Edgar Filing: Teekay LNG Partners L.P.

20-F

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

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

For the fiscal year ended December 31, 2015

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

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

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)

4^th 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

4^th 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

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.

79,551,012 Common Units

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

Act. Yes x 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 x

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 x 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 x No ¨

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


Large Accelerated Filer		x		Accelerated Filer		¨		Non-Accelerated Filer		¨

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

U.S. GAAP

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 x

TEEKAY LNG PARTNERS L.P.

INDEX TO REPORT ON FORM 20-F


		*Page*
PART I.

Item 1.	Identity of Directors, Senior Management and Advisors		4

Item 2.	Offer Statistics and Expected Timetable		4

Item 3.	Key Information		5

	Selected Financial Data		5

	Risk Factors		9

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

	C. Regulations		34

	D. Properties		37

	E. Organizational Structure		37

Item 4A.	Unresolved Staff Comments		37

Item 5.	Operating and Financial Review and Prospects		38

	Overview		38

	Significant Developments in 2015 and Early 2016		38

	Important Financial and Operational Terms and Concepts		39

	Results of Operations		40

	Year Ended December 31, 2015 versus Year Ended December 31, 2014		41

	Year Ended December 31, 2014 versus Year Ended December 31, 2013		46

	Liquidity and Cash Needs		50

	Credit Facilities		52

	Contractual Obligations and Contingencies		53

	Off-Balance Sheet Arrangements		54

	Critical Accounting Estimates		54

Item 6.	Directors, Senior Management and Employees		57

	Management of Teekay LNG Partners L.P.		57

	Directors and Executive Officers		57

	Annual Executive Compensation		58

	Compensation of Directors		59

	2005 Long-Term Incentive Plan		59

	Board Practices		59

	Crewing and Staff		60

	Unit Ownership		60

Item 7.	Major Unitholders and Related Party Transactions		61

	Major Unitholders		61


	Related Party Transactions	61

Item 8.	Financial Information	62

	A. Consolidated Financial Statements and Other Financial Information	62

	Consolidated Financial Statements and Notes	62

	Legal Proceedings	62

	Cash Distribution Policy	62

	B. Significant Changes	63

Item 9.	The Offer and Listing	64

Item 10.	Additional Information	64

	Memorandum and Articles of Association	64

	Material Contracts	64

	Exchange Controls and Other Limitations Affecting Unitholders	66

	Taxation	66

	Marshall Islands Tax Consequences	66

	United States Tax Consequences	66

	Canadian Federal Income Tax Considerations	76

	Other Taxation	76

	Documents on Display	76

Item 11.	Quantitative and Qualitative Disclosures About Market Risk	77

Item 12.	Description of Securities Other than Equity Securities	78

PART II.

Item 13.	Defaults, Dividend Arrearages and Delinquencies	78

Item 14.	Material Modifications to the Rights of Unitholders and Use of Proceeds	78

Item 15.	Controls and Procedures	78

Item 16A.	Audit Committee Financial Expert	79

Item 16B.	Code of Ethics	79

Item 16C.	Principal Accountant Fees and Services	79

Item 16D.	Exemptions from the Listing Standards for Audit Committees	80

Item 16E.	Purchases of Units by the Issuer and Affiliated Purchasers	80

Item 16F.	Change in Registrant’s Certifying Accountant	80

Item 16G.	Corporate Governance	80

Item 16H.	Mine Safety Disclosure	80

PART III.

Item 17.	Financial Statements	81

Item 18.	Financial Statements	81

Item 19.	Exhibits	81

Signature		84

PART I

This annual report of Teekay LNG Partners L.P. on Form 20-F for the year ended December 31, 2015 (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 common units described herein, shall mean specifically Teekay LNG Partners L.P. References in this Annual Report to “Teekay Corporation” refer to Teekay Corporation and/or any one or more of its subsidiaries.

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

•

our distribution policy and our ability to make cash distributions on our units or any increases in quarterly distributions, the temporary nature of our current reduced distribution level 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, anticipated funds for liquidity needs and the sufficiency of cash flows;

•

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;

•

our ability to conduct and operate our business and the business of our subsidiaries in a manner than minimizes taxes imposed upon us and our subsidiaries;

•

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 ability to maximize the use of our vessels, including the redeployment or disposition of vessels no longer under long-term charter, including our 52% owned vessels, the Magellan Spirit and the Methane Spirit;

•

the adequacy of our insurance coverage, including our expectation that insurance will cover the costs related to the grounding of the Magellan Spirit, less an applicable deductible;

•

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

•

expected purchases and deliveries of newbuilding vessels, our ability to obtain charter contracts for LNG carrier newbuildings that are not yet subject to fixed-rate contracts, and the newbuildings’ commencement of service under charter contracts;

•

expected financing and 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;

•

expected refinancing of our two debt facilities maturing in 2016, including our $50.4 million debt facility that is expected to be refinanced with a new $60.0 million three year term loan in May 2016;

•

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 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;

•

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

•

our expectations regarding timing of redelivery of the Hamilton Spirit and the Bermuda Spirit to Centrofin Management Inc. (or Centrofin) and losses resulting from such sales to Centrofin;

•

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 financing, 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%), Samsung C&T (or Samsung) (20%) and Gulf Investment Corporation (or GIC) (20%) (or the Bahrain LNG Joint Venture), and our expectations regarding the supply, modification and charter of the 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 Advisors

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 2011 through 2015, 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, 2015, 2014 and 2013.

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


(in thousands of U.S. Dollars, except per unit and fleet data)	Year Ended December 31, 2011 $			Year Ended December 31, 2012 $			Year Ended December 31, 2013 $			Year Ended December 31, 2014 $			Year Ended December 31, 2015 $
Income Statement Data:
Voyage revenues		380,469			392,900			399,276			402,928			397,991
Total operating expenses⁽¹⁾		(206,966	)		(245,109	)		(222,920	)		(219,105	)		(216,619	)

Income from vessel operations		173,503			147,791			176,356			183,823			181,372

Equity income⁽²⁾		20,584			78,866			123,282			115,478			84,171
Interest expense		(49,880	)		(54,211	)		(55,703	)		(60,414	)		(43,259	)
Interest income		6,687			3,502			2,972			3,052			2,501
Realized and unrealized loss on derivative
instruments⁽³⁾		(63,030	)		(29,620	)		(14,000	)		(44,682	)		(20,022	)
Foreign currency exchange gain (loss)⁽⁴⁾		10,310			(8,244	)		(15,832	)		28,401			13,943
Other income (expense)		(37	)		1,683			1,396			836			1,526
Income tax expense		(781	)		(625	)		(5,156	)		(7,567	)		(2,722	)

Net income		97,356			139,142			213,315			218,927			217,510

Non-controlling and other interest in net income		18,982			36,740			37,438			44,676			42,903
Limited partners’ interest in net income		78,374			102,402			175,877			174,251			174,607
Limited partners’ interest in net income per:
Common unit (basic and diluted)		1.33			1.54			2.48			2.30			2.21
Cash distributions declared per unit		2.5200			2.6550			2.7000			2.7672			2.8000
Balance Sheet Data (at end of period):
Cash and cash equivalents		93,627			113,577			139,481			159,639			102,481
Restricted cash⁽⁵⁾		495,634			528,589			497,298			45,997			111,519
Vessels and equipment⁽⁷⁾		2,021,125			1,949,640			1,922,662			1,989,230			2,108,160
Investment in and advances to equity accounted
joint ventures		191,448			409,735			671,789			891,478			883,731
Net investments in direct financing leases⁽⁸⁾		409,541			403,386			699,695			682,495			666,658
Total assets^{(5) (6)}		3,572,138			3,769,649			4,203,143			3,947,275			4,052,980
Total debt and capital lease obligations^(5) (6)		1,945,682			2,035,130			2,359,385			1,970,531			2,058,336
Partners’ equity		1,113,467			1,212,980			1,390,790			1,537,752			1,519,062
Total equity		1,139,709			1,254,274			1,443,784			1,547,371			1,543,679
Common units outstanding		64,857,900			69,683,763			74,196,294			78,353,354			79,551,012
Other Financial Data:
Net voyage revenues⁽⁹⁾		379,082			391,128			396,419			399,607			396,845
EBITDA⁽¹⁰⁾		233,743			290,950			369,086			377,983			353,243
Adjusted EBITDA⁽¹⁰⁾		320,929			413,033			461,018			468,954			464,353
Capital expenditures:
Expenditures for vessels and equipment		64,685			39,894			470,213			194,255			191,969
Liquefied Gas Fleet Data:
Consolidated:
Calendar-ship-days⁽¹¹⁾		5,126			5,856			5,981			6,619			6,935
Average age of our fleet (in years at end of period)		5.8			6.6			6.7			7.9			8.9
Vessels at end of period⁽¹³⁾		16			16			18			19			19
Equity Accounted:⁽¹²⁾
Calendar-ship-days⁽¹¹⁾		2,469			5,481			11,059			11,338			11,720
Average age of our fleet (in years at end of period)		3.0			3.4			9.4			8.0			8.5
Vessels at end of period⁽¹³⁾		9			16			32			31			32
Conventional Fleet Data:
Calendar-ship-days⁽¹¹⁾		4,015			4,026			3,994			3,202			2,920
Average age of our fleet (in years at end of period)		6.9			7.9			8.5			8.5			9.5
Vessels at end of period		11			11			10			8			8

(1)

Total operating expenses include voyage expenses and vessel operating 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. Vessel operating expenses include crewing, ship management services, repairs and maintenance, insurance, stores, lube oils and communication expenses.

(2)

Equity income includes unrealized gains (losses) on derivative instruments, and any ineffectiveness of derivative instruments designated as hedges for accounting purposes of ($5.8) million, $5.5 million, $25.9 million, $1.6 million and $10.2 million for the years ended December 31, 2011, 2012, 2013, 2014 and 2015, respectively.

(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 13 – Derivative Instruments.”

(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. Starting in May 2012, foreign exchange gains and losses included 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 269.2 million Euros ($348.9 million) at December 31, 2011, 258.8 million Euros ($341.4 million) at December 31, 2012, 247.6 million Euros ($340.2 million) at December 31, 2013, 235.6 million Euros ($285.0 million) at December 31, 2014 and 222.7 million Euros ($241.8 million) at December 31, 2015. Our NOK-denominated bonds totaled 700.0 million NOK ($125.8 million) at December 31, 2012, 1.6 billion NOK ($263.5 million) at December 31, 2013, 1.6 billion NOK ($214.7 million) at December 31, 2014 and 2.6 billion NOK ($294.0 million) at December 31, 2015.

(5)

On December 22, 2014, we terminated the leasing of three LNG carriers and acquired them from the lessor. Prior to the acquisition of these three LNG carriers, we operated these LNG carriers under lease arrangements whereby we borrowed under term loans and deposited the proceeds into restricted cash accounts. Concurrently, we entered into capital leases for the vessels, and the vessels were recorded as assets on our consolidated balance sheets. The restricted cash deposits, plus the interest earned on the deposits, would fund the remaining amounts we owed under the capital lease arrangements. Therefore, the payments under these capital leases were fully funded through our restricted cash deposits, and the continuing obligation was the repayment of the term loans. However, under GAAP we recorded both the obligations under the capital leases and the term loans as liabilities, and both the restricted cash deposits and our vessels under capital leases as assets. This accounting treatment had the effect of increasing our assets and liabilities by the amount of restricted cash deposits relating to the corresponding capital lease obligations as at December 31, 2011, 2012 and 2013.

(6)

Prior to the adoption of Accounting Standards Update 2015-03, Simplifying the Presentation of Debt Issuance Costs (or ASU 2015-03), all debt issuance costs were presented as other non-current assets in our consolidated balance sheets. With the adoption of ASU 2015-03, we present debt issuance costs related to a recognized debt liability as a direct deduction from the carrying amount of that debt liability in our consolidated balance sheets. As a result of adopting ASU 2015-03, total assets and total debt and capital lease obligations decreased by $16.6 million (December 31, 2011), $15.8 million (December 31, 2012), $16.5 million (December 31, 2013), $17.1 million (December 31, 2014) and $16.3 million (December 31, 2015).

(7)	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.

(8)

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.

(9)

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, a non-GAAP financial measure, 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, 2011			Year Ended December 31, 2012			Year Ended December 31, 2013			Year Ended December 31, 2014			Year Ended December 31, 2015
Voyage revenues		380,469			392,900			399,276			402,928			397,991
Voyage expenses		(1,387	)		(1,772	)		(2,857	)		(3,321	)		(1,146	)

Net voyage revenues		379,082			391,128			396,419			399,607			396,845

(10)	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 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 units.

Neither EBITDA nor Adjusted EBITDA, which are non-GAAP measures, 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, and our historical consolidated Adjusted EBITDA to net operating cash flow.


(in thousands of U.S. Dollars)	Year Ended December 31, 2011			Year Ended December 31, 2012			Year Ended December 31, 2013			Year Ended December 31, 2014			Year Ended December 31, 2015
Reconciliation of “EBITDA” and “Adjusted EBITDA” to “Net income”:
Net income		97,356			139,142			213,315			218,927			217,510
Depreciation and amortization		92,413			100,474			97,884			94,127			92,253
Interest expense, net of interest income		43,193			50,709			52,731			57,362			40,758
Income tax expense		781			625			5,156			7,567			2,722

EBITDA		233,743			290,950			369,086			377,983			353,243

Restructuring charge, net of reimbursement		—			—			1,786			1,989			—
Write down of vessels		—			29,367			—			—			—
Foreign currency exchange (gain) loss		(10,310	)		8,244			15,832			(28,401	)		(13,943	)
Amortization of in-process contracts included in voyage revenues, net of offsetting vessel operating expenses		(494	)		(649	)		(1,113	)		(1,113	)		(1,113	)
Unrealized loss (gain) on derivative instruments		277			(6,900	)		(22,568	)		2,096			(12,375	)
Realized loss on interest rate swaps		62,660			37,427			38,089			41,725			28,968
Adjustments to Equity Accounted EBITDA⁽¹⁴⁾		35,053			54,594			59,906			74,675			109,573

Adjusted EBITDA		320,929			413,033			461,018			468,954			464,353

Reconciliation of “Adjusted EBITDA” to “Net operating cash flow”:
Net operating cash flow		122,046			192,013			183,532			191,097			239,729
Expenditures for dry docking		19,638			7,493			27,203			13,471			10,357
Interest expense, net of interest income		43,193			50,709			52,731			57,362			40,758
Income tax expense		781			625			5,156			7,567			2,722
Change in operating assets and liabilities		33,458			7,307			(10,078	)		(18,822	)		34,187
Equity income from joint ventures		20,584			78,866			123,282			115,478			84,171
Dividends received from equity accounted joint ventures		(15,340	)		(14,700	)		(13,738	)		(11,005	)		(97,146	)
Restructuring charge, net of reimbursement		—			—			1,786			1,989			—
Realized loss on interest rate swaps		62,660			37,427			38,089			41,725			28,968
Realized (gain) loss on cross-currency swaps recorded in foreign currency exchange (gain) loss		—			(257	)		338			2,222			7,640
Adjustments to Equity Accounted EBITDA⁽¹⁴⁾		35,053			54,594			59,906			74,675			109,573
Other, net		(1,144	)		(1,044	)		(7,189	)		(6,805	)		3,394

Adjusted EBITDA		320,929			413,033			461,018			468,954			464,353

(11)	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.

(12)

Equity accounted vessels include (i) six LNG carriers (or the MALT LNG Carriers) relating to our joint venture with Marubeni Corporation from 2012 (or the Teekay LNG-Marubeni Joint Venture), (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 and (iv) two LNG carriers (or the Exmar LNG Carriers) relating our LNG joint venture with Exmar NV (or Exmar) and (v) 16, 15 and 16 LPG carriers (or the Exmar LPG Carriers) from 2015, 2014 and 2013, 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 percentage.

(13)	For 2015, the number of vessels indicated do not include 11 LNG newbuilding carriers in our consolidated liquefied gas fleet and 17 LNG and LPG newbuilding carriers in our equity accounted liquefied gas fleet.

(14)	The following table details the adjustments to equity income:


(in thousands of U.S. Dollars)	Year Ended December 31, 2011			Year Ended December 31, 2012			Year Ended December 31, 2013			Year Ended December 31, 2014			Year Ended December 31, 2015
Reconciliation of “Adjusted Equity-Accounted EBITDA” to “Equity Income”:

Equity Income		20,584			78,866			123,282			115,478			84,171

Depreciation and amortization		5,501			25,589			45,664			45,885			48,702
Interest expense, net of interest income		14,368			26,622			35,110			36,916			37,376
Income tax (recovery) expense		(315	)		87			163			(155	)		315
Amortization of in-process revenue contracts		(341	)		(11,083	)		(14,173	)		(8,295	)		(7,153	)
Foreign currency exchange loss (gain)		133			(18	)		149			(441	)		(527	)
(Gain) loss on sales of vessels		—			—			—			(16,923	)		1,228
Unrealized loss (gain) on derivative instruments		5,830			(5,549	)		(26,432	)		(1,563	)		10,945
Realized loss on interest rate swaps		9,877			18,946			19,425			19,251			18,687

Adjustments to Equity-Accounted EBITDA		35,053			54,594			59,906			74,675			109,573

Adjusted Equity-Accounted EBITDA		55,637			133,460			183,188			190,153			193,744

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 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 units.

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

The amount of cash we can distribute on our common 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.

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 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) each quarter. 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 have temporarily 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.

Current market conditions limit our access to capital and our growth.

We have relied primarily upon bank financing and debt and equity offerings to fund our growth. Current depressed market conditions generally in the energy sector and for master limited partnerships have significantly reduced our access to capital, particularly equity capital. Public debt financing or refinancing may not be available on acceptable terms, if at all. Issuing additional common equity given current market conditions would be highly dilutive and costly. Lack of access to public debt or equity capital at reasonable rates will adversely affect our growth prospects and our ability to refinance debt and make distributions to our unitholders.

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, 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:

•

seeking to restructure 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 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 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 these acquisitions. We currently have 20 LNG carrier newbuildings scheduled for delivery between 2016 and 2020, and six LPG carrier newbuildings scheduled for delivery between 2016 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 at various times from 2016 through to 2018 and which have an aggregate purchase price of approximately $65.9 million at December 31, 2015.

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.

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 and in pursuing other business opportunities.

As at December 31, 2015, our consolidated debt, capital lease obligations and advances from affiliates totaled $2.1 billion and we had the capacity to borrow an additional $130.0 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 a new line 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. 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 to us and on our units. In addition, our financing agreements prohibit the payment of distributions upon the occurrence of the following events, among others:

•

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;

•

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.

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 subsidiaries of Teekay Corporation and certain of our joint venture partners, on the other hand, the Teekay Corporation subsidiaries and certain of our joint venture partners provide to us administrative and business development services and to our operating subsidiaries significant operational services (including vessel maintenance, crewing for some of our vessels, purchasing, shipyard supervision, insurance and financial services) and other technical, advisory and administrative services. Our operational success and ability to execute our growth strategy depend significantly upon Teekay Corporation’s and certain of our joint venture partners’ satisfactory performance of these services. Our business will be harmed if Teekay Corporation or certain of our joint venture partners fails to perform these services satisfactorily or if Teekay Corporation or certain of our joint venture partners stops providing these services to us or our operating subsidiaries.

Our ability to compete for the transportation requirements of LNG and oil projects and to enter into new time-charters and expand our customer relationships depends largely on our ability to leverage our relationship with Teekay Corporation and its reputation and relationships in the shipping industry. Our ability to compete for the transportation requirement of LPG projects and to enter into new charters and expand our customer relationships depends largely on our ability to leverage our relationship with one of our joint venture partners and their 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;

•

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.

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

•

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;

•

low oil prices negatively affecting 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 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 tanker business. Upon completion of the remaining charter terms for our conventional tankers, any adverse changes in the oil markets may affect our ability to enter into long-term fixed-rate contracts for our conventional tankers. 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. Consequently, 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 results of operations.

Commencing in 2007 and 2008, the global economy experienced an economic downturn and crisis in the global financial markets that produced illiquidity in the capital markets, market volatility, increased exposure to interest rate and credit risks and reduced access to capital markets. If there is economic instability in the future, we may face restricted access to the capital markets or secured debt lenders, such as our revolving credit facilities. The 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:

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

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

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

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

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

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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.

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:

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shipping industry relationships and reputation for customer service and safety;

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

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quality and experience of seafaring crew;

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

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relationships with shipyards and the ability to get suitable berths;

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

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

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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.

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:

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quality or engineering problems;

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

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work stoppages or other labor disturbances at the shipyard;

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bankruptcy or other financial crisis of the shipbuilder;

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a backlog of orders at the shipyard;

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

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

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our requests for changes to the original vessel specifications;

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

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

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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.

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

We currently have 10 wholly-owned LNG carrier newbuildings on order, which are scheduled for delivery between 2016 and 2019, and we have time-charter contracts for all but two of the 10 ordered newbuildings. The process of obtaining new charters is highly competitive. Consequently, we may be unable to secure charters for these or other newbuildings we may order before their scheduled delivery, if at all, which could harm our business, results of operations and financial condition and our ability to make cash distributions.

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 will depend upon, among other things, the then current states of the LNG and LPG carrier markets. The time charter for two of the MALT LNG Carriers are scheduled to expire in mid-2016. 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.

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 2014, they accounted for approximately 29% 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:

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

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

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competition from more technologically advanced vessels;

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increases in the supply of vessel capacity; and

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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 Floating Storage Unit or a LNG receiving and regasification terminal.

We are converting one of our LNG carrier newbuildings into a floating storage unit (or FSU) to service a LNG regasification and receiving terminal in which we will have a 30% ownership in, please read “Item 18 – Financial Statements: Note 6a – Equity Method 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.

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:

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

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

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

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

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

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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.

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

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.

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, and 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 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 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 security guards, could increase in such circumstances. We may not be adequately insured to cover losses from these incidents, which could have a material adverse effect on us. In addition, hijacking as a result of an act of piracy against our vessels, or an increase in cost or unavailability of insurance for our vessels, could have a material adverse impact on our business, financial condition and results of operations.

Our 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 are chartered to YLNG, an entity that operates in Yemen and has close ties to the Yemeni government. The hostilities in Yemen have adversely affected the LNG facilities in Yemen and could hinder YLNG’s ability to perform its obligations under its time charter contracts with our joint venture, which would adversely affect our operating results and liquidity. As a result, in December 2015, the Teekay LNG-Marubeni Joint Venture agreed to a temporary deferral of a portion of the charter payments for the two LNG carriers for the period from January 1, 2016 to December 31, 2016. Upon future resumption of the LNG plant in Yemen, it is presumed that YLNG will repay the deferred amounts in full plus interest thereon 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.

The 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 units could be substantially affected if the Yamal LNG Project is not completed.

The LNG carrier newbuildings ordered by the Yamal LNG Joint Venture 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:

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failure of the project to obtain debt financing;

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failure to achieve expected operating results;

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changes in demand for LNG;

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

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

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labor disputes; and

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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 on our common units.

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 by 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. In addition, OFAC and other governments or organizations may impose additional sanctions on Novatek, the Yamal LNG Project or other project participants, which may further hinder the ability of the Yamal LNG Project to receive necessary financing. Although we believe that we are in compliance with all applicable sanctions laws and regulations, and intend to maintain such compliance, these sanctions have recently been imposed and the scope of these laws may be subject to changing interpretation. 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 units.

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 units. If the charter party defaults on the time-charter contracts, we may be unable to redeploy the vessels under other time-charter contracts or may be forced to scrap the vessels.

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

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

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

Some of our vessels are chartered to unrated entities, such as the four LNG carriers chartered to Angola LNG Supply Services LLC, the two LNG carriers chartered to YLNG and in addition, our 30% ownership interest in a LNG receiving and regasification terminal, that is scheduled to be built in 2018, has a terminal use agreement with a state-owned company in Bahrain. Some of these unrated entities will use revenue generated from the sale of the shipped gas to pay their shipping and other operating expenses, including the charter fees. The price of the gas may be subject to market fluctuations and the LNG supply may be curtailed by start-up delays and stoppages. If the revenue generated by the charterer is insufficient to pay the charter fees, we may be unable to realize the expected economic benefit from these charter agreements.

