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EX-31.2 - EX-31.2 CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER PURSUANT TO SECTION 302 - TC PIPELINES LPa16-6443_1ex31d2.htm
EX-32.2 - EX-32.2 CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER PURSUANT TO SECTION 906 - TC PIPELINES LPa16-6443_1ex32d2.htm

Table of Contents

 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

 

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

 

For the quarterly period ended March 31, 2016

 

or

 

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

 

For the transition period from _________ to _________

 

Commission File Number:  001-35358

 

TC PipeLines, LP

(Exact name of registrant as specified in its charter)

 

Delaware

52-2135448

(State or other jurisdiction of

incorporation or organization)

(I.R.S. Employer

Identification Number)

 

700 Louisiana Street, Suite 700

Houston, Texas

77002-2761

(Address of principle executive offices)

(Zip code)

 

877-290-2772

(Registrant’s telephone number, including area code)

 

Indicate by check mark whether 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 o

 

Indicate by check mark whether the registrant 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 o

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

Large accelerated filer x

Accelerated filer o

 

Non-accelerated filer o

(Do not check if a smaller reporting
company)

Smaller reporting company o

 

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes o                                                             No x

 

As of May 2, 2016, there were 65,098,380 of the registrant’s common units outstanding.

 




Table of Contents

 

DEFINITIONS

 

The abbreviations, acronyms, and industry terminology used in this quarterly report are defined as follows:

 

2013 Term Loan Facility

 

TC PipeLines, LP’s term loan credit facility under a term loan agreement dated July 1, 2013

2015 GTN Acquisition

 

Partnership’s acquisition of the remaining 30 percent interest in GTN on April 1, 2015

2015 Term Loan Facility

 

TC PipeLines, LP’s term loan credit facility under a term loan agreement dated September 30, 2015

ASC

 

Accounting Standards Codification

ASU

 

Accounting Standards Update

ATM program

 

At-the-market equity issuance program

Bison

 

Bison Pipeline LLC

Carty Lateral

 

GTN lateral pipeline in north-central Oregon that delivers natural gas to a power plant owned by Portland General Electric Company

Consolidated Subsidiaries

 

GTN, Bison, North Baja and Tuscarora

DOT

 

U.S. Department of Transportation

EBITDA

 

Earnings Before Interest, Tax, Depreciation and Amortization

EPA

 

U.S. Environmental Protection Agency

FASB

 

Financial Accounting Standards Board

FERC

 

Federal Energy Regulatory Commission

GAAP

 

U.S. generally accepted accounting principles

General Partner

 

TC PipeLines GP, Inc.

Great Lakes

 

Great Lakes Gas Transmission Limited Partnership

GTN

 

Gas Transmission Northwest LLC

IDRs

 

Incentive Distribution Rights

ILPs

 

Intermediate Limited Partnerships

LIBOR

 

London Interbank Offered Rate

NGA

 

Natural Gas Act of 1938

North Baja

 

North Baja Pipeline, LLC

Northern Border

 

Northern Border Pipeline Company

Our pipeline systems

 

Our ownership interests in GTN, Northern Border, Bison, Great Lakes, North Baja, Tuscarora, and PNGTS

Partnership

 

TC PipeLines, LP including its subsidiaries, as applicable

Partnership Agreement

 

Third Amended and Restated Agreement of Limited Partnership of the Partnership

PHMSA

 

U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration

PNGTS

 

Portland Natural Gas Transmission System

PNGTS Acquisition

 

Partnership’s acquisition of a 49.9 percent interest in PNGTS, effective January 1, 2016

SEC

 

Securities and Exchange Commission

Senior Credit Facility

 

TC PipeLines, LP’s senior facility under revolving credit agreement as amended and restated, dated November 20, 2012

Short-Term Loan Facility

 

TC PipeLines, LP’s short-term loan facility under loan agreement dated October 1, 2014

TransCanada

 

TransCanada Corporation and its subsidiaries

Tuscarora

 

Tuscarora Gas Transmission Company

U.S.

 

United States of America

VIEs

 

Variable Interest Entities

 

Unless the context clearly indicates otherwise, TC PipeLines, LP and its subsidiaries are collectively referred to in this quarterly report as “we,” “us,” “our” and “the Partnership.” We use “our pipeline systems” and “our pipelines” when referring to the Partnership’s ownership interests in Gas Transmission Northwest LLC (GTN), Northern Border Pipeline Company (Northern Border), Bison Pipeline LLC (Bison), Great Lakes Gas Transmission Limited

 

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Partnership (Great Lakes), North Baja Pipeline, LLC (North Baja), Tuscarora Gas Transmission Company (Tuscarora) and Portland Natural Gas Transmission System (PNGTS).

 

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Table of Contents

 

PART I

 

FORWARD-LOOKING STATEMENTS AND CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

 

This report includes certain forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements are identified by words and phrases such as: “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe,” “forecast,” “should,” “predict,” “could,” “will,” “may,” and other terms and expressions of similar meaning. The absence of these words, however, does not mean that the statements are not forward-looking. These statements are based on management’s beliefs and assumptions and on currently available information and include, but are not limited to, statements regarding anticipated financial performance, future capital expenditures, liquidity, market or competitive conditions, regulations, organic or strategic growth opportunities, contract renewals and ability to market open capacity, business prospects, outcome of regulatory proceedings and cash distributions to unitholders.

 

Forward-looking statements involve risks and uncertainties that may cause actual results to differ materially from the results predicted. Factors that could cause actual results and our financial condition to differ materially from those contemplated in forward-looking statements include, but are not limited to:

 

·                                 the ability of our pipeline systems to sell available capacity on favorable terms and renew expiring contracts which are affected by, among other factors:

o                 demand for natural gas;

o                 changes in relative cost structures and production levels of natural gas producing basins;

o                 natural gas prices and regional differences;

o                 weather conditions;

o                 availability and location of natural gas supplies in Canada and the United States (U.S.) in relation to our pipeline systems;

o                 competition from other pipeline systems;

o                 natural gas storage levels; and

o                 rates and terms of service;

·                                 the performance by the shippers of their contractual obligations on our pipeline systems;

·                                 the outcome and frequency of rate proceedings or settlement negotiations on our pipeline systems;

·                                 changes in the taxation of master limited partnerships by state or federal governments such as final adoption of proposed regulations narrowing the sources of income qualifying for partnership tax treatment or the elimination of pass-through taxation or tax deferred distributions;

·                                 increases in operational or compliance costs resulting from changes in laws and governmental regulations affecting our pipeline systems, particularly regulations issued by the Federal Energy Regulatory Commission (FERC), the U.S. Environmental Protection Agency (EPA) and U.S. Department of Transportation (DOT);

·                                 the impact of recent significant declines in oil and natural gas prices, including the effects on the creditworthiness of our shippers;

·                                 our ongoing ability to grow distributions through acquisitions, accretive expansions or other growth opportunities, including the timing, structure and closure of further potential acquisitions;

·                                 potential conflicts of interest between TC PipeLines GP, Inc., our general partner (General Partner), TransCanada and us;

·                                 the ability to maintain secure operation of our information technology;

·                                 the impact of any impairment charges;

·                                 cybersecurity threats, acts of terrorism and related disruptions;

·                                 operating hazards, casualty losses and other matters beyond our control; and

·                                 the level of our indebtedness, including the indebtedness of our pipeline systems, and the availability of capital.

 

These are not the only factors that could cause actual results to differ materially from those expressed or implied in any forward-looking statement. Other factors described elsewhere in this document, or factors that are unknown or unpredictable, could also have material adverse effects on future results. These and other risks are described in greater detail in Part I, Item 1A. “Risk Factors” in our Form 10-K for the year ended December 31, 2015. All

 

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forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these factors. All forward-looking statements are made only as of the date made and except as required by applicable law, we undertake no obligation to update any forward-looking statements to reflect new information, subsequent events or other changes.

 

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Table of Contents

 

PART I – FINANCIAL INFORMATION

 

Item 1.           Financial Statements

 

TC PIPELINES, LP

CONSOLIDATED STATEMENTS OF INCOME

 

 

 

Three months ended

(unaudited)

 

March 31,

(millions of dollars, except per common unit amounts)

 

2016

 

2015

 

 

 

 

 

 

 

 

Transmission revenues

 

86

 

 

87

 

Equity earnings (Note 4)

 

42

 

 

31

 

Operation and maintenance expenses

 

(10

)

 

(11

)

Property taxes

 

(5

)

 

(6

)

General and administrative

 

(2

)

 

(3

)

Depreciation

 

(21

)

 

(21

)

Financial charges and other (Note 14)

 

(17

)

 

(13

)

Net income

 

73

 

 

64

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income attributable to non-controlling interests

 

-

 

 

7

 

 

 

 

 

 

 

 

Net income attributable to controlling interests

 

73

 

 

57

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income attributable to controlling interest allocation

 

 

 

 

 

 

 

 

 

 

 

 

 

Common units

 

71

 

 

56

 

General Partner

 

2

 

 

 

 

 

73

 

 

57

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income per common unit (Note 8)basic and diluted

 

$1

.10

 

$0

.88

 

 

 

 

 

 

 

Weighted average common units outstanding basic and diluted (millions)

 

6

4.4

 

6

3.6

 

 

 

 

 

 

 

Common units outstanding, end of period (millions)

 

6

4.7

 

6

3.6

 

 

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

 

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TC PIPELINES, LP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

 

 

 

Three months ended

(unaudited)

 

March 31,

(millions of dollars)

 

2016

 

2015

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income

 

73

 

 

64

 

Other comprehensive income

 

 

 

 

 

 

Change in fair value of cash flow hedges (Note 12)

 

(2

)

 

-

 

Reclassification to net income of gains and losses on cash flow hedges (Note 12)

 

-

 

 

(1

)

Comprehensive income

 

71

 

 

63

 

Comprehensive income attributable to non-controlling interests

 

-

 

 

7

 

Comprehensive income attributable to controlling interests

 

71

 

 

56

 

 

 

 

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

 

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Table of Contents

 

TC PIPELINES, LP

CONSOLIDATED BALANCE SHEETS

 

 

(unaudited)

 

 

 

 

(millions of dollars)

 

March 31, 2016

 

December 31, 2015

 

 

 

 

 

ASSETS

 

 

 

 

Current Assets

 

 

 

 

Cash and cash equivalents

 

48

 

39

Accounts receivable and other (Note 13)

 

36

 

35

Distribution receivable from affiliate (Note 11)

 

6

 

-

Inventories

 

