20-F 1 d849729d20f.htm 20-F 20-F
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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

 

FORM 20-F

 

 

(Mark One)

¨

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

OR

 

x

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

For the fiscal year ended December 31, 2014

OR

 

¨

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

OR

 

¨

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

Date of event requiring this shell company report                     

For the transition period from                      to                     

Commission file number 1- 32479

 

 

TEEKAY LNG PARTNERS L.P.

(Exact name of Registrant as specified in its charter)

 

 

Republic of The Marshall Islands

(Jurisdiction of incorporation or organization)

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

Telephone: (441) 298-2530

(Address and telephone number of principal executive offices)

Edith Robinson

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

Telephone: (441) 298-2530

Fax: (441) 292-3931

(Contact information for company contact person)

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

 

Title of each class

 

Name of each exchange on which registered

Common Units   New York Stock Exchange

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.

78,353,354 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  x

    

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

 

 


Table of Contents

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

     4   
 

Selected Financial Data

     4   
 

Risk Factors

     9   

Item 4.

 

Information on the Partnership

     24   
 

A. Overview, History and Development

     24   
 

B. Operations

     24   
 

Our Charters

     24   
 

Liquefied Gas Segment

     25   
 

Conventional Tanker Segment

     29   
 

Business Strategies

     29   
 

Safety, Management of Ship Operations and Administration

     30   
 

Risk of Loss, Insurance and Risk Management

     31   
 

Flag, Classification, Audits and Inspections

     31   
 

C. Regulations

     32   
 

D. Properties

     35   
 

E. Organizational Structure

     35   

Item 4A.

 

Unresolved Staff Comments

     35   

Item 5.

 

Operating and Financial Review and Prospects

     36   
 

General

     36   
 

Significant Developments in 2014 and Early 2015

     36   
 

Important Financial and Operational Terms and Concepts

     37   
 

Results of Operations

     38   
 

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

     39   
 

Year Ended December 31, 2013 versus Year Ended December 31, 2012

     43   
 

Liquidity and Cash Needs

     48   
 

Credit Facilities

     49   
 

Contractual Obligations and Contingencies

     51   
 

Off-Balance Sheet Arrangements

     52   
 

Critical Accounting Estimates

     52   

Item 6.

 

Directors, Senior Management and Employees

     54   
 

Management of Teekay LNG Partners L.P.

     54   
 

Directors and Executive Officers

     55   
 

Annual Executive Compensation

     56   
 

Compensation of Directors

     56   
 

2005 Long-Term Incentive Plan

     57   
 

Board Practices

     57   
 

Crewing and Staff

     58   
 

Unit Ownership

     58   

Item 7.

 

Major Unitholders and Related Party Transactions

     58   
 

Major Unitholders

     58   

 

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Related Party Transactions

  59   

Item 8.

Financial Information

  60   

A. Consolidated Financial Statements and Other Financial Information

  60   

Consolidated Financial Statements and Notes

  60   

Legal Proceedings

  60   

Cash Distribution Policy

  60   

B. Significant Changes

  61   

Item 9.

The Offer and Listing

  61   

Item 10.

Additional Information

  62   

Memorandum and Articles of Association

  62   

Material Contracts

  62   

Exchange Controls and Other Limitations Affecting Unitholders

  64   

Taxation

  64   

Marshall Islands Tax Consequences

  64   

United States Tax Consequences

  64   

Canadian Federal Income Tax Considerations

  73   

Other Taxation

  74   

Documents on Display

  74   

Item 11.

Quantitative and Qualitative Disclosures About Market Risk

  74   

Item 12.

Description of Securities Other than Equity Securities

  76   

PART II.

Item 13.

Defaults, Dividend Arrearages and Delinquencies

  76   

Item 14.

Material Modifications to the Rights of Unitholders and Use of Proceeds

  76   

Item 15.

Controls and Procedures

  76   

Item 16A.

Audit Committee Financial Expert

  76   

Item 16B.

Code of Ethics

  77   

Item 16C.

Principal Accountant Fees and Services

  77   

Item 16D.

Exemptions from the Listing Standards for Audit Committees

  77   

Item 16E.

Purchases of Units by the Issuer and Affiliated Purchasers

  77   

Item 16F.

Change in Registrant’s Certifying Accountant

  77   

Item 16G.

Corporate Governance

  77   

Item 16H.

Mine Safety Disclosure

  77   

PART III.

Item 17.

Financial Statements

  78   

Item 18.

Financial Statements

  78   

Item 19.

Exhibits

  78   

Signature

  81   

 

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PART I

This annual report of Teekay LNG Partners L.P. on Form 20-F for the year ended December 31, 2014 (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 ability to make cash distributions on our units or any increases in quarterly distributions;

 

   

our future financial condition and results of operations and our future revenues and expenses;

 

   

growth prospects of the liquefied natural gas (or LNG) and liquefied petroleum gas (or LPG) shipping and oil tanker markets;

 

   

LNG, LPG and tanker market fundamentals, including the balance of supply and demand in the LNG, LPG and tanker markets;

 

   

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;

 

   

our expectation regarding our vessels’ ability to perform to specifications and maintain their hire rates;

 

   

our ability to maximize the use of our vessels, including the redeployment or disposition of vessels no longer under long-term charter;

 

   

expected purchases and deliveries of newbuilding vessels and commencement of service of newbuildings under charter contracts and our ability to obtain charter contracts on our unfixed newbuildings, including with respect to the nine LNG newbuildings ordered from Daewoo Shipbuilding & Marine Engineering Co. (or DSME), four LNG newbuildings ordered within our joint venture with China LNG, CETS Investment Management (HK) Co. Ltd. and BW LNG Investments Pte. Ltd. (or the BG Joint Venture), six LNG newbuildings relating to our joint venture with China LNG Shipping (Holdings) Limited (or the Yamal LNG Joint Venture), and eight LPG newbuildings within Exmar LPG BVBA;

 

   

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 expectation that we will not record a gain or loss on future sales of vessels under capital lease;

 

   

the expected source of funds for short-term and long-term liquidity needs;

 

   

our financial condition and liquidity, including our ability to borrow funds under our credit facilities, to refinance our existing facilities and to obtain additional financing in the future to fund capital expenditures, acquisitions and other general corporate activities;

 

   

estimated capital expenditures and our ability to fund them;

 

   

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;

 

   

the recent economic downturn and financial crisis in the global market and potential negative effects on our customers’ ability to charter our vessels and pay for our services;

 

   

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

 

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the expected timing, amount and method of financing for the purchase of two of our leased Suezmax tankers, the nine LNG carrier newbuildings ordered from DMSE, the six LNG carrier newbuildings for the Yamal LNG Joint Venture, the four LNG carrier newbuildings for the BG Joint Venture, and eight LPG carrier newbuildings ordered within Exmar LPG BVBA;

 

   

our expected financial flexibility to pursue acquisitions and other expansion opportunities;

 

   

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

 

   

the expected cost of, and our ability to comply with, governmental regulations and maritime self-regulatory organization standards applicable to our business;

 

   

the impact of new environmental regulations, including Regulation (EU) No 1257/2013;

 

   

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 adequacy of our insurance coverage for accident-related risks, environmental damage and pollution;

 

   

the future valuation of goodwill;

 

   

our expectations as to any impairment of our vessels;

 

   

our involvement in any EU anti-trust investigation of container line operators;

 

   

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

 

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

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

 

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(in thousands of U.S. Dollars, except per unit and fleet data)    Year Ended
December 31,

2010
$
    Year Ended
December 31,

2011
$
    Year Ended
December 31,

2012
$
    Year Ended
December 31,

2013
$
    Year Ended
December 31,

2014
$
 

Income Statement Data:

          

Voyage revenues

     374,502       380,469       392,900       399,276       402,928  

Total operating expenses(1)(2)

     (195,542     (206,966     (245,109     (222,920     (219,105
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income from vessel operations

  178,960     173,503     147,791     176,356     183,823  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Equity income(3)

  8,043     20,584     78,866     123,282     115,478  

Interest expense

  (49,019   (49,880   (54,211   (55,703   (60,414

Interest income

  7,190     6,687     3,502     2,972     3,052  

Realized and unrealized loss on derivative

instruments(4)

  (78,720   (63,030   (29,620   (14,000   (44,682

Foreign currency exchange gain (loss)(5)

  27,545     10,310     (8,244   (15,832   28,401  

Other income (expense)

  615     (37   1,683     1,396     836  

Income tax expense

  (1,670   (781   (625   (5,156   (7,567
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income

  92,944     97,356     139,142     213,315     218,927  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Non-controlling and other interest in net income

  14,216     18,982     36,740     37,438     44,676  

Limited partners’ interest in net income

  78,728     78,374     102,402     175,877     174,251  

Limited partners’ interest in net income per:

Common unit (basic and diluted)

  1.46     1.33     1.54     2.48     2.30  

Cash distributions declared per unit

  2.3700     2.5200     2.6550     2.7000     2.7672  

Balance Sheet Data (at end of period):

Cash and cash equivalents

  81,055     93,627     113,577     139,481     159,639  

Restricted cash(6)

  572,138     495,634     528,589     497,298     45,997  

Vessels and equipment(7)

  2,019,576     2,021,125     1,949,640     1,922,662     1,989,230  

Investment in and advances to equity accounted

joint ventures

  172,898     191,448     409,735     671,789     891,478  

Net investments in direct financing leases(8)

  415,695     409,541     403,386     699,695     682,495  

Total assets (6)

  3,547,395     3,588,734     3,785,446     4,219,594     3,964,418  

Total debt and capital lease obligations (6)

  2,137,249     1,962,278     2,050,927     2,375,836     1,987,674  

Partners’ equity

  896,200     1,113,467     1,212,980     1,390,790     1,537,752  

Total equity

  913,323     1,139,709     1,254,274     1,443,784     1,547,371  

Common units outstanding

  55,106,100     64,857,900     69,683,763     74,196,294     78,353,354  

Other Financial Data:

Net voyage revenues(9)

  372,460     379,082     391,128     396,419     399,607  

EBITDA(10)

  226,284     233,743     290,950     369,086     377,983  

Adjusted EBITDA(10)

  297,508     320,929     413,033     461,018     468,954  

Capital expenditures:

Expenditures for vessels and equipment

  26,652     64,685     39,894     470,213     194,255  

Liquefied Gas Fleet Data:

Consolidated:

Calendar-ship-days (11)

  5,051     5,126     5,856     5,981     6,619  

Average age of our fleet (in years at end of period)

  5.3     5.8     6.6     6.7     7.9  

Vessels at end of period(13)

  13     16     16     18     19  

Equity Accounted:(12)

Calendar-ship-days(11)

  1,576     2,469     5,481     11,059     11,338  

Average age of our fleet (in years at end of period)

  3.5     3.0     3.4     9.4     8.0  

Vessels at end of period (13)

  6     9     16     32     31  

Conventional Fleet Data:

Calendar-ship-days(11)

  4,015     4,015     4,026     3,994     3,202  

Average age of our fleet (in years at end of period)

  6.1     6.9     7.9     8.5     8.5  

Vessels at end of period

  11     11     11     10     8  

 

(1)

Total operating expenses include voyage expenses, which 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.

 

(2)

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

 

(3)

Equity income includes unrealized gains (losses) on derivative instruments, and any ineffectiveness of derivative instruments designated as hedges for accounting purposes of ($6.5) million, ($5.8) million, $5.5 million, $25.9 million and $1.6 million for the years ended December 31, 2010, 2011, 2012, 2013 and 2014, respectively.

 

(4)

We entered into interest rate swaps 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 one interest rate swap in one of our equity accounted joint ventures, and as a result, changes in the fair value of our derivatives are recognized immediately into income and are presented as realized and unrealized loss on derivative instruments in the consolidated statements of income. Please see “Item 18 – Financial Statements: Note 12 – Derivative Instruments.”

 

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(5)

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, long-term debt and capital lease obligations, 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 278.9 million Euros ($373.3 million) at December 31, 2010, 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 and 235.6 million Euros ($285.0 million) at December 31, 2014. 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 and 1.6 billion NOK ($214.7 million) at December 31, 2014.