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

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

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marine disasters;

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bad weather or natural disasters;

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mechanical failures;

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grounding, fire, explosions and collisions;

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piracy;

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human error; and

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war and terrorism.

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

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

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delays in the delivery of cargo;

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loss of revenues from or termination of charter contracts;

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governmental fines, penalties or restrictions on conducting business;

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higher insurance rates; and

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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.

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: C. Regulations.”

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

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

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

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. 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 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 bonds. We incur interest expense on our Norwegian Kroner-denominated bonds and we have entered into cross-currency swaps to economically hedge the foreign exchange risk on the principal and interest payments of our Norwegian Kroner bonds.

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.

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:

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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

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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 the conflicts committee of its board of directors, not to cause us or our subsidiaries to acquire or operate the carriers;

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

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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.

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, 2015 owned a 31.7% limited partner interest in us. 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:

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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 stockholders of Teekay Corporation, which may be contrary to our interests;

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the executive officers and three of the directors of our General Partner also currently serve as executive officers or directors of Teekay Corporation;

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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;

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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 common 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;

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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;

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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;

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

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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;

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

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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. However, the Chief Executive Officer, the Chief Financial Officer 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. As is typical in these leasing arrangements, tax and change of law risks are assumed by the lessee. The rentals payable under the lease arrangements are predicated on the basis of certain tax and financial assumptions at the commencement of the leases. If an assumption proves to be incorrect or there is a change in the applicable tax legislation or the interpretation thereof by the United Kingdom (U.K.) 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 and our joint venture partner were the lessee under three separate 30-year capital lease arrangements (or the RasGas II Leases) with a third party for three LNG carriers (or the RasGas II LNG Carriers). On December 22, 2014, we and our joint venture partner voluntarily terminated the leasing of the RasGas II LNG Carriers. However, Teekay Nakilat Corporation (or the Teekay Nakilat Joint Venture), of which we own a 70% interest, remains obligated to the lessor under the RasGas II Leases to maintain the lessor’s agreed after-tax margin from the commencement of the lease to the lease termination date.

The UK taxing authority (or HMRC) has been challenging the use of similar lease structures. 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. Initial indications are that HMRC will attempt to progress matters on other leases including the lease of Teekay Nakilat Joint Venture with the intent of asking the lessees to accept the LEL1 tax case verdict that capital allowances were not due. If the Teekay Nakilat Joint Venture were to be challenged by HMRC, it is uncertain 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 potential exposure in the Teekay Nakilat Joint Venture 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 had 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 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 common units.

United States common 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. common unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from their share of our taxable income.

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

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

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

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

The 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:

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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.

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

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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.

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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.

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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.

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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 common units may be modified by administrative, legislative or judicial interpretation at any time. For example, on May 6, 2015, the IRS published proposed regulations that provide guidance regarding whether income earned from certain mineral or natural resources activities will constitute qualifying income. We do not believe the proposed regulations affect our ability to qualify as a publicly traded partnership. However, finalized regulations could modify the amount of our gross income that we are able to treat as qualifying income for the purposes of the qualifying income requirement.

In addition, from time to time, members of Congress propose and consider substantive changes to the existing U.S. federal income tax laws that affect publicly traded partnerships. 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 common unitholders and the value of an investment in our common units.

If the IRS contests the U.S. federal income tax positions we take, the value of our common units could be adversely affected and the costs of any such contest will reduce cash available for distribution to common unitholders. Recently enacted legislation alters the procedures for assessing and collecting taxes due for taxable years beginning after December 31, 2017, in a manner that could substantially reduce cash available for distribution to common 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 common units. In addition, the costs of any contest with the IRS will be borne by us reducing the cash available for distribution to our common unitholders.

Recently enacted legislation applicable to us for taxable years beginning after December 31, 2017 alters the procedures for auditing large partnerships and also alters the procedures for assessing and collecting taxes due (including applicable penalties and interest) as a result of an audit. 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.

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 units on the first business day of each month, instead of on the basis of the date a particular unit is transferred. Recently adopted final 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 common units that may result in adverse U.S. tax consequences to them.

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

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 2015 and that Teekay LNG Holdco L.L.C., our sole remaining regarded corporate subsidiary as of January 1, 2015, will fail to qualify for the Section 883 Exemption in 2015 and in subsequent tax years. Any resulting imposition of U.S. federal income taxes will result in decreased cash available for distribution to common 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 common 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 unitholder with respect to a common unit. The IRS could also challenge certain other tax positions that we have taken, including our position that certain of our subsidiaries that have been classified as corporations for U.S. federal income tax purposes in past years are not PFICs for federal income tax purposes. Any such IRS challenges, whether or not successful, could adversely affect the value of our common units.

Common unitholders may be subject to income tax in one or more non-U.S. countries, including Canada, as a result of owning our common units if, under the laws of any such country, we are considered to be carrying on business there. Such laws may require common 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 common unitholders.

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

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 may provide increased access to emerging opportunities from global expansion of the LNG and LPG sectors. We seek to leverage the expertise, relationships and reputation of Teekay Corporation and its affiliates to pursue these opportunities in the LNG and LPG sectors and may consider other opportunities to which our competitive strengths are well suited. Although we may acquire additional crude oil tankers from time to time, we view our conventional tanker fleet primarily as a source of stable cash flow as we seek to continue to expand our LNG and LPG operations.

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

As of December 31, 2015, our fleet, excluding newbuildings, consisted of 29 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), 22 LPG carriers (including the 16 Exmar LPG Carriers that are accounted for under the equity method), seven Suezmax-class crude oil tankers, and one Handymax product tanker, all of which are double-hulled. Our fleet is young, with an average age of approximately nine years for our LNG carriers, approximately nine years for our LPG Carriers and approximately 10 years for our conventional tankers (Suezmax and Handymax), compared to world averages of 11, 16 and ten years, respectively, as of December 31, 2015.

Our fleets of LNG and LPG carriers currently have approximately 4.6 million and 0.7 million cubic meters of total capacity, respectively. The aggregate capacity of our conventional tanker fleet is approximately 1.1 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 4^th 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 primarily operate under long-term, fixed-rate charters with major energy and utility companies and Teekay Corporation. As of December 31, 2015, the average remaining term for these charters is approximately 11 years for our LNG carriers, approximately five years for our LPG carriers and approximately two years for our conventional tankers (Suezmax and Handymax), subject, in certain circumstances, to termination or vessel purchase rights.

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

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

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

When a vessel is “off-hire” – or not available for service – the customer generally is not required to pay the hire rate and we are responsible for all costs. Prolonged off-hire may lead to vessel substitution or termination of the time-charter. A vessel will be deemed to be off-hire if it is in dry dock. 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.

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 1/600^th 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 on 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, 2015, our LNG carriers 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 413 vessels in the world LNG fleet and approximately 157 additional LNG carriers under construction or on order for delivery through 2019.

The following table provides additional information about our LNG carriers as of December 31, 2015, excluding our 21 newbuildings scheduled for delivery between 2016 and 2020 in which our ownership interest ranges from 20% to 100% (one LNG carrier newbuilding was delivered in February 2016):


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⁾
Equity Accounted
Al Huwaila		214,176		2008		40	%⁽⁷⁾	Ras Laffan Liquefied Natural Gas Company Ltd.	Apr. 2033⁽²⁾
Al Kharsaah		214,198		2008		40	%⁽⁷⁾	Ras Laffan Liquefied Natural Gas Company Ltd.	Apr. 2033⁽²⁾
Al Shamal		213,536		2008		40	%⁽⁷⁾	Ras Laffan Liquefied Natural Gas Company Ltd.	May 2033⁽²⁾
Al Khuwair		213,101		2008		40	%⁽⁷⁾	Ras Laffan Liquefied Natural Gas Company Ltd.	Jun. 2033⁽²⁾
Excelsior		138,087		2005		50	%⁽⁸⁾	Excelerate Energy LP	Jan. 2025⁽²⁾
Excalibur		138,034		2002		49	%⁽⁸⁾	Excelerate Energy LP	Mar. 2022
Soyo		160,400		2011		33	%⁽⁹⁾	Angola LNG Supply Services LLC	Aug. 2031⁽²⁾
Malanje		160,400		2011		33	%⁽⁹⁾	Angola LNG Supply Services LLC	Sep. 2031⁽²⁾
Lobito		160,400		2011		33	%⁽⁹⁾	Angola LNG Supply Services LLC	Oct. 2031⁽²⁾
Cubal		160,400		2012		33	%⁽⁹⁾	Angola LNG Supply Services LLC	Jan. 2032⁽²⁾
Meridian Spirit		165,700		2010		52	%⁽¹⁰⁾	Total E&P Norge AS Mansel Limited	Nov. 2030⁽⁶⁾
Magellan Spirit		165,700		2009		52	%⁽¹⁰⁾	Australia Pacific LNG Processing PTY Limited	Apr. 2016⁽¹¹⁾
Marib Spirit		165,500		2008		52	%⁽¹⁰⁾	Yemen LNG Company Limited	Mar. 2029⁽⁶⁾
Arwa Spirit		165,500		2008		52	%⁽¹⁰⁾	Yemen LNG Company Limited	Apr. 2029⁽⁶⁾
Methane Spirit		165,500		2008		52	%⁽¹⁰⁾	Australia Pacific LNG Processing PTY Limited	Apr. 2016⁽¹²⁾
Woodside Donaldson		165,500		2009		52	%⁽¹⁰⁾	Pluto LNG Party Limited	Jun. 2026⁽¹³⁾

		4,553,079

(1)	Each of our time-charters are subject to certain termination and purchase provisions.

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

(3)	The charterer has one option to extend the term for an additional five years.

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

(5)	The charterer has an option to extend the term for one additional year and at the end of the charter period the charterer has an obligation to repurchase each vessel at a fixed price.

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

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

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

(9)	The Angola LNG Carriers are accounted for under the equity method.

(10)	The MALT LNG Carriers are accounted for under the equity method.

(11)	The charterer has two options to extend the term for an additional 60 days each.

(12)	The charterer has two options to extend the term for 90 days and 60 days, respectively.

(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 2015, 2014 and 2013.


	Year Ended December 31,
	2015			2014			2013
Ras Laffan Liquefied Natural Gas Company Ltd.		18	%		17	%		17	%
Shell Spain LNG S.A.U. ⁽¹⁾		12	%		13	%		13	%
The Tangguh Production Sharing Contractors		11	%		11	%		12	%

(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 contract; voyage revenues in 2013 were only from Repsol YPF, S.A.

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, 2015, our LPG carriers had an average age of approximately nine years, compared to the world LPG carrier fleet average age of approximately 16 years. As of that date, the worldwide LPG tanker fleet consisted of approximately 1,341 vessels and approximately 207 additional LPG vessels were on order for delivery through 2018. LPG carriers range in size from approximately 100 to approximately 86,000 cubic meters. Approximately 50% of the number of 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, 2015, excluding our 50% ownership interest in seven newbuildings scheduled for delivery between 2016 and 2018 (one LPG carrier newbuilding was delivered in February 2016):

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

Mar. 2024

Norgas Cathinka

10,000

2009

99%

Bareboat

I.M. Skaguen SE

Oct. 2024

Norgas Camilla

10,000

2011

99%

Bareboat

I.M. Skaguen SE

Sep. 2026

Norgas Unikum

12,000

2011

99%

Bareboat

I.M. Skaguen SE

Jun. 2026

Bahrain Vision

12,000

2011

99%

Bareboat

I.M. Skaguen SE

Oct. 2026

Norgas Napa

10,200

2003

99%

Bareboat

I.M. Skaguen SE

Nov. 2019

Equity Accounted

Brugge Venture

35,418

1997

50%

Time charter

An international fertilizer company

Jan. 2016

Temse

12,030

1995

50% –

Capital lease

Time charter

An international fertilizer company

Feb. 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%

Time charter

An international fertilizer company

Dec. 2016

Bastogne

35,229

2002

50%

CoA⁽¹⁾

North Sea charters

Oct. 2016

Courcheville

28,006

1989

50%

Time charter

An international energy company

Feb. 2016

Eupen

38,961

1999

50%

Time charter

An international energy company

Jun. 2016

Brussels

35,454

1997

50% –

Capital lease

Time charter

An international fertilizer company

Dec. 2017

Antwerpen

35,223

2005

50% – In-chartered

CoA⁽¹⁾

North Sea charters

Sep. 2016

BW Tokyo

83,270

2009

50% – In-chartered

Time charter

An international energy company

Jun. 2016

Waregem

38,189

2014

50%

Time charter

An international trading company

Jan. 2020

Warinsart

38,213

2014

50%

Time charter

An international energy company

Jun. 2016

Waasmunster

38,245

2014

50%

CoA⁽¹⁾

North Sea charters

Sep. 2016

Warisoulx

38,000

2015

50%

Time charter

An international trading company

Jun. 2018

Kaprijke

38,000

2015

50%

Time charter

An international fertilizer company

Feb. 2026

674,610

(1)	“CoA” refers to contracts of affreightment.

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

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, 2015, the world tanker fleet included 454 conventional Suezmax tankers, representing approximately 15% of worldwide oil tanker capacity, excluding tankers under 10,000 dwt.

As of December 31, 2015, our conventional tankers had an average age of approximately ten years, which is consistent with the average age for the world conventional tanker fleet. 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, 2015:


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. 2016⁽⁴⁾
African Spirit		151,736		2003	100%	ConocoPhillips Shipping LLC	Nov. 2016⁽⁴⁾
Asian Spirit		151,693		2004	100%	ConocoPhillips Shipping LLC	Jan. 2017⁽⁴⁾
Bermuda Spirit		159,000		2009	100%	Centrofin Management Inc.	Apr 2016⁽⁵⁾
Hamilton Spirit		159,000		2009	100%	Centrofin Management Inc.	May 2016⁽⁵⁾
Alexander Spirit		40,083		2007	100%	Caltex Australian Petroleum Pty Ltd.	Sep. 2019

		1,122,702

(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 onwards, 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)

Centrofin, the charterer for both the Bermuda Spirit and Hamilton Spirit Suezmax tankers, exercised its option to purchase both the Bermuda Spirit and Hamilton Spirit in February and March 2016, respectively. We redelivered the Bermuda Spirit to Centrofin in April 2016 and expect to redeliver the Hamilton Spirit to Centrofin in May 2016.

CEPSA accounted for 6%, 7% and 12% of our 2015, 2014 and 2013 consolidated voyage revenues, respectively. No other conventional tanker 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.

Business Strategies

Our primary long-term business objective is to increase distributable cash flow per unit. However, we believe there is currently a dislocation in the energy and master limited partnership capital markets relative to the stability of our businesses. Based on upcoming capital requirements for our committed growth projects and scheduled debt repayment obligations, coupled with uncertainty regarding how long it will take for these capital markets to normalize, 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, we have temporarily reduced our quarterly distributions on our common units and our near-term business strategy is primarily to focus on funding and implementing existing growth projects and repaying or refinancing scheduled debt obligations, rather than pursuing additional growth projects. Despite significant weakness in the global energy and capital markets, 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:

•

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).

•

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.

•

Manage our conventional tanker fleet to provide stable cash flows. The remaining terms for our existing long-term conventional tanker charters are one to six years. We believe the fixed-rate time-charters for our tanker fleet provide us stable cash flows during their terms and a source of funding for expanding our LNG and LPG operations. Depending on prevailing market conditions during and at the end of each existing charter, we may seek to extend the charter, enter into a new charter, operate the vessel on the spot market or sell the vessel, in an effort to maximize returns on our conventional tanker fleet while managing residual risk.

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 the “Operational Leadership” campaign to reinforce commitment to personal and operational safety.

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 Det Norske Veritas. Subject to satisfactory completion of these internal and external audits, certification is valid for five years.

We have established key performance indicators to facilitate regular monitoring of our operational performance. We set targets on an annual basis to drive continuous improvement, and we review performance indicators quarterly to determine if remedial action is necessary to reach our targets.

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 and LPG operations. This staff also provides administrative support to our operations in finance, accounting and human resources. We believe this arrangement affords a safe, efficient and cost-effective operation.

Critical ship management functions undertaken by subsidiaries of Teekay Corporation are:

•

vessel maintenance;

•

crewing;

•

purchasing;

•

shipyard supervision;

•

insurance; and

•

financial management services.

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

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

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

Risk of Loss, Insurance and Risk Management

The operation of any ocean-going vessel carries an inherent risk of catastrophic marine disasters, death or injury of persons and property losses caused by adverse weather conditions, mechanical failures, human error, war, terrorism, piracy and other circumstances or events. In addition, the transportation of crude oil, petroleum products, LNG and LPG is 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): 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 regime supported by our sea staff, shore-based operational and technical specialists and members of our QATO program. We carry out a minimum of two such inspections annually, which helps ensure us that:

•

our vessels and operations adhere to our operating standards;

•

the structural integrity of the vessel is being maintained;

•

machinery and equipment is being maintained to give reliable service;

•

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

•

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

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

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

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

C. Regulations

General

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

International Maritime Organization (or IMO)

The IMO is the United Nations’ agency for maritime safety 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 and European Union authorities have indicated that vessels not in compliance with the ISM Code will be prohibited from trading in U.S. and European Union ports. The ISM Code requires vessel operators to obtain a safety management certification for each vessel they manage, evidencing the ship owner’s development and maintenance of an extensive safety management system. Each of the existing vessels in our fleet is currently ISM Code-certified, and we expect to obtain safety management certificates for each newbuilding vessel upon delivery.

LNG and LPG carriers are also subject to regulation under the IGC Code. Each LNG and LPG carrier must obtain a certificate of compliance evidencing that it meets the requirements of the IGC Code, including requirements relating to its design and construction. Each of our LNG and LPG carriers is currently IGC Code certified. A revised and updated IGC Code, to take account of advances in science and technology, was adopted by the IMO’s Maritime Safety Committee (or MSC) on May 22, 2014. It entered into force on January 1, 2016 with an implementation/application date of July 1, 2016.

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

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

In addition, the IMO has proposed (by the adoption in 2004 of the International Convention for the Control and Management of Ships’ Ballast Water and Sediments (or the Ballast Water Convention) that all tankers of the size we operate that were built starting in 2012 contain ballast water treatment systems, and that all other similarly sized tankers install ballast water treatment systems, to comply with the ballast water performance standard specified in the Ballast Water Convention. This convention has not yet entered into force, but when it becomes effective, we estimate that the installation of ballast water treatment systems on our tankers 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 is to enter into force on January 1, 2017.

European Union (or EU)

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

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

IMO regulations require that, as of January 1, 2015, all vessels operating within Emissions Control Areas (or ECAs) worldwide recognized under MARPOL Annex VI must comply with 0.1% sulfur requirements. Currently, the only grade of fuel meeting this low sulfur content requirement is low 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 sulfur control areas 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.

The EU has recently adopted Regulation (EU) No 1257/2013 which imposes rules regarding ship recycling and management of hazardous materials on vessels. The Regulation sets out requirements for the recycling of vessels in an environmentally sound manner at approved recycling facilities, so as to minimize the adverse effects of recycling on human health and the environment. The Regulation also contains rules to control and properly manage hazardous materials on vessels and prohibits or restricts the installation or use of certain hazardous materials on vessels. The Regulation aims at facilitating the ratification of the Hong Kong International Convention for the Safe and Environmentally Sound Recycling of Ships adopted by the IMO in 2009 (which has not entered into force). It applies to vessels flying the flag of a Member State. In addition, certain of its provisions also apply to vessels flying the flag of a third country calling at a port or anchorage of a Member State. For example, when calling at a port or anchorage of a Member State, the vessels flying the flag of a third country will be required, amongst other things, to have on board an inventory of hazardous materials which complies with the requirements of the Regulation and to be able to submit to the relevant authorities of that Member State a copy of a statement of compliance issued by the relevant authorities of the country of their flag and verifying the inventory. The Regulation is to apply not earlier than December 31, 2015 and not later than December 31, 2018, although certain of its provisions are applicable from December 31, 2014 and certain others are to apply from December 31, 2020.

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 liabilities 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:

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natural resources damages and the related assessment costs;

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real and personal property damages;

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

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

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

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loss of subsistence use of natural resources.

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

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

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

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

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

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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”;

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describe crew training and drills; and

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

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

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

The United States 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 195 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 deals with greenhouse gas emission reduction measures and targets from 2020 in order to limit the global temperature increases above pre-industrial levels to not more than 1.5° Celsius. 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 include the “Energy Efficiency Design Index,” which is mandatory for newbuilding vessels, and the “Ship Energy Efficiency Management Plan,” which is mandatory for all vessels. 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. Work on the development of such a system continued during 2015. 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 recently adopted Regulation (EU) 2015/757 on the monitoring, reporting and verification of CO2 emissions from vessels (or the MRV Regulation) which entered into force on July 1, 2015. The MRV Regulation is to generally apply to all vessels over 5,000 gross tonnage, irrespective of flag, in respect of CO2 emissions released during intra-EU voyages and EU incoming and outgoing voyages. The first reporting period will commence on January 1, 2018. The monitoring, reporting and verification system adopted by the MRV Regulation may be the precursor to a market-based mechanism to be adopted in the future. In the United States, the EPA issued an “endangerment finding” regarding greenhouse gases under the Clean Air Act. While this finding in itself does not impose any requirements on our industry, it authorizes the EPA to regulate directly greenhouse gas emissions through a rule-making process. In addition, climate change initiatives are being considered in the United States Congress and by individual states. Any passage of new climate control legislation or other regulatory initiatives by the IMO, EU, the United States or other countries or states where we operate that restrict emissions of greenhouse gases could have a significant financial and operational impact on our business that we cannot predict with certainty at this time.

Vessel Security

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

D. Properties

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

E. Organizational Structure

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

Please read Exhibit 8.1 to this Annual Report for a list of our significant subsidiaries as at December 31, 2015.

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 may provide increased access to emerging opportunities from global expansion of the LNG and LPG sectors. We seek to leverage the expertise, relationships and reputation of Teekay Corporation and its affiliates to pursue these opportunities in the LNG and LPG sectors and may consider other opportunities to which our competitive strengths are well suited. Although we may acquire additional crude oil tankers from time to time, we view our conventional tanker fleet primarily as a source of stable cash flow as we continue to expand our LNG and LPG operations.

Global natural gas and crude oil prices have significantly declined since mid-2014. A continuation of lower natural gas or oil prices or a further decline in natural gas or oil prices may adversely affect investment in the exploration for or development of new or existing natural gas reserves or projects and limit our growth opportunities, as well as reduce our revenues upon entering into replacement or new charter contracts. In addition, lower oil prices may negatively affect both the competitiveness of natural gas as a fuel for power generation and the market price of natural gas, to the extent that natural gas prices are benchmarked to the price of crude oil. These changes may impact our ability to charter our two LNG carriers under construction that have no charter contracts yet or the daily hire rates we are able to negotiate on any charters we are able to obtain for these two vessels. 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 2015 AND EARLY 2016

Charter Contracts for two Suezmax Tankers

During February and March 2016, Centrofin, the charterer for both the Bermuda Spirit and Hamilton Spirit Suezmax tankers, exercised its option to purchase both the Bermuda Spirit and Hamilton Spirit as permitted under the charter agreement. As a result of Centrofin’s acquisition of the Bermuda Spirit and Hamilton Spirit, we expect to record a loss from the sale of these vessels and expected termination of the charter agreements in 2016 of approximately $14 million per vessel. The Bermuda Spirit was sold on April 15, 2016 and the Hamilton Spirit is expected to be sold in May 2016.

