islands Limited Partnership Act, we may not make a distribution to unitholders to the extent that at the time of the distribution, 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, 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 operating expenses, principal and interest payments on outstanding debt, tax expenses, working capital requirements, maintenance capital expenditures or anticipated cash needs.

• Our distribution policy may be affected by restrictions on distributions under our credit facility agreements, which contain material financial tests and covenants that must be satisfied and complied with. Should we be unable to satisfy these restrictions included in our 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 ability to make cash distributions to unitholders, notwithstanding our stated cash distribution policy.

• If we make distributions out of capital surplus, as opposed to operating surplus (as such terms are defined in our partnership agreement), those distributions will constitute a return of capital and will result in a reduction in the minimum quarterly distribution and the target distribution levels under our partnership agreement. We do not anticipate that we will make any distributions from capital surplus.

Incentive Distribution Rights

Incentive distribution rights represent the right to receive an increasing percentage of quarterly distributions of 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 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 from operating surplus we distribute up to and including the corresponding amount in the column “Quarterly Distribution Target Amount,’’ until 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 2.0% 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 (per unit)	Marginal Percentage Interest In Distributions
		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.

B. Significant Changes

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

Item 9. The Offer and Listing

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.

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Years Ended	Dec. 31, 2016		Dec. 31, 2015		Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
High	$	16.94	$	43.38	$	47.49	$	45.42	$	42.26
Low	7.92		8.80		33.02		37.73		33.00
Quarters Ended	Mar. 31, 2017		Dec. 31, 2016		Sept. 30, 2016		June 30, 2016		Mar. 31, 2016		Dec. 31, 2015		Sept. 30, 2015		June 30, 2015		Mar. 31, 2015
High	$	19.90	$	16.94	$	15.81	$	15.02	$	14.80	$	27.04	$	32.30	$	40.73	$	43.38
Low	14.25		13.06		9.47		10.30		7.92		8.80		22.03		31.64		34.13
Months Ended	Mar. 31, 2017		Feb. 28, 2017		Jan. 31, 2017		Dec. 31, 2016		Nov. 30, 2016		Oct. 31, 2016
High	$	19.15	$	19.90	$	19.90	$	16.35	$	15.75	$	16.94
Low	16.14		17.95		14.25		13.80		13.06		14.25

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.

Years Ended	Dec. 31, 2016 (1)
High	$	25.06
Low	22.66
Quarters Ended	Mar. 31, 2017		Dec. 31, 2016 (1)
High	$	25.60	$	25.06
Low	23.52		22.66
Months Ended	Mar. 31, 2017		Feb. 28, 2017		Jan. 31, 2017		Dec. 31, 2016		Nov. 30, 2016		Oct. 31, 2016 (2)
High	$	25.60	$	25.34	$	25.44	$	24.12	$	25.00	$	25.06
Low	24.80		24.76		23.52		22.66		23.00		24.52

(1)Period from October 10, 2016, when the Series A Preferred Units started trading on the NYSE, to December 31, 2016.

(2)Period from October 10, 2016, when the Series A Preferred Units started trading on the NYSE, to October 31, 2016.

Item 10. Additional Information

Memorandum and Articles of Association

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

Material Contracts

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:

(a) Amended and Restated Omnibus agreement with Teekay Corporation, Teekay Offshore, our General Partner and related parties. Please read “Item 7 – Major Unitholders and Related Party Transactions” for a summary of certain contract terms.

(b) We and certain of our operating subsidiaries have entered into services agreements with certain subsidiaries of Teekay Corporation pursuant to which the Teekay Corporation subsidiaries provide administrative services to the Partnership and administrative, advisory, technical, strategic consulting services, business development and ship management services to operating subsidiaries for a reasonable fee that includes reimbursement of these direct and indirect expenses incurred in providing these services. Please read “Item 7 – Major Unitholders and Related Party Transactions” for a summary of certain contract terms.

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(c) Syndicated Loan Agreement between Naviera Teekay Gas III, S.L. (formerly Naviera F. Tapias Gas III, S.A.) and Caixa de Aforros de Vigo Ourense e Pontevedra, as Agent, dated as of October 2, 2000, as amended. This facility was used to make restricted cash deposits that fully fund payments under a capital lease for one of our LNG carriers, the Catalunya Spirit. Interest payments are based on EURIBOR plus a margin. The term loan matures in 2023 with monthly payments that reduce over time.

(d) Amended Teekay LNG Partners L.P. 2005 Long-Term Incentive Plan. Please read “Item 6 – Directors, Senior Management and Employees” for a summary of certain plan terms.

(e) Agreement dated August 23, 2006, for a U.S. $330,000,000 Secured Revolving Loan Facility between Teekay LNG Partners L.P., ING Bank N.V. and various other banks. This facility bears interest at LIBOR plus a margin of 0.55%. The amount available under the facility reduces semi-annually by amounts ranging from $4.3 million to $8.4 million, with a bullet reduction of $188.7 million on maturity in August 2018. The revolver is collateralized by first-priority mortgages granted on two of our LNG carriers. The credit facility may be used for general partnership purposes and to fund cash distributions.

(f) Agreement dated June 30, 2008, for a U.S. $172,500,000 Secured Revolving Loan Facility between Arctic Spirit L.L.C., Polar Spirit L.L.C. and DnB Nor Bank A.S.A. and various other banks. This facility bears interest at LIBOR plus a margin of 0.80%. The amount available under the facility reduces by $6.1 million semi-annually, with a balloon reduction of $56.6 million on maturity in June 2018. The revolver is collateralized by first-priority mortgages granted on two of our LNG carriers. The credit facility may be used for general partnership purposes and to fund cash distributions.

(g) Deed of Amendment and Restatement dated October 10, 2008, relating to a Loan Agreement for a U.S. $92,400,000 Buyer Credit and a U.S. $117,600,000 Commercial Loan between MiNT LNG I, Ltd., BNP Paribas S.A., and various other banks. The Buyer Credit bears interest at LIBOR plus a margin of 0.78% and the Commercial Loan bears interest at LIBOR plus a margin of 1.30%. In addition, a commitment fee will be charged at the rate of 0.25% and 0.45% on undrawn and uncancelled amounts of the Buyer Credit and Commercial Loan, respectively. The amount available under the facilities reduces quarterly by amounts ranging from $1.2 million to $2.5 million. The Commercial Loan is due by one installment on maturity in 2023.

(h) Deed of Amendment and Restatement dated October 10, 2008, relating to a Loan Agreement for a U.S. $92,400,000 Buyer Credit and a U.S. $117,600,000 Commercial Loan between MiNT LNG II, Ltd., BNP Paribas S.A., and various other banks. The Buyer Credit bears interest at LIBOR plus a margin of 0.78% and the Commercial Loan bears interest at LIBOR plus a margin of 1.30%. In addition, a commitment fee will be charged at the rate of 0.25% and 0.45% on undrawn and uncancelled amounts of the Buyer Credit and Commercial Loan, respectively. The amount available under the facilities reduces quarterly by amounts ranging from $1.2 million to $2.5 million. The Commercial Loan is due by one installment on maturity in 2023.

(i) Deed of Amendment and Restatement dated October 10, 2008, relating to a Loan Agreement for a U.S. $92,400,000 Buyer Credit and a U.S. $117,600,000 Commercial Loan between MiNT LNG III, Ltd., BNP Paribas S.A., and various other banks. The Buyer Credit bears interest at LIBOR plus a margin of 0.78% and the Commercial Loan bears interest at LIBOR plus a margin of 1.30%. In addition, a commitment fee will be charged at the rate of 0.25% and 0.45% on undrawn and uncancelled amounts of the Buyer Credit and Commercial Loan, respectively. The amount available under the facilities reduces quarterly by amounts ranging from $1.2 million to $2.5 million. The Commercial Loan is due by one installment on maturity in 2023.

(j) Deed of Amendment and Restatement dated October 10, 2008, relating to a Loan Agreement for a U.S. $92,400,000 Buyer Credit and a U.S. $117,600,000 Commercial Loan between MiNT LNG IV, Ltd., BNP Paribas S.A., and various other banks. The Buyer Credit bears interest at LIBOR plus a margin of 0.78% and the Commercial Loan bears interest at LIBOR plus a margin of 1.30%. In addition, a commitment fee will be charged at the rate of 0.25% and 0.45% on undrawn and uncancelled amounts of the Buyer Credit and Commercial Loan, respectively. The amount available under the facilities reduces quarterly by amounts ranging from $1.2 million to $2.5 million. The Commercial Loan is due by one installment on maturity in 2024.

(k) Agreement dated October 27, 2009, for a U.S. $122,000,000 Credit Facility that is secured by the LPG carriers and multigas carriers chartered to I.M. Skaugen SE. Interest payments under the facility are based on three months LIBOR plus 2.75% and require quarterly payments. This loan facility is collateralized by first priority mortgages on the five vessels to which the loans relate, together with certain other related security and is guaranteed by us. The loans have varying maturities through 2018.

(l) Agreement dated September 30, 2011, for a EURO 149,933,766 Credit Facility between Naviera Teekay Gas IV S.L.U., ING Bank N.V. and various other banks. This facility bears interest at EURIBOR plus a margin of 2.25%. The amount available under the facility reduces monthly by amounts ranging from $0.4 million to $0.7 million, with a bullet reduction of $104.4 million on maturity in 2018. The loan facility is guaranteed by us.

(m) Agreement dated February 28, 2012; Teekay LNG Operating L.L.C. and Marubeni Corporation entered into an agreement to acquire, through the Teekay LNG-Marubeni Joint Venture, 100% ownership of six LNG carriers from AP Moller-Maersk A/S.

(n) Agreement dated April 30, 2012, for NOK 700,000,000, Senior Unsecured Bonds due May 2017, between Teekay LNG Partners L.P. and Norsk Tillitsmann ASA.

(o) Agreement dated February 12, 2013; Teekay Luxembourg S.a.r.l. entered into a share purchase agreement with Exmar and Exmar Marine NV to purchase 50% of the shares in Exmar LPG BVBA.

(p) Agreement dated June 27, 2013, for U.S. $195,000,000 Senior Secured Notes between Meridian Spirit ApS and Wells Fargo Bank Northwest N.A. The loan bears interest at fixed rate of 4.11%. The facility requires quarterly repayments through 2030.

(q) Agreement dated June 28, 2013, for a U.S. $160,000,000 Loan Facility between Malt Singapore Pte. Ltd. and Commonwealth Bank of Australia. The loan bears interest at LIBOR plus a margin of 2.60%. The facility requires quarterly repayments, with a bullet payment on maturity in 2021.

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(r) Agreement dated July 30, 2013, for a U.S. $608,000,000 Loan Facility between Malt LNG Netherlands Holdings B.V. and DNB Bank ASA, acting as agent and security trustee. The loan bears interest at LIBOR plus a margin of 3.15% for Tranche A and LIBOR plus a margin of 0.5% for Tranche B. The facility requires quarterly repayments, with a bullet payment on maturity in 2017. The loan facility is guaranteed by us and Marubeni Corporation based on our proportionate ownership percentages in the Teekay LNG-Marubeni Joint Venture.

(s) Agreement dated August 30, 2013, for NOK 900,000,000, Senior Unsecured Bonds due September 2018 between Teekay LNG Partners L.P. and Norsk Tillitsmann ASA.

(t) Agreement dated December 9, 2013, for a U.S. $125,000,000 Secured Credit Facility between Wilforce L.L.C. and Credit Suisse AG and others. The loan bears interest at LIBOR plus a margin of 3.20% until June 2014 and a margin of 2.80% thereafter. The facility requires quarterly repayments, with a bullet payment in 2018.

(u) Agreement dated March 28, 2014, for a U.S. $130,000,000 Secured Credit Facility between Wilpride L.L.C., Nordea Bank Finland and various other banks. The loan bears interest at LIBOR plus a margin of 2.75%. The facility requires quarterly repayments, with a bullet payment in 2018.

(v) Agreement dated July 7, 2014; Teekay LNG Operating L.L.C. entered into a shareholder agreement with China LNG Shipping (Holdings) Limited to form TC LNG Shipping L.L.C. in connection with the Yamal LNG Project.

(w) Agreement dated November 7, 2014, for a U.S. $175,000,000 Secured Loan Facility between Solaia Shipping L.L.C. and Excelsior BVBA, Nordea Bank Norge ASA and various other banks. The loan bears interest at LIBOR plus a margin of 2.75%. The facility requires quarterly repayments, with a bullet payment in 2019. The loan facility is guaranteed by us and Exmar based on our proportionate ownership percentages in the Exmar LNG Carriers.

(x) Agreement dated December 17, 2014, for a U.S. $450,000,000 Secured Loan Facility between Nakilat Holdco L.L.C. and Qatar National Bank SAQ. The loan bears interest at LIBOR plus a margin of 1.85%. The facility requires quarterly repayments, with a bullet payment in 2026.

(y) Agreement dated May 18, 2015, for NOK 1,000,000,000, Senior Unsecured Bonds due May 2020 between Teekay LNG Partners L.P. and Nordic Trustee ASA.

(z) Amending and Restating Agreement dated June 5, 2015, for a U.S. $460,000,000 Secured Loan Facility between Exmar LPG BVBA, Nordea Bank Norge ASA and various other banks. The loan bears interest at LIBOR plus a margin of 1.90%. The facility requires quarterly repayments with a balloon payment in 2021. The loan facility is guaranteed by us and Exmar based on our proportionate ownership percentages in Exmar LPG BVBA.

(aa) Agreement dated February 11, 2016 for a sale leaseback agreement between Creole Spirit L.L.C. and Hai Jiao 1601 Limited (a subsidiary of ICBC Financial Leasing Co., Ltd.). The lease agreement requires quarterly lease payments. At the end of the 10-year tenor of the lease, we have an obligation of $100.0 million to repurchase the vessel from ICBC Financial Leasing Co., Ltd.

(ab) Agreement dated February 11, 2016 for a sale leaseback agreement between Oak Spirit L.L.C. and Hai Jiao 1602 Limited (a subsidiary of ICBC Financial Leasing Co., Ltd.). The lease agreement requires quarterly lease payments. At the end of the 10-year tenor of the lease, we have an obligation of $100.0 million to repurchase the vessel from ICBC Financial Leasing Co., Ltd.

(ac) Agreement dated May 4, 2016, for a U.S. $60,000,000 secured loan facility between African Spirit L.L.C., European Spirit L.L.C. and Asian Spirit L.L.C., and Scotiabank Europe plc. The loan bears interest at LIBOR plus a margin of 1.65%. The facility requires quarterly repayments with a balloon payment in May 2019.

(ad) Agreement dated November 15, 2016, for a U.S. $730,000,000 Secured Loan Facility between Bahrain LNG W.L.L. and Standard Chartered Bank and various other banks. The loan bears interest at LIBOR plus a margin ranging from 1.50% to 3.60% over the agreement duration. The facility requires semi-annual repayments 12 months after the estimated scheduled commercial start date in February 2019, with a balloon payment in 2036.

(ae) Agreement dated November 17, 2016, for U.S. $170,000,000 unsecured Revolving Credit Facility between Teekay LNG Partners L.P. and Citigroup Global Markets Limited and various other banks. The loan bears interest at LIBOR plus a margin of 1.10% and additional utilization fees up to 0.40%. The facility requires a bullet payment in November 2017. The credit facility may be used for General Partnership purposes and to fund cash distributions.

(af) Agreement dated December 20, 2016 for a sale leaseback agreement between DSME Hull No. 2416 L.L.C. and Hai Jiao 1605 Limited (a subsidiary of ICBC Financial Leasing Co., Ltd.). The lease agreement requires quarterly lease payments. At the end of the 10-year tenor of the lease, we have an obligation of $100.0 million to repurchase the vessel from ICBC Financial Leasing Co., Ltd.

(ag) Agreement dated December 20, 2016 for a sale leaseback agreement between DSME Option Vessel No.1 L.L.C. and Hai Jiao 1606 Limited (a subsidiary of ICBC Financial Leasing Co., Ltd.). The lease agreement requires quarterly lease payments. At the end of the 10-year tenor of the lease, we have an obligation of $100.0 million to repurchase the vessel from ICBC Financial Leasing Co., Ltd.

(ah) Agreement dated December 20, 2016 for a sale leaseback agreement between DSME Option Vessel No.3 L.L.C. and Hai Jiao 1607 Limited (a subsidiary of ICBC Financial Leasing Co., Ltd.). The lease agreement requires quarterly lease payments. At the end of the 10-year tenor of the lease, we have an obligation of $100.0 million to repurchase the vessel from ICBC Financial Leasing Co., Ltd.

(ai) Agreement dated December 21, 2016, for a U.S. $723,200,000 Secured Loan Facility between Teekay Nakilat (III) Corporation and Qatar National Bank SAQ. The loan bears interest at LIBOR plus a margin of 2.25% for the first 12 months and 2.50% thereafter. The facility requires quarterly repayments, with a balloon payment in 2026.

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Exchange Controls and Other Limitations Affecting Unitholders

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 holders of our 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.

Taxation

Marshall Islands Tax Consequences. We and our subsidiaries do not, and we do not expect that we and our subsidiaries will, conduct business or operations in the Republic of The Marshall Islands. Consequently, neither we nor our subsidiaries will be subject to income, capital gains, profits or other taxation under current Marshall Islands law, other than taxes or fees due to (i) the continued existence of legal entities registered in the Republic of The Marshall Islands, (ii) the incorporation or dissolution of legal entities registered in the Republic of The Marshall Islands, (iii) filing certificates (such as certificates of incumbency, merger, or redomiciliation) with The Marshall Islands registrar, (iv) obtaining certificates of goodstanding from, or certified copies of documents filed with, The Marshall Islands registrar, or (v) compliance with Marshall Islands law concerning vessel ownership, such as tonnage tax. As a result, distributions by our subsidiaries to us will not be subject to Marshall Islands taxation. In addition, because all documentation related to our initial public offering and follow-on offerings were executed outside of the Republic of The Marshall Islands, under current Marshall Islands law, no taxes or withholdings are imposed by the Republic of The Marshall Islands on distributions, including upon a return of capital, made to unitholders, so long as such persons are not citizens of and do not reside in, maintain offices in, nor engage in business or transactions in the Republic of The Marshall Islands. In addition, no stamp, capital gains or other taxes are imposed by the Republic of The Marshall Islands on the purchase, ownership or disposition by such persons of our common units.

United States Tax Consequences. The following is a discussion of certain material U.S. federal income tax considerations that may be relevant to unitholders who are individual citizens or residents of the United States. This discussion is based upon provisions of the Internal Revenue Code of 1986, as amended (or the Code), legislative history, applicable U.S. Treasury Regulations (or Treasury Regulations), judicial authority and administrative interpretations, all as in effect on the date of this Annual Report, and which are subject to change, possibly with retroactive effect, or are subject to different interpretations. Changes in these authorities may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to “we,” “our” or “us” are references to Teekay LNG Partners L.P.

This discussion is limited to unitholders who hold their 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:

• dealers in securities or currencies;

• traders in securities that have elected the mark-to-market method of accounting for their securities;

• persons whose functional currency is not the U.S. Dollar;

• persons holding our units as part of a hedge, straddle, conversion or other “synthetic security” or integrated transaction;

• certain U.S. expatriates;

• financial institutions;

• insurance companies;

• persons subject to the alternative minimum tax;

• persons that actually or under applicable constructive ownership rules own 10 percent or more of our units; and

• entities that are tax-exempt for U.S. federal income tax purposes.

