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EX-31.2 - EX-31.2 CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER PURSUANT TO SECTION 302 - TC PIPELINES LPa16-11477_1ex31d2.htm
EX-32.2 - EX-32.2 CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER PURSUANT TO SECTION 906 - TC PIPELINES LPa16-11477_1ex32d2.htm
EX-32.1 - EX-32.1 CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER PURSUANT TO SECTION 906 - TC PIPELINES LPa16-11477_1ex32d1.htm
EX-31.1 - EX-31.1 CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER PURSUANT TO SECTION 302 - TC PIPELINES LPa16-11477_1ex31d1.htm

 

 

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 June 30, 2016

 

or

 

¨

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

Smaller reporting company o

(Do not check if a smaller reporting

 

company)

 

 

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 August 2, 2016, there were 65,937,080 of the registrant’s common units outstanding.

 

 

 



 

TC PIPELINES, LP

 

 

Page No.

 

 

TABLE OF CONTENTS

 

 

 

 

PART I

FINANCIAL INFORMATION

 

 

 

 

Item 1.

Financial Statements (Unaudited)

5

Item 2.

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

25

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

35

Item 4.

Controls and Procedures

37

 

 

 

PART II

OTHER INFORMATION

 

 

 

 

Item 1.

Legal Proceedings

37

Item 1A.

Risk Factors

38

Item 6.

Exhibits

40

 

Signatures

41

 

All amounts are stated in United States dollars unless otherwise indicated.

 

2



 

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

 

3



 

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,” “assume, “ “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:

·                  demand for natural gas;

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

·                  natural gas prices and regional differences;

·                  weather conditions;

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

·                  competition from other pipeline systems;

·                  natural gas storage levels; and

·                  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, terms and closure of future potential acquisitions;

·                                          the outcome of TransCanada’s master limited partnership (MLP) strategy review;

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

·                                          the impact of any impairment charges;

·                                          cybersecurity threats, acts of terrorism and related disruptions;

·                                          the impact of new accounting pronouncements;

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

·                                          potential of claims for rescission or loss in connection with certain sales under our at-the-market equity issuance program (ATM program); and

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

 

These and other risks are described elsewhere in this Form 10-Q, including the risks described in greater detail in Part II, Item 1A “Risk Factors” and those described in Part I, Item 1A. “Risk Factors” in our Form 10-K for the year ended December 31, 2015. All 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.

 

4



 

PART I — FINANCIAL INFORMATION

 

Item 1.                                 Financial Statements

 

TC PIPELINES, LP

CONSOLIDATED STATEMENTS OF INCOME

 

 

 

Three months ended

 

 

Six months ended

 

 

(unaudited)

 

June 30,

 

 

June 30,

 

 

(millions of dollars, except per common unit amounts)

 

2016

 

 

2015

 

 

2016

 

 

2015

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Transmission revenues

 

89

 

 

85

 

 

175

 

 

172

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity earnings (Note 4)

 

22

 

 

15

 

 

64

 

 

46

 

 

Operation and maintenance expenses

 

(12

)

 

(13

)

 

(22

)

 

(24

)

 

Property taxes

 

(5

)

 

(5

)

 

(10

)

 

(11

)

 

General and administrative

 

(2

)

 

(1

)

 

(4

)

 

(4

)

 

Depreciation

 

(22

)

 

(21

)

 

(43

)

 

(42

)

 

Financial charges and other (Note 14)

 

(16

)

 

(16

)

 

(33

)

 

(29

)

 

Net income

 

54

 

 

44

 

 

127

 

 

108

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income attributable to non-controlling interests

 

 

 

 

 

 

 

7

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income attributable to controlling interests

 

54

 

 

44

 

 

127

 

 

101

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income attributable to controlling interest allocation

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Common units

 

50

 

 

42

 

 

121

 

 

98

 

 

General Partner

 

3

 

 

2

 

 

5

 

 

3

 

 

Class B units

 

1

 

 

 

 

1

 

 

 

 

 

 

54

 

 

44

 

 

127

 

 

101

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

$

0.76

 

 

$

0.66

 

 

$

1.86

 

 

$

1.53

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Weighted average common units outstanding basic and diluted (millions)

 

65.5

 

 

63.8

 

 

64.9

 

 

63.7

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Common units outstanding, end of period (millions)

 

65.9

 

 

64.0

 

 

65.9

 

 

64.0

 

 

 

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

 

5



 

TC PIPELINES, LP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

 

 

 

Three months ended

 

 

Six months ended

 

 

(unaudited)

 

June 30,

 

 

June 30,

 

 

(millions of dollars)

 

2016

 

 

2015

 

 

2016

 

 

2015

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income

 

54

 

 

44

 

 

127

 

 

108

 

 

Other comprehensive income

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

(1

)

 

 

 

(3

)

 

(1

)

 

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

 

 

 

 

 

 

 

 

 

Comprehensive income

 

53

 

 

44

 

 

124

 

 