Bahrain Project

On December 2, 2015, a consortium composed of Samsung, GIC and us agreed with the Government of the Kingdom of Bahrain (or Kingdom) for the development of an LNG receiving and regasification terminal in Bahrain. The project, to be developed on a BOOT (build, own, operate, transfer) basis, will be located in the Hidd Industrial area of Bahrain and will help the Kingdom meet its increasing demand for gas supplies to satisfy its industrial and urban development. The LNG receiving and regasification terminal will be owned and operated through the Bahrain LNG Joint Venture.

The project will include a floating storage unit (or FSU), 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. The project is expected to have a capacity of 800 million standard cubic feet per day and will be owned and operated under a 20-year agreement which is expected to commence in 2018. The terminal project, excluding the FSU but including project management and development, financing and other costs, is expected to cost approximately $872 million, which is expected to be funded by the Bahrain LNG Joint Venture through a combination of equity capital and project-level debt through a consortium of regional and international banks.

We will supply the FSU vessel by using one of our previously unchartered MEGI LNG carrier newbuildings, which will be modified specifically for this project, and we will charter this FSU to the Bahrain LNG Joint Venture for a period of 20 years commencing in 2018.

LNG Newbuildings

In June 2015, we ordered two LNG carrier newbuildings from Hyundai Samho Heavy Industries Co., Ltd. (or HHI), of which one of the LNG carrier newbuildings will be chartered out to BP Shipping Limited (or BP) at fixed rates for a period of 13 years. As discussed above, the Bahrain project will include a FSU, which will be modified from one of our existing MEGI LNG carrier newbuildings. In total, we have 11 wholly-owned LNG carrier newbuildings on order as of December 31, 2015, and on February 18, 2016, we took delivery of the first of the 11 MEGI LNG carrier newbuildings on order, which commenced its five-year charter contract with a subsidiary of Cheniere Energy, Inc. on February 29, 2016. The remaining 10 wholly-owned LNC carrier newbuildings on order are scheduled for delivery between mid-2016 and early 2019; we have time-charter contracts for all but two of the remaining 10 ordered newbuildings. In addition to our 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.

Equity Offerings

During 2015, we sold a total of 1,173,428 common units of which 160,000 units were from 2014 transactions which settled in 2015 under our continuous offering program for net proceeds of $35.4 million (including our General Partner’s 2% proportionate capital contribution and net of offering costs). We used the proceeds for general partnership purposes, including funding newbuilding installments.

Bond Issuance

In May 2015, we issued, in the Norwegian bond market, NOK 1,000 million in senior unsecured bonds that mature in May 2020. The aggregate principal amount of the bonds was equivalent to $134.0 million and all interest and principal payments have been swapped into U.S. Dollars at a fixed interest rate of 5.92%. We used the net proceeds from the bond offering for general partnership purposes, including the funding of newbuilding installments. The bonds are listed on the Oslo Stock Exchange.

Charter Contracts for MALT LNG Carriers

In January 2015, the Magellan Spirit, one of the six MALT LNG Carriers in our joint venture with Marubeni Corporation (or the Teekay LNG-Marubeni Joint Venture) in which we have a 52% ownership interest, had a grounding incident. The vessel was subsequently refloated and returned to service. We expect the cost of such refloating and related costs associated with the grounding to be covered by insurance, less an applicable deductible. The charterer has 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, which it did in late-March 2015. The Teekay LNG-Marubeni Joint Venture has disputed both the charterer’s aggregate off-hire claims as well as the charterer’s ability to terminate the charter contract, which originally would have expired in September 2016. The Teekay LNG-Marubeni Joint Venture has obtained legal assistance in seeking to resolve this dispute. The impact in future periods from this incident will depend upon our ability to re-charter the vessel and the resolution of this dispute. The charter contract of another MALT LNG Carrier, the Methane Spirit, expired in March 2015 as scheduled. The Teekay LNG-Marubeni Joint Venture secured some short-term employment for the Magellan Spirit and Methane Spirit during the second and third quarters of 2015. In October 2015, both the Magellan Spirit and the Methane Spirit commenced charter contracts for a period of six months plus two extension options ranging from two to three months at significantly lower charter rates than their previous contracts. The Teekay LNG-Marubeni Joint Venture continues to seek medium-term to long-term employment for both vessels.

The Teekay LNG-Marubeni Joint Venture is a party to a loan facility for four of its LNG carriers, including the Magellan Spirit that had the grounding incident in January 2015. We have guaranteed our 52% share of the Teekay LNG-Marubeni Joint Venture’s obligations under this facility. The loan facility contains mandatory prepayment provisions upon early termination of a charter and requires the borrower to maintain a specific debt service coverage ratio. In June 2015, the lenders waived the mandatory prepayment provision in relation to the Magellan Spirit and the debt service coverage ratio covenant for the loan facility. Both waivers are for the remaining term of the facility. In return, the Teekay LNG-Marubeni Joint Venture funded an earnings account, which is collateral for the loan facility, with $7.5 million and prepaid $30.0 million of the loan facility, both in September 2015. These amounts were funded by us and Marubeni Corporation based on our respective ownership percentages.

Two of the MALT LNG Carriers, 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 down its operations of its LNG plant in Yemen in 2015. As a result, in December 2015, the Teekay LNG-Marubeni Joint Venture agreed to a temporary deferral of a portion of the charter payments for the two LNG carriers for the period from January 1, 2016 to December 31, 2016. Upon future resumption of the LNG plant in Yemen, it is presumed that YLNG will repay the deferred amounts in full plus interest thereon over a period of time to be agreed upon. Our proportionate share of the estimated impact in 2016 would be a reduction to equity income of approximately $18 million.

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, 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:

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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;

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

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

Revenue Days. Revenue days are the total number of calendar days our vessels were in our possession during a period less the total number of off-hire days during the period associated with major repairs, dry dockings or special or intermediate surveys. Consequently, revenue days represents the total number of days available for the vessel to earn revenue. Idle days, which are days when the vessel is available to earn revenue, yet is not employed, are included in revenue days. We use revenue days to explain changes in our net voyage revenues between periods.

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

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

RESULTS OF OPERATIONS

Items You Should Consider When Evaluating Our Results of Operations

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

•

The amount and timing of dry docking of our vessels can significantly affect our revenues between periods. Our vessels are off-hire at various times due to scheduled and unscheduled maintenance. During 2015, 2014 and 2013, we had 69, 140 and 135 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 14 days in 2015, 26 days in 2014 and none in 2013 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 2015 and Early 2016” above for further details about certain prior and future vessel deliveries and sales.

•

Vessel operating and other costs are facing industry-wide cost pressures. The shipping industry continues to experience a global manpower shortage of qualified seafarers in certain sectors due to growth in the world fleet and competition for qualified personnel. Going forward, there may be significant increases in crew compensation as vessel and officer supply dynamics continue to change. 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 12c – Related Party Transactions” and “Note 13 – Derivative Instruments.” The unrealized gains or losses relating to changes in fair value of our derivative instruments do not impact our cash flows.

•

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

•

Three of our Suezmax tankers and one of our LPG carriers earned revenues based partly on spot market rates. The time-charter contract for one of our Suezmax tankers, the Teide Spirit, and one of our LPG carriers, the Norgas Napa, contain a component providing for additional revenue to us beyond the fixed-hire rate when spot market rates exceed certain threshold amounts. The time-charter contracts for the Bermuda Spirit and Hamilton Spirit Suezmax tankers were amended in the fourth quarter of 2012 for a period of 24 months, which ended on September 30, 2014, and during this period 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.

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, (ii) the four Angola LNG Carriers, (iii) the four RasGas 3 LNG Carriers, (iv) four LNG carrier newbuildings relating to the BG Joint Venture, (v) six LNG carrier newbuildings relating to the Yamal LNG Joint Venture, (vi) the two Exmar LNG Carriers and (vii) the 16 Exmar LPG Carriers and seven LPG carrier newbuildings relating to our 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:


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

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);

•

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.

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 own and two of which we lease 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,	Year Ended December 31,						% Change
calendar-ship-days and percentages)	2015			2014			% Change
Voyage revenues		92,935			95,502			(2.7	)
Voyage expenses		(1,349	)		(1,553	)		(13.1	)

Net voyage revenues		91,586			93,949			(2.5	)
Vessel operating expenses		(30,757	)		(36,721	)		(16.2	)
Depreciation and amortization		(20,930	)		(22,416	)		(6.6	)
General and administrative expenses⁽¹⁾		(5,726	)		(5,868	)		(2.4	)
Restructuring charges		(4,001	)		(1,989	)		101.2

Income from vessel operations		30,172			26,955			11.9

Operating Data:
Revenue Days (A)		2,884			3,121			(7.6	)
Calendar-Ship-Days (B)		2,920			3,202			(8.8	)
Utilization (A)/(B)		98.8	%		97.5	%

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

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.

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 (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:

•

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, on August 12, 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)	Angola LNG Carriers		Exmar LNG Carriers			Exmar LPG Carriers			MALT LNG Carriers			RasGas 3 LNG Carriers		Other			Total Equity Income
Year ended December 31, 2015		16,144		9,332			32,733			4,620			21,527		(185	)		84,171
Year ended December 31, 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 derivative instruments in 2015 as a result of long-term LIBOR benchmark interest rates increasing for interest rate swaps compared to unrealized losses on 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 were 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.

The $32.2 million decrease for 2015 in our 52% investment in the MALT LNG Carriers were 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 Derivative Instruments. Net realized and unrealized losses on derivative instruments decreased to $20.0 million for 2015, from $44.7 million for 2014 as set forth in the table below.


	Year Ended December 31, 2015									Year Ended December 31, 2014
(in thousands of U.S. Dollars)	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 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 derivative instruments.

Foreign Currency Exchange Gains and (Losses). 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 and unrealized losses of ($57.8) million on our cross currency swaps.

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 and unrealized losses of ($51.8) million on our cross-currency swaps.

Other Income (Expense). 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). 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.

Year Ended December 31, 2014 versus Year Ended December 31, 2013

Liquefied Gas Segment

As at December 31, 2014, our liquefied gas segment fleet, including newbuildings, included 47 LNG carriers and 30 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 eight LNG carrier newbuildings under construction as at December 31, 2014 and the following vessels accounted for under the equity method: (i) the six MALT LNG Carriers, (ii) the four Angola LNG Carriers, (iii) the four RasGas 3 LNG Carriers, (iv) four LNG carrier newbuildings relating to the BG Joint Venture, (v) six LNG carrier newbuildings relating to the Yamal LNG Joint Venture, (vi) the two Exmar LNG Carriers and (vii) the 15 Exmar LPG Carriers and nine LPG carrier newbuildings relating to our 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 2014 and 2013, and compares its net voyage revenues (which is a non-GAAP financial measure) for 2014 and 2013, to voyage revenues, the most directly comparable GAAP financial measure. The following table also provides a summary of the changes in calendar-ship-days and revenue days for our liquefied gas segment:


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

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

Income from vessel operations		156,868			144,430			8.6

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

⁽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 11% to 6,619 days in 2014 from 5,981 days in 2013, as a result of the acquisition and delivery of two LNG carriers from Awilco (or the Awilco LNG Carriers), the Wilforce and Wilpride, on September 16, 2013 and November 28, 2013, respectively, and the acquisition and delivery of the Norgas Napa on November 13, 2014.

During 2014, the Galicia Spirit, Madrid Spirit and Polar Spirit were off-hire for 28, 24 and 6 days, respectively, for scheduled dry dockings and an in-water survey, compared to the Arctic Spirit and Catalunya Spirit being off-hire for 41 and 21 days, respectively, for scheduled dry dockings in 2013.

Net Voyage Revenues. Net voyage revenues increased during 2014 compared to 2013, primarily as a result of:

•

an increase of $20.7 million as a result of the acquisition and delivery of the Awilco LNG Carriers in September 2013 and November 2013;

•

an increase of $3.2 million due to the Arctic Spirit being off-hire for 41 days in the first quarter of 2013 for a scheduled dry docking;

•

an increase of $2.1 million due to the Catalunya Spirit being off-hire for 21 days in the second quarter of 2013 for a scheduled dry docking;

•

an increase of $0.9 million due to the effect on our Euro-denominated revenues from the strengthening of the Euro against the U.S. Dollar compared to 2013;

•

an increase of $0.8 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 carrier newbuildings in the BG Joint Venture (however, we had a corresponding increase in operating expenses); and

•

an increase of $0.5 million as a result of the acquisition and delivery of the Norgas Napa on November 13, 2014;

partially offset by:

•

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

•

a decrease of $2.4 million relating to 18 days of unscheduled off-hire in the first quarter of 2014 due to repairs required for one of our LNG carriers;

•

a decrease of $2.1 million due to the Madrid Spirit being off-hire for 24 days in the third quarter of 2014 for a scheduled dry docking;

•

a decrease of $0.7 million due to the Polar Spirit being off-hire for six days in the fourth quarter of 2014 for a scheduled in-water survey and a further eight days of unscheduled off-hire in the fourth quarter of 2014 for repairs; and

•

a decrease of $0.6 million due to operating expense and dry-docking recovery adjustments under our charter provisions for the Tangguh Hiri and Tangguh Sago.

Vessel Operating Expenses. Vessel operating expenses increased during 2014 compared to 2013, primarily as a result of:

•

an increase of $1.6 million relating to costs to train our crew for two LNG carrier newbuildings that are expected to deliver in the first half of 2016;

•

an increase of $0.9 million as a result of higher manning costs due to wage increases relating to certain of our LNG carriers; and

•

an increase of $0.8 million in relation to our agreement to provide shipbuilding and site supervision costs associated with the four LNG carrier newbuildings in the BG Joint Venture.

Conventional Tanker Segment

As at December 31, 2014, our fleet included seven Suezmax-class double-hulled conventional crude oil tankers and one Handymax product tanker, six of which we own and two of which we lease 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. 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 Tenerife Spirit in December 2013, 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 2014 and 2013, and compares its net voyage revenues (which is a non-GAAP financial measure) for 2014 and 2013 to voyage revenues, the most directly comparable GAAP financial measure. The following table also provides a summary of the changes in calendar-ship-days and revenue days for our conventional tanker segment:


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

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

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

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

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

Net Voyage Revenues. Net voyage revenues decreased during 2014 compared to 2013, primarily as a result of:

•

a decrease of $23.1 million due to the sales of the Tenerife Spirit, Algeciras Spirit and Huelva Spirit in December 2013, February 2014 and August 2014, respectively;

•

a decrease of $1.1 million due to the Teide Spirit being off-hire for 31 days for a scheduled dry docking in 2014; and

•

a decrease 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;

partially offset by:

•

an increase of $2.7 million due to off-hire of the European Spirit, Asian Spirit and African Spirit for 25, 22 and 27 days, respectively, in 2013 for scheduled dry dockings;

•

an increase of $2.6 million due to higher revenues earned by the Bermuda Spirit and Hamilton Spirit relating to the agreement between us and the charterer as Suezmax tanker spot rates exceeded the renegotiated charter rate, therefore the additional revenues received were greater during 2014 as compared to last year; and

•

an increase of $2.4 million due to higher revenues earned by the Toledo Spirit in 2014 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).

Vessel Operating Expenses. Vessel operating expenses decreased by $7.8 million during 2014 compared to 2013 primarily as a result of the sales of the Tenerife Spirit, Algeciras Spirit and Huelva Spirit in December 2013, February 2014 and August 2014, respectively.

Depreciation and Amortization. Depreciation and amortization decreased by $4.0 million during 2014 compared to 2013, as a result of the sales of the Tenerife Spirit, Algeciras Spirit and Huelva Spirit in December 2013, February 2014 and August 2014, respectively.

Restructuring Charge. Restructuring charge of $2.0 million and $1.8 million for 2014 and 2013, respectively, were related to the seafarer severance payments upon CEPSA selling our vessels under capital lease, the Tenerife Spirit, Algeciras Spirit and Huelva Spirit, between December 2013 and August 2014.

Other Operating Results

General and Administrative Expenses. General and administrative expenses increased to $23.9 million for 2014, from $20.4 million for 2013, primarily due to a greater amount of business development, legal and tax services provided to us by Teekay Corporation to support our growth, higher advisory fees incurred to support our business development activities, and legal and tax fees associated with the termination of the capital lease obligations in the Teekay Nakilat Joint Venture.

Equity Income. Equity income decreased to $115.5 million for 2014, from $123.3 million for 2013, as set forth in the table below:


(in thousands of U.S. Dollars)	Angola LNG Carriers			Exmar LNG Carriers		Exmar LPG Carriers		MALT LNG Carriers			RasGas 3 LNG Carriers			Other			Total Equity Income
Year ended December 31, 2014		3,472			10,651		44,114		36,805			20,806			(370	)		115,478
Year ended December 31, 2013		29,178			10,650		17,415		43,428			22,611			—			123,282

Difference		(25,706	)		1		26,699		(6,623	)		(1,805	)		(370	)		(7,804	)

The $25.7 million decrease for 2014 in our 33% investment in the four Angola LNG Carriers was primarily due to $23.6 million of unrealized losses on derivative instruments in 2014 as a result of long-term LIBOR benchmark interest rates decreasing for interest rate swaps maturing in 2023 and 2024, compared to unrealized gains on derivative instruments in the same period last year, and an increase in vessel operating expenses relating to vessel main engine overhauls in 2014.

The $26.7 million increase for 2014 in our 50% ownership interest in Exmar LPG BVBA was primarily due to our 50% acquisition of this joint venture in February 2013, the $16.9 million gain on the sales of the Flanders Tenacity, Eeklo and Flanders Harmony, which were sold during the second and third quarters of 2014, the delivery of three newbuildings, the Waasmunster, Warinsart and Waregem, during the second and third quarters of 2014, and higher revenues as a result of higher Very Large Gas Carrier spot rates earned in 2014; partially offset by the redelivery of Berlian Ekuator back to its owner in January 2014, a loss on the sale of Temse in the first quarter of 2014, and less income generated as a result of the disposals of the Donau (March 2013), Temse, Eeklo, Flanders Tenacity and Flanders Harmony.

The $6.6 million decrease for 2014 in our 52% investment in the MALT LNG Carriers was primarily due to the off-hire of Woodside Donaldson and Magellan Spirit for 34 days and 23 days, respectively, during 2014 for scheduled dry dockings, the off-hire of Woodside Donaldson for seven days in 2014 for motor repairs, an increase in vessel operating expenses due to higher overall repair expenditures in 2014, an increase in interest expenses due to higher interest margins upon completion of debt refinancing within the Teekay LNG-Marubeni Joint Venture in June and July 2013, and an increase in depreciation expenses due to dry-dock additions in 2014. These decreases were partially offset by the Methane Spirit being off-hire for 28 days for a scheduled dry docking in 2013.

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

Interest Expense. Interest expense increased to $60.4 million for 2014, from $55.7 million for 2013. 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 $7.0 million relating to two new debt facilities used to fund the deliveries of the two Awilco LNG Carriers in late-2013;

•

an increase of $4.7 million as a result of our Norwegian Kroner bond issuance in September 2013; and

•

an increase of $3.0 million relating to accelerated amortization of Teekay Nakilat Joint Venture’s deferred debt issuance cost upon the termination of the leasing of the RasGas II LNG Carriers and related debt refinancing in 2014;

partially offset by:

•

a decrease of $5.8 million due to lower interest on capital lease obligations from the Tenerife Spirit, Algeciras Spirit and Huelva Spirit in December 2013, February 2014 and August 2014, respectively;

•

a decrease of $2.4 million due to debt repayments during 2013 and 2014 and a decrease in LIBOR for our floating-rate debt; and

•

a decrease of $1.7 million due to an increase in capitalized interest expense as a result of a higher number of newbuildings in 2014 compared to 2013.

Realized and Unrealized Loss on Derivative Instruments. Net realized and unrealized losses on derivative instruments increased to $44.7 million for 2014, from $14.0 million for 2013 as set forth in the table below.


	Year Ended									Year Ended
	December 31, 2014									December 31, 2013
(in thousands of U.S. Dollars)	Realized			Unrealized						Realized			Unrealized
	gains			gains						gains			gains
	(losses)			(losses)			Total			(losses)			(losses)		Total
Interest rate swap agreements		(39,406	)		4,204			(35,202	)		(38,089	)		18,868		(19,221	)
Interest rate swap agreements termination		(2,319	)		—			(2,319	)		—			—		—
Toledo Spirit time-charter derivative		(861	)		(6,300	)		(7,161	)		1,521			3,700		5,221

		(42,586	)		(2,096	)		(44,682	)		(36,568	)		22,568		(14,000	)

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

During 2013, we recognized unrealized losses on our interest rate swaps associated with our U.S. Dollar-denominated restricted cash deposits. This resulted from $63.0 million of unrealized losses relating to increases in long-term forward LIBOR benchmark interest rates, relative to the beginning of 2013, and transfers of $21.7 million of previously recognized unrealized gains to realized gains related to actual cash settlement of our interest rate swaps.

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

Long-term forward EURIBOR benchmark interest decreased during 2014 and increased during 2013, which resulted in an unrealized loss of $14.2 million and an unrealized gain of $9.7 million, respectively, from our interest rate swaps associated with our Euro-denominated long-term debt. The projected average tanker rates in the tanker market in 2014 increased compared to 2013, which resulted in $6.3 million of unrealized losses on our Toledo Spirit time-charter derivative in 2014. The projected average tanker rates in 2013 decreased compared to 2012, which resulted in a $3.7 million unrealized gain on our Toledo Spirit time-charter derivative in 2013. The Toledo Spirit time-charter derivative is the agreement with Teekay Corporation under which Teekay Corporation pays us any amounts payable to the charterer of the Toledo 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.

Foreign Currency Exchange Gains and (Losses). Foreign currency exchange gains and (losses) were $28.4 million and ($15.8) million for 2014 and 2013, respectively. These foreign currency exchange gains and losses, 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. 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. 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.

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

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

Other Income. Other income decreased by $0.6 million for 2014 compared to 2013 primarily due to one of our guarantee liabilities being fully amortized in 2013.

Income Tax Expense. Income tax expense increased to $7.6 million for 2014, from $5.2 million for 2013, primarily as a result of higher income in 2014 from the termination of capital lease obligations and refinancing in the Teekay Nakilat Joint Venture.

Other Comprehensive Income/(loss) (OCI). OCI decreased to a loss of ($1.5) million for 2014, from income of $0.1 million for 2013, due to an unrealized loss on the valuation of an interest rate swap which was entered into during 2013 and accounted for using hedge accounting within the equity accounted Teekay LNG-Marubeni 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. 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. We believe there is currently a dislocation in these markets relative to the stability of our businesses. Based on upcoming capital requirements for our committed growth projects and scheduled debt repayment obligations, coupled with the uncertainty regarding how long it will take for the energy and master limited partnership capital markets to normalize, 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 temporarily reduced our quarterly cash distribution per common unit to $0.14 from $0.70. Despite significant weakness in the global energy and capital markets, our operating cash flows remain largely stable and growing, supported by a large and well-diversified portfolio of fee-based contracts with high quality counterparties. In addition to using more of our internally generated cash flows to fund future growth projects and reduce our debt levels, we may seek alternative sources of financing such as sale and leaseback transactions.

Our primary liquidity needs for 2016 to 2018 include payment of our quarterly distributions, operating expenses, dry-docking expenditures, debt service costs, scheduled repayments of long-term, bank debt maturities, capital expenditures we are committed to and the funding of general working capital requirements. We anticipate that our primary source of funds for our short-term liquidity needs will be cash flows from operations, proceeds from debt financings and dividends from our equity accounted joint ventures. For 2016 to 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 our liquidity needs, specifically the equity portion of our committed capital expenditures. This assumes that we are able to secure debt financing for an adequate portion of our committed capital expenditures and we are able to refinance our loan facilities maturing in 2016 to 2018 and our Norwegian Kroner-denominated bonds due in 2018. In terms of debt financing for committed capital expenditures, in February 2016, we secured financing for two of our MEGI LNG carrier newbuildings which delivered or will be delivering in 2016 through a sale-leaseback transaction of approximately $179 million per vessel. In addition, we also have committed debt financing in place for the vessels under construction for the BG Joint Venture. We are actively working on obtaining debt financings for the six LNG carriers under construction for the Yamal LNG Joint Venture, the five LNG carriers under construction that have been chartered to a wholly owned subsidiary of Royal Dutch Shell PLC along with one of the other LNG carriers under construction at DSME, and the assets of the Bahrain LNG Joint Venture and associated FSU.