 

(6)

On December 22, 2014, we terminated the leasing of three LNG carriers and acquired them as discussed in “Item 18 – Financial Statements: Note 4 – Leases and Restricted Cash.” 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.

 

(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.

 

     Year Ended
December 31,
    Year Ended
December 31,
    Year Ended
December 31,
    Year Ended
December 31,
    Year Ended
December 31,
 
(in thousands of U.S. Dollars)    2010     2011     2012     2013     2014  

Voyage revenues

     374,502       380,469       392,900       399,276       402,928  

Voyage expenses

     (2,042     (1,387     (1,772     (2,857     (3,321
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net voyage revenues

  372,460     379,082     391,128     396,419     399,607  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(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 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.

 

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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,
2010
    Year Ended
December 31,
2011
    Year Ended
December 31,
2012
    Year Ended
December 31,
2013
    Year Ended
December 31,
2014
 

Reconciliation of “EBITDA” and “Adjusted EBITDA” to “Net income”:

         

Net income

    92,944       97,356       139,142       213,315       218,927  

Depreciation and amortization

    89,841       92,413       100,474       97,884       94,127  

Interest expense, net of interest income

    41,829       43,193       50,709       52,731       57,362  

Income tax expense

    1,670       781       625       5,156       7,567  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

EBITDA

  226,284     233,743     290,950     369,086     377,983  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Restructuring charge

  175     —       —       1,786     1,989  

Write down of vessels

  —       —       29,367     —       —    

Foreign currency exchange (gain) loss

  (27,545   (10,310   8,244     15,832     (28,401

Gain on sale of vessel

  (4,340   —       —       —       —    

Amortization of in-process revenue contracts included in

voyage revenues

  (494   (494   (649   (1,113   (1,113

Unrealized loss (gain) on derivative instruments

  34,306     277     (6,900   (22,568   2,096  

Realized loss on interest rate swaps

  42,495     62,660     37,427     38,089     41,725  

Adjustments to Equity-Accounted EBITDA(14)

  26,627     35,053     54,594     59,906     74,675  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted EBITDA

  297,508     320,929     413,033     461,018     468,954  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Reconciliation of “Adjusted EBITDA” to “Net operating cash flow”:

Net operating cash flow

  174,970     122,046     192,013     183,532     191,097  

Expenditures for dry docking

  12,727     19,638     7,493     27,203     13,471  

Interest expense, net of interest income

  41,829     43,193     50,709     52,731     57,362  

Income tax expense

  1,670     781     625     5,156     7,567  

Change in operating assets and liabilities

  (6,657   33,458     7,307     (10,078   (18,822

Equity income from joint ventures

  8,043     20,584     78,866     123,282     115,478  

Restructuring charge

  175     —       —       1,786     1,989  

Realized loss on interest rate swaps

  42,495     62,660     37,427     38,089     41,725  

Dividends received from equity accounted joint ventures

  —       (15,340   (14,700   (13,738   (11,005

Adjustments to Equity-Accounted EBITDA(14)

  26,627     35,053     54,594     59,906     74,675  

Other, net

  (4,371   (1,144   (1,301   (6,851   (4,583
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted EBITDA

  297,508     320,929     413,033     461,018     468,954  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(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 (including three vessels deemed to be in our possession for accounting purposes as a result of the impact of the Dropdown Predecessor prior to our actual acquisition of such vessels).

 

(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) from 2010 relating our LNG joint venture with Exmar NV and (v) 15 and 16 LPG carriers (or the Exmar LPG Carriers) from 2014 and 2013, respectively, relating to our LPG joint venture with Exmar NV. The figures in the selected financial data for our equity accounted vessels are at 100% and not based on our ownership percentage.

 

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(13)

For 2014, the number of vessels indicated do not include eight LNG newbuilding carriers in our consolidated liquefied gas fleet and 19 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,
2010
    Year Ended
December 31,
2011
    Year Ended
December 31,
2012
    Year Ended
December 31,
2013
    Year Ended
December 31,
2014
 

Reconciliation of “Adjusted Equity-Accounted EBITDA” to “Equity Income”:

          

Equity Income

     8,043       20,584       78,866       123,282       115,478  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Depreciation and amortization

  833     5,501     25,589     45,664     45,885  

Interest expense, net of interest income

  11,431     14,368     26,622     35,110     36,916  

Income tax expense (recovery)

  325     (315   87     163     (155

Amortization of in-process revenue contracts

  (31   (341   (11,083   (14,173   (8,295

Foreign currency exchange loss (gain)

  —       133     (18   149     (441

Gain on sales of vessels

  —       —       —       —       (16,923

Unrealized loss (gain) on derivative instruments

  6,453     5,830     (5,549   (26,432   (1,563

Realized loss on interest rate swaps

  7,616     9,877     18,946     19,425     19,251  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Adjustments to Equity-Accounted EBITDA

  26,627     35,053     54,594     59,906     74,675  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted Equity-Accounted EBITDA

  34,670     55,637     133,460     183,188     190,153  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

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;

 

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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 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.

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.

Our significant maintenance capital expenditures reduce the amount of cash we have available for distribution to our unitholders.

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. 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. We generally will be required to make significant installment payments for acquisitions of newbuilding vessels prior to their delivery and generation of revenue. Depending on whether we finance our expenditures through cash from operations or by issuing debt or equity securities, our ability to make required payments on our debt securities and cash distributions on our common units may be diminished or our financial leverage could increase or our unitholders could be diluted.

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 19 LNG carrier newbuildings scheduled for delivery between 2016 and 2020, with options to order up to four additional vessels, and eight LPG carrier newbuildings scheduled for delivery between 2015 and 2018. We may also be obligated to purchase two of our leased Suezmax tankers 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 $73.7 million at December 31, 2014.

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

To fund the remaining portion of existing or future capital expenditures, we will be required to use cash from operations or incur borrowings or raise capital through the sale of debt or additional equity securities. Use of cash from operations will reduce cash available for distributions 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 resulting from, among other things, general economic conditions and contingencies and uncertainties that are beyond our control. Our failure to obtain the funds for necessary future capital expenditures could have a material adverse effect on our business, results of operations and financial condition and on our ability to make cash distributions. Even if we are successful in obtaining necessary funds, the terms of such financings could limit our ability to pay cash distributions to unitholders. In addition, incurring additional debt may significantly increase our interest expense and financial leverage, and issuing additional equity securities may result in significant unitholder dilution and would increase the aggregate amount of cash required to maintain our level of quarterly distributions to unitholders, which could have a material adverse effect on our ability to make cash distributions.

 

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

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

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

Our substantial debt levels may limit our flexibility in obtaining additional financing and in pursuing other business opportunities.

As at December 31, 2014, our consolidated debt, capital lease obligations and advances from affiliates totaled $2.0 billion and we had the capacity to borrow an additional $135.6 million under our 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 reducing distributions, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets, restructuring or refinancing our debt, or seeking additional equity capital or 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 two 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 of the obligations may become immediately due and payable, and the lenders’ commitment to make further loans may terminate. 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;

 

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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 3 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 decrease charter payments due 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.

 

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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.

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

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

 

   

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.

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;

 

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

 

   

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.

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

We have several LPG carriers either owned or chartered-in by the Exmar LPG Joint Venture that operate in the LPG spot market. 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.

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

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

 

   

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

 

   

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

 

   

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

 

   

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

 

   

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

 

   

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

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

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

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

 

   

shipping industry relationships and reputation for customer service and safety;

 

   

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

 

   

quality and experience of seafaring crew;

 

   

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

 

   

relationships with shipyards and the ability to get suitable berths;

 

   

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

 

   

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

 

   

competitiveness of the bid in terms of overall price.

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

 

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Delays in deliveries of newbuildings could harm our operating results and lead to the termination of related charters.

The delivery of newbuildings we may order 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 could be delayed because of:

 

   

quality or engineering problems;

 

   

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

 

   

work stoppages or other labor disturbances at the shipyard;

 

   

bankruptcy or other financial crisis of the shipbuilder;

 

   

a backlog of orders at the shipyard;

 

   

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

 

   

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

 

   

our requests for changes to the original vessel specifications;

 

   

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

 

   

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

 

   

our inability to obtain requisite permits or approvals.

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

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

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

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 one of the MALT LNG Carriers expired in March 2015 and, due to extended off-hire, the charterer of another MALT LNG Carrier claims to have terminated the time charter for that vessel. 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 2013, they accounted for approximately 27% 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 and, if these values are lower at a time when we are attempting to dispose of a vessel, we may incur a loss.

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

 

   

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

 

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

 

   

increases in the supply of vessel capacity; and

 

   

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

If a charter terminates, we may be unable to redeploy the vessel at attractive rates and, rather than continue to incur costs to maintain and finance it, 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.

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 specifications which may result in performance issues or claims based on charter party agreements.

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

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

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

 

   

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

 

   

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

 

   

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

 

   

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

 

   

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

 

   

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

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

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.

 

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Changes in the insurance markets attributable to terrorist attacks 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 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, and other current and future conflicts, 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.

In addition, LNG, LPG and oil facilities, shipyards, vessels, pipelines and oil and gas fields could be targets of future terrorist attacks and our vessels could be targets of pirates or hijackers. 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 an 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 have recently increased in frequency, 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 continue to be significant numbers of piracy incidents in the Gulf of Aden and Indian Ocean, recently there have been increases in the frequency and severity of piracy incidents off the coast of West Africa. 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 substantial operations outside the United States expose us to political, governmental and economic instability, which could harm our operations.

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

The LNG carrier newbuildings 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.

 

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

 

   

failure of the project to obtain debt financing;

 

   

failure to achieve expected operating results;

 

   

changes in demand for LNG;

 

   

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

 

   

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

 

   

labor disputes; and

 

   

environmental regulations or potential claims.

If the project is not completed or is abandoned, proceeds if any, received from limited Yamal LNG project sponsor guarantees and potential alternative employment, if any, of the vessels and from potential sales of components and scrapping of the vessels likely would fall substantially short of the cost of the vessels to the Yamal LNG Joint Venture. Any such shortfall could have a material adverse effect on our financial condition, results of operations and ability to make distributions 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) recently placed Russia-based Novatek OAO (or Novatek), a 60% owner of the Yamal LNG Project, on the Sectoral Sanctions Identifications List. OFAC also previously imposed sanctions on an investor in Novatek, which sanctions remain in effect. The restrictions on Novatek prohibit U.S. persons from participating in debt financing transactions of greater than 90 day maturity by Novatek and, by virtue of Novatek’s 60% ownership interest, the Yamal LNG Project. To the extent the Yamal LNG Project or Novatek are dependent on financing involving participation by U.S. persons, these OFAC actions could have a material adverse effect on the ability of the Yamal LNG Project to be completed or perform as expected. Effective August 1, 2014, 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 appear to focus on oil exploration projects, not gas projects. Furthermore, 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 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 charter 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 and the two LNG carriers chartered to Yemen LNG Company Limited. 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.

 

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

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

 

   

marine disasters;

 

   

bad weather or natural disasters;

 

   

mechanical failures;

 

   

grounding, fire, explosions and collisions;

 

   

piracy;

 

   

human error; and

 

   

war and terrorism.

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

 

   

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

 

   

delays in the delivery of cargo;

 

   

loss of revenues from or termination of charter contracts;

 

   

governmental fines, penalties or restrictions on conducting business;

 

   

higher insurance rates; and

 

   

damage to our reputation and customer relationships generally.

Any of these results could have a material adverse effect on our business, financial condition and operating results.

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.

 

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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, long-term debt and capital lease obligations, 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:

 

   

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

 

   

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

 

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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:

 

   

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;

 

   

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

 

   

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 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, 2014 owned a 32.2% 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:

 

   

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;

 

   

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

 

   

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

 

   

our General Partner has limited its liability and reduced its fiduciary duties under the laws of the Marshall Islands, while also restricting the remedies available to our unitholders, and as a result of purchasing 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;

 

   

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

 

   

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

 

   

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

 

   

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

 

   

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

 

   

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

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.