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

Classification as a Partnership

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 its share of items of income, gain, loss, deduction and credit of the partnership in computing its U.S. federal

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income tax liability, regardless of whether cash distributions are made to 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 its partnership interest.

Section 7704 of the Code provides that a publicly traded partnership generally will be treated as a 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 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 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 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.

Status as a Partner

The treatment of unitholders described in this section applies only to unitholders treated as partners in us for U.S. federal income tax purposes. 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, 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 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 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 units will be treated as partners in us for U.S. federal income tax purposes.

The status of assignees of 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 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 units, unless the units are held in a nominee or street name account and the nominee or broker has executed and delivered a transfer application for those units.

Under certain circumstances, a beneficial owner of units whose units have been loaned to another may lose 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. Common unitholders not described here and Series A preferred unitholders are urged to consult their tax advisors with respect to their status as partners in us for U.S. federal income tax purposes.

Consequences of Unit Ownership

Flow-through of Taxable Income. Each unitholder is required to include in computing its taxable income its allocable share of our items of income, gain, loss, deduction and credit for our taxable year ending with or within its taxable year, without regard to whether we make corresponding cash distributions to it. Our taxable year ends on December 31. Consequently, we may allocate income to a unitholder as of December 31 of a given year, and the unitholder will be required to report this income on its tax return for its tax year that ends on or includes such date, even if it has not received a cash distribution from us as of that date. As discussed further below under “—Allocation of Income,

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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 units.

Treatment of Distributions.Except as described below with respect to distributions in respect of Series A preferred units, distributions by us to a unitholder generally will not be taxable to the unitholder for U.S. federal income tax purposes to the extent of its tax basis in its common units immediately before the distribution. Our cash distributions in excess of a unitholder’s tax basis generally will be considered to be gain from the sale or exchange of common units, taxable in accordance with the rules described under “—Disposition of Common Units” below. Any reduction in a unitholder’s share of our liabilities for which no partner, including the general partner, bears the economic risk of loss, known as “nonrecourse liabilities,” will be treated as a distribution of cash to that unitholder. A decrease in a unitholder’s percentage interest in us because of our issuance of additional common units will decrease its share of our nonrecourse liabilities, and thus will result in a corresponding deemed distribution of cash. To the extent our distributions cause a unitholder’s “at risk” amount to be less than zero at the end of any taxable year, it must recapture any losses deducted in previous years.

A non-pro rata distribution of money or property may result in ordinary income to a unitholder, regardless of its tax basis in its common units, if the distribution reduces the unitholder’s share of our “unrealized receivables,” including depreciation recapture, and/or substantially appreciated “inventory items,” both as defined in the Code (or, collectively, Section 751 Assets). To that extent, a unitholder will be treated as having been distributed its proportionate share of the Section 751 Assets and having exchanged those assets with us in return for the non-pro rata portion of the actual distribution made to him. This latter deemed exchange will generally result in the unitholder’s realization of ordinary income, which will equal the excess of (1) the non-pro rata portion of that distribution over (2) the unitholder’s tax basis for the share of Section 751 Assets deemed relinquished in the exchange.

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.

Tax Basis of Common Units. A unitholder’s initial U.S. federal income tax basis for its units will be the amount it paid for the units plus its share of our nonrecourse liabilities. That tax basis will be increased by its share of our income and by any increases in its share of our nonrecourse liabilities and by its share of our tax-exempt income, if any, and decreased, but not below zero, by distributions from us, by the unitholder’s share of our losses, by any decreases in its share of our nonrecourse liabilities and by its share of our expenditures that are not deductible in computing taxable income and are not required to be capitalized. A unitholder will have no share of our debt that is recourse to the general partner, but will have a share, generally based on its share of profits, of our nonrecourse liabilities.

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.

Limitations on Deductibility of Losses. The deduction by a unitholder of its share of our losses will be limited to the tax basis in its units and, in the case of an individual unitholder or a corporate unitholder more than 50 percent of the value of the stock of which is owned directly or indirectly by five or fewer individuals or some tax-exempt organizations, to the amount for which the unitholder is considered to be “at risk” with respect to our activities, if that is less than its tax basis. In general, a unitholder will be at risk to the extent of the tax basis of its units, excluding any portion of that basis attributable to its share of our nonrecourse liabilities, reduced by any amount of money it borrows to acquire or hold its units, if the lender of those borrowed funds owns an interest in us, is related to the unitholder or can look only to the units for repayment. A unitholder must recapture losses deducted in previous years to the extent that distributions cause its at risk amount to be less than zero at the end of any taxable year. Losses disallowed to a unitholder or recaptured as a result of these limitations will carry forward and will be allowable to the extent that its tax basis or at risk amount, whichever is the limiting factor, is subsequently increased. Upon the taxable disposition of a unit, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at risk limitation but may not be offset by losses suspended by the basis limitation. Any excess suspended loss above that gain is no longer utilizable.

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

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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 it disposes of 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.

Limitations on Interest Deductions. The deductibility of a non-corporate taxpayer’s “investment interest expense” generally is limited to the amount of that taxpayer’s “net investment income.” For this purpose, investment interest expense includes, among other things, a unitholder’s share of our interest expense attributed to portfolio income. The IRS has indicated that net passive income earned by a publicly traded partnership will be treated as investment income to its unitholders. In addition, the unitholder’s share of our portfolio income will be treated as investment income.

Entity-Level Collections. If we are required or elect under applicable law to pay any U.S. federal, state or local or foreign income or withholding taxes on behalf of any present or former unitholder or the general partner, we are authorized to pay those taxes from our funds. That payment, if made, will be treated as a distribution of cash to the partner on whose behalf the payment was made. We are authorized to amend the partnership agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of units and to adjust later distributions, so that after giving effect to these distributions, the priority and characterization of distributions otherwise applicable under the partnership agreement are maintained as nearly as is practicable. Payments by us as described above could give rise to an overpayment of tax on behalf of an individual partner, in which event the partner would be required to file a claim in order to obtain a credit or refund of tax paid.

Allocation of Income, Gain, Loss, Deduction and Credit. In general, if we have a net profit, our items of income, gain, loss, deduction and credit will be allocated among the general partner and the common unitholders in accordance with their percentage interests in us. At any time that incentive distributions are made to the general partner, gross income will be allocated to the general partner to the extent of these distributions. If we have a net loss for the entire year, that loss generally will be allocated first to the general partner and the common unitholders in accordance with their percentage interests in us to the extent of their positive capital accounts and, second, to the general partner.

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 units, referred to in this discussion as “Adjusted Property.” The effect of these allocations to a unitholder purchasing 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 its interest in us, which will be determined by taking into account all the facts and circumstances, including:

• the type of interest held by the partner;

• its relative contributions to us;

• the interests of all the partners in profits and losses;

• the interest of all the partners in cash flow; and

• the rights of all the partners to distributions of capital upon liquidation.

A unitholder’s taxable income or loss with respect to a 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 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

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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 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 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 unit.

Section 754 Election. We have made an election under Section 754 of the Code to adjust a unit purchaser’s U.S. federal income tax basis in our assets (or inside basis) to reflect the purchaser’s purchase price (or a Section 743(b) adjustment). The Section 743(b) adjustment belongs to the purchaser and not to other unitholders and does not apply to unitholders who acquire their units directly from us. For purposes of this discussion, a unitholder’s inside basis in our assets will be considered to have two components: (1) its share of our tax basis in our assets (or common basis) and (2) its Section 743(b) adjustment to that basis.

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 it would have been allocated had the election not been revoked.

Treatment of Short Sales. A unitholder whose units are loaned to a “short seller” who sells such units may be considered to have disposed of those units. If so, the unitholder would no longer be a partner with respect to those units until the termination of the loan and may recognize gain or loss from the disposition. As a result, any of our income, gain, loss, deduction or credit with respect to the units may not be reportable by the unitholder who loaned them and any cash distributions received by such unitholder with respect to those units may be fully taxable as ordinary income.

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.

Tax Treatment of Operations

Accounting Method and Taxable Year. We use the calendar year as our taxable year and the accrual method of accounting for U.S. federal income tax purposes. Each unitholder will be required to include in income its share of our income, gain, loss, deduction and credit (and, for Series A preferred unitholders, its income from our guaranteed payments) for our taxable year ending within or with its taxable year. In addition, a unitholder who disposes of all of its units must include its share of our income, gain, loss, deduction and credit through the date of disposition in income for its taxable year that includes the date of disposition, with the result that a unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of its units following the close of our taxable year but before the close of its taxable year must include its share of more than one year of our income, gain, loss, deduction and credit in income for the year of the disposition. Similarly, a Series A preferred unitholder that has a taxable year ending on a date other than December 31 and that disposes of all its units following the close of our taxable year but before the close of its taxable year will be required to include in income for its taxable year income from more than one year of guaranteed payments.

Asset Tax Basis, Depreciation and Amortization. The tax basis of our assets will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. The U.S. federal income tax burden associated with any difference between the fair market value of our assets and their tax basis immediately prior to an offering of units will be borne by the general partner and the existing limited partners.

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 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 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

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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.

Disposition of Units

Recognition of Gain or Loss. In general, gain or loss will be recognized on a sale of units equal to the difference between the amount realized and the unitholder’s tax basis in the units sold. A unitholder’s amount realized will be measured by the sum of the cash, the fair market value of other property received by it and, in the case of a common unitholder, its share of our nonrecourse liabilities. Because the amount realized by a common unitholder includes a common unitholder’s share of our nonrecourse liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash or property received from the sale.

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 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. Because Series A preferred unitholders generally are not expected to be allocated a share of our items of depreciation, depletion or amortization, it is not anticipated that Series A preferred unitholders would be required to recharacterize any portion of their gain as ordinary income 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 units transferred with an ascertainable holding period to elect to use the actual holding period of the units transferred. Thus, according to the ruling, a unitholder will be unable to select high or low basis units to sell as would be the case with corporate stock, but, according to the Treasury Regulations, may designate specific units sold for purposes of determining the holding period of units transferred. A unitholder electing to use the actual holding period of units transferred must consistently use that identification method for all subsequent sales or exchanges of units. A unitholder considering the purchase of additional units or a sale of units purchased in separate transactions is urged to consult 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 units.

Allocations Between Transferors and Transferees. In general, our taxable income or loss will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the common unitholders in proportion to the number of common units owned by each of them as of the opening of the applicable exchange on the first business day of the month. However, gain or loss realized on a sale or other disposition of our assets other than in the ordinary course of business will be allocated among the common unitholders on the first business day of the month in which that gain or loss is recognized. As a result of the foregoing, a common unitholder transferring common units may be allocated income, gain, loss, deduction and credit realized after the date of transfer. A common unitholder who owns common units at any time during a calendar quarter and who disposes of them prior to the record date set for a cash distribution for that quarter will be allocated items of our income, gain, loss, deductions and credit attributable to months within that quarter in which the common units were held but will not be entitled to receive that cash distribution. 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. Because Series A preferred unitholders generally are not expected to be allocated a share of our items of depreciation, depletion or amortization, it is not anticipated that Series A preferred unitholders would be affected by the proration method we have adopted.

Holders of Series A preferred units owning Series A preferred units as of the close of the applicable exchange on the last business day of a calendar quarter (or the Allocation Date) will be entitled to receive the distribution of the guaranteed payment payable with respect to their Series A preferred units for that quarter on the next distribution payment date. Purchasers of Series A preferred units after the Allocation Date will therefore not be entitled to a cash distribution on their Series A preferred units until the next Allocation Date.

Transfer Notification Requirements. A unitholder who sells any of its units, other than through a broker, generally is required to notify us in writing of that sale within 30 days after the sale (or, if earlier, January 15 of the year following the sale). A unitholder who acquires units

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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.

Constructive Termination. 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 and profits within a 12-month period. A constructive termination results in the closing of our taxable year for all unitholders. In the case of a unitholder reporting on a taxable year other than a calendar year, the closing of our taxable year may result in more than 12 months of our taxable income or loss being includable in its taxable income for the year of termination. We would be required to make new tax elections after a termination, including a new election under Section 754 of the Code, and a termination would result in a deferral of our deductions for depreciation. A termination could also result in penalties if we were unable to determine that the termination had occurred. Moreover, a termination might either accelerate the application of, or subject us to, tax legislation applicable to a newly formed partnership.

Foreign Tax Credit Considerations

Subject to detailed limitations set forth in the Code, a unitholder may elect to claim a credit against its liability for U.S. federal income tax for 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 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 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 its share of foreign taxes paid by us.

Tax-Exempt Organizations and Non-U.S. Investors

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) raise issues unique to those investors and, as described below, may result in substantially adverse tax consequences to them.

Employee benefit plans and most other organizations exempt from U.S. federal income tax, including individual retirement accounts and other retirement plans, are subject to U.S. federal income tax on unrelated business taxable income (or UBTI). Virtually all of our income allocated to a unitholder that is such a tax-exempt organization will be UBTI to it subject to U.S. federal income tax. As described above, we will treat distributions on the Series A preferred units as guaranteed payments for the use of capital. The treatment of guaranteed payments for the use of capital to tax-exempt investors is not certain because there is no direct controlling authority on such treatment. Accordingly, such guaranteed payments may be treated as UBTI. Series A preferred unitholders that are tax-exempt organizations are encouraged to consult with their tax advisors regarding the tax consequences to them of the receipt of guaranteed payments for the use of capital.

A non-U.S. common unitholder may be subject to a 4 percent U.S. federal income tax on its share of the U.S. source portion of our gross income attributable to transportation that begins or ends (but not both) in the United States, unless either (a) an exemption applies and it files a U.S. federal income tax return to claim that exemption or (b) that income is effectively connected with the conduct of a trade or business in the United States (or U.S. effectively connected income). The applicability of this tax to the guaranteed payments made to Series A preferred unitholders is uncertain. For this purpose, transportation income includes income from the use, hiring or leasing of a vessel to transport cargo, or the performance of services directly related to the use of any vessel to transport cargo. The U.S. source portion of our transportation income is deemed to be 50 percent of the income attributable to voyages that begin or end (but not both) in the United States. Generally, no amount of the income from voyages that begin and end outside the United States is treated as U.S. source, and consequently a non-U.S. unitholder would not be subject to U.S. federal income tax with respect to our transportation income attributable to such voyages. Although the entire amount of transportation income from voyages that begin and end in the United States would be fully taxable in the United States, we currently do not expect to have a material amount of transportation income from voyages that begin and end in the United States.

A non-U.S. unitholder may be entitled to an exemption from the 4 percent U.S. federal income tax or a refund of tax withheld on U.S. effectively connected income that constitutes transportation income if any of the following applies: (1) such non-U.S. unitholder qualifies for an exemption from this tax under an income tax treaty between the United States and the country where such non-U.S. unitholder is resident; (2) in the case of an individual non-U.S. unitholder, it qualifies for the exemption from tax under Section 872(b)(1) of the Code as a resident of a country that grants an equivalent exemption from tax to residents of the United States; or (3) in the case of a corporate non-U.S. unitholder, it qualifies for the exemption from tax under Section 883 of the Code (or the Section 883 Exemption) (for the rules relating to qualification for the Section 883 Exemption, please read below under “— Possible Classification as a Corporation — The Section 883 Exemption”).

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 its U.S. effectively

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connected income (including 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 tax advisors regarding the U.S. federal, state, local and other tax consequences of an investment in units and any filing requirements related thereto.

Functional Currency

We are required to determine the functional currency of any of our operations that constitute a separate qualified business unit (or QBU) for U.S. federal income tax purposes. For purposes of the foreign currency rules, a QBU includes a separate trade or business owned by a partnership in the event separate books and records are maintained for that separate trade or business. The functional currency of a QBU is determined based upon the economic environment in which the QBU operates. Thus, a QBU whose revenues and expenses are primarily determined in a currency other than the U.S. Dollar will have a non-U.S. Dollar functional currency. We believe our principal operations constitute a QBU whose functional currency is the U.S. Dollar, but certain of our operations constitute separate QBUs whose functional currencies are other than the U.S. Dollar. Any transactions conducted by us other than in the U.S. Dollar or by a QBU other than in its functional currency may give rise to foreign currency exchange gain or loss. The U.S. Treasury Department and the IRS recently issued final regulations relating to the amount of foreign currency translation gain or loss. However, the final regulations did not address the application of the foreign currency translation gain and loss rules to partnerships such as us, and in the preamble to the final regulations, indicated that further regulations will developed under a separate project. As a result, the manner in which foreign currency translation gain or loss may be recognized by unitholders is uncertain. Despite this uncertainty, based upon our current projections of the capital invested in and profits of the non-U.S. Dollar QBUs and the different ways in which foreign currency translation gain or loss could be recognized, we believe that only a nominal amount of foreign currency translation gain or loss would be recognized each year. Unitholders are urged to consult their tax advisors for specific advice regarding the application of the rules for recognizing foreign currency translation gain or loss.

Information Returns and Audit Procedures

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 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 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

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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 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.

Special Reporting Requirements for Owners of Non-U.S. Partnerships.

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 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 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.

Accuracy-related Penalties

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:

(1) for which there is, or was, “substantial authority”; or

(2) as to which there is a reasonable basis and the pertinent facts of that position are disclosed 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.

Possible Classification as a Corporation

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

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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.

If we were treated as a corporation in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income, gain, loss, deduction and credit would not pass through to unitholders. Instead, we would be subject to U.S. federal income tax based on the rules applicable to foreign corporations, not partnerships, and such items would be treated as our own. In addition, Section 743(b) adjustments to the basis of our assets would no longer be available to purchasers in the marketplace. Subject to the discussion of passive foreign investment companies (or PFICs) below, any distribution made to a unitholder would be treated as taxable dividend income to the extent of our current and accumulated earnings and profits, as determined under U.S. federal income tax principles. Distributions in excess of our earnings and profits would be treated first as a nontaxable return of capital to the extent of the unitholder’s tax basis in its units, and taxable capital gain thereafter. Dividends paid on our units to U.S. unitholders who are individuals, estates or trusts generally would be treated as “qualified dividend income” that is subject to tax at preferential capital gain rates, subject to certain holding period and other requirements. In addition, certain U.S. unitholders who are individuals, estates or trusts would be required to pay an additional 3.8 percent tax on the dividends and distributions taxable as capital gain paid to them.

Taxation of Operating Income. We expect that substantially all of our gross income and the gross income of our corporate subsidiaries will be attributable to the transportation of LNG, LPG, ammonia, crude oil and related products. For this purpose, gross income attributable to transportation (or Transportation Income) includes income derived from, or in connection with, the use (or hiring or leasing for use) of a vessel to transport cargo, or the performance of services directly related to the use of any vessel to transport cargo, and thus includes both time charter and bareboat charter income.

Fifty percent (50%) of Transportation Income attributable to transportation that either begins or ends, but that does not both begin and end, in the United States (or U.S. Source International Transportation Income) is considered to be derived from sources within the United States. Transportation Income attributable to transportation that both begins and ends in the United States (or U.S. Source Domestic Transportation Income) is considered to be 100 percent derived from sources within the United States. Transportation Income attributable to transportation exclusively between non-U.S. destinations is considered to be 100 percent derived from sources outside the United States. Transportation Income derived from sources outside the United States generally is not subject to U.S. federal income tax.

Based on our current operations and the operations of our subsidiaries, we expect substantially all of our Transportation Income to be from sources outside the United States and not subject to U.S. federal income tax. In addition, we believe that we have not earned a material amount of U.S. Source Domestic Transportation Income, and we expect that we will not earn a material amount of such income in future years. However, in the event we were treated as a corporation, if we or any of our subsidiaries does earn U.S. Source International Transportation Income or U.S. Source Domestic Transportation Income, our income or our subsidiaries’ income would be subject to U.S. federal income taxation under either the net basis and branch profits taxes or the 4 percent gross basis tax, each of which is discussed below, unless the exemption from U.S. taxation under Section 883 of the Code (or the Section 883 Exemption) applies.