Our liquidity needs beyond 2018 decline significantly compared to 2016 to 2018 as a majority of our commitments for capital expenditures relate to 2016 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 either public or private offerings.

Our revolving credit facilities and term loans are described in “Item 18 – Financial Statements: Note 10 – Long-Term Debt.” They contain covenants and other restrictions typical of debt financing secured by vessels, that 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, 2015, we and our affiliates were in compliance with all covenants relating to our credit facilities and term loans.

We have one credit facility that requires us to maintain a vessel value to outstanding loan principal balance ratio of 115%, which as at December 31, 2015, was 194%. The vessel value was 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.

As at December 31, 2015, our consolidated cash and cash equivalents were $102.5 million, compared to $159.6 million at December 31, 2014. Our total liquidity, which consists of cash, cash equivalents and undrawn credit facilities, was $232.5 million as at December 31, 2015, compared to $295.2 million as at December 31, 2014. The decrease in total consolidated liquidity was primarily due to installment payments relating to our LNG carrier newbuildings.

As at December 31, 2015, we had a working capital deficit of $179.6 million, which includes $70.4 million outstanding on two of our debt facilities which mature in 2016. The $50.4 million debt facility maturing in 2016 is expected to be refinanced with a new $60.0 million three year term loan that is expected to be completed in May 2016 and we expect to refinance our other debt facility maturing in 2016 before it matures. We expect to manage our working capital deficit primarily with net operating cash flow, debt refinancing and, to a lesser extent, existing undrawn revolving credit facilities. As at December 31, 2015, we had undrawn revolving credit facilities of $130.0 million through a new $150.0 million unsecured revolving credit facility. As at December 31, 2014, we had a working capital deficit of $117.7 million, which included a $57.7 million outstanding balance on one of our debt facilities that matured and refinanced in the second quarter of 2015. The increase in working capital deficit in 2015 was primarily due to a performance bond placed on the Bahrain LNG Joint Venture project, which was recorded as long-term restricted cash.

As described under “Item 4 – Information on the Company: C. 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:


(in thousands of U.S. Dollars)	Year Ended December 31,
	2015			2014			2013
Net cash flow from operating activities		239,729			191,097			183,532
Net cash flow (used for) from financing activities		(84,357	)		100,069			351,506
Net cash flow used for investing activities		(212,530	)		(271,008	)		(509,134	)

Operating Cash Flows. 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 I.M. Skaugen SE (or 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 increased to $191.1 million in 2014 from $183.5 million in 2013, primarily due to the acquisition and delivery of the two Awilco LNG Carriers in late-2013, an increase in revenue from the Bermuda Spirit and Hamilton Spirit as a result of the agreement between us and the charterer as Suezmax tanker spot rates exceeded the renegotiated charter rate during 2014 and the charter rates reverting back to their original rates in October 2014, and the acquisition of the Norgas Napa in November 2014; partially offset by the sales of the Tenerife Spirit, Algeciras Spirit and Huelva Spirit conventional tankers in December 2013, February 2014 and August 2014, respectively, and 18 days of unscheduled off-hire during 2014 due to repairs required for one of our LNG carriers. 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 shareholders. 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, 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 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 $15.0 million increase in cash distributions paid to our 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. Net cash flow from financing activities decreased to $100.1 million in 2014 compared to $351.5 million in 2013, primarily as a result of a $468.8 million increase in prepayments of capital lease obligations due to the lease termination in the Teekay Nakilat Joint Venture in 2014, $130.9 million lower proceeds from debt financings net of scheduled repayments, prepayments and debt issuance costs, due to the issuance of a NOK bond in 2013 and higher prepayment of debt in 2014, partially offset by the completed debt refinancing in the Teekay Nakilat Joint Venture in 2014, $42.3 million more dividends paid to non-controlling interest, $25.1 million increase in cash distributions paid to our unitholders and General Partner, and $8.4 million lower proceeds from equity offerings. These decreases were partially offset by a decrease in restricted cash of $448.9 million in 2014 compared to a $27.8 million decrease in restricted cash in 2013 as a result of the lease termination in the Teekay Nakilat Joint Venture.

Restricted cash increased in 2015 by $30.3 million compared to a decrease in 2014 restricted cash of $448.9 million. This 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. This increase was the result of:

•

an increase in the number of units eligible to receive cash distributions from us as a result of our common unit public offering in July 2014 and common units sold under our COP from December 2014 to December 2015; and

•

an increase in our quarterly cash distribution to $0.7000 per unit from $0.6918 per unit paid in the first quarter of 2015.

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

•

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

•

an increase in our quarterly cash distribution to $0.6918 per unit from $0.6750 per unit paid in the first quarter of 2014.

After December 31, 2015, a cash distribution totaling $11.4 million was declared with respect to the fourth quarter of 2015, which was paid in February 2016. This cash distribution reflected a decrease in our quarterly distribution to $0.14 per unit from $0.70 per unit. As a result of this reduction in quarterly distributions, we made no distribution under the incentive distribution rights held by our General Partner.

Investing Cash Flows. Net cash flow used for investing activities decreased to $212.5 million in 2015 from $271.0 million in 2014. We used cash of $187.2 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 (please read Item 18 – Financial Statements: Note 6e – Equity Method Investments), partially offset by a $23.7 million shareholder loan repayment to us by Exmar LPG BVBA in 2015. During 2014, we used cash of $100.2 million primarily to acquire and fund our proportionate interest of newbuilding installments in the BG Joint Venture and the Yamal LNG Joint Venture, $140.4 million relating to newbuilding installments for our eight LNG 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. During 2013, we used cash of $308.0 million to fund the acquisitions of two LNG carriers from Awilco in September and November 2013, $149.6 million to fund our 50% ownership interest in the acquisition of the Exmar LPG Joint Venture and $58.6 million incurred for our three additional LNG newbuilding carriers ordered in July and November 2013.

Credit Facilities

Our revolving credit facilities and term loans are described in Item 18 – Financial Statements: Note 10 – 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. We have one credit facility that requires us to maintain a vessel value to outstanding loan principal balance ratio of 115%, which as at December 31, 2015, was 194%. The vessel value was 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. One of our term loans is guaranteed by Teekay Corporation and contains covenants that require Teekay Corporation to maintain the greater of a minimum liquidity (cash and cash equivalents) of at least $50.0 million and 5.0% of Teekay Corporation’s total consolidated debt which has recourse to Teekay Corporation. As at December 31, 2015, 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, 2015:


													Beyond
	Total		2016		2017		2018		2019		2020		2020
	(in millions of U.S. Dollars)
U.S. Dollar-Denominated Obligations:
Long-term debt:⁽¹⁾
Scheduled repayments		628.8		112.9		115.4		99.9		60.9		63.4		176.3
Repayments at maturity		850.9		70.4		—		466.0		—		—		314.5
Commitments under capital leases⁽²⁾		65.9		7.7		30.9		27.3		—		—		—
Commitments under operating leases⁽³⁾		319.6		24.1		24.1		24.1		24.1		24.1		199.1

Newbuilding installments/shipbuilding supervision⁽⁴⁾		3,209.0		555.7		960.6		1,023.4		471.0		198.3		—

Total U.S. Dollar-denominated obligations		5,074.2		770.8		1,131.0		1,640.7		556.0		285.8		689.9

Euro-Denominated Obligations:⁽⁵⁾
Long-term debt⁽⁶⁾		241.8		15.0		16.1		128.8		9.2		9.9		62.8

Total Euro-denominated obligations		241.8		15.0		16.1		128.8		9.2		9.9		62.8

Norwegian Kroner-Denominated Obligations:⁽⁵⁾
Long-term debt⁽⁷⁾		294.0		—		79.2		101.8		—		113.0		—

Total Norwegian Kroner-Denominated obligations		294.0		—		79.2		101.8		—		113.0		—

Totals		5,610.0		785.8		1,226.3		1,871.3		565.2		408.7		752.7

⁽¹⁾

Excludes expected interest payments of $26.2 million (2016), $23.9 million (2017), $17.4 million (2018), $11.4 million (2019), $10.7 million (2020), and $34.3 million (beyond 2020). Expected interest payments are based on the existing interest rates (fixed-rate loans) and LIBOR at December 31, 2015, plus margins on debt that has been drawn that ranged up to 2.80% (variable-rate loans). 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.

⁽²⁾

Includes, in addition to lease payments, amounts we may be required to pay to purchase leased vessels at the end of lease terms. The lessor has the option to sell these vessels to us at any time during the remaining lease term; however, in this table we have assumed the lessor will not exercise its right to sell the vessels to us until after the lease term expires, which is during the years 2017 to 2018. The purchase price for any vessel 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 18 – Financial Statements: Note 5 – Leases and Restricted Cash.”

⁽³⁾	We have corresponding leases whereby we are the lessor and expect to receive an aggregate of approximately $281.5 million for these leases from 2016 to 2029. Please read “Item 18 – Financial Statements: Note 5 – Leases and Restricted Cash.”

⁽⁴⁾

Between December 2012 and June 2015, we entered into agreements for the construction of 11 LNG newbuildings. The remaining cost for these newbuildings totaled $1.8 billion as of December 31, 2015, including estimated interest and construction supervision fees. In February 2016, we secured financing on our two MEGI LNG carrier newbuildings delivering in 2016 through a sale-leaseback transaction of approximately $179 million per vessel.

As part of the acquisition of an ownership interest in the BG Joint Venture, we agreed to assume BG’s obligation to provide shipbuilding supervision and crew training services for the four LNG carrier newbuildings and to fund our proportionate share of the remaining newbuilding installments. The estimated remaining costs for the shipbuilding supervision and crew training services and our proportionate share of newbuilding installments, net of the secured financing within the joint venture for the LNG carrier newbuildings, totaled $79.0 million. However, as part of this agreement with BG, we expect to recover approximately $18.2 million of the shipbuilding supervision and crew training costs from BG between 2016 and 2019.

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 newbuildings. As at December 31, 2015, our 50% share of the remaining cost for these six newbuildings totaled $941.3 million. The Yamal LNG Joint Venture intends to secure debt financing for 70% to 80% of the fully built-up cost of the six newbuildings.

In December, 2015, we entered into an agreement with Nogaholding, Samsung and GIC to form a joint venture, Bahrain LNG Joint Venture, in which we have 30% ownership interest for the development of an LNG receiving and regasification terminal in Bahrain and the supply of a FSU vessel. The terminal will have a capacity of 800 million standard cubic feet per day and will be owned and operated under a twenty-year agreement commencing July 2018. The receiving and regasification terminal is expected to have a fully-built up cost of approximately $872 million. As at December 31, 2015, our proportionate share of the costs to be incurred is $261.2 million.

The table above includes our proportionate share of the newbuilding costs, net of secured financing, for the seven LPG carrier newbuildings scheduled for delivery between 2016 and 2018 in the joint venture between Exmar and us. As at December 31, 2015, our 50% share of the remaining cost for these seven newbuildings, net of the secured financing within the joint venture, totaled $86.9 million, including estimated interest and construction supervision fees.

⁽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, 2015.

⁽⁶⁾

Excludes expected interest payments of $3.2 million (2016), $3.0 million (2017), $1.6 million (2018), $0.3 million (2019), $0.3 million (2020), and $0.5 million (beyond 2020). Expected interest payments are based on EURIBOR at December 31, 2015, plus margins that ranged up to 2.25%, as well as the prevailing U.S. Dollar/Euro exchange rate as of December 31, 2015. 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 $16.1 million (2016), $12.8 million (2017), $9.2 million (2018), $5.5 million (2019), and $2.7 million (2020). Expected interest payments are based on NIBOR at December 31, 2015, plus margins that range up to 5.25%, as well as the prevailing U.S. Dollar/NOK exchange rate as of December 31, 2015. The expected interest payments do not reflect the effect of the related cross-currency swap 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. The details of our equity accounted investments are shown in Item 18 – Financial Statements: Note 6 – Equity Method 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, 2015. Specifically, the following table reflects all such vessels, except those operating on contracts where the remaining term is significant and the estimated future undiscounted cash flows relating to such contracts are sufficiently greater than the carrying value of the vessels such that we consider it unlikely an impairment would be recognized in the following year. Consequently, the vessels included in the following table generally include those vessels near the end of existing charters or other operational contracts. While the market values of these vessels are below their carrying values, no impairment has been recognized on any of these vessels as the estimated future undiscounted cash flows relating to such vessels are greater than their carrying values.

We would consider the vessels reflected in the following table to be at a higher risk of future impairment. The estimated future undiscounted cash flows of the vessels reflected in the following table are significantly greater than their respective carrying values. Consequently, in these cases the following table would not necessarily represent vessels that would likely be impaired in the next 12 months, and the recognition of an impairment in the future for those vessels may primarily depend upon our deciding to dispose of the vessel instead of continuing to operate it. In deciding whether to dispose of a vessel, we determine whether it is economically preferable to sell the vessel or continue to operate it. This assessment includes an estimate of the net proceeds expected to be received if the vessel is sold in its existing condition compared to the present value of the vessel’s estimated future revenue, net of operating costs. Such estimates are based on the terms of the existing charter, charter market outlook and estimated operating costs, given a vessel’s type, condition and age. In addition, we typically do not dispose of a vessel that is servicing an existing customer contract.


(in thousands of U.S. Dollars, except number of vessels) Reportable Segment	Number of Vessels		Market Values⁽¹⁾ $		Carrying Values$
Liquefied Gas Segment⁽²⁾		2		107,743		164,784
Conventional Tanker Segment^{(2) (3)}		5		191,590		234,426

Total		7		299,333		399,210

⁽¹⁾	Market values are determined using reference to second-hand market comparable values as at December 31, 2015. 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.

⁽³⁾	Subsequent to December 31, 2015, for two of our Suezmax tankers included in the table above, the charterer exercised its purchase option to acquire the Bermuda Spirit and the Hamilton Spirit. We expect to incur a loss of approximately $14 million per vessel in 2016.

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 from Assumptions. 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 2015, 2014 and 2013 were $10.1 million, $14.8 million and $13.4 million, respectively. As at December 31, 2015, 2014 and 2013, our capitalized dry-dock expenditures were $10.4 million, $13.5 million and $27.2 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 $2.7 million.

Goodwill and Intangible Assets

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

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

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

At December 31, 2015, we had one reporting unit with goodwill attributable to it. As of the date of this filing, we do not believe that there is a reasonable possibility that the goodwill attributable to this reporting unit might be impaired within the next year. However, certain factors that impact this assessment are inherently difficult to forecast and as such we cannot provide any assurances that an impairment will or will not occur in the future. An assessment for impairment involves a number of assumptions and estimates that are based on factors that are beyond our control. These are discussed in more detail in the following section entitled in Part I – Forward-Looking Statements.

Amortization expense of intangible assets for each of the years 2015, 2014 and 2013 was $8.9 million, $9.2 million and $13.1 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 currency swap agreements at the end of each period are most significantly affected by the interest rate implied by the benchmark interest yield curve, including its relative steepness, and forward foreign exchange rates. Interest rates and foreign exchange rates have experienced significant volatility in recent years in both the short and long term. While the fair value of our interest and currency swap agreements are typically more sensitive to changes in short-term rates, significant changes in the long-term benchmark interest and foreign exchange rates also materially impact our interest and currency swap agreements.

The fair value of our interest and 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 from Assumptions. 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 13 – Derivative Instruments” for the effects on the change in fair value of our derivative instruments on our consolidated statements of income and statements of comprehensive income.

Taxes

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

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

Effect if Actual Results Differ from Assumptions. If we determined that we were able to realize a net deferred tax asset in the future, in excess of the net recorded amount, an adjustment to the deferred tax assets would typically increase our net income 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, 2015, we had recorded valuation allowances of $53.2 million (2014 – $58.4 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. The day-to-day affairs of our business are managed by the officers of our General Partner and key employees of certain of our operating subsidiaries. Employees of certain subsidiaries of Teekay Corporation provide assistance to us and our operating subsidiaries pursuant to services agreements. Please read “Item 7 – Major Unitholders and Related Party Transactions.”

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

Officers of our General Partner and those individuals providing services to us or our subsidiaries may face a conflict regarding the allocation of their time between our business and the other business interests of Teekay Corporation or its affiliates. Our General Partner seeks to cause its officers to devote as much time to the management of our business and affairs as is necessary for the proper conduct of our business and affairs.

Directors and Executive Officers

The following table provides information about the directors and executive officers of our General Partner and of our operating subsidiary Teekay Shipping Spain SL. Directors are elected for one-year terms. The business address of each of our directors and executive officers listed below is c/o 4^th Floor, Belvedere Building, 69 Pitts Bay Road, Hamilton, HM 08, Bermuda. The business address of our key employee of Teekay Shipping Spain SL. is Musgo Street 5—28023, Madrid, Spain. Ages of the individuals are as of December 31, 2015.


Name	Age	Position
Ida Jane Hinkley	65	Chairperson^(1)(2)(3) since June 9, 2015
Peter Evensen	57	Chief Executive Officer, Chief Financial Officer and Director
Beverlee F. Park	53	Director⁽¹⁾⁽³⁾
Vincent Lok	47	Director since June 9, 2015⁽⁴⁾
C. Sean Day	66	Director⁽³⁾
Joseph E. McKechnie	57	Director^(1)(2)(3)
George Watson	68	Director^(1)(2)(3)
Andres Luna	59	Managing Director, Teekay Shipping Spain SL

(1)	Member of Audit Committee.

(2)	Member of Conflicts Committee.

(3)	Member of Corporate Governance Committee.

(4)	Mr. Vincent Lok joined the Board of Directors on June 9, 2015, replacing Mr. Kenneth Hvid, who resigned from the Board of Directors on the same day.

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

Ida Jane Hinkley was appointed Chairperson of Teekay GP L.L.C. on June 9, 2015 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 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.

Peter Evensen has served as Chief Executive Officer and Chief Financial Officer of Teekay GP L.L.C. since it was formed in November 2004 and as a Director since January 2005. He has also served as Chief Executive Officer, Chief Financial Officer, and a Director of Teekay Offshore GP L.L.C., formed in August 2006. He served as a Director of Teekay Tankers Ltd. from October 2007 until June 2013 and from June 2015 to present. Effective April 2011, he assumed the position of President and Chief Executive Officer of Teekay Corporation and also became a Director of Teekay Corporation. Mr. Evensen joined Teekay Corporation in May 2003 as Senior Vice President, Treasurer and Chief Financial Officer. He was appointed Executive Vice President and Chief Strategy Officer of Teekay Corporation in 2006. Mr. Evensen has over 30 years’ experience in banking and shipping finance. Prior to joining Teekay Corporation, Mr. Evensen was Managing Director and Head of Global Shipping at J.P. Morgan Securities Inc., and worked in other senior positions for its predecessor firms. His international industry experience includes positions in New York, London and Oslo.

Beverlee F. Park joined the Board of Teekay GP L.L.C. 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 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 has served as Chairman of Teekay GP L.L.C. since it was formed in November 2004 until June 2015 and currently serves 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. since it was formed in August 2006. He served as a Chairman of Teekay Tankers Ltd. from October 2007 until June 2013. From 1989 to 1999, he was President and Chief Executive Officer of Navios Corporation, a large bulk shipping company based in Stamford, Connecticut. Prior to this, Mr. Day held a number of senior management positions in the shipping and finance industry. He is currently serving as a Director of Kirby Corporation and Chairman of Compass Diversified Holdings. Mr. Day is engaged as a consultant to Kattegat Limited, the parent company of Teekay’s largest shareholder, to oversee its investments, including that in the Teekay group of companies.

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.

George Watson has served as a Director of Teekay GP L.L.C. since January 2005. He currently serves as Chairman of Critical Control Solutions Inc. (formerly WNS Emergent), a provider of information control applications for the energy sector. He held the position of CEO of Critical Control from 2002 to 2007. From February 2000 to July 2002, he served as Executive Chairman at VerticalBuilder.com Inc. Mr. Watson served as President and Chief Executive Officer of TransCanada Pipelines Ltd. from 1993 to 1999 and as its Chief Financial Officer from 1990 to 1993.

Andres Luna has served as the Managing Director of Teekay Shipping Spain SL since April 2004. Mr. Luna joined Alta Shipping, S.A., a former affiliate company of Naviera F. Tapias S.A., in September 1992 and served as its General Manager until he was appointed Commercial General Manager of Naviera F. Tapias S.A. in December 1999. He also served as Chief Executive Officer of Naviera F. Tapias S.A. from July 2000 until its acquisition by Teekay Corporation in April 2004, when it was renamed Teekay Shipping Spain. Mr. Luna’s responsibilities with Teekay Spain have included business development, newbuilding contracting, project management, development of its LNG business and the renewal of its tanker fleet. He has been in the shipping business since his graduation as a naval architect from Madrid University in 1981.

Annual Executive Compensation

Because the Chief Executive Officer and Chief Financial Officer of our General Partner, Peter Evensen, is an employee of Teekay Corporation, his compensation (other than any awards under the long-term incentive plan described below) is set and paid by Teekay Corporation, and we reimburse Teekay Corporation for time he spends on partnership matters. During 2015, the aggregate amount for which we reimbursed Teekay Corporation for compensation expenses of the officers of the General Partner incurred on our behalf and for compensation earned by the executive officer of Teekay Spain listed above was approximately $1.7 million. The amounts were paid primarily in U.S. Dollars or in Euros, but are reported here in U.S. Dollars using an exchange rate 1.09 U.S. Dollar for each Euro, the exchange rate on December 31, 2015. Teekay Corporation’s annual bonus plan, in which each of the Officers participates, considers both company performance, team performance and individual performance (through comparison to established targets).

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 2015, each non-management director received compensation for attending meetings of the Board of Directors, as well as committee meetings. Non-management directors received a director fee of $50,000 for the year and common units with a value of approximately $70,000 for the 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 year, respectively, and the chairs of the audit, conflicts and governance committees each received an additional fee of $12,000, respectively, for serving in that role. Each director is fully indemnified by us for actions associated with being a director to the extent permitted under Marshall Islands law.

During 2015, the five non-management directors received, in the aggregate, $356,750 in cash fees for their services as directors, plus reimbursement of their out-of-pocket expenses. In March 2015, our General Partner’s Board of Directors granted to the five non-management directors an aggregate of 10,447 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 2015, the General Partner awarded 32,054 restricted units to the employees who provide services to our business. The restricted units vest evenly over a three-year period from the grant date.

Board Practices

Our General Partner’s board of directors (or the Board) currently consists of seven 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 2015, the Board held five meetings. Each director attended all Board meetings. The members of the Audit Committee, Conflicts Committee and Corporate Governance Committee attended all meetings.

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

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

•

the integrity of our consolidated financial statements;

•

our compliance with legal and regulatory requirements;

•

the independent auditors’ qualifications and independence; and

•

the performance of our internal audit function and independent auditors.

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

The Conflicts Committee:

•

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

•

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

Any matters approved by the Conflicts Committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners, and not a breach by our General Partner of any duties it may owe us or our unit holders. 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, Beverlee F. Park and George Watson.

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, 2015, approximately 1,463 seagoing staff served on our vessels and approximately 11 staff served on shore in technical, commercial and administrative roles in various countries, compared to approximately 1,628 seagoing staff and 11 on shore staff as of December 31, 2014 and approximately 1,400 seagoing staff and 15 on shore staff as of December 31, 2013. 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 on one of our vessels. Teekay Corporation also has a career development plan that we follow, which was designed to ensure a continuous flow of qualified officers who are trained on its vessels and familiarized with its operational standards, systems and policies. We believe that high-quality crewing and training policies will play an increasingly important role in distinguishing larger independent shipping companies that have in-house or affiliate capabilities from smaller companies that must rely on outside ship managers and crewing agents on the basis of customer service and safety. As such, we have a LNG training facility in Glasgow that serves this purpose.