7

 

7

 

 

97

 

81

Equity investments (Note 4)

 

1,083

 

965

Plant, property and equipment

 

 

 

 

(Net of $831 accumulated depreciation; 2015 - $811)

 

1,928

 

1,949

Goodwill

 

130

 

130

Other assets (Note 3)

 

-

 

1

 

 

3,238

 

3,126

 

 

 

 

 

LIABILITIES AND PARTNERS’ EQUITY

 

 

 

 

Current Liabilities

 

 

 

 

Accounts payable and accrued liabilities

 

24

 

32

Accounts payable to affiliates (Note 11)

 

4

 

5

Accrued interest

 

13

 

8

Current portion of long-term debt (Note 5)

 

14

 

14

 

 

55

 

59

Long-term debt (Notes 3 and 5)

 

2,059

 

1,889

Other liabilities

 

28

 

27

 

 

2,142

 

1,975

Partners’ Equity

 

 

 

 

Common units

 

981

 

1,021

Class B units (Note 7)

 

95

 

107

General partner

 

24

 

25

Accumulated other comprehensive loss

 

(4)

 

(2)

Controlling interests

 

1,096

 

1,151

 

 

3,238

 

3,126

 

 

 

Variable Interest Entities (Note 17)

Subsequent Events (Note 18)

 

 

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

 

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TC PIPELINES, LP

CONSOLIDATED STATEMENT OF CASH FLOWS

 

 

 

Three months ended

(unaudited)

 

March 31,

(millions of dollars)

 

2016

 

2015

 

 

 

 

 

Cash Generated From Operations

 

 

 

 

Net income

 

73

 

64

Depreciation

 

21

 

21

Amortization of debt issue costs reported as interest expense (Note 3)

 

1

 

1

Accruals for costs related to the 2015 GTN Acquisition

 

-

 

2

Equity earnings in excess of cumulative distributions:

 

 

 

 

Great Lakes

 

-

 

(4)

PNGTS

 

(9)

 

-

Change in operating working capital (Note 10)

 

6

 

3

 

 

92

 

87

Investing Activities

 

 

 

 

Cumulative distributions in excess of equity earnings:

 

 

 

 

Northern Border

 

4

 

2

Great Lakes

 

4

 

-

Investment in Great Lakes

 

(4)

 

(4)

Acquisition of PNGTS (Note 6)

 

(193)

 

-

Capital expenditures

 

(11)

 

(3)

 

 

(200)

 

(5)

Financing Activities

 

 

 

 

Distributions paid (Note 9)

 

(60)

 

(55)

Distributions paid to Class B units (Note 7)

 

(12)

 

-

Distributions paid to non-controlling interests

 

-

 

(9)

ATM equity issuance, net (Note 7)

 

19

 

3

Long-term debt issued, net of discount (Note 5)

 

195

 

349

Long-term debt repaid (Note 5)

 

(25)

 

(10)

Debt issuance costs

 

-

 

(2)

 

 

117

 

276

Increase/(decrease) in cash and cash equivalents

 

9

 

358

Cash and cash equivalents, beginning of period

 

39

 

26

Cash and cash equivalents, end of period

 

48

 

384

 

 

 

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

 

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TC PIPELINES, LP

CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS’ EQUITY

 

 

 

 

Limited Partners

 

 

 

 

 

 

(unaudited)

 

Common Units

 

Class B Units

 

General
Partner

 

Accumulated
Other
Comprehensive
Loss 
(a)

 

Total
Equity

 

 

(millions
of units)

 

(millions
of
dollars)

 

(millions
of units)

 

(millions
of
dollars)

 

(millions
of
dollars)

 

(millions of
dollars)

 

(millions
of
dollars)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Partners’ Equity at December 31, 2015

 

64.3

 

1,021

 

1.9

 

107

 

25

 

(2)

 

1,151

Net income

 

-

 

71

 

-

 

 

 

2

 

-

 

73

Other Comprehensive Loss

 

-

 

-

 

-

 

-

 

-

 

(2)

 

(2)

ATM Equity Issuance, net (Note 7)

 

0.4

 

19

 

-

 

-

 

-

 

-

 

19

Acquisition of PNGTS (Note 6)

 

-

 

(72)

 

-

 

-

 

(1)

 

-

 

(73)

Distributions

 

-

 

(58)

 

-

 

(12)

 

(2)

 

-

 

(72)

Partners’ Equity at March 31, 2016

 

64.7

 

981

 

1.9

 

95

 

24

 

(4)

 

1,096

 

(a)              Losses related to cash flow hedges reported in Accumulated Other Comprehensive Loss and expected to be reclassified to Net Income in the next 12 months are estimated to be $2 million. These estimates assume constant interest rates over time; however, the amounts reclassified will vary based on actual value of interest rates at the date of settlement.

 

 

 

 

 

 

 

 

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

 

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TC PIPELINES, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

NOTE 1        ORGANIZATION

 

TC PipeLines, LP and its subsidiaries are collectively referred to herein as the Partnership. The Partnership was formed by TransCanada PipeLines Limited, a wholly-owned subsidiary of TransCanada Corporation (TransCanada Corporation together with its subsidiaries collectively referred to herein as TransCanada), to acquire, own and participate in the management of energy infrastructure assets in North America.

 

The Partnership owns its pipeline assets through three intermediate limited partnerships (ILPs), TC GL Intermediate Limited Partnership, TC PipeLines Intermediate Limited Partnership and TC Tuscarora Intermediate Limited Partnership.

 

NOTE 2        SIGNIFICANT ACCOUNTING POLICIES

 

The accompanying financial statements and related notes have been prepared in accordance with United States generally accepted accounting principles (GAAP) and amounts are stated in U.S. dollars. The results of operations for the three months ended March 31, 2016 and 2015 are not necessarily indicative of the results that may be expected for the full fiscal year.

 

The accompanying financial statements should be read in conjunction with the financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2015. That report contains a more comprehensive summary of the Partnership’s significant accounting policies. In the opinion of management, the accompanying financial statements contain all of the appropriate adjustments, all of which are normally recurring adjustments unless otherwise noted, and considered necessary to present fairly the financial position of the Partnership, the results of operations and cash flows for the respective periods. Our significant accounting policies are consistent with those disclosed in our Annual Report on Form 10-K for the year ended December 31, 2015, except as described in Note 3, Accounting Pronouncements.

 

 

Use of Estimates

 

The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Although management believes these estimates are reasonable, actual results could differ from these estimates.

 

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NOTE 3                         ACCOUNTING PRONOUNCEMENTS

 

Effective January 1, 2016

 

Consolidation

 

In February 2015, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2015-02 “Consolidation (Topic 810),” an amendment of previously issued guidance on consolidation. This updated guidance requires that an entity evaluate whether it should consolidate certain legal entities. All legal entities are subject to reevaluation under the revised consolidation model. This guidance became effective beginning January 1, 2016 and was applied retrospectively to all financial statements presented. The application of this guidance did not result in any change to the Partnership’s consolidation conclusions. Refer to Note 17.

 

Imputation of interest

 

In April 2015, the FASB issued ASU No. 2015-03 “Interest – Imputation of Interest (Subtopic 835-30),” an amendment of previously issued guidance on imputation of interest. This updated guidance requires debt issuance costs be presented in the balance sheet as a direct deduction from the carrying amount of debt liabilities, consistent with debt discount or premiums. In addition, amortization of debt issuance costs should be reported as interest expense. The recognition and measurement for debt issuance costs would not be affected. This guidance is effective from January 1, 2016 and was applied retrospectively resulting in a reclassification of debt issuance costs previously recorded in other assets to an offset of their respective debt liabilities on the Partnership’s consolidated balance sheet. Amortization of debt issuance costs was reported as interest expense in all periods presented in the Partnership’s consolidated statement of income.

 

As a result of the application of ASU No. 2015-03 and similar to the presentation of debt discounts, Debt issuance costs of $7 million at December 31, 2015 previously reported as other assets in the balance sheet were reclassified as an offset against their respective debt liabilities.

 

Earnings per share

 

In April 2015, the FASB issued ASU No.2015-06 “Earnings Per Share (Topic 260),” an amendment of previously issued guidance on earnings per share (EPS) as it is being calculated by master limited partnerships. This updated guidance specifies that for purposes of calculating historical EPS under the two-class method, the earnings (losses) of a transferred business before the date of a dropdown transaction should be allocated entirely to the general partner interest, and previously reported EPS of the limited partners would not change as a result of a dropdown transaction. Qualitative disclosures about how the rights to the earnings (losses) differ before and after the dropdown transaction occurs are also required. This guidance became effective from January 1, 2016 and applies to all dropdown transactions requiring recast. The retrospective application of this guidance did not have a material impact on the Partnership’s consolidated financial statements as our current accounting policy is consistent with the new guidance.

 

Business combinations

 

In September 2015, the FASB issued ASU No. 2015-16 “Business Combinations (Topic 805),” which replaces the requirement that an acquirer in a business combination account for measurement period adjustments retrospectively with a requirement that an acquirer recognize adjustments to the provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. The amended guidance requires that the acquirer record, in the same period’s financial statements, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. The new guidance is effective January 1, 2016 and was applied prospectively. The application of this guidance did not have a material impact on Partnership’s consolidated financial statements.

 

Future accounting changes

 

Revenue from contracts with customers

 

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In May 2014, the FASB issued ASU No. 2014-09 “Revenue from Contracts with Customers (Topic 606).” This guidance supersedes the revenue recognition requirements in Topic 605, Revenue Recognition and most industry-specific guidance. This new guidance requires that an entity recognizes revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. On July 9, 2015, the FASB voted to defer the effective date by one year to December 15, 2017 for annual reporting periods beginning after that date. The FASB also voted to permit early adoption of the standard, but not before the original effective date of December 15, 2016. This new guidance, once effective, allows two methods in which the amendment can be applied: (1) retrospectively to each prior reporting period presented, or (2) retrospectively with the cumulative effect recognized at the date of initial application. The Partnership is currently evaluating the impact of the adoption of this ASU and has not yet determined the effect on its consolidated financial statements.

 

Leases

 

In February 2016, the FASB issued ASU No. 2016-03 “Leases (Topic 842).” The new guidance requires lessees to recognize most leases, including operating leases, on the balance sheet as lease assets and lease liabilities. In addition, lessees will be required to reassess assumptions associated with existing leases as well as to provide expanded qualitative and quantitative disclosures. The new standard does not make extensive changes to lessor accounting. The new guidance is effective January 1, 2019 and will be applied using a modified retrospective approach. The Partnership is currently evaluating the impact of the adoption of this guidance and has not yet determined the effect on its consolidated financial statements.