The Section 883 Exemption. In general, the Section 883 Exemption provides that if a non-U.S. corporation satisfies the requirements of Section 883 of the Code and the Treasury Regulations thereunder, it will not be subject to the net basis and branch profits taxes or the 4% gross basis tax described below on its U.S. Source International Transportation Income. The Section 883 Exemption does not apply to U.S. Source Domestic Transportation Income.

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.

Net Basis Tax and Branch Profits Tax. If we were to be treated as a corporation and if the Section 883 Exemption does not apply, our U.S. Source International Transportation Income may be treated as effectively connected with the conduct of a trade or business in the United States (or Effectively Connected Income) if we have a fixed place of business in the United States and substantially all of our U.S. Source International Transportation Income is attributable to regularly scheduled transportation or, in the case of income derived from bareboat charters, is attributable to a fixed place of business in the United States. Based on our current operations, none of our potential U.S. Source International Transportation Income is attributable to regularly scheduled transportation or is derived from bareboat charters attributable to a fixed place of business in the United States. As a result, if we were classified as a corporation, we do not anticipate that any of our U.S. Source International Transportation Income would be treated as Effectively Connected Income. However, there is no assurance that we would not earn income pursuant to regularly scheduled transportation or bareboat charters attributable to a fixed place of business in the United States in the future, which would result in such income being treated as Effectively Connected Income if we were classified as a corporation. U.S. Source Domestic Transportation Income generally would be treated as Effectively Connected Income. However, we do not anticipate that a material amount of our income has been, or will be, U.S. Source Domestic Transportation Income.

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%) and a 30% branch profits tax imposed under Section 884 of the Code. In addition, a branch interest tax could be imposed on certain interest paid or deemed paid by us if we were classified as a corporation.

On the sale of a vessel that has produced Effectively Connected Income, we generally would be subject to the net basis and branch profits taxes with respect to our gain recognized up to the amount of certain prior deductions for depreciation that reduced Effectively Connected Income. Otherwise, we would not be subject to U.S. federal income tax with respect to gain realized on sale of a vessel, provided the sale is considered to occur outside of the United States under U.S. federal income tax principles.

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The 4 Percent Gross Basis Tax. If we were to be treated as a corporation and if the Section 883 Exemption does not apply and we are not subject to the net basis and branch profits taxes described above, we would be subject to a 4% U.S. federal income tax on our U.S. Source International Transportation Income, without benefit of deductions. We estimate that, in this event, we would be subject to less than $700,000 of U.S. federal income tax in 2017 and in each subsequent year (in addition to any U.S. federal income taxes on our subsidiaries, as described below) based on the amount of U.S. Source International Transportation Income we earned for 2016 and our expected U.S. Source International Transportation Income for 2017 and subsequent years. The amount of such tax for which we would be liable in any year in which we were treated as a corporation for U.S. federal income tax purposes would depend upon the amount of income we earn from voyages into or out of the United States in such year, however, which is not within our complete control.

Consequences of Possible PFIC Classification.

A non-U.S. entity treated as a corporation for U.S. federal income tax purposes will be a 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% of its gross income is “passive” income or (ii) at least 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, 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. By contrast, income derived from the performance of services does not constitute “passive income.”

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 believe that we would not now 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.

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:

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

• the amount allocated to the current taxable year and any taxable year prior to the taxable year we were first treated as a PFIC with respect to the unitholder would be taxed as ordinary income in the current taxable year;

• the amount allocated to each of the other taxable years would be subject to U.S. federal income tax at the highest rate in effect for the applicable class of taxpayer for that year; and

• an interest charge for the deemed deferral benefit would be imposed with respect to the resulting tax attributable to each such other taxable year.

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.

Certain elections, such as a qualified electing fund (or QEF) election or mark to market election, may be available to a unitholder if we were classified as a PFIC. If we determine that we are or will be a PFIC, we will provide unitholders with information concerning the potential availability of such elections.

Taxation of Our Subsidiary Corporation

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% 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 2016 and will not apply in 2017 or subsequent years and therefore, the 4% gross basis tax applied to our subsidiary corporation in 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 2017 and in each subsequent year based on the amount of U.S. Source

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International Transportation Income our corporate subsidiary earned for 2016 and its expected U.S. Source International Transportation Income for 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.

As a non-U.S. entity classified as a corporation for U.S. federal income tax purposes, Teekay LNG Holdco L.L.C. could be considered a PFIC. However, we have received a ruling from the IRS that Teekay LNG Holdco L.L.C. will be classified as a controlled foreign corporation (or a CFC) rather than a PFIC as long as it is wholly-owned by a U.S. partnership.

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 the Tidewater decision in interpreting the PFIC provisions under the Code (as discussed above).

Canadian Federal Income Tax Considerations. The following discussion is a summary of the material Canadian federal income tax considerations under the Income Tax Act (Canada) (or the Canada Tax Act) that we believe are relevant to holders of units who, for the purposes of the Canada Tax Act and the Canada-United States Tax Convention 1980 (or the Canada-U.S. Treaty), are at all relevant times resident in the United States and entitled to all of the benefits of the Canada – U.S. Treaty and who deal at arm’s length with us and Teekay Corporation (or U.S. Resident Holders). This discussion takes into account all proposed amendments to the Canada Tax Act and the regulations thereunder that have been publicly announced by or on behalf of the Minister of Finance (Canada) prior to the date hereof and assumes that such proposed amendments will be enacted substantially as proposed. However, no assurance can be given that such proposed amendments will be enacted in the form proposed or at all. This discussion assumes that Teekay LNG Partners L.P. is, and will continue to be, classified as a partnership for United States federal income tax purposes.

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 Teekay LNG Partners L.P. to the U.S. Resident Holder in respect of such U.S. Resident Holder’s units, provided that for purposes of the Canada-U.S. Treaty, (a) 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 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 units, provided that, for purposes of the Canada-U.S. Treaty, such 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 the activities and affairs of Teekay LNG Partners L.P. are conducted in such a manner that 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 units. We intend that this is and continues to be the case, notwithstanding that Teekay Shipping Limited (a subsidiary of Teekay Corporation that is a non-resident of Canada) and 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 obtain some or all such services under subcontracts with Canadian service providers. If the arrangements we have entered into result in 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.

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.

Other Taxation

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, but we do not expect any such tax to be 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.”

Documents on Display

Documents concerning us that are referred to herein may be inspected at our principal executive offices at 4th Floor, Belvedere Building, 69 Pitts Bay Road, Hamilton, HM 08, Bermuda. Those documents electronically filed via the SEC’s Electronic Data Gathering, Analysis, and Retrieval (or EDGAR) system may also be obtained from the SEC’s website at www.sec.gov, free of charge, or from the SEC’s Public Reference Section at 100 F Street, NE, Washington, D.C. 20549, at prescribed rates. Further information on the operation of the SEC public reference rooms may be obtained by calling the SEC at 1-800-SEC-0330.

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Item 11. Quantitative and Qualitative Disclosures About Market Risk

Interest Rate Risk

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, 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.

Expected Maturity Date

	2017		2018		2019		2020		2021		There- after		Total		Fair Value Liability		Rate(1)
	(in millions of U.S. Dollars, except percentages)
Long-Term Debt:
Variable-Rate ($U.S.) (2)	127.2		490.8		73.6		52.7		174.0		295.2		1,213.5		(1,171.5	)	2.5	%
Variable-Rate (Euro) (3) (4)	15.6		124.8		8.9		9.6		10.3		50.5		219.7		(209.8	)	1.2	%
Variable-Rate (NOK) (4) (5)	47.3		104.2		—		115.7		104.1		—		371.3		(366.4	)	5.8	%
Capital Lease Obligations
Variable-Rate ($U.S.) (6)	40.3		39.1		13.5		14.3		14.9		270.7		392.8		(392.8	)	5.5	%
Average Interest Rate (7)	4.9	%	6.1	%	5.5	%	5.5	%	5.5	%	5.5	%	5.5	%
Interest Rate Swaps:(8)
Contract Amount ($U.S.) (9)	324.5		232.9		155.8		35.3		35.9		241.4		1,025.8		(52.3	)	3.6	%
Average Fixed-Pay Rate (2)	4.1	%	3.6	%	2.7	%	3.5	%	3.4	%	3.4	%	3.6	%
Contract Amount (Euro) (4) (10)	15.6		124.8		8.9		9.6		10.3		50.5		219.7		(34.3	)	3.1	%
Average Fixed-Pay Rate (3)	3.1	%	2.6	%	3.7	%	3.7	%	3.7	%	3.9	%	3.1	%

(1) Rate refers to the weighted-average effective interest rate for our long-term debt and capital lease obligations, including the margin we pay on our floating-rate debt and the average fixed pay rate for our interest rate swap agreements. The average interest rate for our capital lease obligations is the weighted-average interest rate implicit in our lease obligations at the inception of the leases. The average fixed pay rate for our interest rate swaps excludes the margin we pay on our drawn floating-rate debt, which as of December 31, 2016 ranged from 0.30% to 2.80%. Please read “Item 18 – Financial Statements: Note 10 – Long-Term Debt.”

(2) Interest payments on U.S. Dollar-denominated debt and interest rate swaps are based on LIBOR.

(3) Interest payments on Euro-denominated debt and interest rate swaps are based on EURIBOR.

(4) Euro-denominated and NOK-denominated amounts have been converted to U.S. Dollars using the prevailing exchange rate as of December 31, 2016.

(5) Interest payments on our NOK-denominated debt and on our cross-currency swaps are based on NIBOR. Our NOK-denominated bonds have been economically hedged with cross-currency swaps, to swap all interest and principal payments into U.S. Dollars, with the respective interest payments fixed at a rate ranging from 5.92% to 7.72%, and the transfer of principal locked in at $467.3 million upon maturities. Please see below in the foreign currency fluctuation section and read “Item 18 – Financial Statements: Note 12 – Derivative Instruments and Hedging Activities.”

(6) The amount of capital lease obligations represents the present value of minimum lease payments together with our purchase obligation, as applicable.

(7) The average interest rate is the weighted-average interest rate implicit in the capital lease obligations at the inception of the leases. Interest rate adjustments on certain of these leases have corresponding adjustments in charter receipts under the terms of the charter contracts to which these certain leases relate.

(8) The table above does not reflect our interest rate swaption agreements, whereby we have a one-time option to enter into an interest rate swap at a fixed rate with a third party, and the third party has a one-time option to require us to enter into an interest rate swap at a fixed rate. If we or the third party exercises its option, there will be cash settlements for the fair value of the interest rate swap in lieu of taking delivery of the actual interest rate swap. The net fair value of the interest rate swaption agreements as at December 31, 2016 was a liability of $0.9 million. Please read “Item 18 – Financial Statements: Note 12 – Derivative Instruments and Hedging Activities”.

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(9) The average variable receive rate for our U.S. Dollar-denominated interest rate swaps is set at 3-month or 6-month LIBOR.

(10) The average variable receive rate for our Euro-denominated interest rate swaps is set at 1-month EURIBOR.

Spot Market Rate Risk

One of our Suezmax tankers, the Toledo Spirit, operates pursuant to a time-charter contract that increases or decreases the otherwise fixed-rate established in the charter depending on the spot charter rates that we would have earned had we traded the vessel in the spot tanker market. The time-charter contract expires in August 2025, although the charterer has the right to terminate the time-charter in July 2018. We have entered into an agreement with Teekay Corporation under which Teekay Corporation pays us any amounts payable to the charterer as a result of spot rates being below the fixed rate, and we pay Teekay Corporation any amounts payable to us from the charterer as a result of spot rates being in excess of the fixed rate. The amounts payable to or receivable from Teekay Corporation are settled at the end of each year. At December 31, 2016, the fair value of this derivative asset was $2.1 million and the change from December 31, 2015 to the reporting period has been reported in realized and unrealized loss on non-designated derivative instruments.

Foreign Currency Fluctuations

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 208.9 million Euros ($219.7 million) and Euro-denominated restricted cash deposits of 18.3 million Euros ($19.2 million), respectively, as at December 31, 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 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 the NOK-denominated bonds due in 2017 through 2021. Please read “Item 18 – Financial Statements: Note 12 – Derivative Instruments and Hedging Activities.” At December 31, 2016, the fair value of the cross-currency swaps derivative liabilities was $99.8 million and the change from December 2015 to the reporting period has been reported in foreign currency exchange gain 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.

Item 12. Description of Securities Other than Equity Securities

Not applicable.

PART II

Item 13. Defaults, Dividend Arrearages and Delinquencies

None.

Item 14. Material Modifications to the Rights of Unitholders and Use of Proceeds

Not applicable.

Item 15. Controls and Procedures

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 the Exchange 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 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, 2016.

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The Chief Executive Officer and Chief Financial Officer of Service Provider do not expect that our disclosure controls or internal controls will prevent all 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.

Management’s Report on Internal Control over Financial Reporting

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, 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, 2016.

Item 16A. Audit Committee Financial Expert

The Board of Directors of our General Partner has determined that director Ms. Beverlee F. Park qualifies as an audit committee financial expert and is independent under applicable NYSE and SEC standards.

Item 16B. Code of Ethics

We have adopted a Standards of Business Conduct that applies to all our employees and the employees and directors of our General Partner. This document is available under “Investors – Teekay LNG Partners L.P.- Governance” from the home page of our web site (www.teekay.com). We intend to disclose, under “Investors – Teekay LNG Partners L.P. - Governance” in the Investors section of our web site, any waivers to or amendments of our Standards of Business Conduct for the benefit of any directors and executive officers of our General Partner.

Item 16C. Principal Accountant Fees and Services

Our principal accountant for 2016 and 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 2016 and 2015.

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Fees (in thousands of U.S. Dollars)	2016 $	2015 $
Audit Fees(1)	745	729
Audit-Related Fees(2)	—	3
Total	745	732

(1) Audit fees represent fees for professional services provided in connection with the audit of our consolidated financial statements, review of our quarterly consolidated financial statements, audit services provided in connection with other statutory audits and professional services in connection with the review of our regulatory filings for our equity offerings.

(2) Audit-related fees relate to other accounting consultations.

No fees for tax services were provided to the Partnership by the auditor during the term of their appointments in 2016 and 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 2016 and in 2015.

Item 16D. Exemptions from the Listing Standards for Audit Committees

Not applicable.

Item 16E. Purchases of Units by the Issuer and Affiliated Purchasers

Not applicable.

Item 16F. Change in Registrant’s Certifying Accountant

Not applicable.

Item 16G. Corporate Governance

As a foreign private issuer, we are not required to obtain unitholder approval prior to the adoption of equity compensation plans or certain equity issuances, including, among others, issuing 20% or more of our outstanding common units or voting power in a transaction.

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.

Item 16H. Mine Safety Disclosure

Not applicable.

PART III

Item 17. Financial Statements

Not applicable.

Item 18. Financial Statements

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:

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	Page
Reports of Independent Registered Public Accounting Firm	1,2
Consolidated Financial Statements
Consolidated Statements of Income	3
Consolidated Statements of Comprehensive Income	4
Consolidated Balance Sheets	5
Consolidated Statements of Cash Flows	6
Consolidated Statements of Changes in Total Equity	7
Notes to the Consolidated Financial Statements	8

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.

Item 19. Exhibits

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

1.1	Certificate of Limited Partnership of Teekay LNG Partners L.P. (1)
1.2	First Amended and Restated Agreement of Limited Partnership of Teekay LNG Partners L.P., dated May 10, 2005, as amended by Amendment No. 1 dated as of May 31, 2006 and Amendment No. 2 effective as of January 1, 2007. (2)
1.3	Certificate of Formation of Teekay GP L.L.C. (1)
1.4	Second Amended and Restated Limited Liability Company Agreement of Teekay GP L.L.C., dated March 2005, as amended by Amendment No. 1, dated February 25, 2008, and Amendment No.2, dated February 29, 2008. (3)
2.1	Agreement, dated April 30, 2012, for NOK 700,000,000, Senior Unsecured Bonds due May 2017, between Teekay LNG Partners L.P. and Norsk Tillitsmann ASA. (4)
2.2	Agreement, dated August 30, 2013, for NOK 900,000,000, Senior Unsecured Bonds due September 2018, between Teekay LNG Partners L.P. and Norsk Tillitsmann ASA. (5)
2.3	Agreement, dated May 18, 2015, for NOK 1,000,000,000, Senior Unsecured Bonds due May 2020, between Teekay LNG Partners L.P. and Nordic Trustee ASA. (17)
4.2	Amended Teekay LNG Partners L.P. 2005 Long-Term Incentive Plan. (3)
4.3	Amended and Restated Omnibus Agreement with Teekay Corporation, Teekay Offshore, our General Partner and related parties. (6)
4.4	Administrative Services Agreement with Teekay Shipping Limited. (3)
4.5	Advisory, Technical and Administrative Services Agreement between Teekay Shipping Spain S.L. and Teekay Shipping Limited. (3)
4.6	LNG Strategic Consulting and Advisory Services Agreement between Teekay LNG Partners L.P. and Teekay Shipping Limited. (3)
4.7	Syndicated Loan Agreement between Naviera Teekay Gas III, S.L. (formerly Naviera F. Tapias Gas III, S.A.) and Caixa de Aforros de Vigo Ourense e Pontevedra, as Agent, dated as of October 2, 2000, as amended. (3)
4.11	Agreement, dated August 23, 2006, for a U.S. $330,000,000 Secured Revolving Loan Facility between Teekay LNG Partners L.P., ING Bank N.V. and other banks. (7)
4.12	Purchase Agreement, dated November 2005, for the acquisition of Asian Spirit L.L.C., African Spirit L.L.C. and European Spirit L.L.C. (8)
4.13	Agreement, dated June 30, 2008, for a U.S. $172,500,000 Secured Revolving Loan Facility between Arctic Spirit L.L.C., Polar Spirit L.L.C. and DnB Nor Bank A.S.A. and other banks. (8)
4.14	Credit Facility Agreement between Taizhou L.L.C. and DHJS L.L.C. and Calyon, as Agent, dated as of October 27, 2009. (9)
4.16	Credit Facility Agreement between Great East Hull No. 1717 L.L.C., Great East Hull No. 1718 L.L.C., H.S.H.I. Hull No. S363 L.L.C., H.S.H.I. Hull No. S364 L.L.C. and Calyon, dated December 15, 2006. (10)
4.17	Agreement, dated September 30, 2011, for a EURO 149,933,766 Credit Facility between Naviera Teekay Gas IV S.L.U., ING Bank N.V. and other banks. (11)
4.18	Deed of Amendment and Restatement dated October 10, 2008, relating to a Loan Agreement for a U.S. $92,400,000 Buyer Credit and a U.S. $117,600,000 Commercial Loan between MiNT LNG I, Ltd., BNP Paribas S.A., and other banks. (12)