 

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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 resulted in a court decision from the First Tribunal on January 2012 regarding a similar financial lease of an LNG carrier that ruled in favor of the taxpayer, as well as a 2013 decision from the Upper Tribunal that upheld the 2012 verdict. However, HMRC appealed the 2013 decision to the Court of Appeal and in August 2014, HMRC was successful in having the judgment of the First Tribunal (in favor of the taxpayer) set aside. The matter will now be reconsidered by the First Tribunal, taking into account the appellate court’s comments on the earlier judgment. If the lessor of the RasGas II LNG Carriers were to lose on a similar claim from HMRC, which we do not consider to be a probable outcome, 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

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.”

 

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

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

 

   

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

 

   

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

 

   

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

 

   

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

 

   

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

 

   

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

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

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 2014 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 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 in subsequent tax years and that any resulting imposition of U.S. federal income taxes would result in decreased cash available for distribution to common unitholders.

 

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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 unitholders 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 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 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 2014 and Early 2015.”

As of December 31, 2014, 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), 21 LPG carriers (including the 15 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 seven years for our LNG carriers, approximately nine years for our LPG Carriers and approximately nine years for our conventional tankers (Suezmax and Handymax), compared to world averages of 10, 16 and nine years, respectively, as of December 31, 2014.

Our fleets of LNG and LPG carriers currently have approximately 4.6 million and 0.6 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 headquarters at 4th Floor, Belvedere Building, 69 Pitts Bay Road, Hamilton, HM 08, Bermuda. Our telephone number at such address is (441) 298-2530.

B. Operations

Our Charters

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

Our vessels primarily operate under long-term, fixed-rate charters with major energy and utility companies and Teekay Corporation. The average remaining term for these charters is approximately 12 years for our LNG carriers, approximately five years for our LPG carriers and approximately three years for our conventional tankers (Suezmax and Handymax), subject, in certain circumstances, to termination or vessel purchase rights.

 

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“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 1/600th of its volume in a gaseous state. The reduced volume facilitates economical storage and transportation by ship over long distances, enabling countries with limited natural gas reserves or limited access to long-distance transmission pipelines to import natural gas. LNG carriers include a sophisticated containment system that holds the LNG and provides insulation to reduce the amount of LNG that boils off naturally. The natural boil off is either used as fuel to power the engines on the ship or it can be reliquefied and put back into the tanks. LNG is transported overseas in specially built tanks 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 currently are no regulations that require the phase-out from trading of LNG carriers after they reach a certain age. As at December 31, 2014, our LNG carriers had an average age of approximately seven years, compared to the world LNG carrier fleet average age of approximately 10 years. In addition, as at that date, there were approximately 415 vessels in the world LNG fleet and approximately 160 additional LNG carriers under construction or on order for delivery through 2019.

 

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The following table provides additional information about our LNG carriers as of December 31, 2014, excluding our 18 newbuildings scheduled for delivery between 2016 and 2020 in which our ownership interest ranges from 20% to 100%:

 

Vessel

   Capacity    

Delivery

  Our
Ownership
   

Charterer

 

Expiration of
Charter
(1)

     (cubic meters)                    

Operating LNG carriers:

  

       

Consolidated

          

Hispania Spirit

     137,814     2002     100   Shell Spain LNG S.A.U.   Sep. 2022(2)

Catalunya Spirit

     135,423     2003     100   Gas Natural SDG   Aug. 2023(2)

Galicia Spirit

     137,814     2004     100   Uniòn Fenosa Gas   Jun. 2029(3)

Madrid Spirit

     135,423     2004     100   Shell Spain LNG S.A.U.   Dec. 2024(2)
         Ras Laffan Liquefied  

Al Marrouna

     149,539     2006     70   Natural Gas Company Ltd.   Oct. 2026(4)
         Ras Laffan Liquefied  

Al Areesh

     148,786     2007     70   Natural Gas Company Ltd.   Jan. 2027(4)
         Ras Laffan Liquefied  

Al Daayen

     148,853     2007     70   Natural Gas Company Ltd.   Apr. 2027(4)
         The Tangguh Production  

Tangguh Hiri

     151,885     2008     69   Sharing Contractors   Jan. 2029
         The Tangguh Production  

Tangguh Sago

     155,000     2009     69   Sharing Contractors   May 2029

Arctic Spirit

     87,305     1993     99   Teekay Corporation   Apr. 2018(4)

Polar Spirit

     87,305     1993     99   Teekay Corporation   Apr. 2018(4)

Wilforce

     155,900     2013     99   Awilco LNG ASA   Sep. 2018(5)

Wilpride

     155,900     2013     99   Awilco LNG ASA   Nov. 2017(5)

Equity Accounted

          
         Ras Laffan Liquefied  

Al Huwaila

     214,176     2008     40 %(8)    Natural Gas Company Ltd.   Apr. 2033(2)
         Ras Laffan Liquefied  

Al Kharsaah

     214,198     2008     40 %(8)    Natural Gas Company Ltd.   Apr. 2033(2)
         Ras Laffan Liquefied  

Al Shamal

     213,536     2008     40 %(8)    Natural Gas Company Ltd.   May 2033(2)
         Ras Laffan Liquefied  

Al Khuwair

     213,101     2008     40 %(8)    Natural Gas Company Ltd.   Jun. 2033(2)

Excelsior

     138,087     2005     50 %(9)    Excelerate Energy LP   Jan. 2025(2)

Excalibur

     138,034     2002     50 %(9)    Excelerate Energy LP   Mar. 2022

Soyo

     160,400     2011     33 %(10)    Angola LNG Supply Services LLC   Aug. 2031(2)

Malanje

     160,400     2011     33 %(10)    Angola LNG Supply Services LLC   Sep. 2031(2)

Lobito

     160,400     2011     33 %(10)    Angola LNG Supply Services LLC   Oct. 2031(2)

Cubal

     160,400     2012     33 %(10)    Angola LNG Supply Services LLC   Jan. 2032(2)

Meridian Spirit

     165,700     2010     52 %(11)    Total E&P Norge AS Mansel Limited   Nov. 2030(6)

Magellan Spirit

     165,700     2009     52 %(11)    Vitol S.A.   Sep. 2016(13)

Marib Spirit

     165,500     2008     52 %(11)    Yemen LNG Company Limited   Mar. 2029(6)

Arwa Spirit

     165,500     2008     52 %(11)    Yemen LNG Company Limited   Apr. 2029(6)

Methane Spirit

     165,500     2008     52 %(11)    BP Shipping Limited   Mar. 2015(7)

Woodside Donaldson

     165,500     2009     52 %(11)    Pluto LNG Party Limited   Jun. 2026(12)
  

 

 

         

Total Capacity:

  4,553,079  
  

 

 

         

 

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(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 charter contract ended in March 2015 and the Teekay LNG-Marubeni Joint Venture is currently seeking a charter contract for this vessel.

(8)

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

(9)

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

(10)

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

(11)

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

(12)

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

(13)

As a result of an incident in January 2015 that put the vessel off-hire, the charterer has claimed that the off-hire time for this vessel during this period gave them the right to terminate its charter contract on March 28, 2015. The Teekay LNG-Marubeni Joint Venture is currently disputing the charterer’s claims of the aggregate off-hire time for this vessel as a result of this incident as well as the charterer’s ability to terminate the charter contract. In addition, the Teekay LNG-Marubeni Joint Venture is seeking a charter contract for this vessel.

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

 

     Year Ended December 31,  
     2014     2013     2012  

Ras Laffan Liquefied Natural Gas Company Ltd.

     17     17     18

Shell Spain LNG S.A.U. (1)

     13     13     13

The Tangguh Production Sharing Contractors

     11     12     12

 

(1)

In March 2014, Shell Spain LNG S.A.U. acquired the charter contracts from Repsol YPF, S.A. The voyage revenues in 2014 consisted of the voyage revenues from both customers relating to the same charter contract; voyage revenues in 2013 and 2012 were only from Repsol YPF, S.A.

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, 2014, 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 1,277 vessels and approximately 232 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, 2014, excluding our 50% ownership interest in nine newbuildings scheduled for delivery between 2015 and 2018:

 

Vessel

   Capacity      Delivery      Ownership    

Contract
Type

  

Charterer

  

Expiration of Charter

     (cubic meters)                              

Operating LPG carriers:

                

Consolidated

                

Norgas Pan

     10,000        2009        99   Bareboat    I.M. Skaguen ASA    Mar. 2024

Norgas Cathinka

     10,000        2009        99   Bareboat    I.M. Skaguen ASA    Oct. 2024

Norgas Camilla

     10,000        2011        99   Bareboat    I.M. Skaguen ASA    Sep. 2026

Norgas Unikum

     12,000        2011        99   Bareboat    I.M. Skaguen ASA    Jun. 2026

Bahrain Vision

     12,000        2011        99   Bareboat    I.M. Skaguen ASA    Oct. 2026

Norgas Napa

     10,200        2003        99   Bareboat    I.M. Skaguen ASA    Nov. 2019

 

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Vessel

  Capacity     Delivery  

Ownership

  

Contract Type

  

Charterer

  

Expiration of Charter

    (cubic meters)                         

Equity Accounted

              

Brugge Venture

    35,418     1997   50%    Time charter    An international fertilizer company    Jan. 2016

Temse (Kemira Gas

renamed to Temse)

    12,030     1995   50%    Time charter    An international fertilizer company    Feb. 2017

Libramont

    38,455     2006   50%    Time charter    An international fertilizer company    May. 2026

Sombeke

    38,447     2006   50%    Time charter    An international fertilizer company    Jul. 2027

Touraine

    39,270     1996   50%    Time charter    An international fertilizer company    Nov. 2016

Bastogne

    35,229     2002   50%    CoA(1)    North Sea charters    Mar. 2016

Courcheville

    28,006     1989   50%    Time charter    An international energy company    Sep. 2015

Eupen

    38,961     1999   50%    Time charter    An international energy company    Jun. 2016

Brussels

    35,454     1997   Capital lease(2)    Time charter    An international fertilizer company    Nov. 2017

Antwerpen

    35,223     2005   Chartered-In    CoA(1)    North Sea charters    Mar. 2016

Odin

    38,501     2005   Chartered-In    CoA(1)    North Sea charters    Jun. 2016

BW Tokyo

    83,270     2009   Chartered-In    Time charter    An international trading company    Jun. 2016

Waregem

    38,189     2014   50%    Time charter    An international trading company    Jan. 2020

Warinsart

    38,213     2014   50%    Time charter    An international energy company    Jun. 2016

Waasmunster

    38,245     2014   50%    CoA(1)    North Sea charters    Jun. 2016
 

 

 

              

Total Capacity:

  637,111  
 

 

 

              

 

(1)

“CoA” refers to contracts of affreightment.

(2)

Exmar LPG BVBA is the lessee under a capital lease arrangement and will be required to purchase the vessel at the end of the lease term for a fixed price.

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

 

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Conventional Tanker Segment

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

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

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

As of December 31, 2014, our conventional tankers had an average age of approximately nine 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, 2014:

 

Tanker(1)

  Capacity     Delivery     Our Ownership   Charterer   Expiration of
Charter
 
    (dwt)                      

Operating Conventional tankers:

         

Teide Spirit

    149,999       2004     Capital lease (2)   CEPSA     Oct. 2017(3)   

Toledo Spirit

    159,342       2005     Capital lease (2)   CEPSA     Jul. 2018(3)   

European Spirit

    151,849       2003     100%   ConocoPhillips Shipping LLC     Sep. 2015 (4) 

African Spirit

    151,736       2003     100%   ConocoPhillips Shipping LLC     Nov. 2015 (4) 

Asian Spirit

    151,693       2004     100%   ConocoPhillips Shipping LLC     Jan. 2016(4)   

Bermuda Spirit

    159,000       2009     100%   Centrofin Management Inc.     May. 2021(5)   

Hamilton Spirit

    159,000       2009     100%   Centrofin Management Inc.     Jun. 2021(5)   

Alexander Spirit

    40,083       2007     100%   Caltex Australian Petroleum Pty Ltd.     Mar. 2020   
 

 

 

         

Total Capacity:

  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 4 – 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 Management Inc. has the option to purchase the two vessels, which right is exercisable after the end of five years and every year thereafter until the end of the charter agreement.