 

Equity method and joint ventures

 

In March 2016, the FASB issued ASU No. 2016-07 “Investments – equity method and joint ventures (Topic 323)” that simplifies the transition to equity method accounting. The new guidance eliminates the requirement to retroactively apply the equity method of accounting when an increase in ownership interest in an investment qualifies for equity method accounting. This new guidance is effective January 2017 and will be applied prospectively. The Partnership does not expect the adoption of this new standard to have a material impact on its consolidated financial statements.

 

NOTE 4                         EQUITY INVESTMENTS

 

Northern Border, Great Lakes and Portland Natural Gas Transmission System (PNGTS) are regulated by FERC and are operated by TransCanada. The Partnership uses the equity method of accounting for its interests in its equity investees. The Partnership’s equity investments are held through our ILPs that are considered to be variable interest entities (VIEs) (refer to Note 3 and Note 17).

 

 

 

 

 

Equity Earnings

 

Equity Investments

 

 

Ownership

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest at

 

Three months

 

 

 

 

(unaudited)

 

March 31,

 

ended March 31,

 

March 31,

 

December 31,

(millions of dollars)

 

2016

 

 2016

 

  2015

 

2016

 

2015

 

 

 

 

 

 

 

 

 

 

 

Northern Border(a)

 

50%

 

18

 

20

 

476

 

480

Great Lakes

 

46.45%

 

15

 

11

 

485

 

485

PNGTS (b)

 

49.9%

 

  9

 

-

 

122

 

-

 

 

 

 

42

 

31

 

1,083

 

965

 

(a)  Equity earnings from Northern Border is net of the 12-year amortization of a $10 million transaction fee paid to the operator of Northern Border at the time of the Partnership’s additional 20 percent interest acquisition in April 2006.

 

(b)  On January 1, 2016, the Partnership acquired a 49.9 percent interest in PNGTS (Refer to Note 6). For the three months ending March 31, 2016, the Partnership recorded no undistributed earnings from PNGTS.

 

Northern Border

 

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The Partnership did not have undistributed earnings from Northern Border for the three months ended March 31, 2016 and 2015.

 

The summarized financial information for Northern Border is as follows:

 

(unaudited)

 

 

 

 

(millions of dollars)

 

March 31, 2016

 

December 31, 2015

 

 

 

 

 

ASSETS

 

 

 

 

Cash and cash equivalents

 

35

 

27

Other current assets

 

34

 

33

Plant, property and equipment, net

 

1,117

 

1,124

Other assets (a)

 

15

 

16

 

 

1,201

 

1,200

 

 

 

 

 

LIABILITIES AND PARTNERS’ EQUITY

 

 

 

 

Current liabilities

 

46

 

39

Deferred credits and other

 

26

 

26

Long-term debt, including current maturities, net (a)

 

409

 

409

Partners’ equity

 

 

 

 

Partners’ capital

 

722

 

728

Accumulated other comprehensive loss

 

(2)

 

(2)

 

 

1,201

 

1,200

 

(a)  As a result of the application of ASU No. 2015-03 and similar to the presentation of debt discounts, debt issuance costs of $2 million at December 31, 2015 previously reported as other assets in the balance sheet were reclassified as an offset against their respective debt liabilities.

 

 

 

Three months ended

(unaudited)

 

March 31,

(millions of dollars)

 

2016

 

2015

 

 

 

 

 

 

 

 

 

 

Transmission revenues

 

74

 

75

Operating expenses

 

(16)

 

(16)

Depreciation

 

(15)

 

(15)

Financial charges and other

 

(6)

 

(5)

Net income

 

37

 

39

 

Great Lakes

The Partnership made an equity contribution to Great Lakes of $4 million in the first quarter of 2016. This amount represents the Partnership’s 46.45 percent share of a $9 million cash call from Great Lakes to make a scheduled debt repayment.

 

The Partnership did not have undistributed earnings from Great Lakes for the three months ended March 31, 2016 and 2015.

 

The summarized financial information for Great Lakes is as follows:

 

(unaudited)

 

 

 

 

(millions of dollars)

 

March 31, 2016

 

December 31, 2015(a)

 

 

 

 

 

 

 

 

 

 

ASSETS

 

 

 

 

Current assets

 

73

 

86

Plant, property and equipment, net

 

725

 

727

 

 

798

 

813

 

 

 

 

 

LIABILITIES AND PARTNERS’ EQUITY

 

 

 

 

Current liabilities

 

25

 

31

Long-term debt, including current maturities, net (a)

 

288

 

297

Partners’ equity

 

485

 

485

 

 

798

 

813

 

(a)              The application of ASU No. 2015-03 did not have a material effect of Great Lakes’ financial statements.

 

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Three months ended

(unaudited)

 

March 31,

(millions of dollars)

 

2016

 

2015

 

 

 

 

 

 

 

 

 

 

Transmission revenues

 

61

 

48

Operating expenses

 

(15)

 

(11)

Depreciation

 

(7)

 

(7)

Financial charges and other

 

(6)

 

(6)

Net income

 

33

 

24

 

 

NOTE 5                         DEBT AND CREDIT FACILITIES

 

(unaudited)

 

 

 

 

 

 

(millions of dollars)

 

March 31,
2016

 

December 31, 2015 (a)

 

Weighted Average
Interest Rate for the
Three Months Ended
March 31, 2016

 

 

 

 

 

 

 

TC PipeLines, LP Senior Credit Facility due 2017

 

370

 

200

 

1.68%

TC PipeLines, LP 2013 Term Loan Facility due 2018

 

500

 

500

 

1.68%

TC PipeLines, LP 2015 Term Loan Facility due 2018

 

170

 

170

 

1.57%

TC PipeLines, LP 4.65% Unsecured Senior Notes due 2021

 

350

 

350

 

4.65% (b)

TC PipeLines, LP 4.375% Unsecured Senior Notes due 2025

 

350

 

350

 

4.375% (b)

GTN 5.29% Unsecured Senior Notes due 2020

 

100

 

100

 

5.29% (b)

GTN 5.69% Unsecured Senior Notes due 2035

 

150

 

150

 

5.69% (b)

GTN Unsecured Term Loan Facility due 2019

 

75

 

75

 

1.37%

Tuscarora 3.82% Series D Senior Notes due 2017

 

16

 

16

 

3.82% (b)

 

 

2,081

 

1,911

 

 

Less: unamortized debt issuance costs and debt discount (a)

 

8

 

8

 

 

Less: current portion

 

14

 

14

 

 

 

 

2,059

 

1,889

 

 

 

(a)              As a result of the application of ASU no. 2015-03 and similar to the presentation of debt discounts, debt issuance costs of $7 million at December 31, 2015 previously reported as other assets in the balance sheet were reclassified as an offset against debt (Refer to Note 3).

(b)          Fixed interest rate

 

The Partnership’s Senior Credit Facility consists of a $500 million senior revolving credit facility with a banking syndicate, maturing November 20, 2017, under which $370 million was outstanding at March 31, 2016 (December 31, 2015 - $200 million), leaving $130 million available for future borrowing.

 

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After hedging activity, the interest rate incurred on the 2013 Term Loan Facility averaged 2.20 percent for the three months ended March 31, 2016 (2015 – 1.83 percent). Prior to hedging activities, the LIBOR-based interest rate was 1.69 percent at March 31, 2016 (December 31, 2015 – 1.50 percent).

 

The 2013 Term Loan Facility and the 2015 Term Loan Facility (Term Loan Facilities) and the Senior Credit Facility require the Partnership to maintain a certain leverage ratio (debt to adjusted cash flow [net income plus cash distributions received, extraordinary losses, interest expense, expense for taxes paid or accrued, and depreciation and amortization expense less equity earnings and extraordinary gains]) be no greater than:

 

·                 5.50 to 1.00 for the quarters ending March 31, 2016 to September 30, 2016;

·                 5.00 to 1.00 for the quarter ending December 31, 2016 and each subsequent fiscal quarter, except for the fiscal quarter and the two following fiscal quarters in which one or more acquisitions has been executed, in which case the leverage ratio is to be no greater than 5.50 to 1.00.

 

The leverage ratio was 4.86 to 1.00 as of March 31, 2016.

 

GTN’s Unsecured Senior Notes, along with GTN’s Unsecured Term Loan Facility contain a covenant that limits total debt to no greater than 70 percent of GTN’s total capitalization.  GTN’s total debt to total capitalization ratio at March 31, 2016 was 44.1 percent.

 

The Series D Senior Notes which require yearly principal payments until maturity, are secured by Tuscarora’s transportation contracts, supporting agreements and substantially all of Tuscarora’s property. The note purchase agreements contain certain provisions that include, among other items, limitations on additional indebtedness and distributions to partners. The Series D Senior Notes contain a covenant that limits total debt to no greater than 45 percent of Tuscarora’s total capitalization.  Tuscarora’s total debt to total capitalization ratio at March 31, 2016 was 15.1 percent. Additionally, the Series D Senior Notes require Tuscarora to maintain a Debt Service Coverage Ratio (cash available from operations divided by a sum of interest expense and principal payments) of greater than 3.00 to 1.00. The ratio was 4.56 to 1.00 as of March 31, 2016.

 

At March 31, 2016, the Partnership was in compliance with its financial covenants, in addition to the other covenants which include restrictions on entering into mergers, consolidations and sales of assets, granting liens, material amendments to the Third Amended and Restated Agreement of Limited Partnership (Partnership Agreement), incurring additional debt and distributions to unitholders.

 

The principal repayments required of the Partnership on its debt are as follows:

 

(unaudited)

 

 

(millions of dollars)

 

 

 

 

 

2016

 

14

2017

 

392

2018

 

690

2019

 

35

2020

 

100

Thereafter

 

850

 

 

2,081

 

NOTE 6                         ACQUISITION

 

PNGTS Acquisition

 

On January 1, 2016, the Partnership acquired a 49.9 percent interest in PNGTS from a subsidiary of TransCanada (PNGTS Acquisition). The total purchase price of the PNGTS Acquisition was $228 million and consisted of $193 million in cash (including the final purchase price adjustment of $5 million) and the assumption of $35 million in proportional PNGTS debt.

 

The Partnership funded the cash portion of the transaction using proceeds received from our ATM program and additional borrowings under our Senior Credit Facility. The purchase agreement provides for additional payments to

 

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TransCanada ranging from $5 million up to a total of $50 million if pipeline capacity is expanded to various thresholds during the fifteen year period following the date of closing.