88

4.19	Deed of Amendment and Restatement dated October 10, 2008, relating to a Loan Agreement for a U.S. $92,400,000 Buyer Credit and a U.S. $117,600,000 Commercial Loan between MiNT LNG II, Ltd. , BNP Paribas S.A., and other banks. (12)
4.20	Deed of Amendment and Restatement dated October 10, 2008, relating to a Loan Agreement for a U.S. $92,400,000 Buyer Credit and a U.S. $117,600,000 Commercial Loan between MiNT LNG III, Ltd ., BNP Paribas S.A., and other banks. (12)
4.21	Deed of Amendment and Restatement dated November 10, 2008, relating to a Loan Agreement for a U.S. $92,400,000 Buyer Credit and a U.S. $117,600,000 Commercial Loan between MiNT LNG IV, Ltd., BNP Paribas S.A., and other banks. (12)
4.22	Share purchase agreement dated February 28, 2012 to purchase Maersk LNG A/S through the Teekay LNG- Marubeni Joint Venture from AP Moller-Maersk A/S. (12)
4.23	Agreement dated January 1, 2012, for business development services between Teekay LNG Operating L.L.C. and Teekay Shipping Limited. (13)
4.24	Agreement dated June 27, 2013, for U.S. $195,000,000 senior secured notes between Meridian Spirit ApS and Wells Fargo Bank Northwest N.A. (14)
4.25	Agreement dated June 28, 2013, for U.S. $160,000,000 loan facility between Malt Singapore Pte. Ltd. and Commonwealth Bank of Australia. (14)
4.26	Agreement dated July 30, 2013, for U.S. $608,000,000 loan facility between Malt LNG Netherlands Holdings B.V. and DNB Bank ASA, acting as agent and security trustee. (14)
4.27	Agreement dated December 9, 2013, for U.S. $125,000,000 loan facility between Wilforce L.L.C. and Credit Suisse AG and others. (5)
4.28	Agreement dated February 12, 2013; Teekay Luxembourg S.a.r.l. entered into a share purchase agreement with Exmar NV and Exmar Marine NV to purchase 50% of the shares in Exmar LPG BVBA. (5)
4.29	Agreement dated July 7, 2014; Teekay LNG Operating L.L.C. entered into a shareholder agreement with China LNG Shipping (Holdings) Limited to form TC LNG Shipping L.L.C. in connection with the Yamal LNG Project. (15)
4.30	Agreement dated December 17, 2014, for U.S. $450,000,000 loan facility between Nakilat Holdco L.L.C. and Qatar National Bank SAQ. (15)
4.31	Agreement dated November 7, 2014, for a U.S. $175,000,000 secured loan facility between Solaia Shipping L.L.C. and Excelsior BVBA, and Nordea Bank Norge ASA and other banks. (16)
4.33	Agreement dated March 28, 2014, for U.S. $130,000,000 secured loan facility between Wilpride L.L.C. and Nordea Bank Finland and other banks. (17)
4.34	Amending and Restating Agreement dated June 5, 2015, for a U.S. $460,000,000 secured loan facility between Exmar LPG BVBA and Nordea Bank Norge ASA and other banks. (17)
4.36	Agreement dated May 4, 2016, for a U.S. $60,000,000 secured loan facility between African Spirit L.L.C., European Spirit L.L.C. and Asian Spirit L.L.C., and Scotiabank Europe plc. (18)
4.37	Agreement dated November 15, 2016, for a U.S. $730,000,000 Secured Loan Facility between Bahrain LNG W.L.L. and Standard Chartered Bank and other banks.
4.38	Agreement dated November 17, 2016, for U.S. $170,000,000 unsecured Revolving Credit Facility between Teekay LNG Partners L.P. and Citigroup Global Markets Limited and other banks.
4.39	Agreement dated December 21, 2016, for a U.S. $723,200,000 Secured Loan Facility between Teekay Nakilat (III) Corporation and Qatar National Bank SAQ.
4.40	Agreement dated February 11, 2016 for a sale leaseback agreement between Creole Spirit L.L.C. and Hai Jiao 1601 Limited (a subsidiary of ICBC Financial Leasing Co., Ltd.).
4.41	Agreement dated February 11, 2016 for a sale leaseback agreement between Oak Spirit L.L.C. and Hai Jiao 1602 Limited (a subsidiary of ICBC Financial Leasing Co., Ltd.).
4.42	Agreement dated December 20, 2016 for a sale leaseback agreement between DSME Hull No. 2416 L.L.C. and Hai Jiao 1605 Limited (a subsidiary of ICBC Financial Leasing Co., Ltd.).
4.43	Agreement dated December 20, 2016 for a sale leaseback agreement between DSME Option Vessel No.1 L.L.C. and Hai Jiao 1606 Limited (a subsidiary of ICBC Financial Leasing Co., Ltd.).
4.44	Agreement dated December 20, 2016 for a sale leaseback agreement between DSME Option Vessel No.3 L.L.C. and Hai Jiao 1607 Limited (a subsidiary of ICBC Financial Leasing Co., Ltd.).
8.1	List of Subsidiaries of Teekay LNG Partners L.P.
12.1	Rule 13a-15(e)/15d-15(e) Certification of Mark Kremin, President and Chief Executive Officer of Teekay Gas Group Ltd.
12.2	Rule 13a-15(e)/15d-15(e) Certification of Brody Speers, Chief Financial Officer of Teekay Gas Group Ltd.
13.1	Certification of Mark Kremin, President and Chief Executive Officer of Teekay Gas Group Ltd., pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

89

13.2	Certification of Brody Speers, Chief Financial Officer of Teekay Gas Group Ltd., pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
15.1	Consent of KPMG LLP, as independent registered public accounting firm, for Teekay LNG Partners L.P.
15.2	Consolidated Financial Statements of Exmar LPG BVBA.
101.INS	XBRL Instance Document.
101.SCJ	XBRL Taxonomy Extension Schema.
101.CAL	XBRL Taxonomy Extension Calculation Linkbase.
101.DEF	XBRL Taxonomy Extension Definition Linkbase.
101.LAB	XBRL Taxonomy Extension Label Linkbase.
101.PRE	XBRL Taxonomy Extension Presentation Linkbase.

____________________________

(1) Previously filed as an exhibit to the Partnership’s Registration Statement on Form F-1 (File No. 333-120727), filed with the SEC on November 24, 2004, and hereby incorporated by reference to such Annual Report.

(2) Previously filed as an exhibit to the Partnership’s Report on Form 20F filed with the SEC on April 4, 2011, and hereby incorporated by reference to such Report.

(3) Previously filed as an exhibit to the Partnership’s Amendment No. 3 to Registration Statement on Form F-1 (File No. 333-120727), filed with the SEC on April 11, 2005, and hereby incorporated by reference to such Registration Statement.

(4) Previously filed as an exhibit to the Partnership’s Report on Form 6-K filed with the SEC on September 27, 2012, and hereby incorporated by reference to such Report.

(5) Previously filed as an exhibit to the Partnership’s Annual Report on Form 20-F (File No. 1-32479), filed with the SEC on April 29, 2014 and hereby incorporated by reference to such report.

(6) Previously filed as an exhibit to the Partnership’s Annual Report on Form 20-F (File No. 1-32479), filed with the SEC on April 19, 2007 and hereby incorporated by reference to such report.

(7) Previously filed as an exhibit to the Partnership’s Report on Form 6-K (File No. 1-32479), filed with the SEC on December 21, 2006 and hereby incorporated by reference to such report.

(8) Previously filed as an exhibit to the Partnership’s Report on Form 6-K (File No. 1-32479), filed with the SEC on March 20, 2009 and hereby incorporated by reference to such report.

(9) Previously filed as an exhibit to the Partnership’s Report on Form 20F (File No. 1-32479), filed with the SEC on April 26, 2010 and hereby incorporated by reference to such report.

(10) Previously filed as an exhibit to the Partnership’s Report on Form 6-K (File No. 1-32479), filed with the SEC on June 1, 2010 and hereby incorporated by reference to such report.

(11) Previously filed as an exhibit to the Partnership’s Report on Form 6-K (File No. 1-32479), filed with the SEC on December 1, 2011 and hereby incorporated by reference to such report.

(12) Previously filed as an exhibit to the Partnership’s Report on Form 20-F (File No. 1-32479), filed with the SEC on April 11, 2011 and hereby incorporated by reference to such report.

(13) Previously filed as an exhibit to the Partnership’s Report on Form 20-F (File No. 1-32479), filed with the SEC on April 16, 2012 and hereby incorporated by reference to such report.

(14) Previously filed as an exhibit to the Partnership’s Report on Form 6-K (File No. 1-32479), filed with the SEC on November 27, 2013 and hereby incorporated by reference to such report.

(15) Previously filed as an exhibit to the Partnership’s Annual Report on Form 20-F (File No. 1-32479), filed with the SEC on April 23, 2015 and hereby incorporated by reference to such report.

(16) Previously filed as an exhibit to the Partnership’s Report on Form 6-K (File No. 1-32479), filed with the SEC on May 26, 2015 and hereby incorporated by reference to such report.

(17) Previously filed as an exhibit to the Partnership’s Annual Report on Form 20-F (File No. 1-32479), filed with the SEC on April 27, 2016 and hereby incorporated by reference to such report.

(18) Previously filed as an exhibit to the Partnership’s Report on Form 6-K (File No. 1-32479), filed with the SEC on August 19, 2016 and hereby incorporated by reference to such report.

90

SIGNATURE

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.

	TEEKAY LNG PARTNERS L.P.
	By:	Teekay GP L.L.C., its General Partner
Date: April 25, 2017	By:	/s/ Edith Robinson
		Edith Robinson
		Corporate Secretary

91

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Unitholders of Teekay LNG Partners L.P.

We have audited the accompanying consolidated balance sheets of Teekay LNG Partners L.P. and subsidiaries (the “Partnership”) as of December 31, 2016 and 2015, and the related consolidated statements of income, comprehensive income, cash flows, and changes in total equity for each of the years in the three-year period ended December 31, 2016. These consolidated financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Partnership as of December 31, 2016 and 2015, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2016, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Partnership’s internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated April 25, 2017 expressed an unqualified opinion on the effectiveness of the Partnership’s internal control over financial reporting.

Chartered Professional Accountants

Vancouver, Canada

April 25, 2017

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Unitholders of Teekay LNG Partners L.P.

We have audited Teekay LNG Partners L.P. and subsidiaries (the “Partnership") internal control over financial reporting as of December 31, 2016, based on the criteria established in Internal Control- Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Partnership's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting in the accompanying Form 20-F. Our responsibility is to express an opinion on the Partnership's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

An entity's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. An entity's internal control over financial reporting includes 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 the assets of the entity; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with U.S. generally accepted accounting principles, and that receipts and expenditures of the entity are being made only in accordance with authorizations of management and directors of the entity; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the entity's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. 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 or procedures may deteriorate.

In our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016, based on the criteria established in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of the Partnership as of December 31, 2016 and 2015, and the related consolidated statements of income, comprehensive income, cash flows, and changes in total equity for each of the years in the three-year period ended December 31, 2016, and our report dated April 25, 2017, expressed an unqualified opinion on those consolidated financial statements.

Chartered Professional Accountants Vancouver, Canada

April 25, 2017

F-2

TEEKAY LNG PARTNERS L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(in thousands of U.S. Dollars, except unit and per unit data)

	Year Ended December 31, 2016 $		Year Ended December 31, 2015 $		Year Ended December 31, 2014 $
Voyage revenues (note 11)	396,444		397,991		402,928
Voyage expenses	(1,656	)	(1,146	)	(3,321	)
Vessel operating expenses (note 11)	(88,590	)	(94,101	)	(95,808	)
Depreciation and amortization	(95,542	)	(92,253	)	(94,127	)
General and administrative expenses (notes 11 and 16)	(18,499	)	(25,118	)	(23,860	)
Restructuring charges (note 17)	—		(4,001	)	(1,989	)
Write-down and loss on sale of vessels (note 18)	(38,976	)	—		—
Income from vessel operations	153,181		181,372		183,823
Equity income (notes 6 and 13d)	62,307		84,171		115,478
Interest expense	(58,844	)	(43,259	)	(60,414	)
Interest income	2,583		2,501		3,052
Realized and unrealized loss on non-designated derivative instruments (note 12)	(7,161	)	(20,022	)	(44,682	)
Foreign currency exchange gain (notes 9 and 12)	5,335		13,943		28,401
Other income	1,537		1,526		836
Net income before income tax expense	158,938		220,232		226,494
Income tax expense (note 10)	(973	)	(2,722	)	(7,567	)
Net income	157,965		217,510		218,927
Non-controlling interest in net income	17,514		16,627		13,489
Preferred unitholders' interest in net income	2,719		—		—
General Partner's interest in net income	2,755		26,276		31,187
Limited partners’ interest in net income	134,977		174,607		174,251
Limited partners’ interest in net income per common unit (note 15):
• Basic	1.70		2.21		2.30
• Diluted	1.69		2.21		2.30
Weighted-average number of common units outstanding (note 15):
• Basic	79,568,352		78,896,767		75,664,435
• Diluted	79,671,858		78,961,102		75,702,886
Cash distributions declared per common unit	0.56		2.80		2.77

Related party transactions (note 11)

Subsequent events (notes 18b and 19)

The accompanying notes are an integral part of the consolidated financial statements.

F-3

TEEKAY LNG PARTNERS L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in thousands of U.S. Dollars)

	Year Ended December 31, 2016 $		Year Ended December 31, 2015 $		Year Ended December 31, 2014 $
Net income	157,965		217,510		218,927
Other comprehensive income (loss) :
Other comprehensive income (loss) before reclassifications
Unrealized loss on qualifying cash flow hedging instruments, net of tax (note 12)	(486	)	(1,723	)	(3,085	)
Amounts reclassified from accumulated other comprehensive income (loss)
To equity income:
Realized loss on qualifying cash flow hedging instruments	3,289		1,075		1,551
Other comprehensive income (loss)	2,803		(648	)	(1,534	)
Comprehensive income	160,768		216,862		217,393
Non-controlling interest in comprehensive income	17,691		16,627		13,489
Preferred unitholders' interest in comprehensive income (note 15)	2,719		—		—
General and limited partners' interest in comprehensive income	140,358		200,235		203,904

The accompanying notes are an integral part of the consolidated financial statements.

F-4

TEEKAY LNG PARTNERS L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands of U.S. Dollars)

	As at December 31, 2016 $	As at December 31, 2015 $
ASSETS
Current
Cash and cash equivalents	126,146	102,481
Restricted cash - current (note 5)	10,145	6,600
Accounts receivable, including non-trade of $19,325 (2015 – $7,058) (note 6a iii)	25,224	22,081
Prepaid expenses	3,724	4,469
Vessel held for sale (note 18)	20,580	—
Current portion of derivative assets (note 12)	531	—
Current portion of net investments in direct financing leases (note 5)	150,342	20,606
Advances to affiliates (notes 11g and 12)	9,739	13,026
Total current assets	346,431	169,263
Restricted cash – long-term (note 5)	106,882	104,919
Vessels and equipment
At cost, less accumulated depreciation of $668,969 (2015 – $666,710)	1,374,128	1,595,077
Vessels under capital leases, at cost, less accumulated depreciation of $69,072 (2015 – $56,316) (note 5)	484,253	88,215
Advances on newbuilding contracts (notes 11f and 13a)	357,602	424,868
Total vessels and equipment	2,215,983	2,108,160
Investment in and advances to equity accounted joint ventures (note 6)	1,037,726	883,731
Net investments in direct financing leases (note 5)	492,666	646,052
Other assets (note 6a iii)	5,529	20,811
Derivative assets (note 12)	4,692	5,623
Intangible assets – net (note 7)	69,934	78,790
Goodwill – liquefied gas segment (note 7)	35,631	35,631
Total assets	4,315,474	4,052,980
LIABILITIES AND EQUITY
Current
Accounts payable	5,562	2,770
Accrued liabilities (notes 8, 12 and 17)	35,881	37,456
Unearned revenue (note 5)	16,998	19,608
Current portion of long-term debt (note 9)	188,511	197,197
Current obligations under capital lease (note 5)	40,353	4,546
Current portion of in-process contracts (note 6a iii)	15,833	12,173
Current portion of derivative liabilities (note 12)	56,800	52,083
Advances from affiliates (notes 11g and 12)	15,492	22,987
Total current liabilities	375,430	348,820
Long-term debt (note 9)	1,602,715	1,802,012
Long-term obligations under capital lease (note 5)	352,486	54,581
Long-term unearned revenue	10,332	30,333
Other long-term liabilities (notes 5, 6a and 6b)	60,573	71,152
In-process contracts (note 6a iii)	8,233	20,065
Derivative liabilities (note 12)	128,293	182,338
Total liabilities	2,538,062	2,509,301
Commitments and contingencies (notes 5, 6, 9, 12, and 13)
Equity
Limited Partners - common units (79.6 million units issued and outstanding at December 31, 2016 and 2015) (note 15)	1,563,852	1,472,327
Limited Partners - preferred units (5.0 million and nil units issued and outstanding at December 31, 2016 and 2015, respectively) (note 15)	123,426	—
General Partner	50,653	48,786
Accumulated other comprehensive income (loss)	575	(2,051	)
Partners' equity	1,738,506	1,519,062
Non-controlling interest	38,906	24,617
Total equity	1,777,412	1,543,679
Total liabilities and total equity	4,315,474	4,052,980

The accompanying notes are an integral part of the consolidated financial statements.

F-5

TEEKAY LNG PARTNERS L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands of U.S. Dollars)

	Year Ended December 31, 2016 $		Year Ended December 31, 2015 $		Year Ended December 31, 2014 $
Cash and cash equivalents provided by (used for)
OPERATING ACTIVITIES
Net income	157,965		217,510		218,927
Non-cash items:
Unrealized (gain) loss on derivative instruments (note 12)	(19,433	)	(12,375	)	2,096
Depreciation and amortization	95,542		92,253		94,127
Write-down and loss on sale of vessels	38,976		—		—
Unrealized foreign currency exchange gain and other                  (notes 9 and 12)	(42,009	)	(26,090	)	(24,931	)
Equity income, net of dividends received of $31,113 (2015 – $97,146 and 2014 – $11,005)	(31,194	)	12,975		(104,473	)
Change in operating assets and liabilities (note 14a)	(20,669	)	(34,187	)	18,822
Expenditures for dry docking	(12,686	)	(10,357	)	(13,471	)
Net operating cash flow	166,492		239,729		191,097
FINANCING ACTIVITIES
Proceeds from issuance of long-term debt	573,514		391,574		944,123
Scheduled repayments of long-term debt	(316,450	)	(126,557	)	(100,804	)
Prepayments of long-term debt	(463,422	)	(90,000	)	(608,501	)
Debt issuance costs	(3,462	)	(2,856	)	(6,431	)
Scheduled repayments and prepayments of capital lease obligations	(21,594	)	(4,423	)	(479,115	)
Proceeds from equity offerings, net of offering costs (note 15)	120,707		35,374		182,139
Decrease (increase) in restricted cash	4,651		(30,321	)	448,914
Cash distributions paid	(45,467	)	(255,519	)	(240,525	)
Novation of derivative liabilities (note 11e)	—		—		2,985
Dividends paid to non-controlling interest	(3,402	)	(1,629	)	(42,716	)
Net financing cash flow	(154,925	)	(84,357	)	100,069
INVESTING ACTIVITIES
Purchase of and additional capital contributions in equity accounted investments	(120,879	)	(25,852	)	(100,200	)
Loan repayments from equity accounted joint ventures	5,500		23,744		631
Receipts from direct financing leases	23,650		15,837		17,200
Proceeds from sale of vessels (note 18a)	94,311		—		—
Proceeds from sale-lease back of vessels	355,306		—		—
Expenditures for vessels and equipment (note 14e)	(345,790	)	(191,969	)	(188,855	)
Increase in restricted cash	—		(34,290	)	—
Other	—		—		216
Net investing cash flow	12,098		(212,530	)	(271,008	)
Increase (decrease) in cash and cash equivalents	23,665		(57,158	)	20,158
Cash and cash equivalents, beginning of the year	102,481		159,639		139,481
Cash and cash equivalents, end of the year	126,146		102,481		159,639

Supplemental cash flow information (note 14)

The accompanying notes are an integral part of the consolidated financial statements.