CEPSA accounted for 7%, 12% and 12% of our 2014, 2013 and 2012 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 business objective is to increase distributable cash flow per unit 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;

 

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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.

 

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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 and boycotts. The occurrence of any of these events may result in loss of revenues or increased costs.

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

We use in our operations 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 we benefit from Teekay Corporation’s commitment to safety and environmental protection as 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 or American Bureau of Shipping.

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 at each office and vessel annually.

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

 

   

the 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.

 

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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. 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 is to enter into force on January 1, 2016 with an implementation/application date of July 1, 2016.

Annex VI (or Annex VI) of the IMO’s International Convention for the Prevention of Pollution from Ships (MARPOL) 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 to comply with the ballast water performance standard specified in the Ballast Water Convention, and that all other similarly sized tankers install water ballast treatment systems, in order to comply with the ballast water performance standard from 2016. In the latter case, compliance is required not later than by the first intermediate or renewal survey in relation to the International Ballast Water Management Certificate, whichever occurs first, after the anniversary date of delivery of the relevant vessel in the year of compliance with the applicable standard. This convention has not yet entered into force, but when it becomes effective, 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 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 the IMO’s Marine Environment Protection Committee (or MEPC) is expected to adopt the environmental provisions of the Polar Code and associated amendments to MARPOL at its next session in 2015. Once adopted, the Polar Code is to enter into force on January 1, 2017.

 

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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 regulations requiring the use of low sulfur fuel. Beginning January 1, 2015, vessels have been required to burn fuel with sulfur content not exceeding 0.1% while within EU member states’ territorial seas, exclusive economic zones and pollution control zones that are included in SOX Emission Control Areas. Other jurisdictions have also adopted regulations requiring the use of low sulfur fuel. The California Air Resources Board (or CARB) requires vessels to burn fuel with 0.1% sulfur content or less within 24 nautical miles of California as of January 1, 2014. IMO regulations require that, as of January 1, 2015, all vessels operating within Emissions Control Areas (or ECAs) worldwide 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 July 1, 2010, the applicable sulfur content limits in the North Sea, the Baltic Sea and the English Channel sulfur control areas have been 1.00%. 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 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:

 

   

natural resources damages and the related assessment costs;

 

   

real and personal property damages;

 

   

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;

 

   

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

 

   

loss of subsistence use of natural resources.

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

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

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

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

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

 

   

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

 

   

describe crew training and drills; and

 

   

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

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

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

The United States 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.

 

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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 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. 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 is currently considering a proposal for a regulation establishing a system of monitoring, reporting and verification of greenhouse gas shipping emissions (or MRV system). The proposed MRV system may be the precursor to a market-based mechanism to be adopted in the future. 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, 2014.

Item 4A. Unresolved Staff Comments

Not applicable.

 

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Item 5. Operating and Financial Review and Prospects

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

General

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 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.

SIGNIFICANT DEVELOPMENTS IN 2014 AND EARLY 2015

RasGas II LNG Carriers

On December 22, 2014, the Teekay Nakilat Joint Venture, in which we have a 70% ownership interest, voluntarily terminated its 30-year capital lease arrangements with the lessor relating to the RasGas II LNG Carriers under capital lease. As part of this transaction, the Teekay Nakilat Joint Venture acquired the RasGas II LNG Carriers from the lessor and the Teekay Nakilat Joint Venture refinanced its original debt facility of $278 million with a new $450 million debt facility and terminated its interest rate swaps relating to its original debt, capital lease obligations and restricted cash deposits. Please read “Item 18 – Financial Statements: Note 4 – Leases and Restricted Cash” and “Note 13 – Commitments and Contingencies.”

LNG Newbuildings

On December 4, 2014, we secured time-charter contracts, ranging in duration from six to eight years plus extension options, with Royal Dutch Shell plc (or Shell) for five LNG carrier newbuildings, which charter contracts will commence upon the vessel deliveries starting from the second half of 2017 into 2018. In connection with securing these time-charter contracts with Shell, we exercised our option to order three LNG carrier newbuildings from DSME. In February 2015, we ordered another LNG newbuilding carrier and have four additional newbuilding options declarable by the end of April 2015. In total, we have nine LNG newbuildings ordered, with four additional newbuilding options. We have entered into time-charter contracts for all but two of the ordered newbuildings.

Acquisition and Bareboat Charter-Back of an LPG Carrier

In November 2014, we acquired a 2003-built 10,200 cubic meter (or cbm) LPG carrier, the Norgas Napa, from I.M. Skaugen SE (or Skaugen) for $27 million. We 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 actual earnings of the vessel, which is trading in Skaugen’s Norgas pool.

Equity Offerings

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

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

Yamal LNG Project

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

BG Joint Venture

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

 

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Sale of Vessels

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

Exmar LPG Fleet Renewal

We hold a 50% interest in Exmar LPG BVBA, a joint venture with Belgium-based Exmar NV, to own and charter-in LPG carriers with a primary focus on the mid-size gas carrier segment. Four of Exmar LPG BVBA’s 12 LPG newbuilding carriers, the Waasmunster, Warinsart, Waregem, and Warisoulx delivered between April 2014 and January 2015. As a result of these newbuilding deliveries, and as part of its fleet renewal strategy, Exmar LPG BVBA sold certain of its LPG carriers. The Temse was sold and delivered to its new owner in March 2014, Flanders Tenacity and Eeklo were sold and delivered to their new owners in June 2014 and Flanders Harmony was sold and delivered to its new owner in August 2014. Exmar LPG BVBA recognized a net gain in 2014 as a result of the sale of these vessels, in which our proportionate share was $16.9 million. In addition, the in-chartered contract for Berlian Ekuator expired in January 2014 and the vessel was delivered back to its owner.

Charter Contracts for MALT LNG Carriers

In January 2015, one of the MALT LNG Carriers, 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 59 days during the first quarter of 2015. In addition, the charterer claimed that the off-hire time for this vessel during this period gave them the right to terminate the charter contract effective March 28, 2015, which they elected to do. The Teekay LNG-Marubeni Joint Venture has disputed the charterer’s claims of the aggregate off-hire time for this vessel as a result of this incident 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 resolving this dispute. However, if the charterer’s claim to terminate the charter contract is upheld, our 52% portion of the potential loss revenue from March 28, 2015 to September 30, 2016, would be $27.3 million, less any amounts received for re-chartering this vessel during this time. The impact in future periods from this incident will depend upon our ability to re-charter the vessel and the resolution of this dispute. The charter contract of another MALT LNG Carrier expired in March 2015 as originally scheduled and the Teekay LNG-Marubeni Joint Venture is seeking to secure employment for this vessel as well.

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 (expense). For more information, please read “Item 18 – Financial Statements: Note 3 – 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.

 

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

 

   

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

 

   

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

 

   

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

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

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

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

RESULTS OF OPERATIONS

Items You Should Consider When Evaluating Our Results of Operations

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

 

   

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

 

   

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

 

   

Vessel operating and other costs are facing industry-wide cost pressures. The shipping industry continues to experience a global manpower shortage of qualified seafarers in certain sectors due to growth in the world fleet and competition for qualified personnel. In recent years, upward pressure on manning costs has temporarily stabilized and resulted in lower wage increases than has been seen in the past. However, this situation will likely not continue in the long term. Going forward, there may be significant increases in crew compensation as vessel and officer supply dynamics continue to change. In addition, factors such as pressure on commodity and raw material prices, as well as changes in regulatory requirements could also contribute to operating expenditure increases. We continue to take action aimed at improving operational efficiencies, and to temper the effect of inflationary and other price escalations; however increases to operational costs are still likely to occur in the future.

 

   

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

 

   

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

 

   

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

 

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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.

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 newbuilding LNG carriers under construction and the following vessels accounted for under the equity method: (i) six LNG carriers relating to our joint venture with Marubeni Corporation (or the MALT LNG Carriers), (ii) four LNG carriers relating to the Angola LNG Project (or the Angola LNG Carriers), (iii) four LNG carriers relating to our joint venture with QGTC Nakilat (1643-6) Holdings Corporation (or the RasGas 3 LNG Carriers), (iv) four newbuilding LNG carriers relating to the BG Joint Venture, (v) six newbuilding LNG carriers relating to the Yamal LNG Joint Venture, (vi) two LNG carriers (or the Exmar LNG Carriers) and (vii) 15 LPG carriers and nine newbuilding LPG carriers (or the Exmar LPG Carriers) relating to our joint ventures with Exmar.

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,        
calendar-ship-days and percentages)    2014     2013     % Change  

Voyage revenues

     307,426       285,694       7.6  

Voyage expenses

     (1,768     (407     334.4  
  

 

 

   

 

 

   

 

 

 

Net voyage revenues

  305,658     285,287     7.1  

Vessel operating expenses

  (59,087   (55,459   6.5  

Depreciation and amortization

  (71,711   (71,485   0.3  

General and administrative (1)

  (17,992   (13,913   29.3  
  

 

 

   

 

 

   

 

 

 

Income from vessel operations

  156,868     144,430     8.6  
  

 

 

   

 

 

   

 

 

 

Operating Data:

Revenue Days (A)

  6,534     5,919     10.4  

Calendar-Ship-Days (B)

  6,619     5,981     10.7  

Utilization (A)/(B)

  98.7   99.0

 

(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, 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 newbuilding carriers in the BG Joint Venture (however, we had a corresponding increase in operating expenses); and

 

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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 dry docking 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 newbuilding carriers in the BG Joint Venture.

Depreciation and Amortization. Depreciation and amortization remained consistent compared to last year.

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,        
calendar-ship-days and percentages)    2014     2013     % Change  

Voyage revenues

     95,502       113,582       (15.9

Voyage expenses

     (1,553     (2,450     (36.6
  

 

 

   

 

 

   

 

 

 

Net voyage revenues

  93,949     111,132     (15.5

Vessel operating expenses

  (36,721   (44,490   (17.5

Depreciation and amortization

  (22,416   (26,399   (15.1

General and administrative (1)

  (5,868   (6,531   (10.2

Restructuring charges

  (1,989   (1,786   11.4  
  

 

 

   

 

 

   

 

 

 

Income from vessel operations

  26,955     31,926     (15.6
  

 

 

   

 

 

   

 

 

 

Operating Data:

Revenue Days (A)

  3,121     3,921     (20.4

Calendar-Ship-Days (B)

  3,202     3,994     (19.8

Utilization (A)/(B)

  97.5   98.2

 

(1)

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

 

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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:

 

     Angola     Exmar      Exmar      MALT     RasGas 3           Total  
     LNG     LNG      LPG      LNG     LNG           Equity  
     Carriers     Carriers      Carriers      Carriers     Carriers     Other     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.

 

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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

Interest Income. Interest income remained comparable to 2013.

Realized and Unrealized Loss on Derivative Instruments. Net realized and unrealized losses on derivative instruments decreased 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  
     Realized     Unrealized           Realized     Unrealized         
     gains     gains           gains     gains         
(in thousands of U.S. Dollars)    (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 2014, we recognized unrealized losses on our interest rate swaps associated with our U.S. Dollar-denominated restricted cash deposits, which were terminated in December 2014. This resulted from transfers of $172.5 million of previously recognized unrealized gains to realized gains related to actual cash settlements of our interest rate swaps, partially offset by $90.0 million of unrealized gains relating to decreases in long-term forward LIBOR benchmark interest rates relative to the beginning of 2014.

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

During 2013, 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, plus 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.

 

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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.

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

For 2013, foreign currency exchange 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 losses also include the revaluation of our Euro-denominated restricted cash, debt and capital leases resulting in an unrealized loss of $12.5 million.