107

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Comprehensive income attributable to non-controlling interests

 

 

 

 

 

 

 

7

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Comprehensive income attributable to controlling interests

 

53

 

 

44

 

 

124

 

 

100

 

 

 

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

 

6



 

TC PIPELINES, LP

CONSOLIDATED BALANCE SHEETS

 

(unaudited)

 

 

 

 

 

 

 

(millions of dollars)

 

June 30, 2016

 

 

December 31, 2015

 

 

 

 

 

 

 

 

 

 

ASSETS

 

 

 

 

 

 

 

Current Assets

 

 

 

 

 

 

 

Cash and cash equivalents

 

40

 

 

39

 

 

Accounts receivable and other (Note 13)

 

35

 

 

35

 

 

Distribution receivable from affiliate (Note 11)

 

4

 

 

 

 

Inventories

 

7

 

 

7

 

 

 

 

86

 

 

81

 

 

Equity investments (Note 4)

 

1,047

 

 

965

 

 

Plant, property and equipment

 

 

 

 

 

 

 

(Net of $850 accumulated depreciation; 2015 - $811)

 

1,913

 

 

1,949

 

 

Goodwill

 

130

 

 

130

 

 

Other assets (Note 3)

 

 

 

1

 

 

 

 

3,176

 

 

3,126

 

 

 

 

 

 

 

 

 

 

LIABILITIES AND PARTNERS’ EQUITY

 

 

 

 

 

 

 

Current Liabilities

 

 

 

 

 

 

 

Accounts payable and accrued liabilities

 

26

 

 

32

 

 

Accounts payable to affiliates (Note 11)

 

5

 

 

5

 

 

Accrued interest

 

9

 

 

8

 

 

Current portion of long-term debt (Note 5)

 

15

 

 

14

 

 

 

 

55

 

 

59

 

 

Long-term debt (Notes 3 and 5)

 

1,938

 

 

1,889

 

 

Other liabilities

 

29

 

 

27

 

 

 

 

2,022

 

 

1,975

 

 

 

 

 

 

 

 

 

 

Common units subject to rescission (Note 7)

 

83

 

 

 

 

 

 

 

 

 

 

 

 

Partners’ Equity

 

 

 

 

 

 

 

Common units

 

955

 

 

1,021

 

 

Class B units (Note 7)

 

96

 

 

107

 

 

General partner

 

25

 

 

25

 

 

Accumulated other comprehensive loss

 

(5

)

 

(2

)

 

Controlling interests

 

1,071

 

 

1,151

 

 

 

 

3,176

 

 

3,126

 

 

 

Contingencies (Note 15)

Variable Interest Entities (Note 17)

Subsequent Events (Note 18)

 

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

 

7



 

TC PIPELINES, LP

CONSOLIDATED STATEMENT OF CASH FLOWS

 

 

 

Six months ended

 

 

(unaudited)

 

June 30,

 

 

(millions of dollars)

 

2016

 

 

2015

 

 

 

 

 

 

 

 

 

 

Cash Generated From Operations

 

 

 

 

 

 

 

Net income

 

127

 

 

108

 

 

Depreciation

 

43

 

 

42

 

 

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

 

1

 

 

1

 

 

Equity allowance for funds used during construction

 

 

 

(1

)

 

Equity earnings in excess of cumulative distributions:

 

 

 

 

 

 

 

PNGTS

 

(4

)

 

 

 

Change in operating working capital (Note 10)

 

3

 

 

1

 

 

 

 

170

 

 

151

 

 

Investing Activities

 

 

 

 

 

 

 

Cumulative distributions in excess of equity earnings:

 

 

 

 

 

 

 

Northern Border

 

25

 

 

13

 

 

Great Lakes

 

17

 

 

10

 

 

Investment in Great Lakes

 

(4

)

 

(4

)

 

Acquisition of the remaining 30 percent interest in GTN

 

 

 

(264

)

 

Acquisition of PNGTS (Note 6)

 

(193

)

 

 

 

Capital expenditures

 

(18

)

 

(12

)

 

Other

 

2

 

 

(1

)

 

 

 

(171

)

 

(258

)

 

Financing Activities

 

 

 

 

 

 

 

Distributions paid (Note 9)

 

(119

)

 

(110

)

 

Distributions paid to Class B units (Note 7)

 

(12

)

 

 

 

Distributions paid to non-controlling interests

 

 

 

(9

)

 

Common unit issuance, net

 

 

 

26

 

 

Common unit issuance subject to rescission, net (Note 7)

 

83

 

 

 

 

Equity contribution by the General Partner

 

 

 

2

 

 

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

 

205

 

 

424

 

 

Long-term debt repaid (Note 5)

 

(155

)

 

(205

)

 

Debt issuance costs

 

 

 

(3

)

 

 

 

2

 

 

125

 

 

Increase in cash and cash equivalents

 

1

 

 

18

 

 

Cash and cash equivalents, beginning of period

 

39

 

 

26

 

 

Cash and cash equivalents, end of period

 