F-6

TEEKAY LNG PARTNERS L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN TOTAL EQUITY

(in thousands of U.S. Dollars)

	TOTAL EQUITY
	Partners’ Equity
	Limited Partners
	Common Units	Common Units		Preferred Units	Preferred Units	General Partner		Accumulated Other Comprehensive Income (Loss)		Non- controlling Interest		Total
	#	$		#	$	$		$		$		$
Balance as at December 31, 2013	74,196	1,338,133		—	—	52,526		131		52,994		1,443,784
Net income	—	174,251		—	—	31,187		—		13,489		218,927
Other comprehensive loss	—	—		—	—	—		(1,534	)	—		(1,534	)
Cash distributions	—	(209,625	)	—	—	(30,900	)	—		—		(240,525	)
Dividends paid to non-controlling interest	—	—		—	—	—		—		(57,080	)	(57,080	)
Equity based compensation	17	1,415		—	—	29		—		—		1,444
Proceeds from equity offerings	4,140	178,473		—	—	3,666		—		—		182,139
Sale of 1% interest in Norgas Napa to General Partner (note 11d)	—	—		—	—	—		—		216		216
Balance as at December 31, 2014	78,353	1,482,647		—	—	56,508		(1,403	)	9,619		1,547,371
Net income	—	174,607		—	—	26,276		—		16,627		217,510
Other comprehensive loss	—	—		—	—	—		(648	)	—		(648	)
Cash distributions	—	(220,772	)	—	—	(34,747	)	—		—		(255,519	)
Dividends paid to non-controlling interest	—	—		—	—	—		—		(1,629	)	(1,629	)
Equity based compensation, net of tax of $0.4 million	25	1,196		—	—	24		—		—		1,220
Proceeds from equity offerings	1,173	34,649		—	—	725		—		—		35,374
Balance as at December 31, 2015	79,551	1,472,327		—	—	48,786		(2,051	)	24,617		1,543,679
Net income	—	134,977		—	2,719	2,755		—		17,514		157,965
Other comprehensive income	—	—		—	—	—		2,626		177		2,803
Cash distributions	—	(44,557	)	—	—	(910	)	—		—		(45,467	)
Dividends paid to non-controlling interest	—	—		—	—	—		—		(3,402	)	(3,402	)
Equity based compensation, net of tax of $0.2 million	21	1,105		—	—	22		—		—		1,127
Proceeds from equity offerings	—	—		5,000	120,707	—		—		—		120,707
Balance as at December 31, 2016	79,572	1,563,852		5,000	123,426	50,653		575		38,906		1,777,412

The accompanying notes are an integral part of the consolidated financial statements.

F-7

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)

1. Summary of Significant Accounting Policies

Basis of Presentation

The consolidated financial statements have been prepared in accordance with United States generally accepted accounting principles (or GAAP). These financial statements include the accounts of Teekay LNG Partners L.P. (or the Partnership), which is a limited partnership organized under the laws of the Republic of The Marshall Islands and its wholly owned or controlled subsidiaries. The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results may differ from those estimates.

Significant intercompany balances and transactions have been eliminated upon consolidation. In addition, certain of the comparative figures have been reclassified to conform to the presentation adopted in the current period relating to certain operating activities in the Partnership's consolidated statements of cash flows and certain of the summarized financial information in Note 6c.

Foreign currency

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.

Operating revenues and expenses

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 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.

Cash and cash equivalents

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 and allowance for doubtful accounts

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.

Vessels and equipment

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.

Depreciation is calculated on a straight-line basis over a vessel’s estimated useful life, less an estimated residual value. Depreciation is calculated using an estimated useful life of 25 years for conventional tankers, 30 years for liquefied petroleum gas (or LPG) carriers and 35 years for liquefied natural gas (or LNG) carriers, from the date the vessel is delivered from the shipyard, or a shorter period if regulations prevent the Partnership from operating the vessels for 25 years, 30 years, or 35 years, respectively. Depreciation of vessels and equipment for the years ended December 31, 2016, 2015 and 2014 aggregated $86.6 million, $83.4 million and $70.1 million, respectively. Depreciation and amortization includes depreciation on all owned vessels and amortization of vessels accounted for as capital leases.

F-8

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)

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 aggregated $9.9 million, $8.2 million and $3.1 million, respectively.

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 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.

The following table summarizes the change in the Partnership’s capitalized dry docking costs, from January 1, 2014 to December 31, 2016:

	Year Ended December 31,
	2016 $		2015 $		2014 $
Balance at January 1,	33,916		33,635		40,328
Cost incurred for dry docking	13,944		10,357		13,471
Sales of vessels	(2,886	)	—		(5,327	)
Dry-dock amortization	(11,436	)	(10,076	)	(14,837	)
Balance at December 31,	33,538		33,916		33,635

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.

Investments in and advances to equity accounted joint ventures

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.

Debt issuance costs

Debt issuance costs, including fees, commissions and legal expenses, are presented as 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.

F-9

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)

Goodwill and intangible assets

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.

Derivative instruments

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.

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.

For derivative financial instruments that are not designated or that do not qualify as hedges under Financial Accounting Standards Board (or FASB) Accounting Standards Codification (or ASC) 815, Derivatives and Hedging, the changes in the fair value of the derivative financial instruments are recognized in earnings. Gains and losses from the Partnership’s non-designated interest rate swaps, interest rate swaptions, and the Partnership’s agreement with Teekay Corporation for the Suezmax tanker the Toledo Spirit (see Note 11c) are recorded in realized and unrealized loss on non-designated derivative instruments in the Partnership’s consolidated statements of income. Gains and losses from the Partnership’s cross currency swaps are recorded in foreign exchange gain in the Partnership’s consolidated statements of income.

Unit-based compensation

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.

Income taxes

The Partnership accounts for income taxes using the liability method. All but two of the Partnership’s Spanish-flagged vessels are subject to the Spanish Tonnage Tax Regime (or TTR). Under this regime, the applicable tax is based on the weight (measured as net tonnage) of the vessel and the number of days during the taxable period that the vessel is at the Partnership’s disposal, excluding time required for repairs. The income the Partnership receives with respect to the remaining two Spanish-flagged vessels is taxed in Spain at a rate of 25%. However,

F-10

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)

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 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.

Guarantees

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 on the Partnership’s consolidated statements of income 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.

Accumulated other comprehensive income (loss)

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

	Qualifying Cash Flow Hedging Instruments $
Balance as at December 31, 2013	131
Other comprehensive loss	(1,534	)
Balance as at December 31, 2014	(1,403	)
Other comprehensive loss	(648	)
Balance as at December 31, 2015	(2,051	)
Other comprehensive income	2,626
Balance as at December 31, 2016	575

2. Accounting Pronouncements

In May 2014, the FASB issued Accounting Standards Update 2014-09, Revenue from Contracts with Customers, (or ASU 2014-09). ASU 2014-09 will require an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This update creates a five-step model that requires entities to exercise judgment when considering the terms of the contract(s) which include (i) identifying the contract(s) with the customer, (ii) identifying the separate performance obligations in the contract, (iii) determining the transaction price, (iv) allocating the transaction price to the separate performance obligations, and (v) recognizing revenue as each performance obligation is satisfied. ASU 2014-09 is effective for the Partnership on January 1, 2018 and shall be applied, at the Partnership’s option, retrospectively to each period presented or as a cumulative-effect adjustment as of the date of adoption. The Partnership’s only significant source of revenue that will be accounted for pursuant to ASU 2014-09 is its non-lease portion of time-charter contracts. Based on the Partnership’s preliminary assessment of ASU 2014-09, when applied to the standard terms of the Partnership’s time-charter contracts, no significant impact on the accounting for the non-lease portion of time-charter contracts is expected. The Partnership is in the process of validating aspects of its preliminary assessment of ASU 2014-09, determining the transitional impact and completing other items required for the adoption of ASU 2014-09.

In February 2016, the FASB issued Accounting Standards Update 2016-02, Leases (or ASU 2016-02). ASU 2016-02 establishes a right-of-use model that requires a lessee to record a right of use asset and a lease liability on the balance sheet for all leases with terms longer than 12 months. Leases will be classified as either finance or operating, with classification affecting the pattern of expense recognition in the income statement. The Partnership expects to adopt ASU 2016-02 on January 1, 2018. A modified retrospective transition approach is required for lessees for capital and operating leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements, with certain practical expedients available. The Partnership’s lessee-related leasing activities primarily consist of on-balance sheet finance leases. The accounting for such transactions is not significantly impacted by ASU 2016-02. The Partnership also has extensive lessor-related leasing activities, which consist of bareboat charter contracts and the lease portion of time-charter contracts. However, ASU 2016-02 does not make extensive changes to lessor accounting. Based on the Partnership’s preliminary assessment of ASU 2016-02 no significant impact on the accounting for its lessor-related leasing activities is expected. The Partnership is in the process of validating aspects of its preliminary assessment of ASU 2016-02, determining the transitional impact and completing other items required for the adoption of ASU 2016-02.

F-11

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)

In June 2016, the FASB issued Accounting Standards Update 2016-13, Financial Instruments - Credit Losses: Measurement of Credit Losses

on Financial Instruments. This update replaces the incurred loss impairment methodology with a methodology that reflects expected credit

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.

In August 2016, the FASB issued Accounting Standards Update 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts

and Cash Payments, which, among other things, provides guidance on two acceptable approaches of classifying distributions received from

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.

3. Financial Instruments

a) Fair Value Measurements

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

Cash and cash equivalents and restricted cash – The fair value of the Partnership’s cash and cash equivalents and restricted cash approximates its carrying amounts reported in the consolidated balance sheets.

Interest rate swap/swaption and cross-currency swap agreements – The fair value of the Partnership’s derivative instruments is the estimated amount that the Partnership would receive or pay to terminate the agreements at the reporting date, taking into account current interest rates, foreign exchange rates and the current credit worthiness of both the Partnership and the derivative counterparties. The estimated amount is the present value of future cash flows. The Partnership transacts all of its derivative instruments through investment-grade rated financial institutions at the time of the transaction and requires no collateral from these institutions. Given the current volatility in the credit markets, it is reasonably possible that the amount recorded as a derivative asset or liability could vary by a material amount in the near term.

Other derivative – The Partnership’s other derivative agreement is between Teekay Corporation and the Partnership and relates to hire payments under the time-charter contract for the Suezmax tanker Toledo Spirit (see Note 11c). The fair value of this derivative agreement is the estimated amount that the Partnership would receive or pay to terminate the agreement at the reporting date, based on the present value of the Partnership’s projection of future spot market tanker rates, which have been derived from current spot market tanker rates and long-term historical average rates. As projections of future spot rates are specific to the Partnership, these are considered Level 3 inputs for the purposes of estimating the fair value.

Long-term receivable included in accounts receivable and other assets – The fair values of the Partnership’s long-term loan receivable is estimated using discounted cash flow analysis based on rates currently available for debt with similar terms and remaining maturities and the current credit worthiness of the counterparty.

Long-term debt – The fair values of the Partnership’s fixed-rate and variable-rate long-term debt is either based on quoted market prices or estimated using discounted cash flow analyses based on rates currently available for debt with similar terms and remaining maturities and the current credit worthiness of the Partnership.

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.

F-12

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)

		December 31, 2016				December 31, 2015
	Fair Value Hierarchy Level	Carrying Amount Asset (Liability) $		Fair Value Asset (Liability) $		Carrying Amount Asset (Liability) $		Fair Value Asset (Liability) $
Recurring:
Cash and cash equivalents and restricted cash	Level 1	243,173		243,173		214,000		214,000
Derivative instruments (note 12)
Interest rate swap agreements – assets	Level 2	1,080		1,080		—		—
Interest rate swap agreements – liabilities	Level 2	(87,681	)	(87,681	)	(104,137	)	(104,137	)
Interest rate swaption agreements – assets	Level 2	3,283		3,283		5,623		5,623
Interest rate swaption agreements – liabilities	Level 2	(4,230	)	(4,230	)	(6,406	)	(6,406	)
Cross-currency swap agreements	Level 2	(99,786	)	(99,786	)	(128,782	)	(128,782	)
Other derivative	Level 3	2,134		2,134		(6,296	)	(6,296	)
Non-recurring:
Vessel held for sale	Level 2	20,580		20,580		—		—
Other:
Advances to equity accounted joint ventures (note 6)	(i)	272,514		(i)		159,870		(i)
Long-term receivable included in accounts receivable and other assets (ii)	Level 3	10,985		10,944		16,453		16,427
Long-term debt – public (note 9)	Level 1	(368,612	)	(366,418	)	(291,247	)	(288,333	)
Long-term debt – non-public (note 9)	Level 2	(1,422,614	)	(1,381,287	)	(1,707,962	)	(1,677,139	)

(i) The advances to equity accounted joint ventures together with the Partnership’s equity investments in the joint ventures form the net aggregate carrying value of the Partnership’s interests in the joint ventures in these consolidated financial statements. The fair values of the individual components of such aggregate interests are not determinable.

(ii) As at December 31, 2016, the estimated fair value of the non-interest bearing receivable is based on the remaining future fixed payments of $10.9 million to be received from Royal Dutch Shell Plc (or Shell) (formerly BG International Limited (or BG)), as part of the ship construction support agreement, as well as an estimated discount rate of 8.0%. As there is no market rate for the equivalent of an unsecured non-interest bearing receivable from Shell, the discount rate is based on unsecured debt instruments of similar maturity held, adjusted for a liquidity premium. A higher or lower discount rate would result in a lower or higher fair value asset.

Changes in fair value during the years ended December 31, 2016 and 2015 for the Partnership’s other derivative asset, the Toledo Spirit time-charter derivative, which is described below and is measured at fair value on a recurring basis using significant unobservable inputs (Level 3), are as follows:

	Year Ended December 31,
	2016 $		2015 $
Fair value at beginning of year	(6,296	)	(2,137	)
Realized and unrealized gains (losses) included in earnings	3,316		(5,039	)
Settlements	5,114		880
Fair value at end of year	2,134		(6,296	)

The Partnership’s Suezmax tanker the Toledo Spirit operates pursuant to a time-charter contract that increases or decreases the otherwise fixed-hire rate established in the charter depending on the spot charter rates that the Partnership would have earned had it traded the vessel in the spot tanker market. The time-charter contract ends in August 2025, although the charterer has the right to terminate the time-charter contract in July 2018. In order to reduce the variability of its revenue under the Toledo Spirit time-charter, the Partnership entered into an agreement with Teekay Corporation under which Teekay Corporation pays the Partnership any amounts payable to the charterer of the Toledo Spirit as a result of spot rates being below the fixed rate, and the Partnership pays Teekay Corporation any amounts payable to the Partnership by the charterer of the Toledo Spirit as a result of spot rates being in excess of the fixed rate. The estimated fair value of this other derivative is based in part upon the Partnership’s projection of future spot market tanker rates, which has been derived from current spot market tanker rates and long-term historical average rates as well as an estimated discount rate. The estimated fair value of this other derivative as of December 31, 2016 is based upon an average daily tanker rate of $22,875 (December 31, 2015 – $34,093) over the remaining duration of the charter contract and a discount rate of 8.4% (December 31, 2015 – 7.5%). In developing and evaluating this estimate, the Partnership considers the current tanker market fundamentals as well as the short and long-term outlook. A higher or lower average daily tanker rate would result in a higher or lower fair value liability or a lower or higher fair value asset. A higher or lower discount rate would result in a lower or higher fair value asset or liability.

F-13

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)

b) Financing Receivables

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.

Class of Financing Receivable	Credit Quality Indicator	Grade	December 31 2016 $	December 31 2015 $
Direct financing leases	Payment activity	Performing	643,008	666,658
Other receivables:
Long-term receivable and accrued revenue included in accounts receivable and other assets	Payment activity	Performing	12,171	28,256
Advances to equity accounted joint ventures	Other internal metrics	Performing	272,514	159,870
			927,693	854,784

4. Segment Reporting

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 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, 2016, the Partnership’s liquefied gas segment consisted of 50 LNG carriers and LNG carrier newbuildings (including 26 LNG carriers and LNG carrier newbuildings included in joint ventures that are accounted for under the equity method), and 29 LPG/Multigas carriers and LPG carrier newbuildings (including 23 LPG carriers and LPG carrier newbuildings included in a joint venture that is accounted for under the equity method). As at December 31, 2016, the Partnership’s conventional tanker segment consisted of five Suezmax-class crude oil tankers and one Handymax product 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 customers who accounted for 10% or more of the Partnership's consolidated voyage revenues during any of the periods presented.

(U.S. Dollars in millions)	Year Ended December 31, 2016	Year Ended December 31, 2015	Year Ended December 31, 2014
Ras Laffan Liquefied Natural Gas Company Ltd. (i)	$70.3 or 18%	$70.1 or 18%	$69.8 or 17%
Shell Spain LNG S.A.U. (i),(ii)	$48.2 or 12%	$48.5 or 12%	$51.8 or 13%
The Tangguh Production Sharing Contractors (i)	$44.4 or 11%	$44.9 or 11%	$44.3 or 11%

(i) Liquefied gas segment.

(ii) Shell Spain LNG S.A.U. acquired the charter contracts from Repsol YPF, S.A. in March 2014. The voyage revenues in 2014 consisted of the voyage revenues from both customers relating to the same charter contract.