Other Income (Expense). Other income decreased by $0.5 million for 2014 compared to 2013 primarily due to one 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.

Year Ended December 31, 2013 versus Year Ended December 31, 2012

Liquefied Gas Segment

As at December 31, 2013, our liquefied gas segment fleet, including newbuildings, included 34 LNG carriers and 33 LPG/Multigas carriers, in which our interests ranged from 33% to 100%. However, the table below only includes 13 LNG carriers and five LPG/Multigas carriers. The table excludes five newbuilding LNG carriers under construction and the following vessels accounted for under the equity method: (i) six MALT LNG Carriers, (ii) four Angola LNG Carriers, (iii) four RasGas 3 LNG Carriers, (iv) two Exmar LNG Carriers and (v) 28 Exmar LPG Carriers.

The following table compares our liquefied gas segment‘s operating results for 2013 and 2012, and compares its net voyage revenues (which is a non-GAAP financial measure) for 2013 and 2012, to voyage revenues, the most directly comparable GAAP financial measure. The following table also provides a summary of the changes in calendar-ship-days and revenue days for our liquefied gas segment:

 

(in thousands of U.S. Dollars, except revenue days,    Year Ended December 31,        
calendar-ship-days and percentages)    2013     2012     % Change  
      

Voyage revenues

     285,694       278,511       2.6  

Voyage expenses

     (407     (66     516.7  
  

 

 

   

 

 

   

 

 

 

Net voyage revenues

  285,287     278,445     2.5  

Vessel operating expenses

  (55,459   (50,124   10.6  

Depreciation and amortization

  (71,485   (69,064   3.5  

General and administrative (1)

  (13,913   (13,224   5.2  
  

 

 

   

 

 

   

 

 

 

Income from vessel operations

  144,430     146,033     (1.1
  

 

 

   

 

 

   

 

 

 

Operating Data:

Revenue Days (A)

  5,919     5,833     1.5  

Calendar-Ship-Days (B)

  5,981     5,856     2.1  

Utilization (A)/(B)

  99.0   99.6

 

(1)

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

 

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Our liquefied gas segment‘s total calendar-ship-days increased by 2% to 5,981 days in 2013 from 5,856 days in 2012, as a result of the acquisition and delivery of two LNG carriers from Awilco (or the Awilco LNG Carriers), Wilforce and Wilpride, on September 16, 2013 and November 28, 2013, respectively.

During 2013, the Arctic Spirit and Catalunya Spirit were off-hire for 41 and 21 days, respectively, for scheduled dry dockings, compared to the Hispania Spirit being off-hire for approximately 21 days for a scheduled dry docking in 2012.

Net Voyage Revenues. Net voyage revenues increased during 2013 compared to 2012, primarily as a result of:

 

   

an increase of $5.0 million as a result of the acquisition and delivery of the Awilco LNG Carriers on September 16, 2013 and November 28, 2013;

 

   

an increase of $3.2 million due to the effect on our Euro-denominated revenues from the strengthening of the Euro against the U.S. Dollar compared to the prior year;

 

   

an increase of $2.0 million during 2013 due to operating expense and dry-docking recovery adjustments under our charter provisions for the Tangguh Hiri and Tangguh Sago;

 

   

an increase of $1.4 million due to the Hispania Spirit being off-hire for 21 days in 2012 for a scheduled dry docking; and

 

   

an increase of $0.9 million due to a reduction of revenue in the prior year to compensate the charterer of the Galicia Spirit for delaying its scheduled dry docking in 2012;

partially offset by:

 

   

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

 

   

a decrease of $2.0 million due to the Catalunya Spirit being off-hire for 21 days in 2013 for a scheduled dry docking; and

 

   

a decrease of $0.8 million due to one less calendar day during 2013 compared to the prior year.

Vessel Operating Expenses. Vessel operating expenses increased during 2013 compared to 2012, primarily as a result of:

 

   

an increase of $2.1 million during 2013 as a result of higher manning costs due to wage increases in certain of our LNG carriers;

 

   

an increase of $1.8 million due to main engine overhauls and spares and consumables purchased for the Tangguh Hiri and Tangguh Sago for the dry docking of these vessels in 2013 (however, we had a corresponding increase in our revenues relating to operating expense adjustments in our charter provisions); and

 

   

an increase of $1.0 million primarily due to the effect on our Euro-denominated crew manning expenses from the strengthening of the Euro against the U.S. Dollar during 2013 compared to 2012 (a portion of our vessel operating expenses are denominated in Euros, which is primarily due to the nationality of our crew).

Depreciation and Amortization. Depreciation and amortization increased during 2013 compared to 2012, primarily as a result of amortization of dry-dock expenditures incurred throughout 2012 and 2013.

Conventional Tanker Segment

As at December 31, 2013, our fleet included 9 Suezmax-class double-hulled conventional crude oil tankers and one Handymax Product tanker, six of which we own and four 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 for a duration of 24 months, commencing October 1, 2012. The full impact of the change in hire rates is not fully reflected in the table below as the change in the lease payments are being recognized on a straight-line basis over the term of the lease.

In addition, CEPSA, the charterer (who was also the owner) of our conventional vessels under capital lease reached an agreement for the third-party sale of the Tenerife Spirit, Algeciras Spirit and the Huelva Spirit in November 2013, January 2014 and August 2014, respectively. Upon sale of the vessels, we were not required to pay the balance of the capital lease obligations as the vessels under capital leases were returned to the owner and the capital lease obligations were concurrently extinguished. We did not record a gain or loss on the sale of these vessels and we do not expect to record a gain or loss on future sales of vessels under capital lease. When the vessels were sold to a third party, we were subject to seafarer severance related costs.

 

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The following table compares our conventional tanker segment‘s operating results for the years ended December 31, 2013 and 2012, and compares its net voyage revenues (which is a non-GAAP financial measure) for the years ended December 31, 2013 and 2012 to voyage revenues, the most directly comparable GAAP financial measure. The following table also provides a summary of the changes in calendar-ship-days and revenue days for our conventional tanker segment:

 

(in thousands of U.S. Dollars, except revenue days,    Year Ended December 31,        
calendar-ship-days and percentages)    2013     2012     % Change  

Voyage revenues

     113,582       114,389       (0.7

Voyage expenses

     (2,450     (1,706     43.6  
  

 

 

   

 

 

   

 

 

 

Net voyage revenues

  111,132     112,683     (1.4

Vessel operating expenses

  (44,490   (44,412   0.2  

Depreciation and amortization

  (26,399   (31,410   (16.0

General and administrative (1)

  (6,531   (5,736   13.9  

Restructuring charge

  (1,786   —       100.0  

Write down of vessels

  —       (29,367   (100.0
  

 

 

   

 

 

   

 

 

 

Income from vessel operations

  31,926     1,758     1,716.0  
  

 

 

   

 

 

   

 

 

 

Operating Data:

Revenue Days (A)

  3,921     4,026     (2.6

Calendar-Ship-Days (B)

  3,994     4,026     (0.8

Utilization (A)/(B)

  98.2   100.0

 

(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 2013 compared to 2012, primarily as a result of:

 

   

a decrease of $2.5 million due to the African Spirit, Asian Spirit and European Spirit being off-hire for 26, 22 and 25 days, respectively, as a result of scheduled dry dockings during 2013;

 

   

a decrease of $0.9 million relating to a full year of the reduced charter rates on the Bermuda Spirit and Hamilton Spirit in 2013 compared to one quarter in the prior year as the renegotiated charter rates commenced on October 1, 2012;

 

   

a decrease of $0.6 million as the conventional spot market rates decreased compared to the prior year which impacts the revenue earned by the Toledo Spirit relating to the time-charter agreement between us and CEPSA (however, we had a corresponding increase in our realized gain on a related derivative with Teekay Corporation; therefore this decrease and future decreases or increases related to this agreement did not and will not affect our cash flow or net income); and

 

   

a decrease of $0.6 million due to the sale of the Tenerife Spirit on December 10, 2013;

partially offset by:

 

   

an increase of $2.9 million during 2013 due to adjustments to the daily charter rates based on inflation and an increase in interest rates in accordance with the time-charter contracts for the Suezmax tankers subject to capital leases (however, under the terms of these capital leases, we had corresponding increases in our lease payments, which are reflected as increases to interest expense; therefore, these and future similar interest rate adjustments do not affect our cash flow or net income).

Vessel Operating Expenses. Vessel operating expenses remained consistent between 2013 and 2012.

Depreciation and Amortization. Depreciation and amortization decreased during 2013 compared to 2012, as a result of:

 

   

a decrease of $7.2 million due to the effect of vessel write-downs in the fourth quarter of 2012 relating to the Algeciras Spirit, Huelva Spirit and Tenerife Spirit;

partially offset by:

 

   

an increase of $2.8 million due to the accelerated amortization, commencing in the fourth quarter of 2012, of the intangible assets relating to the charter contracts of the Algeciras Spirit, Huelva Spirit and Tenerife Spirit, as we expect the life of these intangible assets to be shorter than originally assumed in prior periods.

Restructuring Charge. The restructuring charge of $1.8 million for the year ended December 31, 2013 was related to the seafarer severance payments upon CEPSA selling our vessels under capital lease, the Tenerife Spirit and Algeciras Spirit.

Other Operating Results

General and Administrative Expenses. General and administrative expenses increased 7.8% to $20.4 million for 2013, from $19.0 million for 2012, primarily due to timing of accounting recognition of restricted unit awards as a result of certain senior personnel meeting retirement eligibility criteria. Please read “Item 18 – Financial Statements: Note: 16 – Unit-Based compensation.”

 

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Equity Income. Equity income increased to $123.3 million for 2013, from $78.9 million for 2012, 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
     Total Equity
Income
 

Year ended December 31, 2013

     29,178        10,650        17,415        43,428        22,611        123,282  

Year ended December 31, 2012

     13,015        7,994        —          39,349        18,508        78,866  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Difference

  16,163     2,656     17,415     4,079     4,103     44,416  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Equity income increased by $44.4 million from the prior year, primarily as a result of:

 

   

an increase of $17.4 million due to the acquisition of a 50% ownership interest in Exmar LPG BVBA in February 2013;

 

   

an increase of $16.2 in our 33% investment in the four Angola LNG Carriers, primarily due to the change in unrealized gains on derivative instruments as a result of long-term LIBOR benchmark interest rates increasing, as compared to 2012;

 

   

an increase of $7.6 million from a full year of operations from our 52% ownership interest in the six LNG carriers from A.P. Moller Maersk A/S (the MALT LNG Carriers) which was acquired in February 2012;

 

   

an increase of $4.1 million in our 40% investment in the RasGas 3 LNG Carriers, primarily due to the change in unrealized gains on derivative instruments as a result of long-term LIBOR benchmark interest rates increasing, as compared to 2012; and

 

   

an increase of $2.7 million due to higher net income from our 50% investment in the Exmar LNG Carriers primarily resulting from a provision from a customer‘s claim relating to the two LNG carriers in 2012 and from the off-hire of Excalibur for scheduled dry docking during 2012;

partially offset by:

 

   

a decrease of $2.4 million primarily due to the dry docking of the Methane Spirit during March 2013 resulting in 28 off-hire days and higher interest margins upon completion of debt refinancing within the MALT LNG Carriers in June and July 2013; and

 

   

a decrease of $1.0 million relating to the ineffective portion of the hedge accounted interest rate swap within the MALT LNG Carriers that was entered into during 2013.

Interest Expense. Interest expense increased to $55.7 million for 2013, from $54.2 million for 2012. Interest expense primarily reflects interest incurred on our capital lease obligations and long-term debt. This increase was primarily the result of:

 

   

an increase of $5.8 million as a result of the NOK bond issuances in May 2012 and September 2013;

 

   

an increase of $1.8 million due to an interest rate adjustment on our Suezmax tanker capital lease obligations (however, as described above, under the terms of the time-charter contracts for these vessels, we have a corresponding increase in charter receipts, which are reflected as an increase to voyage revenues); and

 

   

an increase of $0.5 million relating to a new debt facility used to fund the delivery of the first Awilco LNG Carrier in late-2013;

partially offset by:

 

   

a decrease of $6.4 million due to principal debt repayments made during 2013 and 2012 on our USD and EURO denominated debt and decreases in LIBOR compared to the prior year.