40

 

 

44

 

 

 

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

 

8



 

TC PIPELINES, LP

CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS’ EQUITY

 

 

 

 

 

 

 

 

 

 

 

 

Accumulated

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Other

 

 

 

 

 

 

 

Limited Partners

 

 

General

 

 

Comprehensive

 

 

Total

 

 

(unaudited)

 

Common Units

 

 

Class B Units

 

 

Partner

 

 

Loss (a)

 

 

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

 

 

 

121

 

 

 

 

1

 

 

5

 

 

 

 

127

 

 

Other Comprehensive Loss

 

 

 

 

 

 

 

 

 

 

 

(3

)

 

(3

)

 

Common unit issuance subject to rescission, net (Note 7)

 

1.6

 

 

81

 

 

 

 

 

 

2

 

 

 

 

83

 

 

Reclassification of common unit issuance subject to rescission, net (Note 7)

 

(1.6

)

 

(81

)

 

 

 

 

 

(2

)

 

 

 

(83

)

 

Acquisition of PNGTS (Note 6)

 

 

 

(72

)

 

 

 

 

 

(1

)

 

 

 

(73

)

 

Distributions

 

 

 

(115

)

 

 

 

(12

)

 

(4

)

 

 

 

(131

)

 

Partners’ Equity at June 30, 2016

 

64.3

 

 

955

 

 

1.9

 

 

96

 

 

25

 

 

(5

)

 

1,071

 

 

 


(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.

 

9



 

TC PIPELINES, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

 

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 and six months ended June 30, 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.

 

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, Variable Interest Entities.

 

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.

 

10



 

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 the Partnership’s consolidated financial statements.

 

Future accounting changes

 

Revenue from contracts with customers

 

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. This guidance supersedes the current revenue recognition requirements and most industry-specific guidance. The core principle relating to the new guidance requires that an entity recognize 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. To achieve the core principle, a five step process is required:

 

1) Identify the contract with the customer

2) Identify the performance obligations in the contract

3) Determine the transaction price

4) Allocate the transaction price to the performance obligations

5) Recognize revenue when (or as) each performance obligations is satisfied

 

11



 

The new guidance also specifies the accounting for some costs to obtain or fulfill a contract, as well as enhanced disclosure requirements.  The Partnership is currently identifying existing customer contracts or groups of contracts that are within the scope of the new guidance and that will require an assessment in order to determine any impact 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 identifying existing lease agreements that are within the scope of the new guidance that may have an impact 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 1, 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 subsidiaries of 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, Accounting Pronouncements and Note 17, Variable Interest Entities.

 

 

 

Ownership

 

Equity Earnings from Unconsolidated Affiliates

 

Investments in
Unconsolidated Affiliates

 

 

 

Interest at

 

Three months

 

 

Six Months

 

 

 

 

 

 

 

(unaudited)

 

June 30,

 

ended June 30,

 

 

ended June 30,

 

 

June 30,

 

December 31,

 

 

(millions of dollars)

 

2016

 

2016

 

2015

 

 

2016

 

2015

 

 

2016

 

2015

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Northern Border (a)

 

50

%

16

 

15

 

 

34

 

34

 

 

455

 

480

 

 

Great Lakes

 

46.45

%

4

 

 

 

19

 

12

 

 

472

 

485

 

 

PNGTS (b)

 

49.90

%

2

 

 

 

11

 

 

 

120

 

 

 

 

 

 

 

22

 

15

 

 

64

 

46

 

 

1,047

 

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 and six months ended June 30, 2016, the Partnership recorded no undistributed earnings from PNGTS.

 

12



 

Northern Border

 

The Partnership did not have undistributed earnings from Northern Border for the three and six months ended June 30, 2016 and 2015.

 

The summarized financial information for Northern Border is as follows:

 

(unaudited)

 

 

 

 

 

 

 

(millions of dollars)

 

June 30, 2016

 

 

December 31, 2015

 

 

 

 

 

 

 

 

 

 

ASSETS

 

 

 

 

 

 

 

Cash and cash equivalents

 

16

 

 

27

 

 

Other current assets

 

34

 

 

33

 

 

Plant, property and equipment, net

 

1,108

 

 

1,124

 

 

Other assets (a)

 

15

 

 

16

 

 

 

 

1,173

 

 

1,200

 

 

 

 

 

 

 

 

 

 

LIABILITIES AND PARTNERS’ EQUITY

 

 

 

 

 

 

 

Current liabilities

 

40

 

 

39

 

 

Deferred credits and other

 

27

 

 

26

 

 

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

 

429

 

 

409

 

 

Partners’ equity

 

 

 

 

 

 

 

Partners’ capital

 

679

 

 

728

 

 

Accumulated other comprehensive loss

 

(2

)

 

(2

)

 

 

 

1,173

 

 

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

 

 

Six months ended

 

 

(unaudited)

 

June 30,

 

 

June 30,

 

 

(millions of dollars)

 

2016

 

 

2015

 

 

2016

 

 

2015

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Transmission revenues

 

70

 

 

69

 

 

144

 

 

144

 

 

Operating expenses

 

(18

)

 

(18

)

 

(35

)

 

(34

)

 

Depreciation

 

(15

)

 

(14

)

 

(29

)

 

(29

)

 

Financial charges and other

 

(6

)

 

(6

)

 

(11

)

 

(11

)

 

Net income

 

31

 

 

31

 

 

69

 

 

70

 

 

 

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 and six months ended June 30, 2016 and 2015.