 

The acquisition was accounted for as a transaction between entities under common control, whereby the equity investment in PNGTS was recorded at TransCanada’s carrying value.

 

(millions of dollars)

 

 

 

 

 

Net Purchase Price (a)

 

193

 

 

 

Less: TransCanada’s carrying value of PNGTS’ net assets at January 1, 2016

 

120

Excess purchase price (b)

 

73

 

(a)              Total purchase price of $228 million less the assumption of $35 million of proportional PNGTS debt by the Partnership.

(b)              The excess purchase price of $73 million was recorded as a reduction in Partners’ Equity.

 

NOTE 7                         PARTNERS’ EQUITY

 

ATM equity issuance program (ATM program)

 

 

In the three months ended March 31, 2016, we issued 368,448 common units under our ATM program generating net proceeds of approximately $19 million, plus $0.4 million from the General Partner to maintain its effective two percent interest. The commissions to our sales agents for the three months ended March 31, 2016 were approximately $186,000. The net proceeds were used for general partnership purposes.

 

Class B units issued to TransCanada

 

The Class B Units we issued on April 1, 2015 to finance a portion of the 2015 GTN Acquisition represent a limited partner interest in us and entitle TransCanada to an annual distribution based on 30 percent of GTN’s annual distributions as follows: (i) 100 percent of distributions above $20 million through March 31, 2020; and (ii) 25 percent of distributions above $20 million thereafter.

 

For the year ending December 31, 2016, the Class B units’ equity account will be increased by the excess of 30 percent of GTN’s distributions over the annual threshold of $20 million until such amount is declared for distribution and paid in the first quarter of 2017. For the three months ended March 31, 2016, the threshold has not been exceeded.

 

For the year ended December 31, 2015, the Class B distribution was $12 million and was declared and paid in the first quarter of 2016.

 

NOTE 8                         NET INCOME PER COMMON UNIT

 

Net income per common unit is computed by dividing net income attributable to controlling interests, after deduction of amounts attributable to the General Partner and Class B units by the weighted average number of common units outstanding.

 

The amounts allocable to the General Partner equals an amount based upon the General Partner’s effective two percent general partner interest, plus an amount equal to incentive distributions. Incentive distributions are paid to the General Partner if quarterly cash distributions on the common units exceed levels specified in the Partnership Agreement. Incentive distributions allocated to the General Partner for the three months ended March 31, 2016, were $1 million (2015 – $0.3 million).

 

For the year ending December 31, 2016, the amount allocable to the Class B units is equal to 30 percent of GTN’s annual distributable cash flow, less $20 million (Refer to Note 7). During the three months ended March 31, 2016, no amounts were allocated to the Class B units as the annual threshold of $20 million was not exceeded.

 

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Net income per common unit was determined as follows:

 

(unaudited)

 

Three months ended March 31,

(millions of dollars, except per common unit amounts)

 

2016

 

2015

 

 

 

 

 

Net income attributable to controlling interests

 

73

 

57

Net income attributable to the General Partner

 

(1)

 

(1)

Incentive distributions attributable to the General Partner (a)

 

(1)

 

-

Net income attributable to common units

 

71

 

56

Weighted average common units outstanding (millions) – basic and diluted

 

64.4

 

63.6

Net income per common unit – basic and diluted

 

$1.10

 

$0.88

 

(a)              Under the terms of the Partnership Agreement, for any quarterly period, the participation of the incentive distribution rights (IDRs) is limited to the available cash distributions declared. Accordingly, incentive distributions allocated to the General Partner are based on the Partnership’s available cash during the current reporting period, but declared and paid in the subsequent reporting period.

 

NOTE 9                         CASH DISTRIBUTIONS

 

In the three months ended March 31, 2016, the Partnership distributed $0.89 per common unit (2015 – $0.84) for a total of $60 million (2015 - $55 million). The distributions paid in the three months ended March 31, 2016 included an incentive distribution to the General Partner of approximately $1 million (2015- $0.3 million).

 

NOTE 10                  CHANGE IN OPERATING WORKING CAPITAL

 

(unaudited)

 

Three months ended March 31,

(millions of dollars)

 

2016

 

2015

 

 

 

 

 

Change in accounts receivable and other

 

(1) 

 

(1)

Change in accounts payable and accrued liabilities

 

3(a)

 

2

Change in accounts payable to affiliates

 

(1) 

 

(7)

Change in accrued interest

 

 

9

Change in operating working capital

 

 

3

 

(a)              The accrual of $10 million for the construction of GTN’s Carty Lateral in December 31, 2015 was paid during the current quarter. Accordingly, the payment was reported as capital expenditures in our cash flow statement during the current quarter.

 

NOTE 11                  RELATED PARTY TRANSACTIONS

 

The Partnership does not have any employees. The management and operating functions are provided by the General Partner. The General Partner does not receive a management fee in connection with its management of the Partnership. The Partnership reimburses the General Partner for all costs of services provided, including the costs of employee, officer and director compensation and benefits, and all other expenses necessary or appropriate to the conduct of the business of, and allocable to, the Partnership. Such costs include (i) overhead costs (such as office space and equipment) and (ii) out-of-pocket expenses related to the provision of such services. The Partnership Agreement provides that the General Partner will determine the costs that are allocable to the Partnership in any reasonable manner determined by the General Partner in its sole discretion. Total costs charged to the Partnership by the General Partner were $1 million for the three months ended March 31, 2016 and 2015.

 

As operator, TransCanada’s subsidiaries provide capital and operating services to our pipeline systems. TransCanada’s subsidiaries incur costs on behalf of our pipeline systems, including, but not limited to, employee salary and benefit costs, and property and liability insurance costs.

 

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Capital and operating costs charged to our pipeline systems for the three months ended March 31, 2016 and 2015 by TransCanada’s subsidiaries and amounts payable to TransCanada’s subsidiaries at March 31, 2016 and December 31, 2015 are summarized in the following tables:

 

 

 

Three months ended

(unaudited)

 

March 31,

(millions of dollars)

 

2016

 

2015

 

 

 

 

 

 

 

 

 

 

Capital and operating costs charged by TransCanada’s subsidiaries to:

 

 

 

 

Great Lakes (a) 

 

7

 

6

Northern Border (a)

 

6

 

7

PNGTS (a), (c)

 

2

 

-

GTN (a) 

 

6

 

6

Bison (d)

 

(1)

 

1

North Baja

 

1

 

1

Tuscarora

 

1

 

1

Impact on the Partnership’s net income:

 

 

 

 

Great Lakes

 

3

 

3

Northern Border

 

3

 

3

PNGTS (c)

 

1

 

-

GTN (b)

 

5

 

4

Bison

 

1

 

1

North Baja

 

1

 

1

Tuscarora

 

1

 

1

 

 

 

 

 

 

(unaudited)

 

 

 

 

(millions of dollars)

 

March 31, 2016

 

December 31, 2015

 

 

 

 

 

 

 

 

 

 

Net amounts (receivable)/payable to TransCanada’s subsidiaries is as follows:

 

 

 

 

Great Lakes (a)

 

2

 

3

Northern Border (a)

 

2

 

5

PNGTS (a)

 

1

 

-

GTN

 

2

 

3

Bison

 

(1)

 

-

North Baja

 

-

 

-

Tuscarora

 

1

 

1

 

 

 

 

 

 

(a)              Represents 100 percent of the costs.

(b)              In April 2015, the Partnership acquired the remaining 30 percent interest in GTN.

(c)              In January 2016, the Partnership acquired 49.9 percent interest in PNGTS.

(d)              In March 2016, Bison sold excess pipe (at cost) to an affiliate.

 

Great Lakes’ earns revenues from TransCanada and its affiliates, some of which are provided at discounted rates and some are at maximum recourse rates. Great Lakes earned $46 million of transportation revenues under these contracts for the three months ended March 31, 2016 (2015 - $29 million). These amounts represent 76 percent of total revenues earned by Great Lakes for the three months ended March 31, 2016 (2015 – 61 percent).

 

Accordingly, revenue from TransCanada and its affiliates of $22 million is included in the Partnership’s equity earnings from Great Lakes for the three months ended March 31, 2016 (2015 - $14 million). At March 31, 2016, $15 million was included in Great Lakes’ receivables in regards to the transportation contracts with TransCanada and its affiliates (December 31, 2015 - $17 million).

 

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Effective November 1, 2014, Great Lakes executed contracts with an affiliate, ANR Pipeline Company (ANR), to provide firm service in Michigan and Wisconsin.  These contracts were at the maximum FERC authorized rate and were intended to replace historical contracts.  On December 3, 2014, the FERC accepted and suspended Great Lakes’ tariff records to become effective May 3, 2015, subject to refund.  On February 2, 2015, FERC issued an Order granting a rehearing and clarification request submitted by Great Lakes, which allowed additional time for FERC to consider Great Lakes’ request.  Following extensive discussions with numerous shippers and other stakeholders, on April 20, 2015, ANR filed a settlement with FERC that included an agreement by ANR to pay Great Lakes the difference between the historical and maximum rates (ANR Settlement). Great Lakes provided service to ANR under multiple service agreements and rates through May 3, 2015 when Great Lakes’ tariff records became effective and subject to refund.  Great Lakes deferred an approximate $9 million of revenue related to services performed in 2014 and approximately $14 million of additional revenue related to services performed through May 3, 2015 under such agreements. On October 15, 2015, FERC accepted and approved the ANR Settlement.  As a result, Great Lakes recognized the deferred transportation revenue of approximately $23 million in the fourth quarter of 2015.

 

On March 11, 2016, PNGTS declared its first quarter 2016 distribution of $13 million, of which the Partnership received its 49.9 percent share or $6 million on April 18, 2016.

 

NOTE 12                  FAIR VALUE MEASUREMENTS

 

(a) Fair Value Hierarchy

Under ASC 820, Fair Value Measurements and Disclosures, fair value measurements are characterized in one of three levels based upon the inputs used to arrive at the measurement. The three levels of the fair value hierarchy are as follows:

 

·      Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that we have the ability to access at the measurement date.

·      Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly.

·      Level 3 inputs are unobservable inputs for the asset or liability.

 

When appropriate, valuations are adjusted for various factors including credit considerations. Such adjustments are generally based on available market evidence. In the absence of such evidence, management’s best estimate is used.