Interest Income. Interest income decreased to $3.0 million in 2013, from $3.5 million for 2012. These changes were primarily the result of:

 

   

a decrease of $1.2 million due to lower LIBOR relating to our restricted cash deposits;

partially offset by:

 

   

an increase of $0.6 million due to interest earned on our $81.7 million of advances due from Exmar LPG BVBA, see Item 18 - Financial Statements: Note 6(b) – Advances to Joint Venture Partner and Equity Accounted Joint Ventures.

 

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Realized and Unrealized Loss on Derivative Instruments. Net realized and unrealized losses on derivative instruments decreased to $14.0 million for 2013, from $29.6 million for 2012 as set forth in the table below.

 

     Year Ended     Year Ended  
     December 31, 2013     December 31, 2012  
    

Realized

gains

   

Unrealized

gains

          

Realized

gains

   

Unrealized

gains

        
(in thousands of U.S. Dollars)    (losses)     (losses)      Total     (losses)     (losses)      Total  

Interest rate swap agreements

     (38,089     18,868        (19,221     (37,427     5,200        (32,227

Toledo Spirit time-charter derivative

     1,521       3,700        5,221       907       1,700        2,607  
  

 

 

   

 

 

    

 

 

   

 

 

   

 

 

    

 

 

 
  (36,568   22,568     (14,000   (36,520   6,900     (29,620
  

 

 

   

 

 

    

 

 

   

 

 

   

 

 

    

 

 

 

As at December 31, 2013 and 2012, we had interest rate swap agreements with an aggregate average net outstanding notional amount of approximately $870.4 million and $902.9 million, respectively, with average fixed rates of 4.6% for both periods. The realized losses relating to our interest rate swaps increased by $0.7 million between 2013 and 2012 mainly as a result of decreases in the EURIBOR and LIBOR compared to the prior year.

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, plus 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 LIBOR benchmark interest decreased during 2012, which resulted in us recognizing an unrealized gain of $5.9 million from our interest rate swaps associated with our restricted cash deposits and an unrealized loss of $34.4 million on our interest rate swaps associated with our U.S. Dollar-denominated long-term debt and capital leases. The unrealized loss of $34.4 million was offset by a transfer of $49.2 million of previously recognized unrealized losses to realized losses related to actual cash settlements that led to a net gain of $14.8 million from our U.S. Dollar-denominated long-term debt and capital leases.

Long-term forward EURIBOR benchmark interest increased during 2013 and decreased during 2012, which resulted in an unrealized gain of $9.7 million and an unrealized loss of $15.5 million, respectively, from our interest rate swaps associated with our Euro-denominated long-term debt.

The projected average forward tanker rates in 2013 decreased compared to 2012, which resulted in a $3.7 million unrealized gain 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 (see “Item 18—Financial Statements: Note 12—Derivative Instruments”).

Foreign Currency Exchange Losses. Foreign currency exchange losses were $15.8 million and $8.2 million for 2013 and 2012, respectively. These foreign currency exchange 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 and restricted cash for financial reporting purposes and the realized and unrealized losses and gains 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 2013, foreign currency exchange 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 losses also include the revaluation of our Euro-denominated restricted cash, debt and capital leases resulting in an unrealized loss of $12.5 million.

For 2012, foreign currency exchange losses include realized gains of $0.3 million and unrealized losses of $2.7 million on our cross-currency swap and unrealized losses of $0.8 million on the revaluation of our NOK-denominated debt. For 2012, foreign currency exchange losses also include the revaluation of our Euro-denominated restricted cash, debt and capital leases resulting in an unrealized loss of $4.7 million.

Other Income (Expense). Other income remained consistent between 2013 and 2012.

Income Tax Expense. Income tax expense increased to $5.2 million for 2013, from $0.6 million for 2012, primarily as a result of:

 

   

an increase of $3.9 million as a result of recognizing a full valuation allowance on the deferred tax assets relating to our Spanish subsidiaries in 2013, as they no longer meet the recognition criteria for deferred tax assets; and

 

   

an increase of $0.9 million as a result of a reduction in the valuation allowance in 2012 relating to the RasGas II LNG Carriers‘ deferred tax assets.

Other Comprehensive Income (OCI). OCI of $0.1 million in 2013 relates to an unrealized gain 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.

 

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Liquidity and Cash Needs

Our business model is to employ our vessels on fixed-rate contracts with major oil companies, with original terms typically between 10 to 25 years. The operating cash flow our vessels generate each quarter, excluding a reserve for maintenance capital expenditures and debt repayments, are generally paid out to our unitholders within approximately 45 days after the end of each quarter. Our primary short-term liquidity needs are to pay these quarterly distributions on our outstanding units, payment of operating expenses, dry-docking expenditures, debt service costs and to fund general working capital requirements. We anticipate that our primary sources of funds for our short-term liquidity needs will be cash flows from operations.

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

Our revolving credit facilities and term loans are described in “Item 18 – Financial Statements: Note 9 – Long-Term Debt.” They contain covenants and other restrictions typical of debt financing secured by vessels, 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 of our revolving credit facilities and term loans require us to maintain financial covenants. If we do not meet these financial covenants, the lender may accelerate the repayment of the revolving credit facilities and term loans, thus having a significant impact our short-term liquidity requirements. As at December 31, 2014, we and our affiliates were in compliance with all covenants relating to our credit facilities and term loans.

As at December 31, 2014, our cash and cash equivalents were $159.6 million, compared to $139.5 million at December 31, 2013. Our total liquidity, which consists of cash, cash equivalents and undrawn medium-term credit facilities, was $295.2 million as at December 31, 2014, compared to $332.2 million as at December 31, 2013. The decrease in total consolidated liquidity is primarily due to installment payments in 2014 relating to our eight newbuildings, contributions in the BG Joint Venture and the Yamal LNG Joint Venture to fund the newbuild installments in these joint ventures, and the acquisition of the Norgas Napa; partially offset by a new term loan entered into in March 2014 relating to the second Awilco LNG Carrier, the Wilpride, net proceeds from our 3.1 million common unit equity offering in July 2014, net proceeds from our 1.1 million common units issued under our continuous offering program in the fourth quarter of 2014, and the net proceeds upon refinancing of the Teekay Nakilat Joint Venture’s debt facility in the fourth quarter of 2014.

As of December 31, 2014, we had a working capital deficit of $117.9 million. The working capital deficit includes a $57.7 million outstanding balance on one of our debt facilities that matures in the second quarter of 2015. We expect to refinance this debt facility before it comes due.

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

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:

 

     Year Ended December 31,  
(in thousands of U.S. Dollars)    2014      2013      2012  

Net cash flow from operating activities

     191,097        183,532        192,013  

Net cash flow from financing activities

     100,700        334,684        30,374  

Net cash flow used for investing activities

     (271,639      (492,312      (202,437

Operating Cash Flows. 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 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 decreased to $183.5 million in 2013 from $192.0 million in 2012, primarily due to a greater number of off-hire days relating to scheduled dry dockings during 2013 compared to 2012, a corresponding increase in dry-docking expenditures and less dividends received from our equity accounted joint ventures during 2013. 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 from equity accounted investments, fluctuations in working capital balances and spot market hire rates (to the extent we have vessels operating in the spot tanker market or our hire rates are partially affected by spot market rates). The number of vessel dry dockings tends to vary each period depending on the vessel’s maintenance schedule.

 

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Our equity accounted joint ventures are generally required to distribute all available cash to its shareholders. However, the timing and amount of dividends from each of our equity accounted joint ventures may not necessarily coincide with the net income or operating cash flow generated from each respective equity accounted joint venture. The timing and amount of dividends distributed by our equity accounted joint ventures are affected by the timing and amounts of debt repayments in the joint ventures, capital requirements, 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. Our investments in vessels and equipment are financed primarily with term loans, capital lease arrangements and proceeds from issuance of securities. Proceeds from long-term debt were $944.1 million, $719.3 million and $500.3 million, respectively, for 2014, 2013 and 2012. The proceeds from long-term debt for 2014 includes a new $130.0 million term loan entered into in March 2014 relating to the second Awilco LNG Carrier acquired in 2013 and the Teekay Nakilat Joint Venture refinancing its term loan that was due in 2019 of $278.2 million, as of September 30, 2014, with a new US Dollar-denominated term loan of $450.0 million due in 2026. From time to time, we refinance our loans and revolving credit facilities. During 2014, we primarily used the proceeds from the issuance of securities and long-term debt to acquire and fund our proportionate interest of newbuilding installments in the BG Joint Venture and the Yamal Joint Venture, fund the acquisition of the Norgas Napa in November 2014, to fund construction costs for our eight LNG newbuildings, to fund the acquisition of three LNG carriers under capital lease (of which a portion of the repayment was from the release of restricted cash deposits), and to prepay and repay outstanding debt under our revolving credit facilities. The decrease in restricted cash was used to acquire the RasGas II LNG Carriers under capital lease in the Teekay Nakilat Joint Venture. During 2013, we primarily used the proceeds from the issuance of securities and long-term debt to fund the acquisition of our 50% interest in the Exmar LPG Carriers, to fund the acquisition of the Awilco LNG Carriers, to fund construction costs for our five LNG newbuilding carriers, to provide an advance to Exmar LPG BVBA for the purpose of funding newbuildings, to prepay and repay outstanding debt under our revolving credit facilities, and for general partnership purposes. During 2012, we primarily used the proceeds from long-term debt to fund the acquisition of our 52% interest in the six MALT LNG Carriers, to fund the first installment payment for two LNG newbuildings, to fund the acquisition of our 33% interest in the fourth Angola LNG Carrier, to prepay and repay outstanding debt under our revolving credit facilities and for general corporate purposes.

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

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 the cash distribution as a result of the equity offerings during 2014 and 2013; and

 

   

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

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

 

   

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

 

   

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

After December 31, 2014, a cash distribution totaling $63.6 million was declared with respect to the fourth quarter of 2014, which was paid in February 2015. This cash distribution reflected an increase in our quarterly distribution to $0.7000 per unit from $0.6918 per unit.

Investing Cash Flows Net cash flow used in investing activities decreased to $271.6 million in 2014 from $492.3 million in 2013. 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 equipped with the MEGI twin engines, $23.1 million relating to the early termination fee on the termination of the leasing of the RasGas II LNG Carriers (which was capitalized as part of the vessels’ costs) and $21.6 million, which is net of $5.4 million owing to Skaugen, to fund our acquisition of 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, $135.8 million to fund our 50% interest in the Exmar LPG Carriers and $58.6 million incurred for our three additional LNG newbuilding carriers ordered in July and November 2013. During 2012, we used cash of $151.0 million (including working capital contribution and acquisition costs) to fund the acquisition of our 52% interest in the six MALT LNG Carriers, $38.6 million to fund the first installment payment for two LNG newbuildings and $19.1 million for our acquisition of a 33% interest in the fourth and last Angola LNG Carrier.

Credit Facilities

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

 

   

incurring or guaranteeing indebtedness;

 

   

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

 

   

making dividends or distributions if we are in default;

 

   

making capital expenditures in excess of specified levels;

 

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making certain negative pledges and granting certain liens;

 

   

selling, transferring, assigning or conveying assets;

 

   

making certain loans and investments; and

 

   

entering into a new line of business.