 

13



 

The summarized financial information for Great Lakes is as follows:

 

(unaudited)

 

 

 

 

 

 

 

(millions of dollars)

 

June 30, 2016

 

 

December 31, 2015

 

 

 

 

 

 

 

 

 

 

ASSETS

 

 

 

 

 

 

 

Current assets

 

53

 

 

86

 

 

Plant, property and equipment, net

 

721

 

 

727

 

 

 

 

774

 

 

813

 

 

 

 

 

 

 

 

 

 

LIABILITIES AND PARTNERS’ EQUITY

 

 

 

 

 

 

 

Current liabilities

 

29

 

 

31

 

 

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

 

288

 

 

297

 

 

Partners’ equity

 

457

 

 

485

 

 

 

 

774

 

 

813

 

 

 


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

 

 

 

Three months ended

 

 

Six months ended

 

 

(unaudited)

 

June 30,

 

 

June 30,

 

 

(millions of dollars)

 

2016

 

 

2015

 

 

2016

 

 

2015

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Transmission revenues

 

36

 

 

28

 

 

97

 

 

76

 

 

Operating expenses

 

(15

)

 

(14

)

 

(30

)

 

(25

)

 

Depreciation

 

(7

)

 

(7

)

 

(14

)

 

(14

)

 

Financial charges and other

 

(5

)

 

(6

)

 

(11

)

 

(12

)

 

Net income

 

9

 

 

1

 

 

42

 

 

25

 

 

 

NOTE 5                         DEBT AND CREDIT FACILITIES

 

(unaudited)
(millions of dollars)

 

June 30,
2016

 

 

December 31,
2015

 

 

Weighted Average
Interest Rate for the
Six Months Ended
June 30, 2016

 

 

 

 

 

 

 

 

 

 

 

 

 

TC PipeLines, LP Senior Credit Facility due 2017

 

250

 

 

200

 

 

1.69

%

 

TC PipeLines, LP 2013 Term Loan Facility due 2018

 

500

 

 

500

 

 

1.69

%

 

TC PipeLines, LP 2015 Term Loan Facility due 2018

 

170

 

 

170

 

 

1.58

%

 

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

 

65

 

 

75

 

 

1.38

%

 

Tuscarora Unsecured Term Loan due 2019

 

10

 

 

 

 

1.57

%

 

Tuscarora 3.82% Series D Senior Notes due 2017

 

16

 

 

16

 

 

3.82

%(b)

 

 

 

1,961

 

 

1,911

 

 

 

 

 

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

 

8

 

 

8

 

 

 

 

 

Less: current portion

 

15

 

 

14

 

 

 

 

 

 

 

1,938

 

 

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, Accounting Pronouncements.

(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 $250 million was outstanding at June 30, 2016 (December 31, 2015 - $200 million), leaving $250 million available for future borrowing.

 

14



 

After hedging activity, the interest rate incurred on the 2013 Term Loan Facility averaged 2.31 percent and 2.25 percent for the three and six months ended June 30, 2016, respectively (2015 — 1.84 percent). Prior to hedging activities, the LIBOR-based interest rate was 1.71 percent at June 30, 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]) no greater than:

 

·                  5.50 to 1.00 for the quarters ending June 30, 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 4.37 to 1.00 as of June 30, 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 June 30, 2016 was 43.7 percent.

 

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 and was 1.59 percent at June 30, 2016.

 

Tuscarora’s 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 June 30, 2016 was 24 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 4.57 to 1.00 as of June 30, 2016.

 

At June 30, 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

 

4

 

2017

 

273

 

2018

 

691

 

2019

 

43

 

2020

 

100

 

Thereafter

 

850

 

 

 

1,961

 

 

15



 

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 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.

 

The net purchase price was allocated as follows:

 

(unaudited)
(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

 

In the six months ended June 30, 2016, we issued 1,619,631 common units under our ATM program generating net proceeds of approximately $81 million, plus $2 million from the General Partner to maintain its effective two percent interest. The commissions to our sales agents for the six months ended June 30, 2016 were approximately $823,000. The net proceeds were used for general partnership purposes.

 

On July 29, 2016, we filed a new shelf registration with the Securities Exchange Commission (SEC) to register an additional $400 million of common units. On August 2, 2016, we requested accelerated effectiveness of the amended shelf registration statement.