Unit Ownership

The following table sets forth certain information regarding beneficial ownership, as of December 31, 2015, of our units by all directors and officers of our General Partner, and an executive officer of Teekay Spain as a group. 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 February 29, 2016 (60 days after December 31, 2015) 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 units set forth in the following table. Information for all persons listed below is based on information delivered to us.


Identity of Person or Group	Common Units Owned		Percentage of Common Units Owned⁽³⁾
All directors and officers as a group (8 persons)^{(1) (2)}		154,298		0.19	%

(1)

Excludes units owned by Teekay Corporation, which controls us and on the board of which serve the directors of our General Partner, C. Sean Day, Peter Evensen and Vincent Lok. Mr. Evensen is also the Chief Executive Officer of Teekay Corporation. Mr. Lok is also a director of our General Partner and 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 Unitholders and Related Party Transactions

Major Unitholders

The following table sets forth information regarding beneficial ownership, as of December 31, 2015, 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 February 29, 2016 (60 days after December 31, 2015) 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	%
Neuberger Berman Group LLC⁽²⁾		11,725,318		14.7	%
OppenheimerFunds, Inc.⁽³⁾		5,540,133		7.0	%

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

(2)

Neuberger Berman Group LLC and Neuberger Berman Investment Advisors LLC each have shared voting power as to 11,397,505 units and shared dispositive power as to 11,725,318 units. Neuberger Berman LLC has shared voting power and shared dispositive power as to 7,293,848 of such units. The units also include holdings belonging to other affiliates of Neuberger Berman Group LLC. This information is based on the Schedule 13G/A filed by this group with the SEC on February 9, 2016.

(3)

OppenheimerFunds, Inc., an investment advisor, has shared voting power and shared dispositive power as to 5,540,133 units. Oppenheimer SteelPath MLP Income Fund, an investment company, has shared voting power and shared dispositive power as to 4,277,556 of such units. This information is based on the Schedule 13G/A filed by this group with the SEC on February 5, 2016.

Teekay Corporation has the same voting rights with respect to common units it owns as our other 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

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

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

•

acquiring LNG carriers and related time-charters as part of a business and operating or chartering those vessels if a majority of the value of the total assets or business acquired is not attributable to the LNG carriers and related time-charters, as determined in good faith by the board of directors of Teekay Corporation or the conflict 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.

C. Sean Day is the Chairman of our General Partner, Teekay GP L.L.C. since it was formed in November 2004 until June 2015 and currently serves as director. He also is 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.

Peter Evensen is 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.

Kenneth Hvid is a director of Teekay Offshore GP L.L.C. Mr. Hvid was also Executive Vice President and Chief Strategy Officer of Teekay Corporation until December 2015.

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.

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

Please read “Item 18. – Financial Statements: Note 12 – 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.

Cash Distribution Policy

Rationale for Our Cash Distribution Policy

This cash distribution policy reflects a basic judgment that our 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 units relating to the fourth quarter of 2015, we have temporarily and significantly reduced the amount of our quarterly per common unit cash distributions. Global crude oil prices have significantly declined since mid-2014. The significant decline in oil prices has also 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. We believe there is currently a dislocation in these markets relative to the stability of our businesses. Based on upcoming capital requirements for our committed growth projects and scheduled debt repayment obligations, coupled with uncertainty regarding how long it will take for the energy and master limited partnership capital markets to normalize, 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, we have temporarily reduced our quarterly distributions on our common units. We believe there is currently a dislocation in the capital markets relative to the stability of our businesses. Based on the upcoming capital requirements for our committed growth projects, coupled with the uncertainty regarding how long it will take for the energy and capital markets to normalize, we believe that it is in the best interests of our common unitholders to conserve more of our internally generated cash flows to fund future growth projects and to reduce debt levels. This reduction in the amount of unit distributions to establish cash reserves for these purposes is consistent with our cash distribution policy and is consistent with 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 unitholders will receive quarterly distributions from us. Our distribution policy is subject to certain restrictions and may be changed at any time, including:

•

Our 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 and other limitations.

•

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.

•

Under Section 51 of the Marshall Islands Limited Partnership Act, we may not make a distribution to unitholders if the distribution would cause our liabilities to exceed the fair value of our assets.

•

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 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 2015, cash distributions with respect to the first three quarters of 2015 exceeded $0.4625 per common unit, and were below $0.4625 per common unit with respect to the distribution for the fourth quarter of 2015. 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 up to September 30, 2015 and increasing percentages were not used to calculate the General Partner’s interest in net income for the purposes of the net income per common unit calculation from October 1, 2015 to December 31, 2015.

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.


Years Ended	Dec. 31, 2015		Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
High	$	43.38	$	47.49	$	45.42	$	42.26	$	41.50
Low		8.80		33.02		37.73		33.00		28.61

Quarters Ended	Mar. 31, 2016		Dec. 31, 2015		Sept. 30, 2015		June 30, 2015		Mar. 31, 2015		Dec. 31, 2014		Sept. 30, 2014		June 30, 2014		Mar. 31, 2014
High	$	14.80	$	27.04	$	32.30	$	40.73	$	43.38	$	43.86	$	47.49	$	46.69	$	42.92
Low		7.92		8.80		22.03		31.64		34.13		33.02		40.40		41.35		39.03

Months Ended	Mar. 31, 2016		Feb. 29, 2016		Jan. 31, 2016		Dec. 31, 2015		Nov. 30, 2015		Oct. 31, 2015
High	$	14.80	$	12.25	$	13.89	$	22.81	$	26.34	$	27.04
Low		10.03		9.31		7.92		8.80		22.30		23.20

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 September 29, 2006.

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 us and our operating subsidiaries with certain non-strategic services such as, crew training, advisory, technical and administrative services that supplement existing capabilities of the employees of our operating subsidiaries. Teekay Corporation subsidiaries also provide business development services and strategic consulting and advisory services. All these services are charged at reasonable fee that includes reimbursement of the reasonable cost of any direct and indirect expenses they incur in providing these services. Please read “Item 7 – Major Unitholders and Related Party Transactions” for a summary of certain contract terms.

(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)

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 Buyers 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 Buyers 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 Buyers 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 Buyers 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 million 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 to, together with certain other related security and is guaranteed by us. The loans have varying maturities through 2018.

(l)

Agreement dated December 15, 2006 supplemented by agreement dated March 17, 2010, for a U.S. $255,528,228 million Senior Loan and U.S. $80,000,000 million Junior Loan Secured Loan Agreement between Bermuda Spirit L.L.C., Hamilton Spirit L.L.C., Summit Spirit L.L.C., Zenith Spirit L.L.C., and Credit Agricole CIB Bank. The facility was used to finance up to 80% of the shipyard contract price for the Bermuda Spirit and the Hamilton Spirit. Interest payments on one tranche under the loan facility are based on six month LIBOR plus 0.30%, while interest payments on the second tranche are based on six-month LIBOR plus 0.70%. One tranche reduces in semi-annual payments while the other tranche correspondingly is drawn up every six months with a final $20 million bullet payment per vessel due 12 years and six months from each vessel delivery date. This loan facility is collateralized by first-priority mortgages on the four vessels to which the loan relates, together with certain other related security and is guaranteed by Teekay Corporation.

(m)

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.

(n)

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.

(o)

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

(p)

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.

(q)

Agreement dated June 27, 2013, for US$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.

(r)

Agreement dated June 28, 2013, for a US$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.

(s)

Agreement dated July 30, 2013, for a US$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.

(t)

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

(u)

Agreement dated December 9, 2013, for a US$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.

(v)

Agreement dated March 28, 2014, for a US$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.

(w)

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.

(x)

Agreement dated November 7, 2014, for a US$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.

(y)

Agreement dated December 17, 2014, for a US$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.

(z)

Agreement dated April 27, 2015, for a US$55,000,000 Secured Loan Facility between African Spirit L.L.C., European Spirit L.L.C., Asian Spirit L.L.C., and ING Bank N.V. and various other banks. The loan bears interest at LIBOR plus a margin of 1.00%. The amount available under the facility was reduced by $4.6 million in November 2015 with a balloon payment in April 2016.

(aa)

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

(bb)

Amending and Restating Agreement dated June 5, 2015, for a US$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.

(cc)

Agreement dated November 24, 2015, for US$150,000,000 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%. The facility requires a bullet payment in November 2016. The credit facility may be used for General Partnership purposes and to fund cash distributions.

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. 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 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 common 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 common units as capital assets for tax purposes. This discussion does not address all tax considerations that may be important to a particular unitholder in light of the unitholder’s circumstances, or to certain categories of common 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 common 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 common units, the tax treatment of that partnership’s partner generally will depend upon the status of such partner and the activities of such partnership. Partners in partnerships holding our common units should consult their own tax advisors to determine the appropriate tax treatment of the partnership’s ownership of our common units.

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

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

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

Under certain circumstances, a beneficial owner of common units whose units have been loaned to another may lose 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 are urged to consult their own 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.

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

Treatment of Distributions. 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.

Basis of Common Units. A unitholder’s initial U.S. federal income tax basis for its common units will be the amount it paid for the common units plus its share of our nonrecourse liabilities. That 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.

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 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 common 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. If the payment is made on behalf of a person whose identity cannot be determined, we are authorized to treat the payment as a distribution to all current common unitholders. 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.

Specified items of our income, gain, loss and deduction will be allocated to account for any difference between the tax basis and fair market value of any property held by the partnership immediately prior to an offering of common units, referred to in this discussion as “Adjusted Property.” The effect of these allocations to a unitholder purchasing common units in an offering essentially will be the same as if the tax basis of our assets were equal to their fair market value at the time of the offering. In addition, items of recapture income will be allocated to the extent possible to the partner who was allocated the deduction giving rise to the treatment of that gain as recapture income in order to minimize the recognition of ordinary income by some common 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:

•

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

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

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

Section 754 Election. We have made an election under Section 754 of the Code to adjust a common 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 common unitholders and does not apply to common unitholders who acquire their common 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.

Common 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 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.

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 common 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 common unit, (b) we issue additional units or (c) we engage in certain other transactions. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss, deductions or credits previously reported by common unitholders might change, and common unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

Disposition of Common 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 its share of our nonrecourse liabilities. Because the amount realized includes a 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 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 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.

A portion of a 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 unitholder will recognize ordinary income or loss to the extent of the difference between the portion of the unitholder’s amount realized allocable to unrealized receivables or inventory items and the 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 unit and may be recognized even if a net taxable loss is realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and a capital loss upon a sale of units. Net capital losses generally may only be used to offset capital gains. An exception permits individuals to offset up to $3,000 of net capital losses against ordinary income in any given year.

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

In addition, certain U.S. common 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. Common unitholders should consult their tax advisors regarding the effect, if any, of this tax on their ownership of our common 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 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 unitholder transferring units may be allocated income, gain, loss, deduction and credit realized after the date of transfer. A unitholder who owns 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 units were held but will not be entitled to receive that cash distribution. Recently adopted final 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.

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 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 common 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 common unitholders likely 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 common unitholders are urged to consult their own tax advisors to determine whether or to what extent they would be entitled to such credit. A unitholder who does not elect to claim foreign tax credits may instead claim a deduction for its share of foreign taxes paid by us.

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

Investments in common 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. Virtually all of our income allocated to a unitholder that is such a tax-exempt organization will be unrelated business taxable income to it subject to U.S. federal income tax.

A non-U.S. 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). 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 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 any transportation income from voyages that begin and end in the United States; however, there is no assurance that such voyages will not occur.

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, a non-U.S. unitholder would be required to file a U.S. federal income tax return to report its U.S. effectively 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 own tax advisors regarding the U.S. federal, state, local and other tax consequences of an investment in units and any filing requirements related thereto.

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 and report the affairs of any QBU in this functional currency to our common unitholders. 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. Further, if a QBU is required to maintain a functional currency other than the U.S. Dollar, a unitholder may be required to recognize foreign currency translation gain or loss upon a distribution of money or property from a QBU or upon the sale of common units, and items or income, gain, loss, deduction or credit allocated to the unitholder in such functional currency must be translated into the unitholder’s functional currency.

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.

Proposed regulations (or the Section 987 Proposed Regulations) provide that the amount of foreign currency translation gain or loss recognized upon a distribution of money or property from a QBU or upon the sale of common units will reflect the appreciation or depreciation in the functional currency value of certain assets and liabilities of the QBU between the time the unitholder purchased its common units and the time we receive distributions from such QBU or the unitholder sells its common units. Foreign currency translation gain or loss will be treated as ordinary income or loss. A unitholder must adjust the U.S. federal income tax basis in its common units to reflect such income or loss prior to determining any other U.S. federal income tax consequences of such distribution or sale. A unitholder who owns less than a 5 percent interest in our capital or profits generally may elect not to have these rules apply by attaching a statement to its tax return for the first taxable year the unitholder intends the election to be effective. Further, for purposes of computing its taxable income and U.S. federal income tax basis in its common units, a unitholder will be required to translate into its own functional currency items of income, gain, loss or deduction of such QBU and its share of such QBU’s liabilities. We intend to provide such information based on generally applicable U.S. exchange rates as is necessary for common unitholders to comply with the requirements of the Section 987 Proposed Regulations as part of the U.S. federal income tax information we will furnish common unitholders each year. However, a common unitholder may be entitled to make an election to apply an alternative exchange rate with respect to the foreign currency translation of certain items. Common unitholders who desire to make such an election should consult their own tax advisors.

Based upon our current projections of the capital invested in and profits of the non-U.S. Dollar QBUs, we believe that common unitholders will be required to recognize only a nominal amount of foreign currency translation gain or loss each year and upon their sale of units. Nonetheless, the rules for determining the amount of translation gain or loss are not entirely clear at present as the Section 987 Proposed Regulations currently are not effective. Common unitholders are urged to consult their own tax advisors for specific advice regarding the application of the rules for recognizing foreign currency translation gain or loss under their own circumstances. In addition to a unitholder’s recognition of foreign currency translation gain or loss, the U.S. Dollar QBU will engage in certain transactions denominated in the Euro, which will give rise to a certain amount of foreign currency exchange gain or loss each year. This foreign currency exchange gain or loss will be treated as ordinary income 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 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 common 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, common 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 common unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against common 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 common 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 common unitholder having at least a 1 percent interest in profits or by any group of common 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 common unitholder with an interest in the outcome may participate.

The recently enacted Bipartisan Budget Act of 2015 altered the procedures for auditing large partnerships for taxable years beginning after December 31, 2017 and also altered the procedures for assessing and collecting taxes due (including applicable penalties and interest) as a result of an audit. 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 common unitholders may be substantially reduced. In addition, because payment would be due for the taxable year in which the audit is completed, common unitholders during that taxable year would bear the expense of the adjustment even if they were not common 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 common 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 common unitholders to make adequate disclosure on their returns and to take other actions as may be appropriate to permit common 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 common unitholders and other owners in liquidation of their interests in us. Common unitholders that are U.S. persons would be required to file IRS Form 926 to report these deemed transfers and any other transfers they made to us while we were treated as a corporation and may be required to recognize income or gain for U.S. federal income tax purposes to the extent of certain prior deductions or losses and other items. Substantial penalties may apply for failure to satisfy these reporting requirements, unless the person otherwise required to report shows such failure was due to reasonable cause and not willful neglect.

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 common units, and taxable capital gain thereafter. Dividends paid on our common 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. 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, 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 regulations thereunder, it will not be subject to the net basis and branch profits taxes or the 4 percent 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 the 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 will be treated as Effectively Connected Income if we were classified as a corporation. However, we do not anticipate that any 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 not in excess 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.

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 $500,000 of U.S. federal income tax in 2016 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 2015 and our expected U.S. Source International Transportation Income for 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 common unitholders with information concerning the potential availability of such elections.

Consequences of Possible Controlled Foreign Corporation Classification. If we were to be treated as a corporation for U.S. federal income tax purposes and if CFC Shareholders (generally, U.S. unitholders who each own, directly, indirectly or constructively, 10 percent or more of the total combined voting power of our outstanding shares entitled to vote) own directly, indirectly or constructively more than 50 percent of either the total combined voting power of our outstanding shares entitled to vote or the total value of all of our outstanding shares, we generally would be treated as a controlled foreign corporation (or a CFC).

CFC Shareholders are treated as receiving current distributions of their respective shares of certain income of the CFC without regard to any actual distributions and are subject to other burdensome U.S. federal income tax and administrative requirements but generally are not also subject to the requirements generally applicable to shareholders of a PFIC. In addition, a person who is or has been a CFC Shareholder may recognize ordinary income on the disposition of shares of the CFC. Although we do not believe we are or will become a CFC even if we were to be treated as a corporation for U.S. federal income tax purposes, U.S. persons purchasing a substantial interest in us should consider the potential implications of being treated as a CFC Shareholder in the event we become a CFC in the future.

The U.S. federal income tax consequences to U.S. Holders who are not CFC Shareholders would not change in the event we become a CFC in the future.

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 percent 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 2015 and would not apply in subsequent years and therefore, the 4 percent gross basis tax applied to our subsidiary corporation in 2015 and will apply to our subsidiary corporation in subsequent years. In this regard, we estimate that we will be subject to approximately $100,000 or less of U.S. federal income tax in 2015 and in each subsequent year based on the amount of U.S. Source International Transportation Income our corporate subsidiary earned for 2015 and its expected U.S. Source International Transportation Income for 2016 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 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 common 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 we are, and will continue to be, classified as a partnership for United States federal income tax purposes.

We are 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 us to the U.S. Resident Holder in respect of such U.S. Resident Holder’s common units, provided that for purposes of the Canada-U.S. Treaty, (a) we do not carry on business through a permanent establishment in Canada and (b) such U.S. Resident Holder does not hold such common units in connection with a business carried on by such U.S. Resident Holder through a permanent establishment in Canada.

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

We believe that our activities and affairs are conducted in such a manner that we are not carrying on business in Canada and that U.S. Resident Holders should not be considered to be carrying on business in Canada for purposes of the Canada Tax Act or the Canada-U.S. Treaty solely by reason of the acquisition, holding, disposition or redemption of common units. We intend that this is and continues to be the case, notwithstanding that Teekay Shipping Limited (a subsidiary of Teekay Corporation that is resident and based in Bermuda) provides certain services to Teekay LNG Partners L.P. and obtains some or all such services under subcontracts with Canadian service providers. If the arrangements we have entered into result in our 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 11 – Income Tax.”

Documents on Display

Documents concerning us that are referred to herein may be inspected at our principal executive offices at 4^th 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.

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, 2015, 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.

Expected Maturity Date



																						Fair
																There-						Value
	2016			2017			2018			2019			2020			after			Total			Liability			Rate⁽¹⁾
	(in millions of U.S. Dollars, except percentages)
Long-Term Debt:
Variable-Rate ($U.S.)⁽²⁾		183.3			115.4			565.9			60.9			63.4			490.8			1,479.7			(1,444.2	)		1.8	%
Variable-Rate (Euro)^{(3) (4)}		15.0			16.1			128.8			9.2			9.9			62.8			241.8			(232.9	)		1.3	%
Variable-Rate (NOK)^{(4) (5)}		—			79.2			101.8			—			113.0			—			294.0			(288.3	)		3.6	%

Capital Lease Obligations
Variable-Rate ($U.S.)⁽⁶⁾		4.5			28.3			26.3			—			—			—			59.1			(59.1	)		5.5	%
Average Interest Rate⁽⁷⁾		5.4	%		4.6	%		6.4	%		—			—			—			5.5	%
Interest Rate Swaps:⁽⁸⁾
Contract Amount ($U.S.)⁽⁹⁾		351.9			161.9			61.9			144.2			23.2			116.9			860.0			(68.5	)		3.7	%
Average Fixed-Pay Rate⁽²⁾		3.0	%		4.9	%		4.1	%		2.7	%		4.1	%		5.0	%		3.7	%
Contract Amount (Euro)^{(4) (10)}		15.0			16.1			128.8			9.2			9.9			62.8			241.8			(35.7	)		3.1	%
Average Fixed-Pay Rate⁽³⁾		3.1	%		3.1	%		2.6	%		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, 2015 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, 2015.

(5)

Interest payments on our NOK-denominated debt and on our cross-currency swaps are based on NIBOR. Our NOK 700 million and NOK 900 million, and NOK 1,000 million debt 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 of 6.88%, 6.43% and 5.92%, and the transfer of principal locked in at $125.0 million, $150.0 million and $134.0 million upon maturity. Please see below in the foreign currency fluctuation section and read “Item 18 – Financial Statements: Note 13 – Derivative Instruments.”

(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 these leases have corresponding adjustments in charter receipts under the terms of the charter contracts to which these 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, 2015 was a liability of $0.8 million. Please read “Item 18 – Financial Statements: Note 13 – Derivative Instruments”.

(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 remaining term of the time-charter contract is 10 years as of December 31, 2015, 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 receivable or payable to from Teekay Corporation are settled at the end of each year. At December 31, 2015, the fair value of this derivative liability was $6.3 million and the change from December 31,2014 to the reporting period has been reported in realized and unrealized loss on 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 222.7 million Euros ($241.8 million) and Euro-denominated restricted cash deposits of 16.7 million Euros ($18.1 million), respectively, as at December 31, 2015. 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 2020, 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 2020. Please read “Item 18 – Financial Statements: Note 13 – Derivative Instruments.” At December 31, 2015, the fair value of the derivative liabilities was $128.8 million and the change from December 2014 to the reporting period has been reported in foreign currency exchange gain (loss) in the consolidated statements of income. As a result, fluctuations in the Euro and NOK relative to the U.S. Dollar have caused, and are likely to continue to cause, fluctuations in our reported voyage revenues, vessel operating expenses, general and administrative expenses, interest expense, interest income, realized and unrealized loss on derivative instruments and foreign currency exchange gain (loss).

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. Based on the evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are effective as of December 31, 2015.

The Chief Executive Officer and Chief Financial Officer do not expect that our disclosure controls or internal controls will prevent all error 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, 2015.

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, 2015.

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 2015 and 2014 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 2015 and 2014.


	2015		2014
Fees (in thousands of U.S. Dollars)	$		$
Audit Fees⁽¹⁾		736		729
Audit-Related Fees⁽²⁾		—		3

Total		736		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 2015 and 2014.

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 2015 and in 2014.

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

There are no 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:


	Page

Reports of Independent Registered Public Accounting Firm		F-1, F-2

Consolidated Financial Statements

Consolidated Statements of Income		F-3

Consolidated Statements Comprehensive Income		F-4

Consolidated Balance Sheets		F-5

Consolidated Statements of Cash Flows		F-6

Consolidated Statements of Changes in Total Equity		F-7

Notes to the Consolidated Financial Statements		F-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, among, 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, among, 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, among, Teekay LNG Partners L.P. and Nordic Trustee ASA.