F-14

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

	Year Ended December 31, 2016
	Liquefied Gas Segment $		Conventional Tanker Segment $		Total $
Voyage revenues	336,530		59,914		396,444
Voyage expenses	(449	)	(1,207	)	(1,656	)
Vessel operating expenses	(66,087	)	(22,503	)	(88,590	)
Depreciation and amortization	(80,084	)	(15,458	)	(95,542	)
General and administrative expenses(i)	(15,310	)	(3,189	)	(18,499	)
Write-down and loss on sale of vessels	—		(38,976	)	(38,976	)
Income (loss) from vessel operations	174,600		(21,419	)	153,181
Equity income	62,307		—		62,307
Investment in and advances to equity accounted joint ventures	1,037,726		—		1,037,726
Total assets at December 31, 2016	3,957,088		193,553		4,150,641
Expenditures for vessels and equipment	(344,924	)	(63	)	(344,987	)
Expenditures for dry docking	(13,944	)	—		(13,944	)

	Year Ended December 31, 2015
	Liquefied Gas Segment $		Conventional Tanker Segment $		Total $
Voyage revenues	305,056		92,935		397,991
Voyage recoveries (expenses)	203		(1,349	)	(1,146	)
Vessel operating expenses	(63,344	)	(30,757	)	(94,101	)
Depreciation and amortization	(71,323	)	(20,930	)	(92,253	)
General and administrative expenses(i)	(19,392	)	(5,726	)	(25,118	)
Restructuring charges	—		(4,001	)	(4,001	)
Income from vessel operations	151,200		30,172		181,372
Equity income	84,171		—		84,171
Investment in and advances to equity accounted joint ventures	883,731		—		883,731
Total assets at December 31, 2015	3,550,396		360,527		3,910,923
Expenditures for vessels and equipment	(191,642	)	(327	)	(191,969	)
Expenditures for dry docking	(8,659	)	(1,698	)	(10,357	)

	Year Ended December 31, 2014
	Liquefied Gas Segment $		Conventional Tanker 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 expenses(i)	(17,992	)	(5,868	)	(23,860	)
Restructuring charges	—		(1,989	)	(1,989	)
Income from vessel operations	156,868		26,955		183,823
Equity income	115,478		—		115,478
Expenditures for vessels and equipment	(193,669	)	(586	)	(194,255	)
Expenditures for dry docking	(8,127	)	(5,344	)	(13,471	)

F-15

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)

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

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

	December 31 2016 $	December 31 2015 $
Total assets of the liquefied gas segment	3,957,088	3,550,396
Total assets of the conventional tanker segment	193,553	360,527
Unallocated:
Cash and cash equivalents	126,146	102,481
Accounts receivable and prepaid expenses	28,948	26,550
Advances to affiliates	9,739	13,026
Consolidated total assets	4,315,474	4,052,980

5. Leases and Restricted Cash

Capital Lease Obligations

	December 31 2016 $		December 31 2015 $
LNG Carriers	338,257		—
Suezmax Tankers	54,582		59,127
Total obligations under capital lease	392,839		59,127
Less current portion	(40,353	)	(4,546	)
Long-term obligations under capital lease	352,486		54,581

LNG Carriers. As at December 31, 2016, the Partnership was a party to capital leases on two LNG carriers, the Creole Spirit and Oak Spirit. Upon delivery of the Creole Spirit in February 2016 and the Oak Spirit in July 2016, the Partnership sold these vessels to a third party and leased them back under 10-year bareboat charter contracts ending in 2026. The bareboat charter contracts are fixed-rate capital leases with a fixed-price purchase obligation at the end of the lease terms. At inception of these leases, the weighted-average interest rate implicit in these leases was 5.5%. The Partnership guarantees the obligations of the bareboat charter contracts. In addition, the guarantee agreements require the Partnership to maintain minimum levels of tangible net worth and aggregate liquidity, and not to exceed a maximum amount of leverage. In December 2016, the Partnership entered into a $682.8 million sale-leaseback agreement for four of the Partnership’s LNG carrier newbuildings equipped with the M-type, Electronically Controlled, Gas Injection (or MEGI) twin engines, delivering in 2017 and 2018, and at such dates, the buyer will take delivery and charter each respective vessel back to the Partnership.

As at December 31, 2016, the remaining commitments under the two capital leases for the Creole Spirit and the Oak Spirit, including the related purchase obligations, approximated $478.1 million, including imputed interest of $139.8 million, repayable from 2017 through 2026, as indicated below:

Year	Commitment
2017	$	30,065
2018	$	30,065
2019	$	30,065
2020	$	30,147
2021	$	30,065
Thereafter	$	327,686

Suezmax Tankers. As at December 31, 2016, the Partnership was a party to capital leases on two Suezmax tankers. Under these capital leases, the owner has the option to require the Partnership to purchase the two vessels. The charterer, who is also the owner, also has the option to cancel the charter contracts and the cancellation options are first exercisable in October 2017 and July 2018, respectively.

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 vessels to a third party, upon which the remaining lease obligations will be extinguished.

F-16

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)

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.

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

Year	Commitment
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.

Restricted Cash

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 $117.0 million and $111.5 million as at December 31, 2016 and 2015, respectively.

Operating Lease Obligations

Teekay Tangguh Joint Venture

As at December 31, 2016, the Teekay BLT Corporation (or the Teekay Tangguh Joint Venture) was a party to operating leases (or Head Leases) whereby it is leasing its two LNG carriers (or the Tangguh LNG Carriers) to a third party company. The Teekay Tangguh Joint Venture is then leasing back the LNG carriers from the same third party company (or the Subleases). Under the terms of these leases, the third party company claims tax depreciation on the capital expenditures it incurred to lease the vessels. As is typical in these leasing arrangements, tax and change of law risks are assumed by the Teekay Tangguh Joint Venture. Lease payments under the Subleases are based on certain tax and financial assumptions at the commencement of the leases. If an assumption proves to be incorrect, the lease payments are increased or decreased under the Sublease to maintain the agreed after-tax margin. The Teekay Tangguh Joint Venture’s carrying amounts of this tax indemnification guarantee as at December 31, 2016 and 2015 were $7.5 million and $8.0 million, respectively, and are included as part of other long-term liabilities in the consolidated balance sheets of the Partnership. The tax indemnification is for the duration of the lease contract with the third party plus the years it would take for the lease payments to be statute barred, and ends in 2033. Although there is no maximum potential amount of future payments, the Teekay Tangguh Joint Venture may terminate the lease arrangements on a voluntary basis at any time. If the lease arrangements terminate, the Teekay Tangguh Joint Venture will be required to make termination payments to the third party company sufficient to repay the third party company’s investment in the vessels and to compensate it for the tax effect of the terminations, including recapture of any tax depreciation. The Head Leases and the Subleases have 20-year terms and are classified as operating leases. The Head Leases and the Subleases for the two Tangguh LNG Carriers commenced in November 2008 and March 2009, respectively.

As at December 31, 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)
2017	$	21,242	$	24,113
2018	$	21,242	$	24,113
2019	$	21,242	$	24,113
2020	$	21,242	$	24,113
2021	$	21,242	$	24,113
Thereafter	$	154,095	$	174,959
Total	$	260,305	$	295,524

(i) The Head Leases are fixed-rate operating leases while the Subleases have a small variable-rate component. As at December 31, 2016, the Partnership had received $250.0 million of aggregate Head Lease receipts and had paid $187.9 million of aggregate Sublease payments. The portion of the Head Lease receipts that have not been recognized into earnings are deferred and amortized on a straight line basis over the lease terms and, as at December 31, 2016, $3.7 million (December 31, 2015 –$3.8 million) and $36.7 million (December 31, 2015 –$40.4 million) of Head Lease receipts had been deferred and included in unearned revenue and other long-term liabilities, respectively, in the Partnership’s consolidated balance sheets.

(ii) The amount of payments under the Subleases are updated annually to reflect any changes in the lease payments due to changes in tax law.

F-17

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)

Net Investments in Direct Financing Leases

The Tangguh LNG Carriers commenced their time-charters with their charterers in January and May 2009, respectively. Both time-charters are accounted for as direct financing leases with 20-year terms. In September and November 2013, the Partnership acquired two155,900-cubic meter LNG carriers (or Awilco LNG Carriers) from Norway-based Awilco LNG ASA (or Awilco) and chartered them back to Awilco on five- and four-year fixed-rate bareboat charter contracts (plus a one-year extension option), respectively, with Awilco holding fixed-price purchase obligations at the end of the charter. The bareboat charters with Awilco are accounted for as direct financing leases. The purchase price of each vessel was $205.0 million less a $51.0 million upfront prepayment of charter hire by Awilco (inclusive of a $1.0 million upfront fee), which is in addition to the daily bareboat charter rate. The following table lists the components of the net investments in direct financing leases:

	December 31 2016 $		December 31 2015 $
Total minimum lease payments to be received	764,970		843,079
Estimated unguaranteed residual value of leased properties	194,965		194,965
Initial direct costs	393		425
Less unearned revenue	(317,320	)	(371,811	)
Total net investments in direct financing leases	643,008		666,658
Less current portion	(150,342	)	(20,606	)
Net investments in direct financing leases	492,666		646,052

As at December 31, 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 are approximately $39.1 million per year from 2017 through 2021. Both leases are scheduled to end in 2029. In addition, estimated minimum lease payments in the next two years to be received by the Partnership under the Awilco LNG Carrier leases are approximately $162.0 million (2017) and $134.6 million (2018).

Operating Leases

As at December 31, 2016, the minimum scheduled future revenues 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 $349.2 million (2017), $372.2 million (2018), $404.0 million (2019), $393.3 million (2020), and $353.5 million (2021). Minimum scheduled future revenues do not include revenue generated from new contracts entered into after December 31, 2016, revenue from vessels in the Partnership’s equity accounted investments, revenue from unexercised option periods of contracts that existed on December 31, 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 these five years.

6. Equity Accounted Investments

a) A summary of the Partnership's investments in and advances to equity accounted investees are as follows:

				As at December 31,
Name	Ownership Percentage	# of Delivered Vessels	Newbuildings on order	2016 $	2015 $
Bahrain LNG Joint Venture (i)	30%	-	1	63,933	—
Yamal LNG Joint Venture (ii)	50%	-	6	152,702	99,886
BG Joint Venture (iii)	20%-30%	-	4	33,860	25,574
Exmar LPG Joint Venture (iv)	50%	19	4	167,763	166,430
Teekay LNG-Marubeni Joint Venture (v)	52%	6	-	299,601	294,433
Excalibur and Excelsior Joint Ventures (vi)	49%-50%	2	-	79,577	77,845
Angola Joint Venture (vii)	33%	4	-	65,644	58,170
RasGas 3 Joint Venture (viii)	40%	4	-	174,646	161,393
		35	15	1,037,726	883,731

(i) Bahrain LNG Joint Venture

On December 2, 2015, the Partnership (30%) entered into a joint venture agreement with National Oil & Gas Authority (or Nogaholding) (30%), Gulf Investment Corporation (or GIC) (24%) and Samsung C&T (or Samsung) (16%) to form a joint venture, Bahrain LNG W.L.L. (or the Bahrain LNG Joint

F-18

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)

Venture), for the development of an LNG receiving and regasification terminal in Bahrain. The project will include an offshore LNG receiving jetty and breakwater, an adjacent regasification platform, subsea gas pipelines from the platform to shore, an onshore gas receiving facility, and an onshore nitrogen production facility with a total LNG terminal capacity of 800 million standard cubic feet per day and will be owned and operated under a 20-year agreement commencing in early-2019. In addition, the Partnership will supply a floating storage unit (or FSU) in connection with this project, which will be modified from one of the Partnership’s nine MEGI LNG carrier newbuildings ordered from Daewoo Shipbuilding & Marine Engineering Co. (or DSME) (see Note 13a), through a 20-year time-charter contract with the Bahrain LNG Joint Venture.

As at December 31, 2016, the Partnership had advanced $62.9 million (December 31, 2015 – $nil) to the Bahrain LNG Joint Venture. These advances bear interest at LIBOR plus 1.25% and as at December 31, 2016, the interest accrued on these advances was $0.1 million (December 31, 2015 – $nil). These amounts are included in the table above.

(ii) Yamal LNG Joint Venture

On July 9, 2014, the Partnership entered into a 50/50 joint venture (or the Yamal LNG Joint Venture) with China LNG Shipping (Holdings) Limited and ordered six internationally-flagged icebreaker LNG carriers for a project located on the Yamal Peninsula in Northern Russia (or the Yamal LNG Project).

As at December 31, 2016, the Partnership had advanced $146.7 million to the Yamal LNG Joint Venture (December 31, 2015 – $96.9 million). The advances bear interest at LIBOR plus 3.00% compounded semi-annually. As of December 31, 2016, the interest accrued on these advances was $9.4 million (December 31, 2015 – $4.8 million). These amounts are included in the table above.

(iii) BG Joint Venture

On June 27, 2014, the Partnership acquired from BG (which was subsequently acquired by Shell) its ownership interests in four174,000-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. Through this transaction, the Partnership has a 30% ownership interest in two LNG carrier newbuildings and a 20% ownership interest in the remaining two LNG carrier newbuildings (or collectively, the BG Joint Venture). As compensation for Shell’s ownership interest in these four LNG carrier newbuildings, the Partnership assumed Shell’s 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. The Partnership estimates it will incur approximately $36.9 million of costs to provide these services, of which Shell has agreed to pay a fixed amount of $20.3 million. The Partnership estimated that the fair value of the service obligation was $33.3 million and the fair value of the amount due from Shell was $16.5 million. As at December 31, 2016, the carrying value of the service obligation of $22.6 million (December 31, 2015 – $29.7 million) is included in both the current portion of in-process contracts and in-process contracts and the carrying value of the receivable from Shell of $10.9 million (December 31, 2015 – $16.5 million) is included in both accounts receivable and other assets in the Partnership’s consolidated balance sheets.

As at December 31, 2016, the excess of the carrying value of the Partnership's investment over the carrying value of the BG Joint Venture's net assets was $16.8 million (December 31, 2015 – $16.8 million). This basis difference has been allocated notionally to the ship construction support agreements and the time-charter contracts.

As at December 31, 2016, to fund its newbuilding installments, the BG Joint Venture has drawn $221.0 million (December 31, 2015 – $110.3 million) from its $787.0 million long-term debt facility and received $16.6 million of capital contributions from the Partnership (December 31, 2015 – $8.6 million), representing the Partnership’s proportionate share.

(iv) Exmar LPG Joint Venture

The Partnership has a joint venture agreement with Exmar NV (or Exmar). In June 2015, Exmar LPG BVBA (or the Exmar LPG Joint Venture) completed a refinancing of its existing debt facility by entering into a $460.0 million long-term debt facility bearing interest at a rate of LIBOR plus 1.90%, maturing in 2021. The Partnership has guaranteed its 50% share of the secured loan facility in the Exmar LPG Joint Venture and, as a result, recorded a guarantee liability of $1.7 million. The carrying value of the guarantee liability as at December 31, 2016 was $1.3 million (December 31, 2015 – $1.5 million) and is included as part of other long-term liabilities in the Partnership’s consolidated balance sheets.

As at December 31, 2016, the Partnership had advanced $52.3 million (December 31, 2015 – $57.8 million) to the Exmar LPG Joint Venture, which bears interest at LIBOR plus 0.50% and has no fixed repayment terms. As at December 31, 2016, the interest accrued on these advances was $1.1 million (December 31, 2015 – $0.4 million). These amounts are included in the table above.

As at December 31, 2016, the excess of the carrying value of the Partnership's investment over the carrying value of the Exmar LPG Joint Venture's net assets was $30.2 million (December 31, 2015 – $36.4 million). The basis difference has been accounted for as an adjustment to the value of the vessels and charter agreements of the Exmar LPG Joint Venture and recognition of goodwill in accordance with the finalized purchase price allocation.

(v) Teekay LNG-Marubeni Joint Venture

The Partnership has a joint venture with Marubeni Corporation and the Partnership (or the Teekay LNG-Marubeni Joint Venture). Since control of the Teekay LNG-Marubeni Joint Venture is shared jointly between Marubeni and the Partnership, the Partnership accounts for its investment in the Teekay LNG-Marubeni Joint Venture using the equity method. From June to July 2013, the Teekay LNG Marubeni Joint Venture completed a refinancing of its short-term loan facilities by entering into separate long-term debt facilities totaling approximately $963 million. These debt facilities mature between 2017 and 2030 (see Note 19e). The Partnership has guaranteed its 52% share of the secured loan facilities of the Teekay LNG-Marubeni Joint Venture and, as a result, recorded a guarantee liability of $0.7 million. The carrying value of the guarantee liability as at December 31, 2016 was $0.1 million (December 31, 2015 – $0.2 million) and is included as part of other long-term liabilities in the Partnership’s consolidated balance sheets.

(vi) Excalibur and Excelsior Joint Ventures

The Partnership has joint ventures with Exmar (or the Excalibur Joint Venture and the Excelsior Joint Venture). In February 2015, the Excalibur and Excelsior Joint Ventures completed refinancing of their existing debt facilities by entering into a $172.8 million long-term debt facility bearing interest at a rate of LIBOR plus 2.75%, maturing in 2019. The Partnership has guaranteed its 50% share of the secured loan facilities of the Excalibur and Excelsior Joint Ventures and, as a result, recorded a guarantee liability of $0.4 million. The carrying value of the guarantee liability as of December 31, 2016 was $0.2 million (December 31, 2015 – $0.3 million) and is included as part of other long-term liabilities in the Partnership’s consolidated balance sheets.

As at December 31, 2016, the excess of the carrying value of the Partnership's investment over the carrying value of the Excalibur and Excelsior Joint Venture's net assets was $37.2 million (December 31, 2015 – $38.6 million). The basis difference has substantially been accounted for as an increase to the carrying value of the vessels of the Excalibur and Excelsior Joint Ventures in accordance with the finalized purchase price allocation.

F-19

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)

(vii) Angola Joint Venture

The Partnership has a 33% ownership interest in a joint venture (or the Angola Joint Venture) that owns four160,400-cubic meter LNG carriers (or the Angola LNG Carriers). The other partners of the Angola Joint Venture are NYK Energy Transport (or NYK) (33%) and Mitsui & Co. Ltd. (34%).

(viii) RasGas 3 Joint Venture

The Partnership has a 40% ownership interest in Teekay Nakilat (III) Corporation (or the RasGas 3 Joint Venture), and the remaining 60% is held by Qatar Gas Transport Company Ltd. (Nakilat).

b) The RasGas 3 Joint Venture, the Excelsior Joint Venture, the Angola Joint Venture, the Yamal LNG Joint Venture, and the Bahrain LNG Joint Venture are considered variable interest entities; however, the Partnership is not the primary beneficiary and consolidation of these entities with the Partnership is not required. The Partnership’s maximum exposure to loss as a result of its investment in the RasGas 3 Joint Venture, the Excelsior Joint Venture, the Angola LNG Joint Venture, the Yamal LNG Joint Venture, and the Bahrain LNG Joint Venture is the amount it has invested and advanced in these joint ventures, which are $174.6 million, $50.3 million, $65.6 million, $152.7 million and $63.9 million, respectively, as at December 31, 2016. In addition, the Partnership guarantees its portion of the Excelsior Joint Venture’s debt of $45.0 million and the Angola Joint Ventures’ debt and swaps of $256.1 million and provides a guarantee against a charter termination. The carrying value of Angola Joint Venture's guarantee liability as of December 31, 2016 was $1.0 million (December 31, 2015 – $1.2 million) and is included as part of other liabilities in the Partnership’s consolidated balance sheets.

c) The following table presents aggregated summarized financial information reflecting a 100% ownership interest in the Partnership’s equity method investments and excluding the impact from purchase price adjustments arising from the acquisition of Exmar LPG BVBA, the Excalibur and Excelsior Joint Ventures and the BG Joint Venture. The results include the Excalibur and Excelsior Joint Ventures, the RasGas 3 Joint Venture, the Angola Joint Venture, the Exmar LPG Joint Venture, the Teekay LNG-Marubeni Joint Venture, the BG Joint Venture from June 2014, the Yamal LNG Joint Venture from July 2014, and the Bahrain LNG Joint Venture from December 2015.

	As at December 31,
	2016 $	2015 $
Cash and restricted cash – current	388,007	281,943
Other assets – current	111,847	77,861
Vessels and equipment	2,837,870	2,343,397
Net investments in direct financing leases – non-current	1,776,954	1,813,991
Other assets – non-current	37,132	22,120
Current portion of long-term debt and obligations under capital lease	209,814	166,522
Other liabilities – current	102,385	97,405
Long-term debt and obligations under capital lease	3,233,425	2,787,055
Other liabilities – non-current	157,025	177,879

	Years ended December 31,
	2016 $		2015 $		2014 $
Voyage revenues	549,646		596,093		640,105
Income from vessel operations	268,049		302,731		398,836
Realized and unrealized loss on non-designated derivative instruments	(12,277	)	(25,108	)	(52,938	)
Net income	167,052		203,280		267,990

7. Intangible Assets and Goodwill

As at December 31, 2016 and 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 liquefied gas segment is as follows:

	December 31 2016 $		December 31 2015 $
Gross carrying amount	179,813		179,813
Accumulated amortization	(109,879	)	(101,023	)
Net carrying amount	69,934		78,790

F-20

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)

Amortization expense associated with intangible assets was $8.9 million, $8.9 million and $9.2 million for the years ended December 31, 2016, 2015 and 2014, respectively. Amortization expense associated with intangible assets is expected to be approximately $8.9 million per year in each of the next five years.