 

Common unit issuance subject to rescission

 

On July 17, 2014, the SEC declared effective a registration statement (the Registration Statement) that we had filed to cover sales of Common Units under our ATM program. On February 26, 2016, at the time of the filing of the 2015 Form 10-K, we believed that the Partnership continued to be eligible to use the effective Registration Statement to sell Common Units under our ATM program.  However, we have been advised by the SEC on June 23, 2016 that as a result of the untimely filing of an employee-related Form 8-K on October 28, 2015, which was not filed via  EDGAR until 6:02 p.m. Eastern Time (32 minutes after the 5:30 p.m. Eastern Time cutoff), the Partnership was ineligible to use the Registration Statement after the filing of the 2015 Form 10-K.

 

Because the Partnership  was ineligible to continue using the Registration Statement following the filing of the 2015 Form 10-K, it is possible that the sales of an aggregate 1,619,631 Common Units under the Registration Statement (the ATM Common Units), which were sold between March 8, 2016 and May 19, 2016 at per Common Unit prices ranging from $47.00 to $54.95, may be deemed to have been unregistered sales of securities.  If it is determined that persons who purchased the ATM Common Units from the Partnership after February 26, 2016, purchased such

 

16



 

Common Units in an offering deemed to be unregistered, then to the extent there may have been a violation of federal securities laws such persons may be entitled to rescission rights, pursuant to which they could be entitled to recover the amount paid for such ATM Common Units, plus interest (based on the statutory rate under applicable state law), less the amount of any distributions.  If such investor has sold any of the ATM Common Units purchased by the investor, then the investor would be entitled to recover the difference between the amount paid for such ATM Common Units and the amount at which such ATM Common Units were sold, assuming the investor’s ATM Common Units were sold at a loss, plus interest and less the amount of any distributions. If all of the investors who purchased the ATM Common Units from the Partnership after February 26, 2016 continue to own all of the ATM Common Units and were to demand rescission of their purchases, and such investors were in fact found to be entitled to such rescission, then we would be obligated to repay approximately $82,334,015, plus interest, less the amount of any distributions.  The Securities Act generally requires that any claim brought for a violation of Section 5 of the Securities Act be brought within one year of the violation.

 

As a result, at June 30, 2016, the Partnership classified all the 1.6 million common units issued under its ATM program after February 26, 2016 up to and including June 30, 2016, which may be subject to rescission rights, outside of equity given the potential redemption feature which is not within the control of the Partnership. These units are treated as outstanding for financial reporting purposes.

 

The total amount transferred  outside of equity was approximately $83 million which includes interest and less distributions paid and includes our General Partner’s share to maintain its effective two percent interest.

 

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. During the six months ended June 30, 2016, 30 percent of GTN’s total distributable cash flow was $21 million. As a result of exceeding the $20 million threshold, the Class B units’ equity account was increased by $1 million (Refer to Note 8).

 

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.

 

The amount allocable to the Class B units in 2016 will equal an amount based upon 30 percent of GTN’s distributable cash flow during the year ending December 31, 2016 less $20 million (2015 – less $15 million).

 

17



 

Net income per common unit was determined as follows:

 

 

 

Three months ended

 

 

Six months ended

 

 

(unaudited)

 

June 30,

 

 

June 30,

 

 

(millions of dollars, except per common unit amounts)

 

2016

 

 

2015

 

 

2016

 

 

2015

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income attributable to controlling interests

 

54

 

 

44

 

 

127

 

 

101

 

 

Net income attributable to the General Partner

 

(1

)

 

(1

)

 

(2

)

 

(2

)

 

Incentive distributions allocated to the General Partner (a)

 

 (2

)

 

(1

)

 

(3

)

 

(1

)

 

Net income attributable to the Class B units (b)

 

(1

)

 

 

 

(1

)

 

 

 

Net income allocated to common units

 

50

 

 

42

 

 

121

 

 

98

 

 

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

 

65.5

(c)

 

63.8

 

 

64.9

(c)

 

63.7

 

 

Net income per common unit — basic and diluted

 

$

0.76

 

 

$

0.66

 

 

$

1.86

 

 

$

1.53

 

 

 


(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.

(b)             As discussed in Note 7, the Class B units entitle TransCanada to a distribution which is an amount based on 30 percent of GTN’s distributions after achieving certain annual thresholds. The distribution will be payable in the first quarter with respect to the prior year’s distributions. Consistent with the application of Accounting Standards Codification (ASC) Topic 260 — “Earnings per share”, the Partnership allocated a portion of net income attributable to controlling interest to the Class B units upon 30 percent of GTN’s total distributable cash flows exceeding $20 million for the year ending December 31, 2016.  During the six months ended June 30, 2016, 30 percent of GTN’s total distributable cash flow was $21 million.  As a result of exceeding the $20 million threshold, $1 million of net income attributable to controlling interests was allocated to the Class B units (Refer to Note 7). During the same period in 2015, no allocation was made to the Class B units as the threshold level of $15 million for the nine month period ending December 31, 2015 had not been exceeded.