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

 

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Contractual Obligations and Contingencies

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

 

            2016      2018         
            and      and      Beyond  
     Total      2015      2017      2019      2019  
     (in millions of U.S. Dollars)  

U.S. Dollar-Denominated Obligations:

              

Long-term debt (1)

     1,424.4        141.6        175.8        570.2        536.8  

Commitments under capital leases (2)

     73.7        7.8        38.6        27.3        —    

Commitments under operating leases (3)

     343.7        24.1        48.2        48.2        223.2  

Newbuilding installments/shipbuilding supervision (4)

     2,462.7        188.9        1,092.9        979.8        201.1  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total U.S. Dollar-denominated obligations

  4,304.5     362.4     1,355.5     1,625.5     961.1  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Euro-Denominated Obligations: (5)

  

Long-term debt (6)

  285.0     15.6     34.6     153.7     81.1  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Euro-denominated obligations

  285.0     15.6     34.6     153.7     81.1  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Norwegian Kroner-Denominated Obligations: (5)

  

Long-term debt (7)

  214.7     —       93.9     120.8     —    
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Norwegian Kroner-Denominated obligations

  214.7     —       93.9     120.8     —    
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Totals

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

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(1)

Excludes expected interest payments of $23.3 million (2015), $42.2 million (2016 and 2017), $24.6 million (2018 and 2019) and $38.6 million (beyond 2019). Expected interest payments are based on the existing interest rates (fixed-rate loans) and LIBOR at December 31, 2014, 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 expire, 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 1 – Financial Statements: Note 4 – Leases and Restricted Cash.”

(3)

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

(4)

Between December 2012 and December 2014, we entered into agreements for the construction of eight LNG newbuildings. The remaining cost for these newbuildings totaled $1,445.4 million as of December 31, 2014, including estimated interest and construction supervision fees.

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 $89.4 million. However, as part of this agreement with BG, we expect to recover approximately $20.3 million of the shipbuilding supervision and crew training costs from BG between 2015 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, 2014, our 50% share of the remaining cost for these six newbuildings totaled $928.0 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.

The table above excludes nine newbuilding LPG carriers scheduled for delivery between early-2015 and 2018 in the joint venture between Exmar and us. As at December 31, 2014, our 50% share of the remaining cost for these nine newbuildings totaled $190.2 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, 2014.

(6)

Excludes expected interest payments of $4.3 million (2015), $7.9 million (2016 and 2017), $2.7 million (2018 and 2019) and $1.4 million (beyond 2019). Expected interest payments are based on EURIBOR at December 31, 2014, plus margins that ranged up to 2.25%, as well as the prevailing U.S. Dollar/Euro exchange rate as of December 31, 2014. 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.

 

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(7)

Excludes expected interest payments of $13.7 million (2015), $23.0 million (2016 and 2017) and $4.8 million (2018 and 2019). Expected interest payments are based on NIBOR at December 31, 2014, plus margins that range up to 5.25%, as well as the prevailing U.S. Dollar/NOK exchange rate as of December 31, 2014. 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 5 – Equity Method Investments.

Critical Accounting Estimates

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

Vessel Lives and Impairment

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

We review vessels and equipment for impairment whenever events or circumstances indicate the carrying value of an asset, including the carrying value of the charter contract, if any, under which the vessel is employed, may not be recoverable. This occurs when the asset’s carrying value is greater than the future undiscounted cash flows the asset is expected to generate over its remaining useful life. For a vessel under charter, the discounted cash flows from that vessel may exceed its market value, as market values may assume the vessel is not employed on an existing charter. If the estimated future undiscounted cash flows of an asset exceeds 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 10 to 25 years in length. Consequently, while the market value of a vessel may decline below its carrying value, the carrying value of a vessel may still be recoverable based on the future undiscounted cash flows the vessel is expected to obtain from servicing its existing contract and future contracts.

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

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

 

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

Reportable Segment

        

Conventional Tanker Segment(2)

     4        170,392        184,432  

 

(1)

Market values are determined using reference to second-hand market comparable values as at December 31, 2014. 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.

 

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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 2014, 2013 and 2012 were $14.8 million, $13.4 million and $13.1 million, respectively. As at December 31, 2014, 2013 and 2012, our capitalized dry-dock expenditures were $13.5 million, $27.2 million and $7.5 million, respectively. A one-year reduction in the estimated useful lives of capitalized dry-dock expenditures would result in an increase in our current annual amortization by approximately $3.0 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 annual basis or more frequently if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit to below its carrying value. When goodwill is reviewed for impairment, we may elect to assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount, including goodwill. Alternatively, we may bypass this step and use a fair value approach to identify potential goodwill impairment and, when necessary, measure the amount of impairment. The Partnership uses a discounted cash flow model to determine the fair value of reporting units, unless there is a readily determinable fair market value. Intangible assets are assessed for impairment when and if impairment indicators exist. An impairment loss is recognized if the carrying amount of an intangible asset is not recoverable and its carrying amount exceeds its fair value.

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

At December 31, 2014, 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.

 

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

Valuation of Derivative Instruments

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

Judgments and Uncertainties. A substantial majority of the fair value of our derivative instruments and the change in fair value of our derivative instruments from period to period result from our use of interest rate swap agreements. The fair value of our interest rate swap agreements 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 12 – 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 (or decrease our loss) in the period such determination was made. Likewise, if we determined that we were not able to realize all or a part of our deferred tax asset in the future, an adjustment to the deferred tax assets would typically decrease our net income (or increase our loss) in the period such determination was made. As at December 31, 2014, we had a valuation allowance of $58.4 million (2013  – $73.1 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.

 

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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 4th Floor, Belvedere Building, 69 Pitts Bay Road, Hamilton, HM 08, Bermuda. The business address of our key employee of Teekay Shipping Spain SL. is Musgo Street 5 – 28023, Madrid, Spain. Ages of the individuals are as of December 31, 2014.

 

Name

   Age   

Position

C. Sean Day

  

65

  

Chairman

Peter Evensen

  

56

  

Chief Executive Officer, Chief Financial Officer and Director

Beverlee F. Park

  

52

  

Director since March 11, 2014(1)(3)(4)

Kenneth Hvid

  

46

  

Director

Ida Jane Hinkley

  

64

  

Director (1)(2)(3)

Joseph E. McKechnie

  

56

  

Director(2)

George Watson

  

67

  

Director (1)(2)(3)

Andres Luna

  

58

  

Managing Director, Teekay Shipping Spain SL

 

(1)

Member of Audit Committee.

(2)

Member of Conflicts Committee.

(3)

Member of Corporate Governance Committee.

(4)

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

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

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

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

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

 

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

Ida Jane Hinkley has served as a Director of Teekay GP L.L.C. since January 2005. From 1998 to 2001, she served as Managing Director of Navion Shipping AS, a shipping company at that time affiliated with the Norwegian state-owned oil company Statoil ASA (and subsequently acquired by Teekay Corporation’s in 2003). From 1980 to 1997, Ms. Hinkley was employed by the Gotaas-Larsen Shipping Corporation, an international provider of marine transportation services for crude oil and gas (including LNG), serving as its Chief Financial Officer from 1988 to 1992 and its Managing Director from 1993 to 1997. She currently serves as a non-executive director on the Board of Premier Oil plc, a London Stock Exchange listed oil exploration and production company and as a non-executive director of Vesuvius plc, a London Stock Exchange listed engineering company. From 2007 to 2008 she served as a non-executive director on the Board of Revus Energy ASA, a Norwegian listed oil company.

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

George Watson has served as a Director of Teekay GP L.L.C. since January 2005. He currently serves as Executive 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. In addition, Michael Balaski was the Vice President of our General Partner from December 2011 until his resignation on August 20, 2014. His compensation was set and paid by our General Partner, and we reimbursed our General Partner for time he spent on our partnership matters. During 2014, 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 $2.4 million. The amounts were paid primarily in U.S. Dollars or in Euros, but are reported here in U.S. Dollars using an exchange rate 1.33 U.S. Dollar for each Euro, the exchange rate on December 31, 2014. 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 2014, 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, and the chairs of the audit committee, conflicts committee and governance committee received additional fees of $12,000, $12,000, and $10,000, respectively, for serving in that role. Each director is fully indemnified by us for actions associated with being a director to the extent permitted under Marshall Islands law.

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

 

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2005 Long-Term Incentive Plan

Our General Partner adopted the Teekay LNG Partners L.P. 2005 Long-Term Incentive Plan for employees and directors of and consultants to our General Partner and employees and directors of and consultants to its affiliates, who perform services for us. The plan provides for the award of restricted units, phantom units, unit options, unit appreciation rights and other unit or cash-based awards. In 2014, the General Partner awarded 31,961 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

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’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 2014, the Board held seven meetings. Directors attended all Board meetings except for two board members who between them missed four meetings. Audit Committee members attended all meetings except for one member who missed one meeting. Conflicts Committee members attended all applicable meetings. Corporate Governance Committee members attended all committee meetings, except for one member who missed one meeting.

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

 

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Crewing and Staff

As of December 31, 2014, approximately 1,628 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 1,400 seagoing staff and 15 on shore staff as of December 31, 2013 and approximately 1,370 seagoing staff and 15 on shore staff as of December 31, 2012. 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, 2014, 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 March 1, 2015 (60 days after December 31, 2014) 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)

     128,306         0.16

 

(1)

Excludes units owned by Teekay Corporation, which controls us and on the board of which serve the directors of our General Partner, C. Sean Day, Peter Evensen and Kenneth Hvid. Peter Evensen is also the Chief Executive Officer of Teekay Corporation, the Chief Executive Officer and Chief Financial Officer of Teekay Offshore GP L.L.C., and a director of Teekay GP L.L.C. and Teekay Offshore GP L.L.C. Kenneth Hvid is a director of Teekay GP L.L.C. and Teekay Offshore GP L.L.C. Mr. Hvid is also Chief Strategy Officer and Executive Vice President of Teekay Corporation. Please read “Item 7 – Major Unitholders and Related Party Transactions 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, 2014, of our common units by each person we know to beneficially own more than 5% of the outstanding common units. The number of units beneficially owned by each person is determined under SEC rules and the information is not necessarily indicative of beneficial ownership for any other purpose. Under SEC rules a person beneficially owns any units as to which the person has or shares voting or investment power. In addition, a person beneficially owns any units that the person or entity has the right to acquire as of March 1, 2015 (60 days after December 31, 2014) 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.

 

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     Common
Units Owned
     Percentage of
Common Units
Owned (1)
 

Identity of Person or Group

     

Teekay Corporation (1)

     25,208,274         32.2

Neuberger Berman LLC(2)

     9,010,446         11.5

Oppenheimer Funds, Inc.(3)

     7,375,160         9.4

 

(1)

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

(2)

Includes shared voting power as to 8,747,346 units and shared dispositive power as to 9,010,446 units. Both Neuberger Berman Group LLC and Neuberger Berman LLC have shared dispositive power. Neuberger Berman, LLC and Neuberger Berman Management LLC serve as a sub-advisor and investment manager, respectively, of Neuberger Berman Group LLC’s various registered mutual funds which hold such units. The holdings belonging to clients of Neuberger Berman Trust Co N.A., Neuberger Berman Trust Co of Delaware N.A., NB Alternatives Advisers LLC, Neuberger Berman Fixed Income LLC and NB Alternative Investment Management LLC, affiliates of Neuberger Berman LLC, are also aggregated to comprise the holdings referenced herein. This information is based on the Schedule 13G/A filed by this group with the SEC on February 9, 2015.

(3)

Includes shared voting power and shared dispositive power as to 7,375,160 units. This information is based on the Schedule 13G/A filed by this group with the SEC on February 10, 2015.

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

 

  a)

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

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

 

   

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

 

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

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

 

  b)

C. Sean Day is the Chairman of our General Partner, Teekay GP L.L.C. 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). He served as a Chairman of Teekay Tankers Ltd., a publicly held corporation controlled by Teekay Corporation, from 2007 to June 2013.

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

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

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 11 – Related Party Transactions” for a description of our various related-party transactions.

Item 8. Financial Information

A. Consolidated Financial Statements and Other Financial Information

Consolidated Financial Statements and Notes

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

Legal Proceedings

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

Cash Distribution Policy

Rationale for Our Cash Distribution Policy

Our partnership agreement requires us to distribute all of our available cash (as defined in our partnership agreement) within approximately 45 days after the end of each quarter. This 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. Because we believe we will generally finance any capital investments from external financing sources, we believe that our investors are best served by our distributing all of our available cash.