4.2		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)

4.8		Bareboat Charter Agreement between Naviera Teekay Gas III, S.L. (formerly Naviera F. Tapias Gas III, S.A.) and Poseidon Gas AIE dated as of October 2, 2000. (3)

4.9		Bareboat Charter Agreement between Naviera Teekay Gas IV, S.L. (formerly Naviera F. Tapias Gas IV, S.A.) and Pagumar AIE, dated as of December 30, 2003. (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. (9)

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. (10)

4.15		Credit Facility Agreement between Bermuda Spirit L.L.C., Hamilton Spirit L.L.C., Zenith Spirit L.L.C., Summit Spirit L.L.C. and Credit Argicole CIB, dated March 17, 2010. (11)

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. (11)

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 and financial institutions. (12)

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 and financial institutions. (13)



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 and financial institutions. (13)

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 and financial institutions. (13)

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 and financial institutions. (13)

4.22		Share purchase agreement dated February 28, 2012 to purchase Maersk LNG A/S through the Teekay LNG- Marubeni Joint Venture from Maersk. (13)

4.23		Agreement dated January 1, 2012, for business development services between Teekay LNG Operating L.L.C. and Teekay Shipping Limited. (14)

4.24		Agreement dated June 27, 2013, for US$195,000,000 senior secured notes between Meridian Spirit ApS and Wells Fargo Bank Northwest N.A. (15)

4.25		Agreement dated June 28, 2013, for US$160,000,000 loan facility between Malt Singapore Pte. Ltd. and Commonwealth Bank of Australia. (15)

4.26		Agreement dated July 30, 2013, for US$608,000,000 loan facility between Malt LNG Netherlands Holdings B.V. and DNB Bank ASA, acting as agent and security trustee. (15)

4.27		Agreement dated December 9, 2013, for US$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. (16)

4.30		Agreement dated December 17, 2014, for US$450,000,000 loan facility between Nakilat Holdco L.L.C. and Qatar National Bank SAQ. (16)

4.31		Agreement dated November 7, 2014, for a US$175,000,000 secured loan facility between Solaia Shipping L.L.C. and Excelsior BVBA, and Nordea Bank Norge ASA. (17)

4.32		Agreement dated April 27, 2015, for a US$55,000,000 secured loan facility between African Spirit L.L.C., European Spirit L.L.C. and Asian Spirit L.L.C., and ING Bank N.V. (17)

4.33		Agreement dated March 28, 2014, for US$130,000,000 secured loan facility between Wilpride L.L.C. and Nordea Bank Finland and others.

4.34		Agreement dated June 5, 2015, for a US$460,000,000 secured loan facility between Exmar LPG BVBA and Nordea Bank Norge ASA and other banks and financial institutions.

4.35		Agreement dated November 24, 2015, for US$150,000,000 revolving credit facility between Teekay LNG Partners L.P. and Citigroup Global Markets Limited and other banks and financial institutions.

8.1		List of Significant Subsidiaries of Teekay LNG Partners L.P.

12.1		Rule 13a-15(e)/15d-15(e) Certification of Teekay LNG Partners L.P.’s Chief Executive Officer

12.2		Rule 13a-15(e)/15d-15(e) Certification of Teekay LNG Partners L.P.’s Chief Financial Officer

13.1		Teekay LNG Partners L.P. Certification of Peter Evensen, Chief Executive Officer and Chief Financial Officer, 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 Malt LNG Netherlands Holdings B.V.

15.3		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 Amendment No. 1 to Registration Statement on Form F-1 (File No. 333-129413), filed with the SEC on November 3, 2005, and hereby incorporated by reference to such Registration Statement.

(9)	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.

(10)	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.

(11)	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.

(12)	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.

(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 11, 2011 and hereby incorporated by reference to such report.

(14)	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.

(15)	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.

(16)	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.

(17)	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.

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 27, 2016	By:	/s/ Peter Evensen
		Peter Evensen
		Chief Executive Officer and Chief Financial Officer
		(Principal Financial and Accounting Officer)

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, 2015 and 2014, 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, 2015. 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, 2015 and 2014, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2015, 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, 2015, 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 27, 2016 expressed an unqualified opinion on the effectiveness of the Partnership’s internal control over financial reporting.

As discussed in Note 1 to the consolidated financial statements, the Partnership has retrospectively changed its method of accounting for debt issuance costs effective December 31, 2015 due to the adoption of Accounting Standards Update 2015-03, Simplifying the Presentation of Debt Issuance Costs.


Vancouver, Canada				/s/ KPMG LLP
April 27, 2016				Chartered Professional Accountants

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To 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, 2015, 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, 2015 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, 2015 and 2014, 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, 2015, and our report dated April 27, 2016, expressed an unqualified opinion on those consolidated financial statements.


Vancouver, Canada				/s/ KPMG LLP
April 27, 2016				Chartered Professional Accountants

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,			Year Ended December 31,			Year Ended December 31,
	2015			2014			2013
	$			$			$
Voyage revenues (note 12)		397,991			402,928			399,276
Voyage expenses		(1,146	)		(3,321	)		(2,857	)
Vessel operating expenses (note 12)		(94,101	)		(95,808	)		(99,949	)
Depreciation and amortization		(92,253	)		(94,127	)		(97,884	)
General and administrative expenses (notes 12 and 17)		(25,118	)		(23,860	)		(20,444	)
Restructuring charge (note 18)		(4,001	)		(1,989	)		(1,786	)

Income from vessel operations		181,372			183,823			176,356

Equity income (note 6)		84,171			115,478			123,282
Interest expense (notes 5 and 10)		(43,259	)		(60,414	)		(55,703	)
Interest income		2,501			3,052			2,972
Realized and unrealized loss on derivative instruments (note 13)		(20,022	)		(44,682	)		(14,000	)
Foreign currency exchange gain (loss) (notes 10 and 13)		13,943			28,401			(15,832	)
Other income		1,526			836			1,396

Net income before income tax expense		220,232			226,494			218,471
Income tax expense (note 11)		(2,722	)		(7,567	)		(5,156	)

Net income		217,510			218,927			213,315

Non-controlling interest in net income		16,627			13,489			12,073
General Partner’s interest in net income		26,276			31,187			25,365
Limited partners’ interest in net income		174,607			174,251			175,877
Limited partners’ interest in net income per common unit:
• Basic		2.21			2.30			2.48
• Diluted		2.21			2.30			2.48
Weighted-average number of common units outstanding:
• Basic		78,896,767			75,664,435			70,965,496
• Diluted		78,961,102			75,702,886			70,996,869

Cash distributions declared per common unit		2.8000			2.7672			2.7000

Related party transactions (note 12)

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			Year Ended			Year Ended
	December 31,			December 31,			December 31,
	2015			2014			2013
	$			$			$
Net income		217,510			218,927			213,315

Other comprehensive (loss) income:
Unrealized (loss) gain on qualifying cash flow hedging instrument in equity accounted joint ventures before reclassifications, net of tax (note 6)		(1,723	)		(3,085	)		131
Realized loss on qualifying cash flow hedging instrument in equity accounted joint ventures reclassified to equity income, net of tax (note 6)		1,075			1,551			—

Other comprehensive (loss) income		(648	)		(1,534	)		131

Comprehensive income		216,862			217,393			213,446

Non-controlling interest in comprehensive income		16,627			13,489			12,073
General and limited partners’ interest in comprehensive income		200,235			203,904			201,373

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			As at
	December 31,			December 31,
	2015			2014
	$			$
				(Note 1)
ASSETS
Current
Cash and cash equivalents		102,481			159,639
Restricted cash - current		6,600			3,000
Accounts receivable, including non-trade of $7,058 (2014 – $7,998) (note 6c)		22,081			11,265
Prepaid expenses		4,469			3,975
Current portion of net investments in direct financing leases (note 5)		20,606			15,837
Advances to affiliates (note 12h)		13,026			11,942

Total current assets		169,263			205,658

Restricted cash – long-term (note 5)		104,919			42,997
Vessels and equipment
At cost, less accumulated depreciation of $666,710 (2014 – $588,735)		1,595,077			1,659,807
Vessels under capital leases, at cost, less accumulated depreciation of $56,316 (2014 – $50,898) (note 5)		88,215			91,776
Advances on newbuilding contracts (notes 12g and 14)		424,868			237,647

Total vessels and equipment		2,108,160			1,989,230

Investment in and advances to equity accounted joint ventures (notes 6, 7 and 12f)		883,731			891,478
Net investments in direct financing leases (note 5)		646,052			666,658
Other assets (note 6c)		20,811			27,536
Derivative assets (note 13)		5,623			441
Intangible assets – net (note 8)		78,790			87,646
Goodwill – liquefied gas segment (note 8)		35,631			35,631

Total assets		4,052,980			3,947,275

LIABILITIES AND EQUITY
Current
Accounts payable		2,770			643
Accrued liabilities (notes 9, 13 and 18)		37,456			39,037
Unearned revenue (note 5)		19,608			16,565
Current portion of long-term debt (note 10)		197,197			157,088
Current obligations under capital lease (note 5)		4,546			4,422
Current portion of in-process contracts (note 6c)		12,173			4,736
Current portion of derivative liabilities (note 13)		52,083			57,678
Advances from affiliates (notes 12h and 13)		22,987			43,205

Total current liabilities		348,820			323,374

Long-term debt (note 10)		1,802,012			1,749,893
Long-term obligations under capital lease (note 5)		54,581			59,128
Long-term unearned revenue		30,333			33,938
Other long-term liabilities (notes 5, 6d and 6e)		71,152			74,734
In-process contracts (note 6c)		20,065			32,660
Derivative liabilities (note 13)		182,338			126,177

Total liabilities		2,509,301			2,399,904

Commitments and contingencies (notes 5, 6, 10, 13 and 14)

Equity
Limited Partners		1,472,327			1,482,647
General Partner		48,786			56,508
Accumulated other comprehensive loss		(2,051	)		(1,403	)

Partners’ equity		1,519,062			1,537,752
Non-controlling interest		24,617			9,619

Total equity		1,543,679			1,547,371

Total liabilities and total equity		4,052,980			3,947,275

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,			Year Ended December 31,			Year Ended December 31,
	2015			2014			2013
	$			$			$
Cash and cash equivalents provided by (used for)

OPERATING ACTIVITIES
Net income		217,510			218,927			213,315
Non-cash items:
Unrealized (gain) loss on derivative instruments (note 13)		(12,375	)		2,096			(22,568	)
Depreciation and amortization		92,253			94,127			97,884
Unrealized foreign currency exchange (gain) loss (notes 10 and 13)		(22,876	)		(34,079	)		16,019
Equity income, net of dividends received of $97,146 (2014 – $11,005 and 2013 – $13,738)		12,975			(104,473	)		(109,544	)
Amortization of deferred debt issuance costs and other		(3,214	)		9,148			5,551
Change in operating assets and liabilities (note 15a)		(34,187	)		18,822			10,078
Expenditures for dry docking		(10,357	)		(13,471	)		(27,203	)

Net operating cash flow		239,729			191,097			183,532

FINANCING ACTIVITIES
Proceeds from issuance of long-term debt		391,574			944,123			719,300
Scheduled repayments of long-term debt		(126,557	)		(100,804	)		(86,609	)
Prepayments of long-term debt		(90,000	)		(608,501	)		(270,000	)
Debt issuance costs		(2,856	)		(6,431	)		(3,362	)
Scheduled repayments and prepayments of capital lease obligations		(4,423	)		(479,115	)		(10,315	)
Proceeds from equity offerings, net of offering costs (note 16)		35,374			182,139			190,520
(Increase) decrease in restricted cash		(30,321	)		448,914			27,761
Cash distributions paid		(255,519	)		(240,525	)		(215,416	)
Novation of derivative liabilities (note 12e)		—			2,985			—
Dividends paid to non-controlling interest		(1,629	)		(42,716	)		(373	)

Net financing cash flow		(84,357	)		100,069			351,506

INVESTING ACTIVITIES
Purchase of and additional capital contributions in equity accounted investments (note 15h)		(25,852	)		(100,200	)		(135,790	)
Loan repayments from (advances to) equity accounted joint ventures		23,744			631			(16,822	)
Receipts from direct financing leases		15,837			17,200			11,641
Expenditures for vessels and equipment (note 15f)		(191,969	)		(188,855	)		(368,163	)
Increase in restricted cash		(34,290	)		—			—
Other		—			216			—

Net investing cash flow		(212,530	)		(271,008	)		(509,134	)

(Decrease) increase in cash and cash equivalents		(57,158	)		20,158			25,904
Cash and cash equivalents, beginning of the year		159,639			139,481			113,577

Cash and cash equivalents, end of the year		102,481			159,639			139,481

Supplemental cash flow information (note 15)

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
									Accumulated
									Other			Non-
	Limited					General			Comprehensive			controlling
	Partners					Partner			(Loss) Income			Interest			Total
	Number of
	Common Units		$			$			$			$			$
Balance as at December 31, 2012		69,684		1,165,634			47,346			—			41,294			1,254,274

Net income		—		175,877			25,365			—			12,073			213,315
Other comprehensive income		—		—			—			131			—			131
Cash distributions		—		(191,280	)		(24,136	)		—			(373	)		(215,789	)
Equity based compensation (note 17)		7		1,306			27			—			—			1,333
Proceeds from equity offerings (note 16)		4,505		186,596			3,924			—			—			190,520

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 (note 17)		17		1,415			29			—			—			1,444
Proceeds from equity offerings (note 16)		4,140		178,473			3,666			—			—			182,139
Sale of 1% interest in Norgas Napa to General Partner (note 12d)		—		—			—			—			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 (note 17)		25		1,196			24			—			—			1,220
Proceeds from equity offerings (note 16)		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

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. Significant intercompany balances and transactions have been eliminated upon consolidation. 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 as at December 31, 2014 have been reclassified to conform to the presentation adopted in the current period relating to debt issuance costs. As part of the adoption of Accounting Standards Update 2015-03, Simplifying the Presentation of Debt Issuance Costs (or ASU 2015-03) (see note 2), the Partnership has presented debt issuance costs related to a recognized debt liability as a direct deduction from the carrying amount of that debt liability in the Partnership’s consolidated balance sheets. Prior to the adoption of ASU 2015-03, all debt issuance costs were presented as other non-current assets in the Partnership’s consolidated balance sheets.

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.

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)

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, 2015, 2014 and 2013 aggregated $83.4 million, $70.1 million and $71.4 million, respectively. Depreciation and amortization includes depreciation on all owned vessels and amortization of vessels accounted for as capital leases.

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, 2015, 2014 and 2013 aggregated $8.2 million, $3.1 million and $1.3 million, respectively.

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

Generally, the Partnership dry docks each of its vessels every five years. In addition, a shipping society classification intermediate survey is performed on the Partnership’s LNG and LPG carriers between the second and third year of the five-year dry-docking period. 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, 2013 to December 31, 2015:


	Year Ended December 31,
	2015			2014			2013
	$			$			$
Balance at January 1,		33,635			40,328			28,821
Cost incurred for dry docking		10,357			13,471			27,203
Sales of vessels (note 15e)		—			(5,327	)		(2,285	)
Dry-dock amortization		(10,076	)		(14,837	)		(13,411	)

Balance at December 31,		33,916			33,635			40,328

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.

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.

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)

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 and are amortized on an effective interest rate method over the term of the relevant loan. Amortization of debt issuance costs is included in interest expense.

Goodwill 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. At December 31, 2015, the Partnership has not applied hedge accounting to its derivative instruments, except for several interest rate swaps in its equity accounted joint ventures (see note 6).

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 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 12c) are recorded in realized and unrealized loss on 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 (loss) 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. 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 28%. However, 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 2.8% on income from the operation of these two Spanish-flagged vessels.

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)

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 (expense) on the Partnership’s consolidated statements of income as the Partnership’s risk from the guarantees declines over the term of the guarantee. If it becomes probable that the Partnership will have to perform under a guarantee, the Partnership will recognize an additional liability if the amount of the loss can be reasonably estimated.

Accumulated other comprehensive (loss) income

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

2.	Accounting Pronouncements

In April 2014, the FASB issued Accounting Standards Update 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity (or ASU 2014-08) which raises the threshold for disposals to qualify as discontinued operations. A discontinued operation is now defined as: (i) a component of an entity or group of components that has been disposed of or classified as held for sale and represents a strategic shift that has or will have a major effect on an entity’s operations and financial results; or (ii) an acquired business that is classified as held for sale on the acquisition date. ASU 2014-08 also requires additional disclosures regarding discontinued operations, as well as material disposals that do not meet the definition of discontinued operations. ASU 2014-08 was adopted on January 1, 2015. The impact, if any, of adopting ASU 2014-08 on the Partnership’s consolidated financial statements will depend on the occurrence and nature of disposals that occur.

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 interim and annual periods beginning after December 15, 2017 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 is evaluating the effect of adopting this new accounting guidance.

In February 2015, the FASB issued Accounting Standards Update 2015-02, Amendments to the Consolidation Analysis (or ASU 2015-02) which eliminates the deferral of certain consolidation standards for entities considered to be investment companies, modifies the consolidation analysis performed on limited partnerships and modifies the impact of fee arrangements and related parties on the determination of the primary beneficiary of a variable interest entity. ASU 2015-02 is effective for interim and annual periods beginning after December 15, 2015. ASU 2015-02 may be applied using a modified retrospective approach by recording a cumulative-effect adjustment to equity as of the beginning of the fiscal year of adoption. A reporting entity also may apply ASU 2015-02 retrospectively. The adoption of ASU 2015-02 will not have a material impact on the Partnership’s consolidated financial statements.

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 April 2015, the FASB issued ASU 2015-03. The Partnership adopted ASU 2015-03 effective December 31, 2015. Prior period information has been retrospectively adjusted. Prior to the adoption of ASU 2015-03, all debt issuance costs were presented as other non-current assets in the Partnership’s consolidated balance sheets. With the adoption of ASU 2015-03 the Partnership presents those debt issuance costs related to a recognized debt liability as a direct deduction from the carrying amount of that debt liability in the Partnership’s consolidated balance sheets. Debt issuance costs related to loan facilities without a recognized debt liability will continue to be presented as non-current assets in the Partnership’s consolidated balance sheets. As a result of adopting ASU 2015-03, non-current assets and total assets have decreased by $16.3 million (December 31, 2015) and $17.1 million (December 31, 2014), current portion of long-term debt and current liabilities has decreased by $1.1 million (December 31, 2015) and $0.1 million (December 31, 2014), long-term debt has decreased by $15.2 million (December 31, 2015) and $17.0 million (December 31, 2014), and total liabilities has decreased by $16.3 million (December 31, 2015) and $17.1 million (December 31, 2014). Such changes have also impacted the Partnership’s reconciliation of segment assets to total assets (see Note 4) and the carrying value of long-term debt (see Note 10). In addition, the Partnership’s equity accounted investments have adopted ASU 2015-03 effective December 31, 2015. As a result, the Partnership’s condensed summary of its equity accounted investments in Note 6 has been impacted. More specifically, other assets—non-current has decreased by $60.8 million (December 31, 2015) and $17.8 million (December 31, 2014), vessels and equipment has decreased by $15.8 million (December 31, 2014), net investments in direct financing leases – non-current has decreased by $23.5 million (December 31, 2014), current portion of long-term debt and obligations under capital lease has decreased by $5.0 million (December 31, 2015) and $5.0 million (December 31, 2014), and long-term debt and obligations under capital lease has decreased by $55.8 million (December 31, 2015) and $52.1 million (December 31, 2014).

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. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early adoption is permitted. 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 is evaluating the effect of adopting this new accounting guidance.

3.	Financial Instruments

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 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 12c). 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 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.

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)

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.


		December 31, 2015						December 31, 2014
	Fair Value	Carrying			Fair			Carrying			Fair
	Hierarchy	Amount			Value			Amount			Value
	Level	Asset			Asset			Asset			Asset
		(Liability)			(Liability)			(Liability)			(Liability)
		$			$			$			$
Recurring:
Cash and cash equivalents and restricted cash	Level 1		214,000			214,000			205,636			205,636
Derivative instruments(note 13)
Interest rate swap agreements	Level 2		(104,137	)		(104,137	)		(119,558	)		(119,558	)
Interest rate swaption agreements – assets	Level 2		5,623			5,623			—			—
Interest rate swaption agreements – liabilities	Level 2		(6,406	)		(6,406	)		—			—
Cross currency swap agreements	Level 2		(128,782	)		(128,782	)		(70,386	)		(70,386	)
Other derivative	Level 3		(6,296	)		(6,296	)		(2,137	)		(2,137	)
Other:
Advances to equity accounted joint ventures(note 7)	(i)		159,870			(i	)		181,514			(i	)
Long-term receivable included in accountsreceivable and other assets⁽ⁱⁱ⁾	Level 3		16,453			16,427			17,137			17,164
Long-term debt – public(note 10)	Level 1		(291,247	)		(288,333	)		(212,536	)		(220,762	)
Long-term debt – non-public(note 10)	Level 2		(1,707,962	)		(1,677,139	)		(1,694,445	)		(1,659,852	)

⁽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, 2015, the estimated fair value of the non-interest bearing receivable is based on the remaining future fixed payments of $18.2 million to be received from 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 BG, 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, 2015 and 2014 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,
	2015			2014
	$			$
Fair value at beginning of year		(2,137	)		6,344
Realized and unrealized (losses) gains included in earnings		(5,039	)		(7,161	)
Settlements		880			(1,320	)

Fair value at end of year		(6,296	)		(2,137	)

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. 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, 2015 is based upon an average daily tanker rate of $34,093 (December 31, 2014 – $27,554) over the remaining duration of the charter contract and a discount rate of 7.5% (December 31, 2014 – 7.4%). 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)

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.

December 31,

Credit Quality

2015

2014

Class of Financing Receivable

Indicator

Grade

Direct financing leases

Payment activity

Performing

666,658

682,495

Other receivables:

Long-term receivable and accrued revenue included in accounts receivable and other assets

Payment activity

Performing

28,256

30,664

Advances to equity accounted joint ventures (note 7)

Other internal metrics

Performing

159,870

181,514

854,784

894,673

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 12a). As at December 31, 2015, the Partnership’s liquefied gas segment consisted of 50 LNG carriers (including 26 LNG carriers included in joint ventures that are accounted for under the equity method), and 29 LPG/Multigas carriers (including 23 LPG carriers included in a joint venture that is accounted for under the equity method). As at December 31, 2015, the Partnership’s conventional tanker segment consisted of seven Suezmax-class crude oil tankers and one Handymax product tanker which generally operate under long-term, fixed-rate time-charter contracts to international energy and shipping companies. Segment results are evaluated based on income from vessel operations. The accounting policies applied to the reportable segments are the same as those used in the preparation of the Partnership’s consolidated financial statements.

The following table presents voyage revenues and percentage of consolidated voyage revenues for the Partnership’s top customers during any of the periods presented.


	Year Ended	Year Ended	Year Ended
(U.S. Dollars in millions)	December 31, 2015	December 31, 2014	December 31, 2013
Ras Laffan Liquefied Natural Gas Company Ltd.⁽ⁱ⁾	$70.1 or 18%	$69.8 or 17%	$69.7 or 17%
Shell Spain LNG S.A.U.^(i),(ii)	$48.5 or 12%	$51.8 or 13%	$53.5 or 13%
The Tangguh Production Sharing Contractors⁽ⁱ⁾	$44.9 or 11%	$44.3 or 11%	$47.3 or 12%

⁽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; voyage revenues in 2013 were only from Repsol YPF. S.A.

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, 2015
				Conventional
	Liquefied Gas			Tanker
	Segment			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 charge		—			(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
				Conventional
	Liquefied Gas			Tanker
	Segment			Segment			Total
	$			$			$
Voyage revenues		307,426			95,502			402,928
Voyage expenses		(1,768	)		(1,553	)		(3,321	)
Vessel operating expenses		(59,087	)		(36,721	)		(95,808	)
Depreciation and amortization		(71,711	)		(22,416	)		(94,127	)
General and administrative expenses⁽ⁱ⁾		(17,992	)		(5,868	)		(23,860	)
Restructuring charge		—			(1,989	)		(1,989	)

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

Equity income		115,478			—			115,478
Investment in and advances to equity accounted joint ventures		891,478			—			891,478
Total assets at December 31, 2014		3,379,279			381,175			3,760,454
Expenditures for vessels and equipment		(193,669	)		(586	)		(194,255	)
Expenditures for dry docking		(8,127	)		(5,344	)		(13,471	)

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

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

Equity income		123,282			—			123,282
Expenditures for vessels and equipment		(469,463	)		(750	)		(470,213	)
Expenditures for dry docking		(21,090	)		(6,113	)		(27,203	)

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

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)

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


	December 31,		December 31,
	2015		2014
	$		$
Total assets of the liquefied gas segment		3,550,396		3,379,279
Total assets of the conventional tanker segment		360,527		381,175
Unallocated:
Cash and cash equivalents		102,481		159,639
Accounts receivable and prepaid expenses		26,550		15,240
Advances to affiliates		13,026		11,942

Consolidated total assets		4,052,980		3,947,275

5.	Leases and Restricted Cash

Capital Lease Obligations


	December 31,		December 31,
	2015		2014
	$		$
Suezmax Tankers		59,127		63,550
Less current portion		4,546		4,422

Long-term obligations under capital lease		54,581		59,128

Suezmax Tankers. As at December 31, 2015, 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 vessel to a third party, upon which the remaining lease obligation will be extinguished. At the inception of these leases, the weighted-average interest rate implicit in these leases was 5.5%. These capital leases are variable-rate capital leases. However, any change in the lease payments resulting from changes in interest rates is offset by a corresponding change in the charter hire payments received by the Partnership.