 

(b) Fair Value of Financial Instruments

The carrying value of cash and cash equivalents, accounts receivable and other, accounts payable and accrued liabilities, accounts payable to affiliates and accrued interest approximate their fair values because of the short maturity or duration of these instruments, or because the instruments bear a variable rate of interest or a rate that approximates current rates. The fair value of the Partnership’s debt is estimated by discounting the future cash flows of each instrument at estimated current borrowing rates. The fair value of interest rate derivatives is calculated using the income approach, which uses period-end market rates and applies a discounted cash flow valuation model.

 

Long-term debt is recorded at amortized cost and classified in Level II of the fair value hierarchy for fair value disclosure purposes. Interest rate derivative assets and liabilities are classified in Level II for all periods presented where the fair value is determined by using valuation techniques that refer to observable market data or estimated market prices.  The estimated fair value of the Partnership’s debt as at March 31, 2016 and December 31, 2015 was $2,037 million and $1,873 million, respectively.

 

Market risk is the risk that changes in market interest rates may result in fluctuations in the fair values or cash flows of financial instruments. The Partnership’s floating rate debt is subject to LIBOR benchmark interest rate risk. The Partnership uses interest rate derivatives to manage its exposure to interest rate risk. We regularly assess the impact of interest rate fluctuations on future cash flows and evaluate hedging opportunities to mitigate our interest rate risk.

 

The interest rate swaps are structured such that the cash flows of the derivative instruments match those of the variable rate of interest on the 2013 Term Loan Facility. The Partnership hedged interest payments on the variable-rate 2013 Term Loan Facility with interest rate swaps maturing July 1, 2018, at a weighted average fixed interest rate of 2.31 percent. At March 31, 2016, the fair value of the interest rate swaps accounted for as cash flow hedges

 

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was a liability of $4 million (both on a gross and net basis) (December 31, 2015 - $1 million). The Partnership did not record any amounts in net income related to ineffectiveness for interest rate hedges for the three months ended March 31, 2016 and 2015. The change in fair value of interest rate derivative instruments recognized in other comprehensive income was a loss of $2 million for the three months ended March 31, 2016 (2015 – $1 million). For the three months ended March 31, 2016, the net realized loss related to the interest rate swaps was nil million and was included in financial charges and other (2015 – $1 million) (refer to Note 14).

 

The Partnership has no master netting agreements; however, it has derivative contracts containing provisions with rights of offset. The Partnership has elected to present the fair value of derivative instruments with the right to offset on a gross basis in the balance sheet. Had the Partnership elected to present these instruments on a net basis, there would be no effect on the consolidated balance sheet as of March 31, 2016 and December 31, 2015.

 

NOTE 13                  ACCOUNTS RECEIVABLE AND OTHER

 

(unaudited)

 

 

 

 

(millions of dollars)

 

March 31, 2016

 

December 31, 2015

 

 

 

 

 

Trade accounts receivable, net of allowance of nil

 

30

 

31

Other

 

6

 

4

 

 

36

 

35

 

NOTE 14                  FINANCIAL CHARGES AND OTHER

 

 

 

Three months ended

(unaudited)

 

March 31,

(millions of dollars)

 

2016

 

2015

 

 

 

 

 

 

 

 

 

 

Interest Expense (a)

 

17

 

13

Net realized loss related to the interest rate swaps

 

-

 

1

Other Income

 

-

 

(1)

 

 

17

 

13

 

(a) Effective January 1, 2016, interest expense includes debt issuance costs and amortization of discount costs. Refer to Note 3.

 

NOTE 15                  CONTINGENCIES

 

Great Lakes v. Essar Steel Minnesota LLC, et al. –  On October 29, 2009, Great Lakes filed suit in the U.S. District Court, District of Minnesota, against Essar Minnesota LLC and certain Essar affiliates (collectively, Essar) for breach of its monthly payment obligation under its transportation services agreement with Great Lakes. Great Lakes sought to recover approximately $33 million for past and future payments due under the agreement. On September 16, 2015, following a jury trial, the federal district court judge entered a judgment in the amount of $32.9 million in favor of Great Lakes.  On September 20, 2015, Essar appealed the decision to the United States Court of Appeals for the 8th Circuit (8th Circuit) based on an allegation of improper jurisdiction and a number of other rulings by the federal district judge. Essar was required to post a performance bond for the full value of the judgment pending appeal. Essar filed its brief in April 2016 and Great Lakes’ brief is due May 18th, 2016.  The court will set a hearing date after it received the briefings.  The matter is expected to be heard in 2016.

 

Employees Retirement System of the City of St. Louis v. TC PipeLines GP, Inc., et al. – On October 13, 2015, an alleged unitholder of the Partnership filed a class action and derivative complaint in the Delaware Court of Chancery (Chancery Court) against the General Partner, TransCanada American Investments, Ltd. (TAIL) and TransCanada, and the Partnership as a nominal defendant.   The complaint alleges direct and derivative claims for breach of contract, breach of the duty of good faith and fair dealing, aiding and abetting breach of contract, and tortious interference in connection with the 2015 GTN Acquisition, including the issuance by the Partnership of $95 million in Class B Units and amendments to the Partnership Agreement to provide for the issuance of the Class B Units.   Plaintiff seeks, among other things, to enjoin future issuances of Class B Units to TransCanada or any of its subsidiaries, disgorgement of certain distributions to the General Partner, TransCanada and any related entities, return of some or all of the Class B Units to the Partnership, rescission of the amendments to the Partnership Agreement, monetary damages and attorney fees.   To the extent the claims are derivative, the Partnership would be the beneficiary of any monetary award.  The Partnership does not expect legal fees or the impact of the decision on plaintiffs’ other requests to be material.  In April 2016, the Chancery Court held a hearing on the Partnership and other defendants’ motion to dismiss the plaintiffs’ complaint.  A decision on the motion is expected in late second quarter of 2016 or early third quarter 2016.

 

NOTE 16                  REGULATORY

 

Tuscarora -  On January 21, 2016, the FERC issued an Order (the January 21 Order) initiating an investigation pursuant to Section 5 of the NGA to determine whether Tuscarora’s existing rates for jurisdictional services are just and reasonable. On April 5, 2016, Tuscarora filed with the FERC a cost and revenue study as required by the

 

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January 21 Order that supported its current rate levels. The Partnership cannot predict the outcome or potential impact of this proceeding to Tuscarora at this time.

 

NOTE 17                  VARIABLE INTEREST ENTITIES

 

In the normal course of business, the Partnership must re-evaluate its legal entities under the newly effective consolidation guidance to determine if those that are considered to be VIEs are appropriately consolidated or if they should be accounted for under other US GAAP. A variable interest entity (VIE) is a legal entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support or is structured such that equity investors lack the ability to make significant decisions relating to the entity’s operations through voting rights or do not substantively participate in the gains or losses of the entity. A VIE is appropriately consolidated if the Partnership is considered to be the primary beneficiary. The VIE’s primary beneficiary is the entity that has both (1) the power to direct the activities of the VIE that most significantly impact the VIEs economic performance and (2) the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE.

 

As a result of its analysis, the Partnership continues to consolidate all legal entities in which it has a variable interest and for which it is considered to be the primary beneficiary. VIEs where the Partnership is not the primary beneficiary, but has a variable interest in the entity, are accounted for as equity investments.

 

Consolidated VIEs

The Partnership’s consolidated VIEs consist of the Partnership’s ILPs that holds interests in the Partnership’s pipeline systems. After considering the purpose and design of the ILPs and the risks that they were designed to create and pass through to the Partnership, the Partnership has concluded that it is the primary beneficiary of these ILPs because of the significant amount of variability that it absorbs from the ILPs’ economic performance.

 

The assets and liabilities held through these VIEs whose assets cannot be used for purposes other the settlement of the VIEs’ obligations are held through GTN, Tuscarora, Northern Border, Great Lakes and PNGTS due to their third party debt. The following table presents the total assets and liabilities of these entities that are included in the Partnership’s Consolidated Balance Sheet:

 

(unaudited)

 

 

 

 

(millions of dollars)

 

March 31, 2016

 

December 31, 2015

 

 

 

 

 

ASSETS (LIABILITIES)*

 

 

 

 

Accounts receivable and other

 

22

 

25

Inventories

 

6

 

6

Equity investments

 

1,083

 

965

Plant, property and equipment

 

864

 

872

Other assets

 

2

 

2

Accounts payable and accrued liabilities

 

(15)

 

(26)

Accounts payable to affiliates

 

(7)

 

(6)

Accrued interest

 

(5)

 

(1)

Current portion of long-term debt

 

(14)

 

(14)

Long-term debt

 

(326)

 

(326)

Other liabilities

 

(24)

 

(24)

 

*      North Baja and Bison, which are also assets held through our consolidated VIEs, were excluded as the assets of these entities can be used for purposes other than the settlement of the VIEs’ obligations.

 

NOTE 18                  SUBSEQUENT EVENTS

 

Management of the Partnership has reviewed subsequent events through May 5, 2016, the date the financial statements were issued, and concluded there were no events or transactions during this period that would require recognition or disclosure in the consolidated financial statements other than what is disclosed here and/or those already disclosed in the preceding notes.

 

On April 21, 2016, the board of directors of our General Partner declared the Partnership’s first quarter 2016 cash distribution in the amount of $0.89 per common unit payable on May 13, 2016 to unitholders of record as of May 2, 2016.

 

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Northern Border declared its first quarter 2016 distribution of $45 million on April 19, 2016, of which the Partnership will receive its 50 percent share or $23 million on May 2, 2016.

 

Great Lakes declared its first quarter 2016 distribution of $36 million on April 19, 2016, of which the Partnership will receive its 46.45 percent share or $17 million on May 2, 2016.

 

On April 29, 2016, Tuscarora entered into a $9.5 million unsecured variable rate term loan facility which requires yearly principal payments until its maturity on April 29, 2019. The variable interest is based on LIBOR plus an applicable margin.

 

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Item 2.   Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

The following discussion and analysis should be read in conjunction with the unaudited financial statements and notes included in Item 1. “Financial Statements” of this Quarterly Report on Form 10-Q, as well as our Annual Report on Form 10-K for the year ended December 31, 2015.

 

RECENT BUSINESS DEVELOPMENTS

 

Cash Distributions – On April 21, 2016, the board of directors of our General Partner declared the Partnership’s first quarter 2016 cash distribution in the amount of $0.89 per common unit, payable on May 13, 2016 to unitholders of record as of May 2, 2016.