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

8. Accrued Liabilities

	December 31 2016 $	December 31 2015 $
Interest including interest rate swaps	19,957	17,484
Voyage and vessel expenses	9,311	9,315
Payroll and benefits	3,355	5,431
Other general expenses	3,069	2,785
Income tax payable and other	189	2,441
Total	35,881	37,456

9. Long-Term Debt

	December 31, 2016		December 31, 2015
	$		$
U.S. Dollar-denominated Revolving Credit Facilities due from 2017 to 2018	208,222		329,222
U.S. Dollar-denominated Term Loans due from 2018 to 2026	1,005,199		1,150,436
Norwegian Kroner-denominated Bonds due from 2017 to 2021	371,329		294,016
Euro-denominated Term Loans due from 2018 to 2023	219,733		241,798
Total principal	1,804,483		2,015,472
Unamortized discount and debt issuance costs	(13,257	)	(16,263	)
Total debt	1,791,226		1,999,209
Less current portion	(188,511	)	(197,197	)
Long-term debt	1,602,715		1,802,012

As at December 31, 2016, the Partnership had three revolving credit facilities available of which two credit facilities are long-term and one is current. The three credit facilities, as at such date, provided for borrowings of up to $451.9 million (December 31, 2015 – $459.2 million), of which $243.7 million (December 31, 2015 – $130.0 million) was undrawn. Interest payments are based on LIBOR plus margins, which ranged from 0.55% to 1.25%. The amount available under the three revolving credit facilities reduces by $198.2 million (2017) and $253.7 million (2018). 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. One of the revolving credit facilities is unsecured while the other two revolving credit facilities are collateralized by first-priority mortgages granted on 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.

As at December 31, 2016, the Partnership had six U.S. Dollar-denominated term loans outstanding which totaled $1.0 billion in aggregate principal amount. Interest payments on the term loans are based on LIBOR plus a margin, which ranged from 0.30% to 2.80%. The six term loans require quarterly interest and principal payments and have balloon or bullet repayments due at maturity. The term loans are collateralized by first-priority mortgages on 15 of the Partnership’s vessels to which the loans relate, together with certain other related security. In addition, at December 31, 2016, all of the outstanding term loans were guaranteed by either the Partnership or Teekay Nakilat Corporation (or the Teekay Nakilat Joint Venture), a joint venture in which the partnership has a 70% ownership interest and which owns three LNG carriers.

The Partnership has Norwegian Kroner (or NOK) 3.2 billion of senior unsecured bonds in the Norwegian bond market that mature through 2021. As at December 31, 2016, the total amount of the bonds, which are listed on the Oslo Stock Exchange was $371.3 million. The interest payments on the bonds are based on NIBOR plus a margin, which ranges from 3.70% to 6.00%. The Partnership entered into cross-currency rate swaps, to swap all interest and principal payments of the bonds into U.S. Dollars, with the interest payments fixed at rates ranging from 5.92% to 7.72% and the transfer of principal fixed at $467 million upon maturity in exchange for NOK 3.2 billion (see Note 12).

F-21

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 has two Euro-denominated term loans outstanding, which as at December 31, 2016, totaled 208.9 million Euros ($219.7 million). Interest payments are based on EURIBOR plus margins, which ranged from 0.60% to 2.25% as at December 31, 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, 2016 and December 31, 2015 were 3.03% and 2.33%, respectively. 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, 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 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 swaps, the Partnership incurred foreign exchange gains of $5.3 million, $13.9 million, and $28.4 million for the years ended December 31, 2016, 2015 and 2014, respectively.

The aggregate annual long-term debt principal repayments required subsequent to December 31, 2016 are $190.1 million (2017), $719.8 million (2018), $82.5 million (2019), $178.0 million (2020), $288.4 million (2021) and $345.7 million (thereafter).

Certain loan agreements require that (a) the Partnership maintains minimum levels of tangible net worth and aggregate liquidity, (b) the Partnership maintain certain ratios of vessel values related to the relevant outstanding loan principal balance, (c) the Partnership not exceed a maximum amount of leverage, and (d) certain of the Partnership’s subsidiaries maintains restricted cash deposits. As at December 31, 2016, the Partnership had two facilities with an aggregate outstanding loan balance of $127.8 million that require it 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 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's subsidiaries are in default under their term loans or revolving credit facilities. As at December 31, 2016, the Partnership was in compliance with all covenants relating to the Partnership’s credit facilities and term loans.

10. Income Tax

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

	Year Ended December 31, 2016 $		Year Ended December 31, 2015 $		Year Ended December 31, 2014 $
Current	(962	)	(2,646	)	(5,212	)
Deferred	(11	)	(76	)	(2,355	)
Income tax expense	(973	)	(2,722	)	(7,567	)

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 December 31, 2016 $		Year Ended December 31, 2015 $		Year Ended December 31, 2014 $
Net income before income tax expenses	158,938		220,232		226,494
Net income not subject to taxes	(138,542	)	(173,298	)	(81,604	)
Net income subject to taxes	20,396		46,934		144,890
At applicable statutory tax rates
Amount computed using the standard rate of corporate tax	(3,338	)	(12,007	)	(33,083	)
Adjustments to valuation allowance and uncertain tax positions	11,802		5,362		14,851
Permanent and currency differences	(9,125	)	4,204		11,507
Change in tax rate	(312	)	(281	)	(842	)
Tax expense related to the current year	(973	)	(2,722	)	(7,567	)

F-22

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 significant components of the Partnership’s deferred tax assets (liabilities) were as follows:

	Year Ended December 31, 2016 $		Year Ended December 31, 2015 $
Derivative instruments	4,523		7,021
Taxation loss carryforwards and disallowed finance costs	34,927		44,823
Vessels and equipment	3,554		3,462
Capitalized interest	(2,027	)	(2,184	)
	40,977		53,122
Valuation allowance	(41,064	)	(53,198	)
Net deferred tax liabilities included in accrued liabilities	(87	)	(76	)

The Partnership had tax losses in the United Kingdom (or UK) of $12.7 million as at December 31, 2016(December 31, 2015 – $12.7 million) that are available indefinitely for offset against future taxable income in the UK. The Partnership had tax losses and disallowed finance costs in Spain of 110.3 million Euros or approximately $116.1 million(December 31, 2015 – 110.3 million Euros or approximately $119.8 million) and 34.6 million Euros or approximately $36.4 million(December 31, 2015 – 34.2 million Euros or approximately $37.2 million), respectively, at December 31, 2016 that are available indefinitely for offset against future taxable income in Spain. During 2015, as a result of an audit performed by the Spanish tax authorities on the Partnership’s Spanish subsidiaries, the Partnership and the Spanish tax authorities reached an agreement to reduce the Partnership’s tax losses in Spain by 29.0 million Euros or approximately $30.5 million. The losses were subject to a full valuation allowance, and therefore no change in income tax expense or assets will occur as a result of this agreement. The Partnership also had tax losses in Luxembourg of 93.3 million Euros or approximately $98.1 million as at December 31, 2016(December 31, 2015 – 120.9 million Euros or approximately $131.3 million) that are available indefinitely for offset against taxable future income in Luxembourg.

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

11. Related Party Transactions

a) Two of the Partnership’s LNG carriers, the Arctic Spirit and Polar Spirit, are employed on long-term charter contracts with subsidiaries of Teekay Corporation. In addition, the Partnership and certain of its operating subsidiaries have entered into services agreements with certain subsidiaries of Teekay Corporation pursuant to which the Teekay Corporation subsidiaries provide the Partnership and its subsidiaries with administrative, commercial, crew training, advisory, business development, technical and strategic consulting services. In addition, as part of the Partnership’s acquisition of its ownership interest in the BG Joint Venture (see Notes 6a iii and 13a iv), the Partnership entered into an agreement with a subsidiary of Teekay Corporation whereby Teekay Corporation’s subsidiary will, on behalf of the Partnership, provide shipbuilding supervision and crew training services for the four LNG carrier newbuildings in the BG Joint Venture up to their delivery date. All costs incurred by Teekay Corporation’s subsidiary will be charged to the Partnership and recorded as part of vessel operating expenses. Finally, the Partnership reimburses the General Partner for expenses incurred by the General Partner that are necessary for the conduct of the Partnership’s business. Such related party transactions were as follows for the periods indicated: 

	Year Ended
	December 31 2016 $		December 31 2015 $		December 31 2014 $
Voyage revenues (i)	37,336		35,887		37,596
Vessel operating expenses	(20,438	)	(19,914	)	(12,703	)
General and administrative expenses (ii)	(11,890	)	(14,485	)	(13,708	)
General and administrative expenses deferred and capitalized (iii)	(571	)	—		—

(i) Commencing in 2008, the Arctic Spirit and Polar Spirit were time-chartered to Teekay Corporation at a fixed-rate for a period of 10 years (plus options exercisable by Teekay Corporation to extend up to an additional 15 years).

(ii) Includes commercial, strategic, advisory, business development and administrative management fees charged by Teekay Corporation and reimbursements to Teekay Corporation and our General Partner for costs incurred on the Partnership’s behalf.

(iii) Includes the Partnership's proportionate costs associated with the Bahrain LNG Joint Venture including pre-operation, engineering and financing-related expenses, of which $0.4 million was reimbursed by the Bahrain LNG Joint Venture during 2016. The net costs are recorded as part of investments in and advances to equity accounted joint ventures in the Partnership's consolidated balance sheets.

b) In connection with the Partnership’s initial public offering in May 2005, the Partnership entered into an omnibus agreement with Teekay Corporation, the General Partner and other related parties governing, among other things, when the Partnership and Teekay Corporation

F-23

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)

may compete with each other and certain rights of first offer on LNG carriers and Suezmax tankers. In December 2006, the omnibus agreement was amended in connection with the initial public offering of Teekay Offshore Partners L.P. (or Teekay Offshore). As amended, the agreement governs, among other things, when the Partnership, Teekay Corporation and Teekay Offshore may compete with each other and certain rights of first offer on LNG carriers, oil tankers, shuttle tankers, floating storage and offtake units and floating production, storage and offloading units.

c) The Partnership’s Suezmax tanker the Toledo Spirit operates pursuant to a time-charter contract that increases or decreases the otherwise fixed-hire rate established in the charter depending on the spot charter rates that the Partnership would have earned had it traded the vessel in the spot tanker market. The time-charter contract ends in August 2025, although the charterer has the right to terminate the time-charter in July 2018. The Partnership has entered into an agreement with Teekay Corporation under which Teekay Corporation pays the Partnership any amounts payable to the charterer as a result of spot rates being below the fixed rate, and the Partnership pays Teekay Corporation any amounts payable to the Partnership as a result of spot rates being in excess of the fixed rate. The amounts receivable or payable to Teekay Corporation are settled at the end of each year (see Notes 3 and 12).

d) On November 13, 2014, the Partnership acquired a 2003-built 10,200 cubic meter LPG carrier, the Norgas Napa, from I.M. Skaugen SE (or Skaugen) for $27.0 million. The Partnership took delivery of the vessel 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 a portion of the vessel’s earnings from the Skaugen’s Norgas pool in excess of the fixed charter rate. In connection with the acquisition of the Norgas Napa, the General Partner acquired a 1% ownership interest in the Norgas Napa from the Partnership for approximately $0.2 million.

e) In March 2014, two interest rate swap agreements were novated from Teekay Corporation to the Partnership. Teekay Corporation concurrently paid the Partnership $3.0 million in cash consideration, which represented the estimated fair value of the interest rate swap liabilities on the novation date.

f) The Partnership entered into services agreements with certain subsidiaries of Teekay Corporation pursuant to which the Teekay Corporation subsidiaries provide the Partnership with shipbuilding and site supervision services relating to nine LNG carrier newbuildings the Partnership has ordered (December 31, 2015 – 11 LNG carrier newbuildings) (see Notes 13a i and ii). These costs are capitalized and included as part of advances on newbuilding contracts in the Partnership’s consolidated balance sheets. During the years ended 2016, 2015 and 2014, the Partnership incurred shipbuilding and site supervision costs with Teekay Corporation subsidiaries of $8.5 million, $4.3 million and $3.1 million, respectively. As at December 31, 2016 and 2015, shipbuilding and site supervision costs provided by Teekay Corporation subsidiaries included in advances on newbuilding contracts in the Partnership's consolidated balance sheets totaled $10.1 million and $7.6 million, respectively.

g) As at December 31, 2016 and 2015, non-interest bearing advances to affiliates totaled $9.7 million and $13.0 million, respectively, and non-interest bearing advances from affiliates totaled $15.5 million and $23.0 million, respectively. These advances are unsecured and have no fixed repayment terms. Affiliates are entities that are under the same common control.

12. Derivative Instruments and Hedging Activities

The Partnership uses derivative instruments in accordance with its overall risk management policy.

Foreign Exchange Risk

From 2013 through 2016, concurrently with the issuance of NOK 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 2021, and to economically hedge the interest rate exposure. The following table reflects information relating to the cross-currency swaps as at December 31, 2016.

		Floating Rate Receivable
Principal Amount NOK	Principal Amount $	Reference Rate	Margin		Fixed Rate Payable		Fair Value / Carrying Amount of (Liability) $		Weighted- Average Remaining Term (Years)
408,500	72,946	NIBOR	5.25	%	6.88	%	(26,417	)	0.3
900,000	150,000	NIBOR	4.35	%	6.43	%	(49,655	)	1.7
1,000,000	134,000	NIBOR	3.70	%	5.92	%	(19,900	)	3.4
900,000	110,400	NIBOR	6.00	%	7.72	%	(3,814	)	4.8
							(99,786	)

Interest Rate Risk

F-24

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 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, 2016, the Partnership was committed to the following interest rate swap agreements:

	Interest Rate Index	Principal Amount $	Fair Value / Carrying Amount of Assets (Liability) $		Weighted- Average Remaining Term (years)	Fixed Interest Rate (%) (i)
LIBOR-Based Debt:
U.S. Dollar-denominated interest rate swaps	LIBOR	90,000	(5,748	)	1.7	4.9
U.S. Dollar-denominated interest rate swaps	LIBOR	100,000	(1,145	)	0.0	5.3
U.S. Dollar-denominated interest rate swaps(ii)	LIBOR	156,250	(26,765	)	12.0	5.2
U.S. Dollar-denominated interest rate swaps(ii)	LIBOR	53,557	(1,494	)	4.6	2.8
U.S. Dollar-denominated interest rate swaps(iii)	LIBOR	320,000	(17,079	)	1.0	3.4
U.S. Dollar-denominated interest rate swaps(iv)	LIBOR	108,333	(665	)	2.0	1.7
U.S. Dollar-denominated interest rate swaps(v)	LIBOR	197,629	590		9.2	2.3
EURIBOR-Based Debt:
Euro-denominated interest rate swaps(vi)	EURIBOR	219,733	(34,295	)	4.0	3.1
			(86,601	)

(i) Excludes the margins the Partnership pays on its floating-rate term loans, which, at December 31, 2016, ranged from 0.30% to 2.80%.

(ii) Principal amount reduces semi-annually.

(iii) These interest rate swaps are being used to economically hedge expected interest payments on future debt that is planned to be outstanding from 2017 to 2024. These interest rate swaps are subject to mandatory early termination in 2017 and 2018 whereby the swaps will be settled based on their fair value at that time.

(iv) Principal amount reduces quarterly.

(v) Principal amount reduces quarterly commencing December 2017.

(vi) Principal amount reduces monthly to 70.1 million Euros ($73.7 million) by the maturity dates of the swap agreements.

During 2015, as part of its economic hedging program, the Partnership entered into three interest rate swaption agreements, whereby the Partnership has a one-time option (or Call Option) to enter into an interest rate swap with a third party, and the third party has a one-time option (or Put Option) to require the Partnership to enter into interest swap agreements. If the Partnership or the third parties exercises its options, there will be cash settlements for the fair value of the interest rate swap, in lieu of taking delivery of the actual interest rate swaps. At December 31, 2016, the terms of the interest rate swaps underlying the interest rate swaptions were as follows:

F-25

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)

	Interest Rate Index	Principal Amount $		Option Exercise Date	Fair Value / Carrying Amount of Assets (Liability)		Remaining Term (Years)	Interest Rate (%)
Interest rate swaption - Call Option	LIBOR	155,000	(i)	April 28, 2017	31		7.5	3.3
Interest rate swaption - Put Option	LIBOR	155,000	(i)	April 28, 2017	(1,525	)	7.5	2.2
Interest rate swaption - Call Option	LIBOR	160,000	(ii)	January 31, 2018	1,140		8.0	3.1
Interest rate swaption - Put Option	LIBOR	160,000	(ii)	January 31, 2018	(1,457	)	8.0	2.0
Interest rate swaption - Call Option	LIBOR	160,000	(iii)	July 16, 2018	2,112		8.0	2.9
Interest rate swaption - Put Option	LIBOR	160,000	(iii)	July 16, 2018	(1,248	)	8.0	1.8

(i) Amortizing every three months from $155.0 million in April 2017 to $85.4 million in October 2024.

(ii) Amortizing every three months from $160.0 million in January 2018 to $82.5 million in January 2026.

(iii) Amortizing every three months from $160.0 million in July 2018 to $82.5 million in July 2026.

As at December 31, 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 derivative instruments are presented on a gross basis in the Partnership’s consolidated balance sheets. As at December 31, 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 of $173.6 million. As at December 31, 2016, the Partnership had $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.

Credit Risk

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 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.

Other Derivatives

In order to reduce the variability of its revenue, the Partnership has entered into an agreement with Teekay Corporation under which Teekay Corporation pays the Partnership any amounts payable to the charterer of the Toledo Spirit as a result of spot rates being below the fixed rate, and the Partnership pays Teekay Corporation any amounts payable to the Partnership by the charterer of the Toledo Spirit as a result of spot rates being in excess of the fixed rate. The fair value of the derivative asset at December 31, 2016 was $2.1 million (December 31, 2015 – a liability of $6.3 million).

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.