As at December 31, 2015, the remaining commitments under the two capital leases, including the purchase obligations for the two Suezmax tankers, approximated $65.9 million, including imputed interest of $6.8 million, repayable from 2016 through 2018, as indicated below:


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

The Partnership’s capital leases 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 14c) and amounts received from charterers to be used only for dry-docking expenditures and emergency repairs, which cash totaled $111.5 million and $46.0 million as at December 31, 2015 and 2014, respectively.

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)

Operating Lease Obligations

Teekay Tangguh Joint Venture

As at December 31, 2015, 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, 2015 and 2014 were $8.0 million and $8.4 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, 2015, the total estimated future minimum rental payments to be received and paid under the lease contracts are as follows:


	Head Lease		Sublease
Year	Receipts⁽ⁱ⁾		Payments^(i)(ii)
2016	$	21,242	$	24,113
2017	$	21,242	$	24,113
2018	$	21,242	$	24,113
2019	$	21,242	$	24,113
2020	$	21,242	$	24,113
Thereafter	$	175,337	$	199,072

Total	$	281,547	$	319,637

⁽ⁱ⁾

The Head Leases are fixed-rate operating leases while the Subleases have a small variable-rate component. As at December 31, 2015, the Partnership had received $228.8 million of aggregate Head Lease receipts and had paid $163.7 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, 2015, $3.8 million and $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.

Net Investments in Direct Financing Leases

The Tangguh LNG Carriers commenced their time-charters with its 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 two 155,900-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,			December 31,
	2015			2014
	$			$
Total minimum lease payments to be received		843,079			914,943
Estimated unguaranteed residual value of leased properties		194,965			194,965
Initial direct costs		425			458
Unearned revenue		(371,811	)		(427,871	)

Total		666,658			682,495
Less current portion		20,606			15,837

Net investments in direct financing leases - non-current		646,052			666,658

As at December 31, 2015, 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 2016 through 2021. Both leases are scheduled to end in 2029. In addition, estimated minimum lease payments in the next three years to be received by the Partnership under the Awilco LNG Carrier leases are approximately $35.9 million (2016), $165.0 million (2017) and $134.6 million (2018).

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)

Operating Leases

As at December 31, 2015, the minimum scheduled future revenues in the next five years to be received by the Partnership for the lease and non-lease elements under charters that were accounted for as operating leases are approximately $349.5 million (2016), $351.9 million (2017), $397.2 million (2018), $428.2 million (2019) and $419.1 million (2020). Minimum scheduled future revenues do not include revenue generated from new contracts entered into after December 31, 2015, revenue from vessels in the Partnership’s equity accounted investments, revenue from unexercised option periods of contracts that existed on December 31, 2015, or variable or contingent revenues. Therefore, the minimum scheduled future revenues should not be construed to reflect total charter hire revenues for any of the years.

6.	Equity Method Investments

Bahrain LNG Joint Venture

On December 2, 2015, the Partnership entered into an agreement with National Oil & Gas Authority (or Nogaholding), Samsung C&T (or Samsung) and Gulf Investment Corporation (or GIC) to form a joint venture, Bahrain LNG W.L.L. (or the Bahrain LNG joint Venture), for the development of an LNG receiving and regasification terminal in Bahrain. The Bahrain LNG Joint Venture is a joint venture between Nogaholding (30%), the Partnership (30%), Samsung (20%) and GIC (20%). 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 eight hundred million standard cubic feet per day and will be owned and operated under a 20-year agreement commencing in mid-2018 with a fully-built up cost of approximately $872.0 million, which will be funded by the Bahrain LNG Joint Venture through a combination of equity capital and project-level debt through a consortium of regional and international banks. The Partnership will supply a floating storage unit (or FSU) in connection with this project, which will be modified specifically from one of the Partnership’s nine MEGI LNG carrier newbuildings ordered from Daewoo Shipbuilding & Marine Engineering Co. (or DSME) (see Note 14a), through a twenty year time-charter contract with the Bahrain LNG Joint Venture.

Yamal LNG Joint Venture

On July 9, 2014, the Partnership, through a new 50/50 joint venture with China LNG (or the Yamal LNG Joint Venture), 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 (60%), France-based Total S.A. (20%) and China-based China National Petroleum Corporation (or CNPC) (20%), and will consist of three LNG trains with a total expected capacity of 16.5 million metric tons of LNG per annum and is currently scheduled to start-up in early-2018. The six 172,000-cubic meter ARC7 LNG carrier newbuildings will be constructed by Daewoo Shipbuilding & Marine Engineering Co. (or DSME), of South Korea, for a total fully built-up cost of approximately $2.1 billion. The vessels, which will be constructed with maximum 2.1 meter icebreaking capabilities in both the forward and reverse directions, are scheduled to deliver at various times between the first quarter of 2018 and first quarter of 2020. Upon their deliveries, the six LNG carriers will each operate under fixed-rate time-charter contracts with Yamal Trade Pte. Ltd. until December 31, 2045, plus extension options.

As at December 31, 2015, the Partnership has contributed $96.9 million of capital to the Yamal LNG Joint Venture to fund its newbuilding installments (December 31, 2014 – $95.3 million), representing the Partnership’s proportionate share (see Note 7b).

BG Joint Venture

On June 27, 2014, the Partnership acquired from BG its ownership interests in four 174,000-cubic meter Tri-Fuel Diesel Electric LNG carrier newbuildings, which will be constructed by Hudong-Zhonghua Shipbuilding (Group) Co., Ltd. in China for an estimated total fully built-up cost to the joint venture of approximately $1.0 billion. 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 (collectively, the BG Joint Venture). The vessels upon delivery, which are scheduled between September 2017 and January 2019, will each operate under 20-year fixed-rate time-charter contracts, plus extension options with Methane Services Limited, a wholly-owned subsidiary of BG. As compensation for BG’s ownership interest in these four LNG carrier newbuildings, the Partnership assumed BG’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 $38.7 million of costs to provide these services, of which BG 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 BG was $16.5 million. As at December 31, 2015, the carrying value of the service obligation of $29.7 million (December 31, 2014 – $33.7 million) is included in both the current portion of in-process contracts and in-process contracts and the carrying value of the receivable from BG of $16.5 million (December 31, 2014 – $17.1 million) is included in both accounts receivable and other assets in the Partnership’s consolidated balance sheet.

The excess of the Partnership’s investment in the BG Joint Venture over the Partnership’s share of the underlying carrying value of net assets acquired was approximately $16.8 million in accordance with the final purchase price allocation. This basis difference has been allocated notionally to the ship construction support agreements and the time-charter contracts. The Partnership accounts for its investment in the BG Joint Venture using the equity method.

As at December 31, 2015, to fund its newbuilding installments, the BG Joint Venture has drawn $89.0 million (December 31, 2014 – $53.7 million) from its $787.0 million long-term debt facility and received $8.6 million of capital contributions from the Partnership (December 31, 2014 – $3.8 million), representing the Partnership’s proportionate share.

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)

Exmar LPG Joint Venture

In February 2013, the Partnership entered into a 50/50 joint venture agreement with Belgium-based Exmar NV (or Exmar) to own and charter-in LPG carriers with a primary focus on the mid-size gas carrier segment. The joint venture entity, called Exmar LPG BVBA (or the Exmar LPG Joint Venture), took economic effect as of November 1, 2012 and, as of December 31, 2015, included 20 owned LPG carriers (including seven newbuilding carriers scheduled for delivery between 2016 and 2018) and two in-chartered LPG carriers. For its 50% ownership interest in the joint venture, including newbuilding payments made prior to the November 1, 2012 economic effective date of the joint venture, the Partnership invested $133.1 million in exchange for equity and a shareholder loan and assumed approximately $108 million of its pro rata share of existing debt and lease obligations as of the economic effective date. These debt and lease obligations are secured by certain vessels in the Exmar LPG Joint Venture fleet. The Partnership also paid a $2.7 million acquisition fee to Teekay Corporation that was recorded as part of the investment in Exmar LPG Joint Venture (see Note 12f). The excess of the book value of net assets acquired over Teekay LNG’s investment in the Exmar LPG Joint Venture, which amounted to approximately $6.0 million, has been accounted for as an adjustment to the value of the vessels, charter agreements and lease obligations of the Exmar LPG Joint Venture and recognition of goodwill, in accordance with the final purchase price allocation. Control of the Exmar LPG Joint Venture is shared equally between Exmar and the Partnership. The Partnership accounts for its investment in the Exmar LPG Joint Venture using the equity method.

In June 2015, the Exmar LPG Joint Venture completed refinancing 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, 2015 was $1.5 million and is included as part of other long-term liabilities in the Partnership’s consolidated balance sheets. In addition, during 2015, the Exmar LPG Joint Venture entered into three interest rate swap agreements with an aggregate notional amount of $375.7 million, which amortize quarterly over the term of the interest rate swap agreements to $161.2 million at maturity. The interest rate swap agreements exchange the receipts of LIBOR-based interest for the payments of a fixed rate ranging from 1.69% to 1.84% excluding the margin. These interest rate swap agreements have been designated as a qualifying cash flow hedging instruments for accounting purposes. The Exmar LPG Joint Venture uses the same accounting policy for qualifying cash flow hedging instruments as the Partnership.

Teekay LNG-Marubeni Joint Venture

The Partnership has a 52% ownership interest in the joint venture between Marubeni Corporation and the Partnership (or the Teekay LNG-Marubeni Joint Venture), which owns six LNG carriers. 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 the 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. 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, 2015 was $0.2 million (December 31, 2014 was $0.4 million) and is included as part of other long-term liabilities in the Partnership’s consolidated balance sheets.

In July 2013, the Teekay LNG-Marubeni Joint Venture entered into an eight-year interest rate swap agreement with a notional amount of $160.0 million, which amortizes quarterly over the term of the interest rate swap agreement to $70.4 million at maturity. The interest rate swap agreement exchanges the receipt of LIBOR-based interest for the payment of a fixed rate of interest of 2.20% in the first two years and 2.36% in the last six years. This interest rate swap agreement has been designated as a qualifying cash flow hedging instrument for accounting purposes. The Teekay LNG-Marubeni Joint Venture uses the same accounting policy for qualifying cash flow hedging instruments as the Partnership uses.

One of Teekay LNG-Marubeni Joint Venture’s loan facilities for four of its six LNG carriers contains mandatory prepayment provisions upon early termination of a charter and requires the borrower to maintain a specific debt service coverage ratio. One of the joint venture’s vessels, the Magellan Spirit, had a grounding incident in January 2015 and the charterer subsequently claimed to terminate the charter, claimed that 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, which it did in late-March 2015. In June 2015, the lenders waived the mandatory prepayment provision in relation to the Magellan Spirit and the debt service coverage ratio covenant for the loan facility. Both waivers are for the remaining term of the facility. In return, the Teekay LNG-Marubeni Joint Venture funded an earnings account, which is collateral for the loan facility, with $7.5 million and prepaid $30.0 million of the loan facility. These amounts were funded by the Partnership and Marubeni Corporation based on their respective ownership percentages.

Excalibur and Excelsior Joint Ventures

The Partnership has ownership interests ranging from 49% to 50% in its joint ventures with Exmar (or the Excalibur Joint Venture and the Excelsior Joint Venture) which own two LNG carriers that are chartered out under long term contracts. In February 2015, the Excalibur and Excelsior Joint Ventures completed refinancing 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, 2015 was $0.3 million and is included as part of other long-term liabilities in the Partnership’s consolidated balance sheets. In addition, the Excalibur and Excelsior Joint Ventures entered into four-year interest rate swap agreements with an aggregate notional amount of $172.8 million, which amortizes quarterly over the term of the interest rate swap agreements to $133.4 million at maturity. These interest rate swap agreements exchange the receipt of LIBOR-based interest for the payment of a fixed rate of interest of 1.46% excluding the margin. These interest rate swap agreements have been designated as qualifying cash flow hedging instruments for accounting purposes. The Excalibur and Excelsior Joint Ventures use the same accounting policy for qualifying cash flow hedging instruments as the Partnership.

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)

Angola Joint Venture

The Partnership has a 33% ownership interest in four 160,400-cubic meter LNG carriers (or the Angola LNG Carriers or Angola Joint Venture). The Angola LNG Carriers are chartered at fixed rates, subject to inflation adjustments, to Angola LNG Supply Services LLC for a period of 20 years from the date of delivery from the shipyard, with two five year options for the charterer to extend the charter contract and are classified as direct financing leases.

RasGas 3 Joint Venture

The Partnership has a 40% ownership interest in the Teekay Nakilat (III) Corporation (or the RasGas 3 Joint Venture), which owns four LNG carriers that are chartered out under long-term contracts that are classified as direct financing leases.

These joint ventures are accounted for using the equity method. The RasGas 3 Joint Venture, the Excelsior Joint Venture, the Angola Joint Venture and the Yamal 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 Ventures and the Yamal LNG Joint Venture is the amount it has invested and advanced in these joint ventures, which are $161.4 million, $49.0 million, $58.2 million and $99.9 million respectively, as at December 31, 2015. In addition, the Partnership guarantees its portion of the Excelsior Joint Venture’s debt of $47.5 million and the Angola Joint Ventures’ debt and swaps of $272.0 million and guarantee for charter termination of $1.2 million.

The following table presents aggregated summarized financial information assuming 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 included the Excalibur and Excelsior Joint Venture, the RasGas 3 Joint Venture, the Angola Joint Ventures, the Exmar LPG Joint Venture from February 2013, the BG Joint Venture from June 2014 and the Yamal LNG Joint Venture from July 2014.


	As at December 31,
	2015 $		2014 $
Cash and restricted cash		281,943		287,207
Other assets – current		77,861		137,055
Vessels and equipment		2,343,397		2,243,381
Net investments in direct financing leases – non-current		1,813,991		1,850,279
Other assets – non-current		22,120		14,515

Current portion of long-term debt and obligations under capital lease		166,522		435,272
Other liabilities – current		97,405		125,787
Long-term debt and obligations under capital lease		2,583,721		2,321,562
Other liabilities – non-current		381,213		390,467


	Years ended December 31,
	2015 $			2014 $			2013 $
Voyage revenues		596,093			640,105			625,414
Income from vessel operations		302,731			398,836			335,062
Realized and unrealized (loss) gain on derivative instruments		(25,108	)		(52,938	)		16,334
Net income		203,280			267,990			277,096

Certain of the comparative figures have been adjusted to conform to the presentation adopted in the current year (see Note 2).

7.	Advances to Equity Accounted Joint Ventures

As of December 31, 2015, the Partnership had advanced $57.8 million (December 31, 2014 – $81.7 million) to Exmar LPG, which bears interest at LIBOR plus 0.50% and has no fixed repayment terms. As at December 31, 2015, the interest accrued on these advances was $0.4 million (December 31, 2014 – $0.6 million). Both the advances and the accrued interest on these advances are included in investment and advances to equity accounted joint ventures in the Partnership’s consolidated balance sheet.

As of December 31, 2015, the Partnership had advanced of $96.9 million to the Yamal LNG Joint Venture (December 31, 2014 – $95.3 million). The advances bear interest at LIBOR plus 3.00% compounded semi-annually. As of December 31, 2015, the interest accrued on these advances was $4.8 million (December 31, 2014 – $1.0 million). Both the advances and the accrued interest on these advances are included in investments and advances to equity accounted joint ventures in the Partnership’s consolidated balance sheets.

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)

8.	Intangible Assets and Goodwill

As at December 31, 2015 and 2014, intangible assets consisted of time-charter contracts with a weighted-average amortization period of 17.1 years. The carrying amount of intangible assets for the Partnership’s reportable segments is as follows:


	December 31, 2015									December 31, 2014
	Liquefied Gas Segment $			Conventional Tanker Segment $			Total $			Liquefied Gas Segment $			Conventional Tanker Segment $			Total $
Gross carrying amount		179,813			6,797			186,610			179,813			6,797			186,610
Accumulated amortization		(101,023	)		(6,797	)		(107,820	)		(92,167	)		(6,797	)		(98,964	)

Net carrying amount		78,790			—			78,790			87,646			—			87,646

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

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

9.	Accrued Liabilities


	December 31,		December 31,
	2015 $		2014 $
Interest including interest rate swaps		17,484		17,035
Voyage and vessel expenses		9,315		7,829
Payroll and benefits		5,431		5,560
Other general expenses		2,785		4,224
Income tax payable and other		2,441		4,389

Total		37,456		39,037

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)

10.

Long-Term Debt


	December 31, 2015 $			December 31, 2014 $
U.S. Dollar-denominated Revolving Credit Facilities due through 2016 to 2018		329,222			257,661
U.S. Dollar-denominated Term Loan due through 2016		50,415			—
U.S. Dollar-denominated Term Loan due through 2018		83,393			93,595
U.S. Dollar-denominated Term Loan due through 2018		108,333			116,667
U.S. Dollar-denominated Term Loan due through 2018		117,000			125,667
U.S. Dollar-denominated Term Loan due through 2021		271,991			285,274
U.S. Dollar-denominated Term Loan due through 2021		88,339			95,560
U.S. Dollar-denominated Term Loan due through 2026		430,965			450,000
Norwegian Kroner-denominated Bond due in 2017		79,158			93,934
Norwegian Kroner-denominated Bond due in 2018		101,775			120,773
Norwegian Kroner-denominated Bond due in 2020		113,083			—
Euro-denominated Term Loans due through 2023		241,798			284,993

Total principal		2,015,472			1,924,124
Unamortized discount and debt issuance costs		(16,263	)		(17,143	)

Total debt		1,999,209			1,906,981
Less current portion		197,197			157,088

Long-term debt		1,802,012			1,749,893

As at December 31, 2015, the Partnership had three revolving credit facilities available. The three credit facilities, as at such date, provided for borrowings of up to $459.2 million, of which $130.0 million was undrawn. Interest payments are based on LIBOR plus margins, which ranged from 0.55% to 1.10%. The amount available under the three revolving credit facilities reduces by $177.3 million (2016), $28.2 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, 2015, the Partnership had a U.S. Dollar-denominated term loan outstanding in the amount of $50.4 million. Interest payments on this loan are based on LIBOR plus 1.00% with a bullet repayment of $50.4 million due at maturity in 2016. This loan facility is collateralized by first-priority mortgages on the three vessels to which the loan relates, together with certain other related security, and is guaranteed by the Partnership.

As at December 31, 2015, the Partnership had a U.S. Dollar-denominated term loan outstanding in the amount of $83.4 million. Interest payments on this loan are based on LIBOR plus 2.75% and require quarterly interest and principal payments and a bullet repayment of $50.7 million due at maturity in 2018. This loan facility is collateralized by first-priority mortgages on the five vessels to which the loan relates, together with certain other related security, and is guaranteed by the Partnership.

As at December 31, 2015, the Partnership had a U.S. Dollar-denominated term loan outstanding in the amount of $108.3 million. Interest payments on this loan are based on LIBOR plus 2.80% and require quarterly interest and principal payments and a bullet repayment of $83.3 million due at maturity in 2018. This loan facility is collateralized by a first-priority mortgage on the one vessel to which the loan relates, together with certain other related security, and is guaranteed by the Partnership.

As at December 31, 2015, the Partnership had a U.S. Dollar-denominated term loan outstanding in the amount of $117.0 million. Interest payments on this loan are based on LIBOR plus 2.75% and require quarterly interest and principal payments and a bullet repayment of $95.3 million due at maturity in 2018. This loan facility is collateralized by a first-priority mortgage on the one vessel to which the loan relates, together with certain other related security, and is guaranteed by the Partnership.

The Partnership owns a 69% interest in the Teekay Tangguh Joint Venture, a consolidated entity of the Partnership. The Teekay Tangguh Joint Venture has a U.S. Dollar-denominated term loan outstanding, which, as at December 31, 2015, totaled $272.0 million. Interest payments on the loan are based on LIBOR plus margins. Interest payments on one tranche under the loan facility are based on LIBOR plus 0.30%, while interest payments on the second tranche are based on LIBOR plus 0.63%. One tranche reduces in quarterly payments while the other tranche correspondingly is drawn up with a final $95.0 million bullet payment for each of two vessels due in 2021. This loan facility is collateralized by first-priority mortgages on the two vessels to which the loan relates, together with certain other security and is guaranteed by the Partnership.

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)

As at December 31, 2015, the Partnership had a U.S. Dollar-denominated term loan outstanding in the amount of $88.3 million. Interest payments on one tranche under the loan facility are based on LIBOR plus 0.30%, while interest payments on the second tranche are based on LIBOR plus 0.70%. One tranche reduces in semi-annual payments while the other tranche correspondingly is drawn up every six months with a final $20.0 million bullet payment for each of two vessels due at maturity in 2021. This loan facility is collateralized by first-priority mortgages on the two vessels to which the loan relates, together with certain other related security, and is guaranteed by Teekay Corporation.

The Partnership owns a 70% interest in Teekay Nakilat Corporation (or the Teekay Nakilat Joint Venture), a consolidated entity of the Partnership. The Teekay Nakilat Joint Venture has a U.S. Dollar-denominated term loan outstanding, which, as at December 31, 2015, totaled $431.0 million. Interest payments on this loan are based on LIBOR plus 1.85% and the loan facility requires quarterly interest and principal payments over the remaining term of the loan and will require bullet repayments of approximately $155.3 million due at maturity in 2026. This loan facility is collateralized by first-priority mortgages on the three vessels to which the loan relates, together with certain other related security and certain guarantees from the Teekay Nakilat Joint Venture.

The Partnership has Norwegian Kroner (or NOK) 700 million of senior unsecured bonds that mature in May 2017 in the Norwegian bond market. As at December 31, 2015, the carrying amount of the bonds was $79.2 million and the bonds are listed on the Oslo Stock Exchange. The interest payments on the bonds are based on NIBOR plus a margin of 5.25%. The Partnership has a cross-currency swap to swap all interest and principal payments into U.S. Dollars, with the interest payments fixed at a rate of 6.88% (see Note 13) and the transfer of principal fixed at $125.0 million upon maturity in exchange for NOK 700 million.

The Partnership has NOK 900 million of senior unsecured bonds that mature in September 2018 in the Norwegian bond market. As at December 31, 2015, the carrying amount of the bonds was $101.8 million and the bonds are listed on the Oslo Stock Exchange. The interest payments on the bonds are based on NIBOR plus a margin of 4.35%. The Partnership has a cross-currency swap, to swap all interest and principal payments into U.S. Dollars, with the interest payments fixed at a rate of 6.43% (see Note 13) and the transfer of principal fixed at $150.0 million upon maturity in exchange for NOK 900 million.

The Partnership has NOK 1,000 million of senior unsecured bonds that mature in May 2020 in the Norwegian bond market. As at December 31, 2015, the carrying amount of the bonds was $113.1 million and the bonds are listed on the Oslo Stock Exchange. The interest payments on the bonds are based on NIBOR plus a margin of 3.70%. The Partnership has a cross currency swap (see Note 13), to swap all interest and principal payments into U.S. Dollars, with the interest payments fixed at a rate of 5.92% and the transfer of principal fixed at $134.0 million upon maturity in exchange for NOK 1,000 million.

The Partnership has two Euro-denominated term loans outstanding, which as at December 31, 2015, totaled 222.7 million Euros ($241.8 million). Interest payments are based on EURIBOR plus margins, which ranged from 0.60% to 2.25% as of December 31, 2015, 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, 2015 and December 31, 2014 was 2.33% and 2.19%, respectively. This rate does 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 13). At December 31, 2015, the margins on the Partnership’s outstanding revolving credit facilities and term loans ranged from 0.30% to 2.80%.