 

PNGTS - On January 1, 2016, the Partnership acquired a 49.9 percent interest in PNGTS from a subsidiary of TransCanada. The total purchase price of the PNGTS Acquisition was $228 million and consisted of $193 million in cash (including the final purchase price adjustment of $5 million) and the assumption of $35 million in proportional PNGTS debt. This transaction adds a new market geography for us, further diversifying our cash flow stream and extending our breadth of operations.

 

Tuscarora - On January 21, 2016, the FERC issued an Order (the January 21 Order) initiating an investigation pursuant to Section 5 of the NGA to determine whether Tuscarora’s existing rates for jurisdictional services are just and reasonable. On April 5, 2016, Tuscarora filed with the FERC a cost and revenue study as required by the January 21 Order that supported its current rate levels. The Partnership cannot predict the outcome or potential impact of this proceeding to Tuscarora at this time.

 

 

HOW WE EVALUATE OUR OPERATIONS

 

We use certain non-GAAP financial measures that do not have any standardized meaning under GAAP because we believe they enhance the understanding of our operating performance.  We use the following non-GAAP measures:

 

EBITDA

 

We use EBITDA as a proxy of our operating cash flow and current operating profitability.

 

Distributable Cash Flows

 

Total distributable cash flow and distributable cash flow provide measures of distributable cash generated during the current earnings period.

 

RESULTS OF OPERATIONS

 

Net Income Attributable to Controlling Interests

 

We believe that the following presentation of the earnings contribution from each of our pipeline systems will enhance investors’ understanding of the way we analyze our financial performance. However, this presentation is not meant to be considered in isolation or as a substitute for results prepared in accordance with GAAP.

 

Our equity interests in Northern Border, Great Lakes, and effective January 1, 2016, PNGTS, and ownership of GTN, Bison, North Baja and Tuscarora were our only material sources of income during the period. Therefore, our results of operations and cash flows were influenced by, and reflect the same factors that influenced, our pipeline systems.

 

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Three months ended

(unaudited)

 

March 31,

(millions of dollars)

 

2016

 

2015

 

 

 

 

 

 

 

 

 

 

Net income:

 

 

 

 

GTN

 

24

 

24

Bison

 

12

 

11

North Baja

 

6

 

6

Tuscarora

 

4

 

4

Equity earnings:

 

 

 

 

Northern Border

 

18

 

20

Great Lakes

 

15

 

11

PNGTS

 

9

 

-

Partnership expenses

 

(15)

 

(12)

Net income

 

73

 

64

Net income attributable to non-controlling interests

 

-

 

7

Net income attributable to controlling interests

 

73

 

57

 

First Quarter 2016 Compared with First Quarter 2015

 

For the three months ended March 31, 2016, net income attributable to controlling interests increased by $16 million compared to the same period in 2015. The increase was primarily due to the net effect of:

 

·                    the 2015 GTN acquisition effective April 1, 2015, whereby the Partnership now owns 100 percent of GTN;

·                    equity earnings from our investment in PNGTS effective January 1, 2016;

·                    higher equity earnings from Great Lakes mainly due to higher transportation revenues during the period as a result of a timing difference on the recognition of the $14.1 million deferred revenues from ANR contracts during the previous period offset by higher pipeline integrity costs (refer to Note 11 within Item 1. “Financial Statement” for further information);

·                    lower equity earnings from Northern Border due to lower short-term revenues as a result of milder winter weather during 2016 compared to 2015; and

·                    higher Partnership expenses due to an increase in interest expense of approximately $4 million related to additional borrowings to fund a portion of recent acquisitions offset by approximately $1 million of costs incurred in the prior period relating to the 2015 GTN Acquisition.

 

Net Income Attributable to Common Units and Net Income per Common Unit

 

As discussed in Note 8 within Item 1. Financial Statements, we will allocate a portion of the Partnership’s income to the Class B Units after the annual threshold is exceeded which will effectively reduce the income allocable to the common units and net income per common unit. Currently, we expect to allocate a portion of the Partnership’s income to the Class B units beginning in the third quarter of 2016.

 

Please read also Note 7 within Item 1. “Financial Statements” for additional disclosures on the Class B units.

 

LIQUIDITY AND CAPITAL RESOURCES

 

Overview

 

Our principal sources of liquidity and cash flows include distributions received from our investments in partially-owned affiliates, operating cash flows from our subsidiaries, public offerings of debt and equity, term loans and our bank credit facility. The Partnership funds its operating expenses, debt service and cash distributions (including those distributions made to TransCanada through our General Partner and as holder of all our Class B units) primarily with operating cash flow. Long-term capital needs may be met through the issuance of long-term debt and/or equity. Overall, we believe that our pipeline systems’ ability to obtain financing at reasonable rates, together with a history of consistent cash flow from operating activities, provide a solid foundation to meet future liquidity and capital requirements. We expect to be able to fund our liquidity requirements, including our distributions and

 

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required debt repayments, at the Partnership level over the next 12 months utilizing our cash flow and, if required, our existing Senior Credit Facility.

 

The following table sets forth the available borrowing capacity under the Partnership’s Senior Credit Facility

 

(millions of dollars)

 

March 31, 2016

 

December 31, 2015

 

 

 

 

 

Total capacity under the Senior Credit Facility

 

500

 

500

Less: Outstanding borrowings under the Senior Credit Facility

 

370

 

200

Available capacity under the Senior Credit Facility

 

130

 

300

 

Our pipeline systems’ principal sources of liquidity are cash generated from operating activities, long-term debt offerings, bank credit facilities and equity contributions from their owners. Our pipeline systems have historically funded operating expenses, debt service and cash distributions to their owners primarily with operating cash flow. However, since the fourth quarter of 2010, Great Lakes has funded its debt repayments with cash calls to its owners.

 

Capital expenditures are funded by a variety of sources, including cash generated from operating activities, borrowings under bank credit facilities, issuance of senior unsecured notes or equity contributions from our pipeline systems’ owners. The ability of our pipeline systems to access the debt capital markets under reasonable terms depends on their financial position and general market conditions.

 

The Partnership’s pipeline systems monitor the creditworthiness of their customers and have credit provisions included in their tariffs which, although limited by FERC, allow them to request credit support as circumstances dictate.

 

 

EBITDA and Distributable Cash Flow

 

EBITDA is an approximate measure of our operating cash flow during the current earnings period and reconciles directly to the net income amount presented. It measures our earnings before deducting interest, depreciation and amortization, net income attributable to non-controlling interests, and it includes earnings from our equity investments.

 

Total distributable cash flow and distributable cash flow provide measures of distributable cash generated during the current earnings period and reconcile directly to the net income amount presented.

 

Total distributable cash flow includes EBITDA plus:

 

·                  Distributions from our equity investments

 

less:

 

·                  Earnings from our equity investments,

 

·                  Equity allowance for funds used during construction (Equity AFUDC),

 

·                  Interest expense,

 

·                  Distributions to non-controlling interests, and

 

·                  Maintenance capital expenditures

 

Distributable cash flow is computed net of distributions declared to the General Partner and distributions allocable to Class B units. Distributions declared to the General Partner are based on its two percent interest plus an amount equal to incentive distributions. Distributions allocable to the Class B units in 2016 equal 30 percent of GTN’s distributable cash flow less $20 million.

 

Distributable cash flow information and EBITDA are presented to assist investors’ in evaluating our business performance. We believe these measures provide additional meaningful information in evaluating our financial performance and cash distribution capability. In addition, management uses these measures as a basis for

 

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recommendations to our General Partner’s board of directors regarding the distribution amount to be declared each quarter.

 

The non-GAAP measures described above are provided as a supplement to GAAP financial results and are not meant to be considered in isolation or as substitutes for financial results prepared in accordance with GAAP. Additionally, these measures as presented may not be comparable to similarly titled measures of other companies.

 

The following table represents a reconciliation of our EBITDA, Total distributable cash flow and Distributable cash flow to the most directly comparable GAAP financial measure, Net income, for the periods presented:

 

Reconciliations of Net Income to Distributable Cash Flow

 

 

 

Three months ended

(unaudited)

 

March 31,

(millions of dollars)

 

2016

 

2015

Net income

 

73

 

64

 

 

 

 

 

Add:

 

 

 

 

Interest expense

 

17

 

13

Depreciation and amortization

 

21

 

21

 

 

 

 

 

EBITDA

 

111

 

98

 

 

 

 

 

Add:

 

 

 

 

Distributions from equity investments(a)

 

 

 

 

Northern Border

 

23

 

26

Great Lakes

 

17

 

14

PNGTS (b)

 

6

 

-

 

 

46

 

40

Less:

 

 

 

 

Equity earnings:

 

 

 

 

Northern Border

 

(18)

 

(20)

Great Lakes

 

(15)

 

(11)

PNGTS (b)

 

(9)

 

-

 

 

(42)

 

(31)

Less:

 

 

 

 

Interest expense

 

(17)

 

(13)

Distributions to non-controlling interests (c)

 

-

 

(11)

Maintenance capital expenditures (d)

 

(1)

 

(1)

 

 

 

 

 

Total Distributable Cash Flow (e)

 

97

 

82

General Partner distributions declared (f)

 

(2)

 

(1)

Distributions allocable to Class B units (g)

 

-

 

-

Distributable Cash Flow (e)

 

95

 

81

 

(a)              Amounts here are calculated in accordance with the cash distribution policies of these entities. Distributions from each of our equity investments represent our respective share of these entities’ quarterly distributable cash during the current reporting period.

(b)             Our equity investee PNGTS has $22 million of senior secured notes payment due in 2016, of which the Partnership’s share is approximately $11 million. While PNGTS debt repayments are not funded with cash calls to its owners, PNGTS has historically funded its scheduled debt repayments and other cash needs such as tax payments, by adjusting its available cash for distribution, which effectively reduces the net cash that we will receive as distributions from PNGTS.  Accordingly, this amount is net of our 49.9 percent share of the total debt repayment of PNGTS amounting to approximately $6 million during the quarter, resulting in a net distribution decrease of approximately $3 million.

 

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(c)              Amounts here are calculated in accordance with the cash distribution policies of our consolidated subsidiaries. Distributions to non-controlling interests represent our respective share of quarterly distributable cash during the current reporting period not owned by us.

(d)             The Partnership’s maintenance capital expenditures include cash expenditures made to maintain, over the long term, our operating capacity, system integrity and reliability.  Accordingly, this amount represents the Partnership’s and its consolidated subsidiaries maintenance capital expenditures and does not include the Partnership’s share of maintenance capital expenditures on our equity investments. Such amounts are reflected in “Distributions from equity investments” as those amounts are withheld by those entities from their quarterly distributable cash.