(c)              Includes the common units subject to rescission. These units are treated as outstanding for financial reporting purposes (Refer to Note 7).

 

NOTE 9                         CASH DISTRIBUTIONS

 

In the three and six months ended June 30, 2016, the Partnership distributed $0.89 and $1.78 per common unit, respectively (2015 — $0.84 and $1.68 per common unit) for a total of $60 million and $119 million, respectively (2015 - $55 million and $110 million). The distributions paid in the three and six months ended June 30, 2016 included an IDR payment to the General Partner of approximately $1 million and $2 million, respectively (2015 - $0.3 million and $0.6 million). 

 

NOTE 10                  CHANGE IN OPERATING WORKING CAPITAL

 

(unaudited)

 

Six months ended June 30,

 

 

(millions of dollars)

 

2016

 

 

2015

 

 

 

 

 

 

 

 

 

 

Change in accounts receivable and other

 

 

 

4

 

 

Change in accounts payable and accrued liabilities (a)

 

2

 

 

(2

)

 

Change in accounts payable to affiliates

 

 

 

(5

)

 

Change in accrued interest

 

1

 

 

4

 

 

Change in operating working capital

 

3

 

 

1

 

 

 


(a)              The accrual of $10 million for the construction of GTN’s Carty Lateral in December 31, 2015 was paid during the first quarter 2016. Accordingly, the payment was reported as capital expenditures in our cash flow statement during the current period.

 

18



 

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 and $2 million for the three and six months ended June 30, 2016, respectively.   Total costs charged to the Partnership by the General Partner were $1 million for both the three and six months ended June 30, 2015.

 

As operator of our pipelines, 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.

 

Capital and operating costs charged to our pipeline systems for the three and six months ended June 30, 2016 and 2015 by TransCanada’s subsidiaries and amounts payable to TransCanada’s subsidiaries at June 30, 2016 and December 31, 2015 are summarized in the following tables:

 

 

 

Three months ended

 

 

Six months ended

 

 

(unaudited)

 

June 30,

 

 

June 30,

 

 

(millions of dollars)

 

2016

 

 

2015

 

 

2016

 

 

2015

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

Great Lakes (a) 

 

7

 

 

8

 

 

14

 

 

14

 

 

Northern Border (a)

 

9

 

 

9

 

 

15

 

 

16

 

 

PNGTS (a), (c)

 

2

 

 

 

 

4

 

 

 

 

GTN (a), (b)

 

7

 

 

8

 

 

13

 

 

14

 

 

Bison (d)

 

1

 

 

1

 

 

 

 

2

 

 

North Baja

 

1

 

 

2

 

 

2

 

 

3

 

 

Tuscarora

 

1

 

 

1

 

 

2

 

 

2

 

 

Impact on the Partnership’s net income:

 

 

 

 

 

 

 

 

 

 

 

 

 

Great Lakes

 

3

 

 

3

 

 

6

 

 

6

 

 

Northern Border

 

3

 

 

4

 

 

6

 

 

7

 

 

PNGTS (c)

 

1

 

 

 

 

2

 

 

 

 

GTN (b)

 

6

 

 

7

 

 

11

 

 

11

 

 

Bison

 

1

 

 

1

 

 

2

 

 

2

 

 

North Baja

 

1

 

 

1

 

 

2

 

 

2

 

 

Tuscarora

 

1

 

 

1

 

 

2

 

 

2

 

 

 

(unaudited)

 

 

 

 

 

 

 

(millions of dollars)

 

June 30, 2016

 

 

December 31, 2015

 

 

 

 

 

 

 

 

 

 

Net amounts payable to TransCanada’s subsidiaries is as follows:

 

 

 

 

 

 

 

Great Lakes (a)

 

3

 

 

3

 

 

Northern Border (a)

 

3

 

 

5

 

 

PNGTS (a)

 

1

 

 

 

 

GTN

 

3

 

 

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)             Net of proceeds of $1 million from the sale of excess pipe (at cost) to an affiliate.

 

19



 

Great Lakes earns transportation revenues from TransCanada and its affiliates, some of which are provided at discounted rates and some of which are at maximum recourse rates. Great Lakes earned $23 million and $69 million of transportation revenues under these contracts for the three and six months ended June 30, 2016, respectively (2015 - $18 million and $47 million). These amounts represent 64 percent and 71 percent of total revenues earned by Great Lakes for the three and six months ended June 30, 2016, respectively (2015 — 63 percent and 62 percent). Great Lakes also earned $1 million of affiliated rental revenue for the three and six months ended June 30, 2016 (2015 — $1 million).

 

Accordingly, revenue from TransCanada and its affiliates of $10 million and $32 million are included in the Partnership’s equity earnings from Great Lakes for the three and six months ended June 30, 2016, respectively (2015 - $8 million and $22 million). At June 30, 2016, $9 million was included in Great Lakes’ receivables in regards to the transportation contracts with TransCanada and its affiliates (December 31, 2015 - $17 million).