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

The aggregate annual long-term debt principal repayments required after December 31, 2015 are $198.3 million (2016), $210.7 million (2017), $796.5 million (2018), $70.1 million (2019), $186.3 million (2020) and $553.6 million (thereafter).

The Partnership and a subsidiary of Teekay Corporation are borrowers under a loan arrangement and are joint and severally liable for the obligations to the lender. Obligations resulting from long-term debt joint and several liability arrangements are measured at the sum of the amount the Partnership agreed to pay, on the basis of its arrangement among the co-obligor, and any additional amount the Partnership expects to pay on behalf of the co-obligor. This loan arrangement matures in 2021 and as of December 31, 2015 had an outstanding balance of $173.9 million, of which $88.3 million was the Partnership’s share. Teekay Corporation has indemnified the Partnership in respect of any losses and expenses arising from any breach by the co-obligor of the terms and conditions of the loan facility.

Certain loan agreements require that (a) the Partnership maintains minimum levels of tangible net worth and aggregate liquidity, (b) the Partnership maintains certain ratios of vessel values as it relates 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. The Partnership has one facility that requires us to maintain a vessel-value-to-outstanding-loan-principal-balance ratio of 115%, which as at December 31, 2015, was 194%. The vessel value was determined using reference to second-hand market comparables or using a depreciated replacement cost approach. Since vessel values can be volatile, the Partnership’s estimates of market value may not be indicative of either the current or future prices that could be obtained if the Partnership sold any of the vessels. The Partnership’s ship-owning subsidiaries may not, among other things, pay dividends or distributions if the Partnership is in default under its term loans or revolving credit facilities. One of the Partnership’s term loans is guaranteed by Teekay Corporation and contains covenants that require Teekay Corporation to maintain the greater of a minimum liquidity (cash and cash equivalents) of at least $50.0 million and 5.0% of Teekay Corporation’s total consolidated debt which has recourse to Teekay Corporation. As at December 31, 2015, the Partnership, and Teekay Corporation and their affiliates were in compliance with all covenants relating to the Partnership’s credit facilities and term loans.

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)

11.

Income Tax

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


	Year Ended December 31, 2015 $			Year Ended December 31, 2014 $			Year Ended December 31, 2013 $
Current		(2,646	)		(5,212	)		(1,482	)
Deferred		(76	)		(2,355	)		(3,674	)

Income tax expense		(2,722	)		(7,567	)		(5,156	)

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, 2015 $			Year Ended December 31, 2014 $			Year Ended December 31, 2013 $
Net income before income tax expenses		220,232			226,494			218,471
Net income not subject to taxes		(173,298	)		(81,604	)		(131,529	)

Net income subject to taxes		46,934			144,890			86,942

At applicable statutory tax rates
Amount computed using the standard rate of corporate tax		(12,007	)		(33,083	)		(16,476	)
Adjustments to valuation allowance and uncertain tax position		5,362			14,851			12,830
Permanent and currency differences		4,204			11,507			1,576
Change in tax rate		(281	)		(842	)		(3,086	)

Tax expense charge related to the current year		(2,722	)		(7,567	)		(5,156	)

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


	Year Ended December 31, 2015 $			Year Ended December 31, 2014 $
Derivative instruments		7,021			8,647
Taxation loss carryforwards and disallowed finance costs		44,823			48,440
Vessels and equipment		3,462			3,602
Capitalized interest		(2,184	)		(2,261	)

		53,122			58,428
Valuation allowance		(53,198	)		(58,428	)

Net deferred tax liabilities included in accrued liabilities		(76	)		—

The Partnership had tax losses in the United Kingdom (or UK) of $12.7 million as at December 31, 2015 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 (approximately $119.8 million) and 34.2 million Euros (approximately $37.2 million), respectively, at December 31, 2015 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 (approximately $31.5 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 120.9 million Euros (approximately $131.3 million) as at December 31, 2015 that are available indefinitely for offset against taxable future income in Luxembourg.

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 recognizes interest and penalties related to uncertain tax positions in income tax expense. The tax years 2007 through 2015 currently remain open to examination by the major tax jurisdictions to which the Partnership is subject.

12.

Related Party Transactions

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 6c and 14d), 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,			December 31,			December 31,
	2015			2014			2013
	$			$			$
Voyage revenues⁽ⁱ⁾		35,887			37,596			34,573
Vessel operating expenses		(19,914	)		(12,703	)		(10,847	)
General and administrative expenses⁽ⁱⁱ⁾		(14,485	)		(13,708	)		(11,959	)

(i)	Commencing in 2008, the Arctic Spirit and Polar Spirit were time-chartered to Teekay Corporation at a fixed-rate for a period of ten 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.

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 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.

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 Norgas Napa, the General Partner acquired a 1% ownership interest in the Norgas Napa from the Partnership for approximately $0.2 million.

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.

In March 2013, the Partnership incurred a $2.7 million charge relating to a fee to Teekay Corporation for its support in the Partnership’s successful acquisition of its 50% interest in Exmar LPG BVBA (see Note 6d). This acquisition fee is reflected as part of investments in and advances to equity accounted joint ventures in the Partnership’s consolidated balance sheets.

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)

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 11 LNG carrier newbuildings the Partnership owns (see Notes 14a and 14b). These costs are capitalized and included as part of advances on newbuilding contracts in the Partnership’s consolidated balance sheets. During the years ended 2015, 2014 and 2013, the Partnership incurred shipbuilding and site supervision costs of $4.3 million, $3.1 million and $0.2 million, respectively. As at December 31, 2015 and 2014 shipbuilding and site supervision costs provided by Teekay Corporation subsidiaries totaled $7.6 million and $3.3 million, respectively.

As at December 31, 2015 and 2014, non-interest bearing advances to affiliates totaled $13.0 million and $11.9 million, respectively, and non-interest bearing advances from affiliates totaled $23.0 million and $43.2 million, respectively. These advances are unsecured and have no fixed repayment terms. Affiliates are entities that are under the same common control.

13.

Derivative Instruments

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

Foreign Exchange Risk

Through 2012 to 2015, concurrently with the issuance of NOK 700 million, NOK 900 million and NOK 1,000 million, of senior unsecured bonds (see Note 10) 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 and 2020, and to economically hedge the interest rate exposure. The following table reflects information relating to the cross-currency swaps as at December 31, 2015.


											Fair Value /
											Carrying			Weighted-
Principal		Principal		Floating Rate Receivable							Amount of			Average
Amount		Amount		Reference				Fixed Rate			(Liability)			Remaining
NOK		$		Rate	Margin			Payable			$			Term (Years)
	700,000		125,000	NIBOR		5.25	%		6.88	%		(49,703	)		1.3
	900,000		150,000	NIBOR		4.35	%		6.43	%		(54,027	)		2.7
	1,000,000		134,000	NIBOR		3.70	%		5.92	%		(25,052	)		4.4

												(128,782	)

Interest Rate Risk

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, 2015, the Partnership was committed to the following interest rate swap agreements:


				Fair Value /
				Carrying			Weighted-
				Amount of			Average		Fixed
	Interest	Principal		Assets			Remaining		Interest
	Rate	Amount		(Liability)			Term		Rate
	Index	$		$			(years)		(%)⁽ⁱ⁾
LIBOR-Based Debt:
U.S. Dollar-denominated interest rate swaps	LIBOR		90,000		(8,965	)		2.7		4.9
U.S. Dollar-denominated interest rate swaps	LIBOR		100,000		(5,817	)		1.0		5.3
U.S. Dollar-denominated interest rate swaps⁽ⁱⁱ⁾	LIBOR		168,750		(34,567	)		13.0		5.2
U.S. Dollar-denominated interest rate swaps⁽ⁱⁱ⁾	LIBOR		64,268		(2,661	)		5.6		2.8
U.S. Dollar-denominated interest rate swaps⁽ⁱⁱⁱ⁾	LIBOR		320,000		(15,112	)		0.3		2.9
U.S. Dollar-denominated interest rate swaps^(iv)	LIBOR		117,000		(1,341	)		3.0		1.7

EURIBOR-Based Debt:
Euro-denominated interest rate swaps^(v)	EURIBOR		241,798		(35,674	)		5.0		3.1

					(104,137	)

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)

⁽ⁱ⁾	Excludes the margins the Partnership pays on its floating-rate term loans, which, at December 31, 2015, 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 2016 to 2021. These interest rate swaps are subject to mandatory early termination in 2016 whereby the swaps will be settled based on their fair value at that time.

^(iv)

Principal amount reduces quarterly.

^(v)	Principal amount reduces monthly to 70.1 million Euros ($76.1 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, 2015, the terms of the interest rate swaps underlying the interest rate swaptions were as follows:


						Fair Value /
						Carrying
	Interest	Principal			Option	Amount of			Remaining		Interest
	Rate	Amount			Exercise	Assets			Term		Rate
	Index	$			Date	(Liability)			(Years)		(%)
Interest rate swaption - Call Option	LIBOR		155,000	⁽ⁱ⁾	April 28, 2017		686			7.5		3.34	%
Interest rate swaption - Put Option	LIBOR		155,000	⁽ⁱ⁾	April 28, 2017		(2,626	)		7.5		2.15	%
Interest rate swaption - Call Option	LIBOR		160,000	⁽ⁱⁱ⁾	January 31, 2018		1,956			8.0		3.10	%
Interest rate swaption - Put Option	LIBOR		160,000	⁽ⁱⁱ⁾	January 31, 2018		(2,041	)		8.0		1.97	%
Interest rate swaption - Call Option	LIBOR		160,000	⁽ⁱⁱⁱ⁾	July 16, 2018		2,981			8.0		2.94	%
Interest rate swaption - Put Option	LIBOR		160,000	⁽ⁱⁱⁱ⁾	July 16, 2018		(1,739	)		8.0		1.83	%

⁽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, 2015, the Partnership had multiple interest rate swaps and cross-currency swaps with the same counterparty that are subject to the same master agreement. Each of these master agreements provide for the net settlement of all swaps subject to that master agreement through a single payment in the event of default or termination of any one swap. The fair value of these interest rate swaps are presented on a gross basis in the Partnership’s consolidated balance sheets. As at December 31, 2015, these interest rate swaps and cross-currency swaps had an aggregate fair value liability amount of $209.2 million. As at December 31, 2015, the Partnership had $44.8 million on deposit as security for swap liabilities under certain master agreements. The deposit is presented in restricted cash 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 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.

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 liability at December 31, 2015 was $6.3 million (December 31, 2014 – a liability of $2.1 million).

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)

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.


			Accrued
			liabilities/			Current
			Advances			portion of
	Derivative		from			derivative			Derivative
	assets		affiliates			liabilities			liabilities
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	)

As at December 31, 2014
Interest rate swap agreements		441		(7,486	)		(52,356	)		(60,157	)
Cross-currency swap agreements		—		(544	)		(4,922	)		(64,920	)
Toledo Spirit time-charter derivative		—		(637	)		(400	)		(1,100	)

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

Realized and unrealized gains (losses) relating to interest rate swap agreements and the Toledo Spirit time-charter derivative are recognized in earnings and reported in realized and unrealized loss on 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,
	2015									2014									2013
	Realized			Unrealized						Realized			Unrealized						Realized			Unrealized
	gains			gains						gains			gains						gains			gains
	(losses)			(losses)			Total			(losses)			(losses)			Total			(losses)			(losses)		Total
Interest rate swap agreements		(28,968	)		14,768			(14,200	)		(39,406	)		4,204			(35,202	)		(38,089	)		18,868		(19,221	)
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	)		1,521			3,700		5,221

		(32,397	)		12,375			(20,022	)		(42,586	)		(2,096	)		(44,682	)		(36,568	)		22,568		(14,000	)

Unrealized and realized losses relating to cross-currency swap agreements are recognized in earnings and reported in foreign currency exchange gain (loss) in the Partnership’s consolidated statements of income. For the years ended December 31, 2015, 2014 and 2013, unrealized losses of ($57.8) million, ($51.8) million and ($15.4) million, respectively, and realized losses of ($7.6) million, ($2.2) million and ($0.3) million, respectively, were recognized in earnings.

14.

Commitments and Contingencies

Between December 2012 and February 2015, the Partnership signed contracts with DSME for the construction of nine 173,400-cubic meter LNG carriers at a total fully-built up cost of approximately $1.8 billion. These newbuilding vessels will be equipped with the M-type, Electronically Controlled, Gas Injection (or MEGI) twin engines, which are expected to be significantly more fuel-efficient and have lower emission levels than other engines currently being utilized in LNG shipping.

Two of the vessels ordered are scheduled for delivery in 2016 (one of which delivered in February 2016, see Note 19a) and, upon delivery of the vessels, will be chartered to a subsidiary of Cheniere Energy, Inc. at fixed rates for a period of five years. Five of the vessels ordered are scheduled for delivery between 2017 and 2018 and, upon delivery of the vessels, will be chartered to a wholly owned subsidiary of Royal Dutch Shell PLC (or Shell) at fixed rates for a period of six to eight years, plus extension options. One of the vessels is being modified to a FSU for the Bahrain LNG project and will operate under a 20-year fixed-rate charter contract and is scheduled for delivery in 2018. The Partnership intends to secure a charter contract for the remaining newbuilding vessel prior to its delivery in 2017. As at December 31, 2015, costs incurred under these newbuilding contracts totaled $384.7 million and the estimated remaining costs to be incurred are $338.1 million (2016), $607.1 million (2017) and $515.4 million (2018). The Partnership intends to finance the newbuilding payments through existing liquidity and operating cash flow, and expects to secure long-term debt financing for the vessels prior to their scheduled deliveries (see Note 19a).

In June 2015, the Partnership signed contracts with Hyundai Samho Heavy Industries Co., Ltd. of South Korea for the construction of two 174,000-cubic meter LNG carriers equipped with MEGI engines at a total fully-built up cost of approximately $419.8 million. One of the vessels is scheduled for delivery in the first quarter of 2019 and, upon delivery of the vessel, will be chartered to BP Shipping Limited (or BP) at fixed rates for a period of 13 years. The Partnership intends to secure a charter contract for the second newbuilding vessel prior to its delivery in 2019. As at December 31, 2015, costs incurred under these newbuilding contracts totaled $40.2 million and the estimated remaining costs to be incurred are $2.6 million (2016), $82.4 million (2017), $44.9 million (2018) and $249.7 million (2019). 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.

F-28

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 Teekay Nakilat Joint Venture 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) until December 22, 2014. 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. 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. Initial indications are that HMRC will attempt to progress matters on other leases including the lease of the Teekay Nakilat Joint Venture with the intent of asking the lessees to accept the LEL1 tax case verdict that capital allowances were not due. If the Teekay Nakilat Joint Venture were to be challenged by HMRC, it is uncertain 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 the potential exposure in the Teekay Nakilat Joint Venture is estimated to be approximately $60 million. Such estimate is primarily based on information received from the lessor.

As described in Note 6c – Equity Method Investments, the Partnership acquired an ownership interest in the BG Joint Venture and, as part of the acquisition, agreed to assume BG’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. As at December 31, 2015, the Partnership incurred $4.2 million, net of reimbursement from BG, relating to shipbuilding and crew training services. The remaining estimated amounts to be incurred for the shipbuilding and crew training obligation, net of the reimbursement from BG, are $6.0 million (2016), $3.8 million (2017), $4.1 million (2018) and $0.4 million (2019).

In addition, the BG Joint Venture has a $787.0 million debt facility to finance a portion of the estimated fully built-up cost of $1.0 billion for its four LNG carrier newbuildings, with the remaining portion to be financed pro-rata based on ownership interests by the Partnership and the other partners. As at December 31, 2015, the Partnership’s proportionate share of the remaining newbuilding installments, net of the financing, totaled $7.9 million (2016), $15.0 million (2017), $17.3 million (2018) and $6.3 million (2019).

As described in Note 6b – Equity Method Investments, the Partnership, through the Yamal LNG Joint Venture, has a 50% ownership interest in six 172,000-cubic meter ARC7 LNG carrier newbuildings that have an estimated total fully built-up cost of $2.1 billion. As at December 31, 2015, the Partnership’s proportionate costs incurred under these newbuilding contracts totaled $100.5 million and the Partnership’s proportionate share of the estimated remaining costs to be incurred is $74.4 million (2016), $97.6 million (2017), $356.6 million (2018), $214.4 million (2019) and $198.3 million (2020). The Yamal LNG Joint Venture intends to secure debt financing for 70% to 80% of the fully built-up cost of the six LNG carrier newbuildings.

As described in Note 6a – Equity Method Investments, 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 July 2018. The receiving and regasification terminal is expected to have a fully-built up cost of approximately $872 million. As at December 31, 2015, the Partnership’s proportionate share of the costs to be incurred are $115.2 million (2016), $84.0 million (2017) and $62.4 million (2018). The Bahrain LNG Joint Venture intends to secure debt financing for approximately 75% of the fully built-up cost of the LNG receiving and regasification terminal in Bahrain.

As described in Note 6d – Equity Method Investments, the Partnership, has a 50% ownership interest in the Exmar LPG Joint Venture which has seven LPG newbuilding vessels scheduled for delivery between 2016 and 2018 and has obtained financing for three of these newbuilding vessels. As at December 31, 2015, the Partnership’s proportionate share of the remaining costs for these seven newbuilding carriers, net of the financing, totaled $4.9 million (2016), $62.7 million (2017) and $19.3 million (2018).

15.

Supplemental Cash Flow Information

The changes in operating assets and liabilities for years ended December 31, 2015, 2014 and 2013 are as follows:


	Year Ended			Year Ended			Year Ended
	December 31,			December 31,			December 31,
	2015			2014			2013
	$			$			$
Accounts receivable		(5,140	)		9,957			(6,436	)
Prepaid expenses		(494	)		1,781			80
Accounts payable		2,127			(1,098	)		(437	)
Accrued liabilities		(1,581	)		(6,759	)		7,662
Unearned revenue and long-term unearned revenue		(562	)		(536	)		(6,956	)
Restricted cash		(2,785	)		—			4,258
Advances to and from affiliates		(23,714	)		17,953			14,417
Other operating assets and liabilities		(2,038	)		(2,476	)		(2,510	)

Total		(34,187	)		18,822			10,078

F-29

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)

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, 2015, 2014 and 2013 totaled $94.5 million, $128.7 million, and $133.7 million, respectively.

During the years ended December 31, 2015, 2014 and 2013, cash paid for corporate income taxes was $7.8 million, $2.3 million and $5.6 million, respectively.

During 2013, the Partnership acquired two LNG carriers from Awilco for a purchase price of $205.0 million per vessel. The upfront prepayment of charter hire of $51.0 million (inclusive of a $1.0 million upfront fee) per vessel was used to offset the purchase price and was treated as a non-cash transaction in the Partnership’s consolidated statements of cash flows.

During 2014 and 2013, the sales of the Tenerife Spirit, 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 of $56.2 million in 2014 and the sale of the Tenerife Spirit under capital lease of $29.7 million in 2013 and the concurrent extinguishment of the corresponding capital lease obligations of $56.2 million in 2014 and $29.7 million in 2013 were treated as non-cash transactions in the Partnership’s consolidated statements of cash flows.

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.

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.

As described in Notes 6c – Equity Method Investments and 14d – Commitments and Contingencies, during 2014, the Partnership acquired BG’s ownership interest in the BG Joint Venture. As compensation, the Partnership assumed BG’s obligation (net of an agreement by BG 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 BG and was treated as a non-cash transaction in the Partnership’s consolidated statements of cash flows.

16.

Total Capital and Net Income Per Unit

The following table summarizes the issuances of common units over the three years ending December 31, 2015:


								Teekay
								Corporation’s
				Gross		Net		Ownership
	Units		Offering	Proceeds ⁽ⁱ⁾		Proceeds		After the
Date	Issued		Price	$		$		Offering⁽ⁱⁱ⁾	Use of Proceeds
Continuous offeringprogram during 2013		124,071	(iii)		5,383		4,926	(iii)	General partnership purposes
July 2013		931,098	$42.96		40,816		40,776	36.92%	Funding of LNG carrier newbuilding
October 2013		3,450,000	$42.62		150,040		144,818	35.30%	Prepayment of revolving credit facilities, funding of an LNG carrier acquisition and for general partnership purposes
July 2014		3,090,000	$44.65		140,784		140,484	33.96%	Prepayment of revolving credit facilities, funding of the Yamal LNG Project and portion of the MEGI newbuildings
Continuous offeringprogram during 2014		1,050,463	(iii)		42,556		41,655	(iii)	General partnership purposes including funding newbuilding installments
Continuous offeringprogram during 2015^(iv)		1,173,428	(iii)		36,274		35,374	(iii)	General partnership purposes, including funding newbuilding installments

⁽ⁱ⁾	Including the General Partner’s 2% proportionate capital contribution.

⁽ⁱⁱ⁾	Including Teekay Corporation’s indirect 2% general partner interest.

⁽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, at market prices up to a maximum aggregate amount of $100 million.

^(iv)

Includes 160,000 common units for net proceeds of $6.8 million (including General Partner’s 2% proportionate capital contribution) from the COP executed in 2014 that were received in January 2015.

F-30

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)

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 for 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 conducts, directs and manages 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 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	%

In the event of a liquidation, all property and cash in excess of that required to discharge all liabilities will be distributed to the 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 Unit

Net income per unit is determined by dividing net income, after deducting the amount of net income attributable to the non-controlling interest and the General Partner’s interest, by the weighted-average number of units outstanding during the period.

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 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.

17.

Unit-Based Compensation

In March 2015, a total of 10,447 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 2015. These common units were fully vested upon grant. During 2014 and 2013, the Partnership awarded 9,521 and 7,362 common units, respectively, as compensation to non-management directors. The awards were fully vested in March 2014 and March 2013, respectively. The compensation to the non-management directors is included in general and administrative expenses on the Partnership’s consolidated statements of income.

F-31

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)

During March 2015, 2014 and 2013, the Partnership granted 32,054, 31,961 and 36,878 restricted units, respectively, with grant date fair values of $1.1 million, $1.3 million and $1.5 million, respectively, based on the Partnership’s closing unit price on the grant date, to certain of the Partnership’s employees and to certain employees of Teekay Corporation’s subsidiaries who provide services to the Partnership. Each restricted unit represents 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 cancelled, 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 units, net of withholding tax. During the years ended December 31, 2015, 2014 and 2013, the Partnership recorded an expense of $1.2 million, $1.0 million, and $1.0 million, respectively, related to the restricted units.

18.

Restructuring Charge

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, $2.0 million and $1.8 million for the years ended December 31, 2015, 2014 and 2013, respectively. The balances outstanding of $0.7 million and $1.6 million as at December 31, 2015 and 2014, respectively, are included in accrued liabilities in the Partnership’s consolidated balance sheets.

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 included in voyage revenues in the Partnership’s consolidated statements of income. The balance payable to the affected seafarers of $1.1 million at December 31, 2015 is included in accrued liabilities in the Partnership’s consolidated balance sheets.

19.

Subsequent Events

On February 18, 2016, the Partnership took delivery of its first MEGI LNG carrier newbuilding, which commenced its five-year charter contract with a subsidiary of Cheniere Energy, Inc. on February 29, 2016. The Partnership’s second MEGI LNG carrier newbuilding is scheduled to deliver in mid-2016. In February 2016, the Partnership secured financing for these two MEGI LNG carrier newbuildings through a sale-leaseback transaction of approximately $179 million per vessel.

During February and March 2016, Centrofin Management Inc., the charterer for both the Bermuda Spirit and Hamilton Spirit Suezmax tankers, exercised its option to purchase both the Bermuda Spirit and Hamilton Spirit as permitted under the charter agreement. The Bermuda Spirit was sold on April 15, 2016 and the Hamilton Spirit is expected to be sold in May 2016. Substantially all of the net proceeds to be received from the sales are expected to be used to repay existing term loans for these vessels.

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