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 distribution policy is subject to restrictions on distributions under our credit agreements. Specifically, our credit agreements contain material financial tests and covenants that we must satisfy. Should we be unable to satisfy these restrictions under our credit agreements, we would be prohibited from making cash distributions to unitholders notwithstanding our stated cash distribution policy.

 

   

The board of directors of our General Partner has the authority to establish reserves for the prudent conduct of our business and for future cash distributions to our unitholders, and the establishment of those reserves could result in a reduction in cash distributions to unitholders from levels we anticipate pursuant to our stated distribution policy.

 

   

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 our General Partner, taking into consideration the terms of our partnership agreement.

 

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Under Section 51 of the Marshall Islands Limited Partnership Act, we may not make a distribution to unitholders 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 increases in our general and administrative expenses, principal and interest payments on our outstanding debt, tax expenses, the issuance of additional units (which would require the payment of distributions on those units), working capital requirements and anticipated cash needs.

 

   

While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including provisions requiring us to make cash distributions, may be amended. Our partnership agreement can be amended with the approval of a majority of the outstanding common units, voting as a class (including common units held by affiliates of our General Partner).

Minimum Quarterly Distribution

Common unitholders are entitled under our partnership agreement to receive a minimum quarterly distribution of $0.4125 per unit, or $1.6500 per year, to the extent we have sufficient cash from our operations after establishment of cash reserves and payment of fees and expenses, including payments to our General Partner. Our General Partner has the authority to determine the amount of our available cash for any quarter. This determination must be made in good faith. There is no guarantee that we will pay the minimum quarterly distribution on the common units in any quarter, and we will be prohibited from making any distributions to unitholders if it would cause an event of default, or an event of default exists, under our credit agreements.

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

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 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 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 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% general partner interest and assume the General Partner has not transferred the incentive distribution rights.

 

    

Quarterly Distribution Target Amount

   Marginal Percentage   Interest In Distributions
     (per unit)    Unitholders   General Partner

Minimum Quarterly Distribution

   $0.4125    98%   2%

First Target Distribution

   Up to $0.4625    98%   2%

Second Target Distribution

   Above $0.4625 up to $0.5375    85%   15%

Third Target Distribution

   Above $0.5375 up to $0.6500    75%   25%

Thereafter

   Above $0.6500    50%   50%

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,
2014
     Dec. 31,
2013
     Dec. 31,
2012
     Dec. 31,
2011
     Dec. 31,
2010

High

     $47.49      $45.42      $42.26      $41.50      $38.25

Low

     33.02      37.73      33.00      28.61      19.75

 

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Quarters Ended    Mar. 31,
2015
     Dec. 31,
2014
     Sept. 30,
2014
     June 30,
2014
     Mar. 31,
2014
     Dec. 31,
2013
     Sept. 30,
2013
     June 30,
2013
     Mar. 31,
2013
 

High

   $ 43.38      $ 43.86      $ 47.49      $ 46.69      $ 42.92      $ 44.96      $ 45.42      $ 45.06      $ 42.60  

Low

     34.13        33.02        40.40        41.35        39.03        38.17        41.18        38.32        37.73  

 

Months Ended      Mar. 31,
2015
       Feb. 28,
2015
       Jan. 31,
2015
       Dec. 31,
2014
       Nov. 30,
2014
       Oct. 31,
2014
 

High

     $ 37.70        $ 39.47        $ 43.38        $ 43.66        $ 39.78        $ 43.86  

Low

       34.13          36.32          37.10          34.62          35.82          33.02  

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)

Agreement dated December 7, 2005, for a U.S. $137,500,000 Revolving Credit Facility between Asian Spirit L.L.C., African Spirit L.L.C., and European Spirit L.L.C., Den Norske Bank ASA and various other banks. This facility bears interest at LIBOR plus a margin of 0.50%. The amount available under the facility reduces by $4.4 million semi-annually, with a bullet reduction of $57.7 million on maturity in April 2015. The credit facility may be used for general partnership purposes and to fund cash distributions. Our obligations under the facility are secured by a first-priority mortgage on three of our Suezmax tankers and a pledge of certain shares of the subsidiaries operating the Suezmax tankers.

 

  (b)

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.

 

  (c)

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.

 

  (d)

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.

 

  (e)

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.

 

  (f)

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. 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.

 

  (g)

Agreement dated June 30, 2008, for a U.S. $172,500,000 Secured Revolving Loan Facility between Arctic Spirit L.L.C., Polar Spirit L.L.C and DnB Nor Bank A.S.A. and other banks. 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.

 

  (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 I, Ltd., BNP Paribas S.A., and other banks and financial institutions. 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.

 

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  (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 II, Ltd., BNP Paribas S.A., and other banks and financial institutions. 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 III, Ltd., BNP Paribas S.A., and other banks and financial institutions. 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.

 

  (k)

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 other banks and financial institutions. 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.

 

  (l)

Agreement dated October 27, 2009, for a U.S. $122,000,000 million credit facility that is secured by the Skaugen LPG Carriers and the Skaugen Multigas Carriers. 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.

 

  (m)

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 two vessels to which the loan relates, together with certain other related security and is guaranteed by Teekay Corporation.

 

  (n)

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. 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.

 

  (o)

Agreement dated February 28, 2012; Teekay LNG Operating LLC and Marubeni Corporation entered into an agreement to acquire, through the Teekay LNG-Marubeni Joint Venture, 100% ownership of six LNG carriers from Maersk. Please read “Item 18 – Financial Statements: Note 5 – Equity Method Investments.”

 

  (p)

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.

 

  (q)

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.

 

  (r)

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.

 

  (s)

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.

 

  (t)

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.

 

  (u)

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.

 

  (v)

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%. 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 LLC in connection with the Yamal LNG Project.

 

  (x)

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.

 

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Exchange Controls and Other Limitations Affecting Unitholders

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

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 Marshal 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 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 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 “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 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 a partner generally will depend upon the status of the partner and the activities of the partnership. Partner 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 his share of items of income, gain, loss, deduction and credit of the partnership in computing his U.S. federal income tax liability, regardless of whether cash distributions are made to him by the partnership. Distributions by a partnership to a partner generally are not taxable unless the amount of cash distributed exceeds the partner’s adjusted tax basis in his partnership interest.

Section 7704 of the Code provides that a publicly traded partnerships generally will be treated as a corporations for U.S. federal income tax purposes. However, an exception, referred to as the “Qualifying Income Exception,” exists with respect to a publicly traded partnerships whose “qualifying income” represents 90 percent or more of its gross income for every taxable year. Qualifying income includes income and gains derived from the transportation and storage of crude oil, natural gas and products thereof, including liquefied natural gas. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of qualifying income, including stock. We have received a ruling from the Internal Revenue Service (or IRS) that we requested in connection with our initial public offering that the income we derive from transporting LNG and crude oil pursuant to time charters existing at the time of our initial public offering is qualifying income within the meaning of Section 7704. A ruling from the IRS, while generally binding on the IRS, may under certain circumstances be revoked or modified by the IRS retroactively.

 

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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 unitholders described in this section applies only to unitholders treated as partners in us for U.S. federal income tax purposes. 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 his status as a partner with respect to those units for U.S. federal income tax purposes.

In general, a person who is not a partner in a partnership for U.S. federal income tax purposes is not required or permitted to report any share of the partnership’s income, gain, deductions or losses for such purposes, and any cash distributions received by such a person from the partnership therefore may be fully taxable as ordinary income. Unitholders 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 his taxable income his allocable share of our items of income, gain, loss, deduction and credit for our taxable year ending with or within his taxable year, without regard to whether we make corresponding cash distributions to him. 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 his tax return for his tax year that ends on or includes such date, even if he has not received a cash distribution from us as of that date.

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

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 his tax basis in his 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 his 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, he 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 his tax basis in his 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, he will be treated as having been distributed his 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 his common units will be the amount he paid for the common units plus his share of our nonrecourse liabilities. That basis will be increased by his share of our income and by any increases in his share of our nonrecourse liabilities and by his 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 his share of our nonrecourse liabilities and by his 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 his share of profits, of our nonrecourse liabilities.

 

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Limitations on Deductibility of Losses. The deduction by a unitholder of his share of our losses will be limited to the tax basis in his 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 his tax basis. In general, a unitholder will be at risk to the extent of the tax basis of his units, excluding any portion of that basis attributable to his share of our nonrecourse liabilities, reduced by any amount of money he borrows to acquire or hold his 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 his 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 his 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 he disposes of his entire investment in us in a fully taxable transaction with an unrelated party. The passive activity loss rules are applied after other applicable limitations on deductions, including the at risk rules and the basis limitation.

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

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

Entity-Level Collections. If we are required or elect under applicable law to pay any U.S. federal, state or local or foreign income or withholding taxes on behalf of any present or former unitholder or the general partner, we are authorized to pay those taxes from our funds. That payment, if made, will be treated as a distribution of cash to the partner on whose behalf the payment was made. 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 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 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 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 unitholders. Finally, although we do not expect that our operations will result in the creation of negative capital accounts, if negative capital accounts nevertheless result, items of our income and gain will be allocated in an amount and manner to eliminate the negative balance as quickly as possible.

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

 

   

his relative contributions to us;

 

   

the interests of all the partners in profits and losses;

 

   

the interest of all the partners in cash flow; and

 

   

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

 

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A unitholder’s taxable income or loss with respect to a common unit each year will depend upon a number of factors, including (1) the nature and fair market value of our assets at the time the holder acquired the common unit, (2) whether we issue additional units or we engage in certain other transactions and (3) the manner in which our items of income, gain, loss, deduction and credit are allocated among our partners. For this purpose, we determine the value of our assets and the relative amounts of our items of income, gain, loss, deduction and credit allocable to our unitholders and our general partner as holder of the incentive distribution rights by reference to the value of our interests, including the incentive distribution rights. The IRS may challenge any valuation determinations that we make, particularly as to the incentive distribution rights, for which there is no public market. Moreover, the IRS could challenge certain other aspects of the manner in which we determine the relative allocations made to our unitholders and to the general partner as holder of our incentive distribution rights. A successful IRS challenge to our valuation or allocation methods could increase the amount of net taxable income and gain realized by a unitholder with respect to a 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 unitholders and does not apply to 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) his share of our tax basis in our assets (or common basis) and (2) his 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 he 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, he would no longer be a partner with respect to those units until the termination of the loan and may recognize gain or loss from the disposition. As a result, any of our income, gain, loss, deduction or credit with respect to the units may not be reportable by the unitholder who loaned them and any cash distributions received by such unitholder with respect to those units may be fully taxable as ordinary income.

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

Tax Treatment of Operations

Accounting Method and Taxable Year. We use the calendar year as our taxable year and the accrual method of accounting for U.S. federal income tax purposes. Each unitholder will be required to include in income his share of our income, gain, loss, deduction and credit for our taxable year ending within or with his taxable year. In addition, a unitholder who disposes of all of his units must include his share of our income, gain, loss, deduction and credit through the date of disposition in income for his 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 his units following the close of our taxable year but before the close of his taxable year must include his 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 his interest in us.

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

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 him and his 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.

 

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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 his 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 his tax advisor as to the possible consequences of this ruling and application of the Treasury Regulations.

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

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 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 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.

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

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

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

 

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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 his 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 he 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, he 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 his U.S. effectively connected income (including his 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 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 his common units and the time we receive distributions from such QBU or the unitholder sells his 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 his 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 his tax return for the first taxable year the unitholder intends the election to be effective. Further, for purposes of computing his taxable income and U.S. federal income tax basis in his common units, a unitholder will be required to translate into his own functional currency items of income, gain, loss or deduction of such QBU and his share of such QBU’s liabilities. We intend to provide such information based on generally applicable U.S. exchange rates as is necessary for 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 unitholders each year. However, a unitholder may be entitled to make an election to apply an alternative exchange rate with respect to the foreign currency translation of certain items. 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 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. 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.

 

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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 his 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 unitholders that the IRS will not successfully contend that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the units.

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

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

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

A unitholder must file a statement with the IRS identifying the treatment of any item on his 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&nb