 

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 June 16, 2016, PNGTS declared its second quarter 2016 distribution of $8 million, of which the Partnership received its 49.9 percent share or $4 million on July 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.

 

20



 

Long-term debt is recorded at amortized cost and classified in Level 2 of the fair value hierarchy for fair value disclosure purposes. Interest rate derivative assets and liabilities are classified in Level 2 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 June 30, 2016 and December 31, 2015 was $1,994 million and $1,873 million, respectively.

 

The ATM Common units which may be subject to rescission rights, as discussed more fully in Note 7, were measured using the original issuance price, plus statutory interest and less any distributions paid. This fair value measurement is classified as Level 2.

 

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 June 30, 2016, the fair value of the interest rate swaps accounted for as cash flow hedges was a liability of $5 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 and six months ended June 30, 2016 and 2015. The change in fair value of interest rate derivative instruments recognized in other comprehensive income was a loss of $1 million and a loss of $3 million for the three and six months ended June 30, 2016, respectively (2015 — nil and a loss of $1 million). For the three and six months ended June 30, 2016, the net realized loss related to the interest rate swaps was $1 million, and was included in financial charges and other (2015 — nil and $1 million).  Refer to Note 14 — Financial Charges and Other.

 

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 June 30, 2016 and December 31, 2015.

 

(c) Other

 

As discussed more fully in Note 16, we performed a discounted cash flow analysis to assess, for possible impairment, the $82 million of goodwill related to our acquisition of Tuscarora. The estimated fair value measurement is classified as Level 3. In the determination of the fair value, we used internal forecasts for expected future cash flows and applied appropriate discount rates. The determination of expected future cash flows involved significant assumptions and estimates regarding revenue, operating and maintenance costs and future growth capital.

 

NOTE 13                  ACCOUNTS RECEIVABLE AND OTHER

 

(unaudited)

 

 

 

 

 

 

 

(millions of dollars)

 

June 30, 2016

 

 

December 31, 2015

 

 

 

 

 

 

 

 

 

 

Trade accounts receivable, net of allowance of nil

 

30

 

 

31

 

 

Other

 

5

 

 

4

 

 

 

 

35

 

 

35

 

 

 

21



 

NOTE 14                  FINANCIAL CHARGES AND OTHER

 

 

 

Three months ended

 

 

Six months ended

 

 

(unaudited)

 

June 30,

 

 

June 30,

 

 

(millions of dollars)

 

2016

 

 

2015

 

 

2016

 

 

2015

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest Expense (a)

 

16

 

 

16

 

 

33

 

 

29

 

 

Net realized loss related to the interest rate swaps

 

1

 

 

 

 

1

 

 

1

 

 

Other Income

 

(1

)

 

 

 

(1

)

 

(1

)

 

 

 

16

 

 

16

 

 

33

 

 

29

 

 

 


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

 

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. Both parties have filed their briefs. In July 2016, Essar filed for Bankruptcy and asked the 8th Circuit Court of Appeals to stay the appeal pending the bankruptcy proceeding. Great Lakes will file a request with the 8th Circuit Court of Appeals to deny the stay.  Because Great Lakes has a performance bond for the full amount of the judgment, the bankruptcy proceeding is not expected to impact the ability of Great Lakes to receive payment of a final award.

 

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 granted the Partnership and other defendants’ motion to dismiss the plaintiffs’ complaint.  The plaintiff has appealed the decision to dismiss its claims.  The appeal is expected to be heard in late-2016.

 

NOTE 16                  GOODWILL AND REGULATORY

 

On January 21, 2016, the FERC issued an Order (the January 21 Order) initiating an investigation pursuant to Section 5 of the Natural Gas Act of 1938 (NGA) to determine whether Tuscarora’s existing rates for jurisdictional services are just and reasonable. On July 15, 2016, Tuscarora filed a petition with FERC requesting approval of the Stipulation and Agreement of Settlement (Tuscarora Settlement) that, if approved, will resolve the Section 5 rate review initiated by FERC in January 2016. Under the terms of the Tuscarora Settlement, Tuscarora’s system-wide unit rate will initially decrease by 16 percent, with an anticipated effective date of August 1, 2016. Unless superseded by a subsequent rate case or settlement, this rate will remain in effect for three years, after which time the unit rate will decrease an additional seven percent for an additional three years. The settlement does not contain

 

22



 

a rate moratorium and requires Tuscarora to file to establish new rates no later than six years following the effective date of the initial settlement rates.

 

We believe there is a high probability that the Tuscarora settlement will be approved as filed, and as a result, the expected reduction in Tuscarora’s future cash flows constituted a triggering event that led us to evaluate, for possible impairment, the $82 million of goodwill related to our acquisition of Tuscarora.

 

Our analysis resulted in the estimated fair value of Tuscarora exceeding its carrying value but the excess was less than 10 percent. The fair value was measured using a discounted cash flow analysis and included revenue expected from Tuscarora’s current contracting level together with other opportunities on the system. There is a risk that reductions in future cash flow forecasts as a result of Tuscarora not being able to maintain its current contracting level and/or not being able to realize other opportunities on the system, together with adverse changes in other key assumptions such as projected operating costs and other future growth capital, could result in a future impairment of the goodwill balance relating to Tuscarora.