F-26

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)

	Advances to affiliates	Current portion of derivative assets	Derivative assets	Accrued liabilities/ Advances from affiliates		Current portion of derivative liabilities		Derivative liabilities
As at December 31, 2016
Interest rate swap agreements	—	—	1,080	(5,514	)	(22,432	)	(59,735	)
Interest rate swaption agreements	—	31	3,252	—		(1,525	)	(2,705	)
Cross-currency swap agreements	—	—	—	(1,090	)	(32,843	)	(65,853	)
Toledo Spirit time-charter derivative	1,274	500	360	—		—		—
	1,274	531	4,692	(6,604	)	(56,800	)	(128,293	)
As at December 31, 2015
Interest rate swap agreements	—	—	—	(6,833	)	(41,028	)	(56,276	)
Interest rate swaption agreements	—	—	5,623	—		—		(6,406	)
Cross-currency swap agreements	—	—	—	(1,181	)	(9,755	)	(117,846	)
Toledo Spirit time-charter derivative	—	—	—	(3,186	)	(1,300	)	(1,810	)
	—	—	5,623	(11,200	)	(52,083	)	(182,338	)

Realized and unrealized gains (losses) relating to non-designated interest rate swap agreements, interest rate swaption agreements, and the Toledo Spirit time-charter derivative are recognized in earnings and reported in realized and unrealized loss on non-designated derivative instruments 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:

	Year Ended December 31,
	2016						2015						2014
	Realized gains (losses)		Unrealized gains (losses)		Total		Realized gains (losses)		Unrealized gains (losses)		Total		Realized gains (losses)		Unrealized gains (losses)		Total
Interest rate swap agreements	(25,940	)	15,627		(10,313	)	(28,968	)	14,768		(14,200	)	(39,406	)	4,204		(35,202	)
Interest rate swaption agreements	—		(164	)	(164	)	—		(783	)	(783	)	—		—		—
Interest rate swap agreements termination	—		—		—		—		—		—		(2,319	)	—		(2,319	)
Toledo Spirit time-charter derivative	(654	)	3,970		3,316		(3,429	)	(1,610	)	(5,039	)	(861	)	(6,300	)	(7,161	)
	(26,594	)	19,433		(7,161	)	(32,397	)	12,375		(20,022	)	(42,586	)	(2,096	)	(44,682	)

Unrealized and realized gains (losses) relating to cross-currency swap agreements are recognized in earnings and reported in foreign currency exchange gain 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:

	Year Ended December 31,
	2016					2015						2014
	Realized gains (losses)		Unrealized gains (losses)	Total		Realized gains (losses)		Unrealized gains (losses)		Total		Realized gains (losses)		Unrealized gains (losses)		Total
Cross-currency swap agreements	(9,063	)	28,905	19,842		(7,640	)	(57,759	)	(65,399	)	(2,222	)	(51,762	)	(53,984	)
Cross-currency swap agreements termination	(17,711	)	—	(17,711	)	—		—		—		—		—		—
	(26,774	)	28,905	2,131		(7,640	)	(57,759	)	(65,399	)	(2,222	)	(51,762	)	(53,984	)

F-27

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)

For the year ended December 31, 2016 (no activity for the years ended December 31, 2015 and 2014), the following table presents the effective and ineffective portion of losses on interest rate swap agreements designated and qualifying as cash flow hedges. The following table excludes any interest rate swap agreements designated and qualifying as cash flow hedges in the Partnership’s equity accounted joint ventures.

Year Ended December 31, 2016
Effective Portion Recognized in AOCI (i) $	Effective Portion Reclassified from AOCI (ii)                               $	Ineffective Portion (iii) $
590	—	—	Interest expense
590	—	—

(i) Effective portion of designated and qualifying cash flow hedges recognized in other comprehensive income (loss).

(ii) Effective portion of designated and qualifying cash flow hedges recorded in accumulated other comprehensive income (loss) (or AOCI) during the term of the hedging relationship and reclassified to earnings.

(iii) Ineffective portion of designated and qualifying cash flow hedges.

13. Commitments and Contingencies

a) The Partnership’s share of commitments to fund newbuilding and other construction contract costs as at December 31, 2016 are as follows:

	Total $	2017 $	2018 $	2019 $	2020 $
DSME (i)	1,118,345	627,181	491,164	—	—
Hyundai Samho Heavy Industries Co. (ii)	378,347	82,507	45,533	250,307	—
Yamal LNG Joint Venture (iii)	883,030	91,800	344,850	247,800	198,580
BG Joint Venture (iv)	195,565	80,010	86,154	29,401	—
Bahrain LNG Joint Venture (v)	224,080	110,364	80,097	33,619	—
Exmar LPG Joint Venture (vi)	77,504	58,096	19,408	—	—
	2,876,871	1,049,958	1,067,206	561,127	198,580

(i) As at December 31, 2016, the Partnership had seven LNG carrier newbuildings on order with DSME which are scheduled for delivery between 2017 and 2019. As at December 31, 2016, costs incurred under these newbuilding contracts totaled $316.1 million. The Partnership has secured $682.8 million of financing during 2016 related to the commitments for four LNG carrier newbuildings included in the table above (see Note 5) and in April 2017, secured $174.3 million of additional financing for one LNG carrier newbuilding included in the table above.

(ii) As at December 31, 2016, the Partnership had two LNG carrier newbuildings on order with Hyundai Samho Heavy Industries Co. (or HHI) scheduled for delivery in 2019. As at December 31, 2016, costs incurred under these newbuilding contracts totaled $41.5 million. The Partnership intends to finance the newbuilding payments through existing liquidity and expects to secure long-term debt financing for the vessels prior to their scheduled deliveries.

(iii) The Partnership, through the Yamal LNG Joint Venture, has a 50% ownership interest in six172,000-cubic meter ARC7 LNG carrier newbuildings that have an estimated total fully built-up cost of $2.1 billion. As at December 31, 2016, the Partnership’s proportionate costs incurred under these newbuilding contracts totaled $153.3 million. The Yamal LNG Joint Venture intends to secure debt financing for the six LNG carrier newbuildings prior to their scheduled deliveries.

(iv) The Partnership acquired an ownership interest in the BG Joint Venture and, as part of the acquisition, agreed to assume Shell’s obligation to provide shipbuilding supervision and crew training services for the four LNG carrier newbuildings up to their delivery dates pursuant to a ship construction support agreement. The BG Joint Venture has secured financing of $137.1 million related to the commitments included in the table above and the Partnership is scheduled to receive $10.9 million of reimbursement directly from Shell.

(v) The Partnership has a 30% ownership interest in the Bahrain LNG Joint Venture for the development of an LNG receiving and regasification terminal in Bahrain. The project will include a FSU, which will be modified from one of the Partnership’s existing MEGI LNG carrier newbuildings, an offshore gas receiving facility, and an onshore nitrogen production facility. The terminal will have a capacity of 800 million standard cubic feet per day and will be owned and operated under a 20-year agreement commencing early-2019. The receiving and regasification terminal is expected to have a fully-built up cost of approximately $960.0 million. The Bahrain LNG Joint Venture has secured debt financing for approximately 75% of the estimated fully built-up cost of the LNG receiving and regasification terminal in Bahrain.

(vi) The Partnership has a 50% ownership interest in the Exmar LPG Joint Venture which has four LPG newbuilding vessels scheduled for delivery between 2017 and 2018 and has secured financing for the four LPG carrier newbuildings.

b) As of December 31, 2016, the Partnership adopted the new accounting standard ASC-205-40, Presentation of Financial Statements - Going Concern, which requires management to assess if the Partnership will have sufficient liquidity to continue as a going concern for the one-year period following the issuance of its financial statements. The Partnership anticipates making payments related to

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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)

commitments to fund its wholly-owned vessels under construction of $709.7 million during 2017 and $536.7 million during 2018 as well as other payments relating to its joint ventures (see Note 13a).

Based on these factors, over the one-year period following the issuance of its financial statements, the Partnership will need to obtain additional sources of financing, in addition to amounts generated from operations, to meet its minimum liquidity requirements under its financial covenants. These anticipated sources of financing include refinancing a loan facility maturing in the fourth quarter of 2017 as well as obtaining new debt financing for the unfinanced portion of its vessels under construction.

The Partnership is actively pursuing the alternatives described above, which it considers probable of completion based on the Partnership’s history of being able to refinance similar loan facilities and to obtain new debt financing for its vessels under construction, as well as the progress it has made on the financing process to date. The Partnership is in various stages of completion with respect to its anticipated new financing facilities.

Based on the Partnership’s liquidity at the date these consolidated financial statements were issued, the liquidity it expects to generate from operations over the following year, and by incorporating the Partnership’s plans to raise additional liquidity that it considers probable of completion, the Partnership estimates that it will have sufficient liquidity to continue as a going concern for at least the one-year period following the issuance of these consolidated financial statements.

c) The Partnership owns a 70% ownership interest in the Teekay Nakilat Joint Venture, which was the lessee under three separate 30-year capital lease arrangements with a third party for three LNG carriers (or the RasGas II LNG Carriers). Under the terms of the leasing arrangements for the RasGas II LNG Carriers, the lessor claimed tax depreciation on the capital expenditures it incurred to acquire these vessels. As is typical in these leasing arrangements, tax and change of law risks were assumed by the lessee, in this case the Teekay Nakilat Joint Venture. Lease payments under the lease arrangements were based on certain tax and financial assumptions at the commencement of the leases and subsequently adjusted to maintain the lessor’s agreed after-tax margin. On December 22, 2014, the Teekay Nakilat Joint Venture terminated the leasing of the RasGas II LNG Carriers. However, the Teekay Nakilat Joint Venture remains obligated to the lessor to maintain the lessor’s agreed after-tax margin from the commencement of the lease to the lease termination date and placed $6.8 million on deposit with the lessor as security against any future claims and recorded as part of restricted cash - long-term in the Partnership’s consolidated balance sheets.

The UK taxing authority (or HMRC) has been challenging the use of similar lease structures in the UK courts. One of those challenges was eventually decided in favor of HMRC (Lloyds Bank Equipment Leasing No. 1 or LEL1), with the lessor and lessee choosing not to appeal further. The LEL1 tax case concluded that capital allowances were not available to the lessor. On the basis of this conclusion, HMRC is now asking lessees on other leases, including the Teekay Nakilat Joint Venture, to accept that capital allowances are not available to their lessor. The Teekay Nakilat Joint Venture does not accept this contention and has informed HMRC of this position. It is not known at this time whether the Teekay Nakilat Joint Venture would eventually prevail in court. If the former lessor of the RasGas II LNG Carriers were to lose on a similar claim from HMRC, the Partnership’s 70% share of Teekay Nakilat Joint Venture's potential exposure is estimated to be approximately $60 million. Such estimate is primarily based on information received from the lessor.

d) In May 2016, the Teekay LNG-Marubeni Joint Venture reached a settlement agreement with a charterer relating to a disputed charter contract termination for one of its LNG carriers that occurred in 2015. The charterer paid $39.0 million to the Teekay LNG-Marubeni Joint Venture in June 2016 for lost revenues, of which the Partnership’s share of $20.3 million was recorded in equity income for the year ended December 31, 2016.

14. Supplemental Cash Flow Information

a) The changes in operating assets and liabilities for years endedDecember 31, 2016, 2015 and 2014are as follows:

	Year Ended December 31, 2016 $		Year Ended December 31, 2015 $		Year Ended December 31, 2014 $
Accounts receivable	5,494		(5,140	)	9,957
Prepaid expenses	745		(494	)	1,781
Accounts payable	2,791		2,127		(1,098	)
Accrued liabilities	(1,572	)	(1,581	)	(6,759	)
Unearned revenue and long-term unearned revenue	(3,218	)	(562	)	(536	)
Restricted cash	(10,808	)	(2,785	)	—
Advances to and from affiliates	(9,699	)	(23,714	)	17,953
Other operating assets and liabilities	(4,402	)	(2,038	)	(2,476	)
Total	(20,669	)	(34,187	)	18,822

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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)

b) Cash interest paid (including realized losses on interest rate swaps) on long-term debt, advances from affiliates and capital lease obligations, net of amounts capitalized, during the years ended December 31, 2016, 2015 and 2014 totaled $100.9 million, $94.5 million, and $128.7 million, respectively.

c) During the years ended December 31, 2016, 2015 and 2014, cash paid for corporate income taxes was $4.9 million, $7.8 million and $2.3 million, respectively.

d) During 2014, the sales of the Huelva Spirit and Algeciras Spirit conventional tankers resulted in the vessels under capital lease being returned to the owner and the capital lease obligations concurrently extinguished. Therefore, the sales of the Algeciras Spirit and Huelva Spirit under capital lease obligations of $56.2 million in 2014 and the concurrent extinguishment of the corresponding capital lease obligation of $56.2 million in 2014 were treated as non-cash transactions in the Partnership’s consolidated statements of cash flows.

e) During 2014, the Partnership acquired an LPG carrier, the Norgas Napa, from Skaugen for $27.0 million, of which $21.6 million was paid in cash upon delivery and the remaining $5.4 million is an interest-bearing loan to Skaugen.

f) A portion of the dividends declared by the Teekay Tangguh Joint Venture on February 1, 2014 that was used to settle advances made by the Teekay Tangguh Joint Venture to BLT LNG Tangguh Corporation and P.T. Berlian Laju Tanker of $14.4 million, was treated as a non-cash transaction in the Partnership’s consolidated statements of cash flows.

g) As described in Notes 6a iii – Equity Accounted Investments, during 2014, the Partnership acquired the ownership interest of BG (which was subsequently acquired by Shell) in the BG Joint Venture. As compensation, the Partnership assumed Shell’s obligation (net of an agreement by Shell to pay the Partnership approximately $20.3 million) to provide shipbuilding supervision and crew training services for the four LNG carrier newbuildings up to their delivery dates pursuant to a ship construction support agreement. The estimated fair value of the assumed obligation of approximately $33.3 million was used to offset the purchase price and the Partnership’s receivable from Shell and was treated as a non-cash transaction in the Partnership’s consolidated statements of cash flows.

15. Total Capital and Net Income Per Common Unit

As at December 31, 2016, a total of 68.3% of the Partnership's common units outstanding were held by the public. The remaining common units, as well as the 2% general partner interest, were held by a subsidiary of Teekay Corporation. All of the Partnership's outstanding 9.00% Series A Cumulative Redeemable Perpetual Preferred Units (or the Series A Preferred Units) are held by the public.

Limited Partners’ Rights

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

• Right to receive distribution of Available Cash (as defined in the partnership agreement and which takes into account cash reserves for, among other things, future capital expenditures and future credit needs of the Partnership) within approximately 45 days after the end of each quarter.

• No limited partner shall have any management power over the Partnership’s business and affairs; the General Partner is responsible for the conduct, directions and management of the Partnership’s activities.

• The General Partner may be removed if such removal is approved by unitholders holding at least 66-2/3% of the outstanding units voting as a single class, including units held by our General Partner and its affiliates.

Incentive Distribution Rights

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.

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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)

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.

Net Income Per Common Unit

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 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.

Equity Offerings

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

Date	Units Issued	Type of Units	Offering Price		Gross Proceeds (i) $	Net Proceeds $	Teekay Corporation’s Ownership After the Offering(ii)		Use of Proceeds
July 2014 Public Offering	3,090,000	Common	$	44.65	140,784	140,484	33.96	%	Prepayment of revolving credit facilities, funding of the Yamal LNG Project and funding newbuilding installments
Continuous offering program during 2014	1,050,463	Common	(iii)		42,556	41,655	(iii)		General partnership purposes including funding newbuilding installments
Continuous offering program during 2015(iv)	1,173,428	Common	(iii)		36,274	35,374	(iii)		General partnership purposes, including funding newbuilding installments
October 2016 Public Offering (v)	5,000,000	Preferred	$	25.00	125,000	120,707	(v)		General partnership purposes, including debt repayments and funding newbuilding installments

(i) Including the General Partner’s 2%proportionate capital contribution.

(ii) Including Teekay Corporation’s indirect 2% general partner interest relating to common unit offerings.

(iii) Commencing in May 2013, the Partnership implemented a continuous offering program (or COP) under which the Partnership may issue new common units, representing limited partner interests, from time to time at market prices up to a maximum aggregate amount of $100 million.

(iv) Includes 160,000 common units sold under the COP in December 2014 for which net proceeds of $6.8 million (including the General Partner’s 2% proportionate capital contribution) were received in January 2015.

(v) On October 5, 2016, the Partnership issued Series A Preferred Units at a rate of 9.0% per annum of the stated liquidation preference of $25.00 per unit. At any time on or after October 5, 2021, the Partnership 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.

16. Unit-Based Compensation

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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)

In March 2016, a total of 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 2016. These common units were fully vested upon grant. During 2015 and 2014, the Partnership awarded 10,447 and 9,521 common units, respectively, as compensation to non-management directors. The awards were fully vested in March 2015 and March 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 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 2016, 2015 and 2014, the Partnership granted 132,582, 32,054 and 31,961 restricted units, respectively, with grant date fair values of $1.5 million, $1.1 million and $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 restricted unit is equal in value to one of the Partnership's common units plus reinvested distributions from the grant date to the vesting date. The restricted units vest equally over three years from the grant date. Any portion of a restricted unit award that is not vested on the date of a recipient’s termination of service is 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 is paid to each recipient in the form of common units, net of withholding tax. During the years ended December 31, 2016, 2015 and 2014, the Partnership recorded an expense of $1.3 million, $1.2 million, and $1.0 million, respectively, related to the restricted units.

17. Restructuring Charges

a) Compania Espanole de Petroles, S.A., the charterer and owner of the Partnership’s former conventional vessels under capital lease, sold the Tenerife Spirit, Algeciras Spirit, and Huelva Spirit between December 2013 and August 2014. On redeliveries of the vessels, the charter contract with the Partnership was terminated. As a result of these sales, the Partnership recorded restructuring charges of nil, nil and $2.0 million for the years ended December 31, 2016, 2015 and 2014, respectively. The balances outstanding of $0.7 million as at December 31, 2016 and 2015, respectively, are included in accrued liabilities in the Partnership’s consolidated balance sheets.

b) During 2015, pursuant to a request by the charterer of the Alexander Spirit, the Partnership changed the crew on the vessel which resulted in a restructuring charge of $4.0 million relating to seafarer severance payments. The full amount of the restructuring charge was recovered from the charterer and the recovery was included in voyage revenues in the Partnership’s consolidated statements of income. The balances outstanding of nil and $1.1 million as at December 31, 2016 and 2015, respectively, are included in accrued liabilities in the Partnership's consolidated balance sheets.

18. Write-Down and Loss on Sale of Vessels

a) 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, the Partnership 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. The Partnership used the total proceeds of $94.3 million from the sales primarily to repay existing term loans associated with these vessels.

b) On November 30, 2016, the Partnership reached an agreement to sell the Asian Spirit Suezmax tanker for net proceeds of $20.6 million and as a result, recorded an $11.5 million impairment on the write-down of the vessel. Delivery of the vessel to the new owner occurred on March 21, 2017. The Partnership used the net proceeds from the sales primarily to repay existing term loans associated with the vessel. As at December 31, 2016, the vessel was classified as held for sale in the Partnership’s consolidated balance sheets.

19. Subsequent Events

a) In December 2016, the Partnership entered into an agreement to acquire Skaugen's 35% ownership interest in Skaugen Gulf Petchem Carriers B.S.C.(c) (or the Skaugen LPG Joint Venture) which owns the LPG carrier Norgas Sonoma. The Partnership entered into this transaction in exchange for a portion of past due amounts owed to the Partnership by Skaugen. The Skaugen LPG Joint Venture’s other shareholders include Nogaholding, which has a 35% ownership interest and Suffun Bahrain W.L.L.,which has a 30% ownership interest. Both Nogaholding and Suffun exercised their respective option to participate in the sale of the Norgas Sonoma and as a result, on April 20, 2017, the Partnership acquired 100% ownership interest in the Norgas Sonoma for $13 million.

b) On January 23, 2017, the Partnership issued in the Norwegian bond market NOK 300 million (equivalent to approximately $36 million) in new senior unsecured bonds through an add-on to its 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%.

F-32

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)

c) On February 28, 2017, the Partnership took delivery of its third MEGI LNG carrier newbuilding, the Torben Spirit, which commenced its 10-month plus one-year option charter contract with a major energy company on March 3, 2017. The Partnership received proceeds through a sale-leaseback transaction of approximately $125 million in March 2017 for this MEGI LNG carrier newbuilding.

d) On December 21, 2016, the RasGas 3 Joint Venture, of which the Partnership has 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 the Partnership's proportionate share was $40 million.

e) 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. As part of the completed refinancing, the Partnership invested $57 million of additional equity, based on its proportionate ownership interest, into the Teekay LNG-Marubeni Joint Venture.

f) On April 21, 2017, the Partnership entered into a 10-year $174 millionsale-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 the Partnership. At the end of the 10-year tenor of this lease, the Partnership has an obligation to repurchase the vessel from CCBL.

F-33