(e)              “Total Distributable Cash Flow” and “Distributable Cash Flow” represent the amount of distributable cash generated by the Partnership’s subsidiaries and equity investments during the current earnings period and thus reconcile directly to the net income amount presented. The calculation differs from the previous non-GAAP measure “Partnership Cash Flows before General Partner distributions” and “Partnership Cash Flows” as the previously used measures primarily reflected cash received during the period through distributions from our subsidiaries and equity investments that were generated from the prior quarter’s financial results. The amounts reflected here have been adjusted to reflect the calculation as described above and to present the comparable “Total Distributable Cash Flow” and “Distributable Cash Flow” from the previous period.

(f)               Distributions declared to the General Partner for the three months ended March 31, 2016 included an incentive distribution of approximately $1 million (2015 – $0.3 million).

(g)              During the three months ended March 31, 2016, 30 percent of GTN’s total distributions was $11 million, therefore, no distributions were allocated to the Class B units as the threshold level of $20 million has not been exceeded. We expect such threshold will be exceeded beginning the third quarter of 2016.

 

Please read Notes 7 and 8 within Item 1. “Financial Statements” for additional disclosures on the Class B units.

 

First Quarter 2016 Compared with First Quarter 2015

 

Our EBITDA increased by $13 million compared to the same period in 2015 mainly due to higher equity earnings from our equity investments.

 

Distributable cash flow increased by $14 million in the first quarter of 2016 compared to the same period in 2015 primarily due to distributable cash flow from our equity investment in PNGTS and 100 percent ownership in GTN, effective April 1, 2015.

 

Other Cash Flows

 

In the first quarter of 2016, the Partnership made an equity contribution of $4 million to Great Lakes, which was used to fund debt repayments.

 

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Contractual Obligations

 

The Partnership’s contractual obligations related to debt as of March 31, 2016 included the following:

 

 

 

Payments Due by Period

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(millions of dollars)

 

 

Total

 

Less
than
1 Year

 

1-3
Years

 

4-5
Years

 

More
than 5

Years

 

Weighted
Average
Interest Rate
for the Three
Months Ended
March 31,
2016

TC PipeLines, LP Senior Credit Facility due 2017

 

370

 

-

 

370

 

-

 

-

 

1.68%

TC PipeLines, LP 2013 Term Loan Facility due 2018

 

500

 

-

 

500

 

-

 

-

 

1.68%

TC PipeLines, LP 2015 Term Loan Facility due 2018

 

170

 

-

 

170

 

-

 

-

 

1.57%

TC PipeLines, LP 4.65% Senior Notes due 2021, net

 

350

 

-

 

-

 

-

 

350

 

4.65% (a)

TC PipeLines, LP 4.375% Senior Notes due 2025, net

 

350

 

-

 

-

 

-

 

350

 

4.375% (a)

GTN 5.29% Unsecured Senior Notes due 2020

 

100

 

-

 

-

 

100

 

-

 

5.29% (a)

GTN 5.69% Unsecured Senior Notes due 2035

 

150

 

-

 

-

 

-

 

150

 

5.69% (a)

GTN Unsecured Term Loan Facility due 2019

 

75

 

10

 

65

 

-

 

-

 

1.37%

Tuscarora 3.82% Series D Senior Notes due 2017

 

16

 

4

 

12

 

-

 

-

 

3.82% (a)

 

 

2,081

 

14

 

1,117

 

100

 

850

 

 

 

(a)              Fixed interest rate

 

The Partnership’s long-term debt results in exposures to changing interest rates. The Partnership uses derivatives to assist in managing its exposure to interest rate risk. Refer to Item 3. “Quantitative and Qualitative Disclosures About Market Risk” section for additional information regarding the derivatives.

 

The fair value of the Partnership’s long-term debt is estimated by discounting the future cash flows of each instrument at estimated current borrowing rates. The estimated fair value of the Partnership’s debt at March 31, 2016 was $2,037 million.

 

Please read Note 5 within Item 1. “Financial Information” for additional information regarding the Partnership’s debt.

 

Northern Border’s contractual obligations related to debt as of March 31, 2016 included the following:

 

 

 

Payments Due by Period

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(millions of dollars)

 

 

Total

 

Less
than
1 Year

 

1-3
Years

 

4-5
Years

 

More
than 5

Years

 

Weighted
Average
Interest Rate
for the Three
Months Ended
March 31,
2016

6.24% Senior Notes due 2016

 

100

 

100

 

-

 

-

 

-

 

6.24% (a)

7.50% Senior Notes due 2021

 

250

 

-

 

-

 

-

 

250

 

7.50% (a)

$200 million Credit Agreement due 2020 (a)

 

61

 

-

 

-

 

61

 

-

 

1.57%

 

 

411

 

100

 

-

 

61

 

250

 

 

(a)     Fixed interest rate

 

As of March 31, 2016, $61 million was outstanding under Northern Border’s $200 million revolving credit agreement, leaving $139 million available for future borrowings. At March 31, 2016, Northern Border was in compliance with all of its financial covenants.

 

Northern Border has commitments of $2 million as of March 31, 2016 in connection with various capital overhaul and other capital projects.

 

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Great Lakes’ contractual obligations related to debt as of March 31, 2016 included the following:

 

 

 

Payments Due by Period

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(millions of dollars)

 

 

Total

 

Less
than
1 Year

 

1-3
Years

 

4-5
Years

 

More
than 5

Years

 

Weighted
Average
Interest Rate
for the Three
Months Ended
March 31,
2016

6.73% series Senior Notes due 2017 to 2018

 

18

 

9

 

9

 

-

 

-

 

6.73% (a)

9.09% series Senior Notes due 2016 and 2021

 

60

 

10

 

20

 

20

 

10

 

9.09% (a)

6.95% series Senior Notes due 2019 and 2028

 

110

 

-

 

11

 

22

 

77

 

6.95% (a)

8.08% series Senior Notes due 2021 and 2030

 

100

 

-

 

-

 

10

 

90

 

8.08% (a)

 

 

288

 

19

 

40

 

52

 

177

 

 

 

(a) Fixed rate

 

Great Lakes is required to comply with certain financial, operational and legal covenants. Under the most restrictive covenants in the senior note agreements, approximately $155 million of Great Lakes’ partners’ capital was restricted as to distributions as of March 31, 2016 (December 31, 2015 – $160 million). Great Lakes was in compliance with all of its financial covenants at March 31, 2016.

 

Great Lakes has commitments of $3 million as of March 31, 2016 in connection with capital overhaul projects, cathodic protection capital program and gas flow computer replacements.

 

PNGTS’ contractual obligations related to debt as of March 31, 2016 included the following:

 

 

 

Payments Due by Period

 

 

 

 

(millions of dollars)

 

 

Total

 

Less
than
1 Year

 

1-3
Years

 

4-5
Years

 

More
than 5

Years

 

Weighted
Average
Interest Rate
for the Three
Months Ended
March 31,
2016

5.90% Senior Secured Notes due 2018

 

64

 

22

 

42

 

-

 

-

 

5.90% (a)

 

 

64

 

22

 

42

 

-

 

-

 

 

 

(a) Fixed rate

 

Other Cash Flow Matters

 

The Partnership made an equity contribution to Great Lakes of $4 million in the first quarter of 2016. This amount represents the Partnership’s 46.45 percent share of a $9 million cash call from Great Lakes to make a scheduled debt repayment. The Partnership expects to make an additional $5 million equity contribution to Great Lakes in the fourth quarter of 2016 to further fund debt repayments.

 

The Partnership’s equity investee Northern Border has $100 million of senior notes due in August 2016. This amount will be refinanced with a combination of debt and/or equity at the discretion of the management committee. If an equity contribution is elected to repay the senior notes, the Partnership will be expected to make an equity contribution of up to $50 million to Northern Border.

 

Our equity investee PNGTS has $16.5 million of senior secured notes payment due for the remainder of 2016, of which the Partnership’s share is approximately $8 million. While PNGTS debt repayments are not funded with cash calls to its owners, PNGTS has historically funded its scheduled debt repayments by adjusting its available cash for distribution, which effectively reduces the net cash that will be received by the Partnership as distributions from PNGTS.

 

Additionally, PNGTS is restricted under the terms of their note purchase agreement from making cash distributions to its partners unless certain conditions are met. Before a distribution can be made, the debt service reserve account

 

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must be fully funded, and PNGTS debt service coverage ratio for the preceding and succeeding twelve months must be 1.30 or greater.

 

GTN has commitments of $3.2 million as of March 31, 2016 in connection with the closeout costs relating to the Carty Lateral project, various capital overhauls and other capital projects.

 

2016 First Quarter Cash Distribution

 

On April 21, 2016, the board of directors of our General Partner declared the Partnership’s first quarter 2016 cash distribution in the amount of $0.89 per common unit payable on May 13, 2016 to unitholders of record as of May 3, 2016.  Please read Item 2. “Management Discussion and Analysis of Financial Condition and Results of Operations - Recent Business Developments.”

 

Critical Accounting Estimates and Accounting Policy Changes

 

The preparation of financial statements in accordance with GAAP requires us to make estimates and assumptions with respect to values or conditions, which cannot be known with certainty, that affect the reported amount of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements. Such estimates and assumptions also affect the reported amounts of revenue and expenses during the reporting period. Although we believe these estimates and assumptions are reasonable, actual results could differ. There were no significant changes to the Partnership’s critical accounting estimates during the three months ended March 31, 2016. Information about our critical accounting estimates is included in our Annual Report on Form 10-K for the year ended December 31, 2015.

 

Our significant accounting policies have remained unchanged since December 31, 2015 except as described within Note 3 in Item 1. “Financial Statements” of this Quarterly Report on Form 10-Q.  A summary of our significant accounting policies can be found in our Annual Report on Form 10-K for the year ended December 31, 2015.

 

RELATED PARTY TRANSACTIONS

 

Please read Note 11 within Item 1. “Financial Statements” for information regarding related party transactions.

 

Item 3.           Quantitative and Qualitative Disclosures About Market Risk

 

OVERVIEW

 

The Partnership and our pipeline systems are exposed to market risk, counterparty credit risk, and liquidity risk. Our exposure to market risk discussed below includes forward-looking statements and is not necessarily indicative of actual results, which may not represent the maximum possible gains and losses that may occur, since actual gains and losses will differ from those estimated, based on actual market conditions.

 

Our primary risk management objective is to mitigate the impact of these risks on earnings and cash flow, and ultimately, unitholder value. We do not use financial instruments for trading purposes.