 

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 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 hold 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 that are not available to creditors of the Partnership and whose investors have no recourse to the credit of the Partnership 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 Sheets:

 

(unaudited)

 

 

 

 

 

 

 

(millions of dollars)

 

June 30, 2016

 

 

December 31, 2015

 

 

 

 

 

 

 

 

 

 

ASSETS (LIABILITIES) *

 

 

 

 

 

 

 

Accounts receivable and other

 

21

 

 

25

 

 

Inventories

 

6

 

 

6

 

 

Equity investments

 

1,047

 

 

965

 

 

Plant, property and equipment

 

859

 

 

872

 

 

Other assets

 

2

 

 

2

 

 

Accounts payable and accrued liabilities

 

(18

)

 

(26

)

 

Accounts payable to affiliates, net

 

(18

)

 

(6

)

 

Accrued interest

 

(1

)

 

(1

)

 

Current portion of long-term debt

 

(15

)

 

(14

)

 

Long-term debt

 

(325

)

 

(326

)

 

Other liabilities

 

(25

)

 

(24

)

 

 


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

 

23



 

NOTE 18                  SUBSEQUENT EVENTS

 

Management of the Partnership has reviewed subsequent events through August 4, 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 July 21, 2016, the board of directors of our General Partner declared the Partnership’s second quarter 2016 cash distribution in the amount of $0.94 per common unit payable on August 12, 2016 to unitholders of record as of August 1, 2016. The declared distribution reflects a $0.05 per common unit increase to the Partnership’s first quarter 2016 quarterly distribution and will include an IDR payment to our General Partner amounting to approximately $2 million.

 

Northern Border declared its June 2016 distribution of $13 million on July 11, 2016, of which the Partnership will receive its 50 percent share or $6.5 million on July 29, 2016.

 

Great Lakes declared its second quarter 2016 distribution of $12 million on July 19, 2016, of which the Partnership will receive its 46.45 percent share or $6 million on August 1, 2016.

 

24



 

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, and was paid on May 13, 2016 to unitholders of record as of May 2, 2016. The first quarter 2016 cash distribution included an IDR payment to our General Partner amounting to approximately $1 million.

 

On July 21, 2016, the board of directors of our General Partner declared the Partnership’s second quarter 2016 cash distribution in the amount of $0.94 per common unit payable on August 12, 2016 to unitholders of record as of August 1, 2016. The declared distribution reflects a $0.05 per common unit increase to the first quarter 2016 quarterly distribution and will include an IDR payment to our General Partner amounting to approximately $2 million.

 

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 rate case - 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 July 15, 2016, Tuscarora filed a petition with FERC requesting approval of the Tuscarora Settlement that, if approved, will resolve the Section 5 rate review initiated by FERC in January 2016. Under the terms of the Tuscarora Settlement, Tuscarora’s system-wide unit rate will initially decrease by 16 percent, with an anticipated effective date of August 1, 2016. Unless superseded by a subsequent rate case or settlement, this rate will remain in effect for three years, after which time the unit rate will decrease an additional seven percent per year for an additional three years. The settlement does not contain a rate moratorium and requires Tuscarora to file to establish new rates no later than six years following the effective date of the initial settlement rates. While this new rate structure will reduce Tuscarora’s future cash flows, the achievement of rate certainty helps ensure predictable cash flows and enhances Tuscarora’s long term value.

 

ATM program — On July 29, 2016, we filed a new shelf registration statement with the SEC to register an additional $400 million of common units under our ATM Program. On August 2, 2016, we requested accelerated effectiveness of the amended shelf registration statement.

 

Outlook of Our Business

 

TransCanada, the ultimate parent company of our General Partner, is currently executing a large capital program that includes approximately $25 billion Canadian of near-term growth opportunities that are expected to be complete by 2018. Over the medium to longer-term, TransCanada is also advancing over $45 billion Canadian of commercially secured large-scale projects, and various other initiatives backed by long-term contracts or cost-of-service business models.

 

The Partnership has been advised that TransCanada has retained a financial advisor to assist in developing its MLP strategy.  A decision on the MLP strategy is expected to be communicated later in 2016.  TransCanada does not anticipate any dropdowns to the Partnership until the review has been completed.

 

The Partnership’s financial performance continues to benefit from its recent acquisitions, including the acquisition of an interest in PNGTS from TransCanada. Despite uncertainty in energy commodity prices, our portfolio of seven FERC-regulated interstate natural gas pipelines is expected to deliver generally stable results in 2016 due to ship-or-pay contracts with creditworthy customers.

 

25



 

RESULTS OF OPERATIONS

 

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.

 

 

 

Three months
ended

 

 

 

 

 

Six months
ended

 

 

 

 

 

(unaudited)