 

We record derivative financial instruments on the balance sheet as assets and liabilities at fair value. We estimate the fair value of derivative financial instruments using available market information and appropriate valuation techniques. Changes in the fair value of derivative financial instruments are recognized in earnings unless the instrument qualifies as a hedge and meets specific hedge accounting criteria. Qualifying derivative financial instruments’ gains and losses may offset the hedged items’ related results in earnings for a fair value hedge or be deferred in accumulated other comprehensive income for a cash flow hedge.

 

MARKET RISK

 

From time to time, and in order to finance our business and that of our pipeline systems, the Partnership and our pipeline systems issue debt to invest in growth opportunities and provide for ongoing operations. The issuance of floating rate debt exposes the Partnership and our pipeline systems to market risk from changes in interest rates which affect earnings and the value of the financial instruments we hold.

 

Market risk is the risk that changes in market interest rates may result in fluctuations in the fair values or cash flows of financial instruments. We regularly assess the impact of interest rate fluctuations on future cash flows and evaluate hedging opportunities to mitigate our interest rate risk.

 

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As of March 31, 2016, the Partnership’s interest rate exposure resulted from our floating rate Senior Credit Facility, 2015 Term Loan Facility and GTN’s Unsecured Term Facility, under which $615 million, or 30 percent, of our outstanding debt was subject to variability in LIBOR interest rates. As of December 31, 2015, the Partnership’s interest rate exposure resulted from our floating rate Senior Credit Facility, unhedged portion of 2013 Term Loan Facility amounting to $350 million and Short-Term Loan Facility under which $795 million or 42 percent of our outstanding debt was subject to variability in LIBOR interest rates.  As of March 31, 2016, the variable interest rate exposure related to 2013Term Loan Facility was hedged by fixed interest rate swap arrangements. If interest rates hypothetically increased (decreased) by one percent, 100 basis points, compared with rates in effect at March 31, 2016, our annual interest expense would increase (decrease) and net income would decrease (increase) by approximately $6 million.

 

As of March 31, 2016, $61 million, or 15 percent, of Northern Border’s outstanding debt was at floating rates (December 31, 2015 – $61 million or 15 percent). If interest rates hypothetically increased (decreased) by one percent, 100 basis points, compared with rates in effect at March 31, 2016, Northern Border’s annual interest expense would increase (decrease) and its net income would decrease (increase) by approximately $1 million.

 

GTN’s Unsecured Senior Notes, Northern Border’s Senior Notes, all of Great Lakes and Tuscarora’s debt are fixed-rates; therefore, they are not exposed to market risk due to floating interest rates. Interest rate risk does not apply to Bison and North Baja, as they currently do not have any debt.

 

The Partnership and our pipeline systems use derivatives as part of our overall risk management policy to assist in managing exposures to market risk resulting from these activities within established policies and procedures. Derivative contracts used to manage market risk generally consist of the following:

 

·                  Swaps – contractual agreements between two parties to exchange streams of payments over time according to specified terms.

 

·                  Options – contractual agreements to convey the right, but not the obligation, for the purchaser to buy or sell a specific amount of a financial instrument at a fixed price, either at a fixed date or at any time within a specified period.

 

The Partnership hedged interest payments on the variable-rate 2013 Term Loan Facility with interest rate swaps maturing July 1, 2018, at a weighted average fixed interest rate of 2.31 percent. At March 31, 2016, the fair value of the interest rate swaps accounted for as cash flow hedges was a liability of $4 million (both on a gross and net basis) (December 31, 2015 - $1 million). The Partnership did not record any amounts in net income related to ineffectiveness for interest rate hedges for the three months ended March 31, 2016 and 2015. The change in fair value of interest rate derivative instruments recognized in other comprehensive income was a loss of $2 million for the three months ended March 31, 2016 (2015 – $1 million). For the three months ended March 31, 2016, the net realized loss related to the interest rate swaps was nil million and was included in financial charges and other (2015 – $1 million).

 

The Partnership has no master netting agreements; however, it has derivative contracts containing provisions with rights of offset. The Partnership has elected to present the fair value of derivative instruments with the right to offset on a gross basis in the balance sheet. Had the Partnership elected to present these instruments on a net basis, there would be no effect on the consolidated balance sheet as of March 31, 2016 and December 31, 2015.

 

OTHER RISKS

 

Counterparty credit risk represents the financial loss that the Partnership and our pipeline systems would experience if a counterparty to a financial instrument failed to meet its obligations in accordance with the terms and conditions of the financial instruments with the Partnership or its pipeline systems. The Partnership and our pipeline systems have significant credit exposure to financial institutions as they provide committed credit lines and critical liquidity in the interest rate derivative market, as well as letters of credit to mitigate exposures to non-creditworthy customers. The Partnership closely monitors the creditworthiness of our counterparties, including financial institutions. However, we cannot predict to what extent our business would be impacted by uncertainty in energy commodity prices, including possible declines in our customers’ creditworthiness.

 

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Our maximum counterparty credit exposure with respect to financial instruments at the balance sheet date consists primarily of the carrying amount, which approximates fair value, of non-derivative financial assets, such as accounts receivable, as well as the fair value of derivative financial assets. We review our accounts receivable regularly and record allowances for doubtful accounts using the specific identification method. At March 31, 2016, we had not incurred any significant credit losses and had no significant amounts past due or impaired. At March 31, 2016, the Partnership’s maximum counterparty credit exposure consisted of accounts receivable of $30 million and two of our customers, Anadarko Energy Services Company and Pacific Gas and Electric Company owed us approximately $4 million and $3 million, respectively, which represented greater than 10 percent of our accounts receivable.

 

Liquidity risk is the risk that the Partnership and our pipeline systems will not be able to meet our financial obligations as they become due. Our approach to managing liquidity risk is to ensure that we always have sufficient cash and credit facilities to meet our obligations when due, under both normal and stressed conditions, without incurring unacceptable losses or damage to our reputation. At March 31, 2016, the Partnership had a committed revolving bank line of $500 million maturing in 2017 and the outstanding balance on this facility was $370 million. In addition, at March 31, 2016, Northern Border had a committed revolving bank line of $200 million maturing in 2020 and $61 million was drawn.

 

Item 4.                                 Controls and Procedures

 

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

 

As required by Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) the management of our General Partner, including the principal executive officer and principal financial officer, evaluated as of the end of the period covered by this report the effectiveness of our disclosure controls and procedures. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. The Partnership’s disclosure controls and procedures are designed to provide reasonable assurance of achieving their objectives. Based upon and as of the date of the evaluation, the management of our General Partner, including the principal executive officer and principal financial officer, concluded that the Partnership’s disclosure controls and procedures as of the end of the period covered by this quarterly report were effective to provide reasonable assurance that the information required to be disclosed by the Partnership in the reports that it files or submits under the Exchange Act, is (a) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and (b) accumulated and communicated to the management of our General Partner, including the principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.

 

Changes in Internal Control Over Financial Reporting

 

During the quarter ended March 31, 2016, there was no change in the Partnership’s internal control over financial reporting that has materially affected or is reasonably likely to materially affect its reported results of operations.

 

PART II – OTHER INFORMATION

 

Item 1.                                                         Legal Proceedings

 

We are involved in various legal proceedings that arise in the ordinary course of business, as well as proceedings that we consider material under federal securities regulations. For additional information on other legal and environmental proceedings affecting the Partnership, please refer to Part 1. Item 3 of the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2015.

 

Great Lakes v. Essar Steel Minnesota LLC, et al. –  A description of this legal proceeding can be found in Notes to Consolidated Financial Statements –Note 15 Contingencies in Part I, Item 1, of this Quarterly Report on Form 10-Q, and is incorporated herein by reference.

 

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Employees Retirement System of City of St Louis lawsuit-  A description of this legal proceeding can be found in Notes to Consolidated Financial Statements –Note 15 Contingencies in Part I, Item 1, of this Quarterly Report on Form 10-Q, and is incorporated herein by reference.

 

In addition to the above written matter, we and our pipeline systems are parties to lawsuits and governmental proceedings that arise in the ordinary course of our business.

 

Item 1A.                                                Risk Factors

 

TransCanada’s acquisition of Columbia Pipeline Group could change the pace and scope of future acquisitions by the Partnership.

 

With the intended acquisition of additional U.S. natural gas pipeline assets, TransCanada’s actual funding needs and broader business strategies may change.  There can be no assurance of how this intended acquisition may influence TransCanada’s views of future transactions with the Partnership.

 

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Item 6.                                                         Exhibits

Exhibits designated by an asterisk (*) are filed herewith and those designated with asterisks (**) are furnished herewith; all exhibits not so designated are incorporated herein by reference to a prior filing as indicated.

 

No.

 

Description

 

 

 

31.1*

 

Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2*

 

Certification of Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1**

 

Certification of Principal Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2**

 

Certification of Principal Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.INS*

 

XBRL Instance Document.

101.SCH*

 

XBRL Taxonomy Extension Schema Document.

101.CAL*

 

XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF*

 

XBRL Taxonomy Definition Linkbase Document.

101.LAB*

 

XBRL Taxonomy Extension Label Linkbase Document.

101.PRE*

 

XBRL Taxonomy Extension Presentation Linkbase Document.

 

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SIGNATURES

 

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on this 5th day of May 2016.

 

 

TC PIPELINES, LP

 

(A Delaware Limited Partnership)

 

by its General Partner, TC PipeLines GP, Inc.

 

 

 

By:

/s/ Brandon Anderson

 

 

 

Brandon Anderson

 

 

President

 

 

TC PipeLines GP, Inc. (Principal Executive Officer)

 

 

 

 

By:

/s/ Nathaniel A. Brown

 

 

 

Nathaniel A. Brown

 

 

Controller

 

 

TC PipeLines GP, Inc. (Principal Financial Officer)

 

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EXHIBIT INDEX

Exhibits designated by an asterisk (*) are filed herewith and those designated with asterisks (**) are furnished herewith; all exhibits not so designated are incorporated herein by reference to a prior filing as indicated.

 

No.

 

Description

31.1*

 

Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2*

 

Certification of Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1**

 

Certification of Principal Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2**

 

Certification of Principal Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.INS*

 

XBRL Instance Document.

101.SCH*

 

XBRL Taxonomy Extension Schema Document.

101.CAL*

 

XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF*

 

XBRL Taxonomy Definition Linkbase Document.

101.LAB*

 

XBRL Taxonomy Extension Label Linkbase Document.

101.PRE*

 

XBRL Taxonomy Extension Presentation Linkbase Document.