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EX-31.2 - EX-31.2 - TC PIPELINES LPa17-20568_1ex31d2.htm
EX-31.1 - EX-31.1 - TC PIPELINES LPa17-20568_1ex31d1.htm
EX-10.1 - EX-10.1 - TC PIPELINES LPa17-20568_1ex10d1.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 September 30, 2017

 

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, smaller reporting company, or an emerging growth company.  See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth 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

Emerging growth company o

 

 

 

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.    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 November 3, 2017, there were 69,881,012 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 as amended, dated September 29, 2017

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 as amended, dated September 29, 2017

2016 PNGTS Acquisition

 

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

2017 Acquisition

 

Partnership’s acquisition of an additional 11.81 percent interest in PNGTS and 49.34 percent in Iroquois on June 1, 2017

ASC

 

Accounting Standards Codification

ASU

 

Accounting Standards Update

ATM program

 

At-the-market equity issuance program

Bison

 

Bison Pipeline LLC

Consolidated Subsidiaries

 

GTN, Bison, North Baja, Tuscarora and PNGTS

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

Iroquois

 

Iroquois Gas Transmission System, L.P.

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, PNGTS and Iroquois

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

Term Loan Facilities

 

The 2013 Term Loan Facility and the 2015 Term Loan Facility, collectively

SEC

 

Securities and Exchange Commission

Senior Credit Facility

 

TC PipeLines, LP’s senior facility under revolving credit agreement as amended and restated, dated September 29, 2017

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), Portland Natural Gas Transmission System (PNGTS) and Iroquois Gas Transmission System, LP (Iroquois).

 

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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. 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 downward changes 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;

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

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

·                  the overall increase in the allocated management and operational expenses on our pipeline systems as performed by TransCanada

 

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Table of Contents

 

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”of our Annual Report on Form 10-K for the year ended December 31, 2016 as filed with the SEC on February 28, 2017. 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.

 

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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

 

Nine months ended

 

(unaudited)

 

September 30,

 

September 30,

 

(millions of dollars, except per common unit amounts)

 

2017

 

2016 (a)

 

2017

 

2016 (a)

 

 

 

 

 

 

 

 

 

 

 

Transmission revenues

 

100

 

103

 

313

 

315

 

Equity earnings (Note 4)

 

27

 

22

 

87

 

75

 

Operation and maintenance expenses

 

(16

)

(15

)

(47

)

(42

)

Property taxes

 

(7

)

(7

)

(21

)

(20

)

General and administrative

 

(1

)

(1

)

(6

)

(5

)

Depreciation

 

(25

)

(24

)

(73

)

(71

)

Financial charges and other (Note 14)

 

(23

)

(18

)

(59

)

(53

)

Net income before taxes

 

55

 

60

 

194

 

199

 

Income taxes (Note 18)

 

 

 

(1

)

(1

)

Net income

 

55

 

60

 

193

 

198

 

 

 

 

 

 

 

 

 

 

 

Net income attributable to non-controlling interests

 

1

 

2

 

7

 

10

 

Net income attributable to controlling interests

 

54

 

58

 

186

 

188

 

 

 

 

 

 

 

 

 

 

 

Net income attributable to controlling interest allocation (Note 8)

 

 

 

 

 

 

 

 

 

Common units

 

42

 

43

 

164

 

164

 

General Partner

 

4

 

4

 

12

 

9

 

TransCanada and its subsidiaries

 

8

 

11

 

10

 

15

 

 

 

54

 

58

 

186

 

188

 

 

 

 

 

 

 

 

 

 

 

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

 

$

0.61

 

$

0.65

(b)

$

2.38

 

$

2.51

(b)

 

 

 

 

 

 

 

 

 

 

Weighted average common units outstanding basic and diluted (millions)

 

69.4

 

66.1

 

68.9

 

65.3

 

 

 

 

 

 

 

 

 

 

 

Common units outstanding, end of period (millions)

 

69.6

 

66.6

 

69.6

 

66.6

 

 


(a)              Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).

(b)             Net income per common unit prior to recast (Refer to Note 2).

 

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

 

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Table of Contents

 

TC PIPELINES, LP CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

 

 

 

Three months ended

 

Nine months ended

 

(unaudited)

 

September 30,

 

September 30,

 

(millions of dollars)

 

2017

 

2016(a)

 

2017

 

2016(a)

 

 

 

 

 

 

 

 

 

 

 

Net income

 

55

 

60

 

193

 

198

 

Other comprehensive income

 

 

 

 

 

 

 

 

 

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

 

 

2

 

1

 

(1

)

Amortization of realized loss on derivative financial instruments (Note 12)

 

 

 

1

 

1

 

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

 

1

 

 

 

 

Comprehensive income

 

56

 

62

 

195

 

198

 

Comprehensive income attributable to non-controlling interests

 

1

 

2

 

7

 

10

 

Comprehensive income attributable to controlling interests

 

55

 

60

 

188

 

188

 

 


(a)              Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).

 

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)

 

September 30, 2017

 

December 31, 2016 (a)

 

 

 

 

 

 

 

ASSETS

 

 

 

 

 

Current Assets

 

 

 

 

 

Cash and cash equivalents

 

73

 

64

 

Accounts receivable and other (Note 13)

 

35

 

47

 

Inventories

 

7

 

7

 

Other

 

6

 

7

 

 

 

121

 

125

 

 

 

 

 

 

 

Equity investments (Note 4)

 

1,207

 

918

 

Plant, property and equipment

 

 

 

 

 

(Net of $1,158 accumulated depreciation; 2016 - $1,088)

 

2,133

 

2,180

 

Goodwill

 

130

 

130

 

Other assets

 

 

1

 

 

 

3,591

 

3,354

 

 

 

 

 

 

 

LIABILITIES AND PARTNERS’ EQUITY

 

 

 

 

 

Current Liabilities

 

 

 

 

 

Accounts payable and accrued liabilities

 

31

 

29

 

Accounts payable to affiliates (Note 11)

 

5

 

8

 

Distribution payable

 

 

3

 

Accrued interest

 

21

 

10

 

Current portion of long-term debt (Note 5)

 

51

 

52

 

 

 

108

 

102

 

Long-term debt, net (Note 5)

 

2,427

 

1,859

 

Deferred state income taxes (Note 18)

 

10

 

10

 

Other liabilities

 

28

 

28

 

 

 

2,573

 

1,999

 

 

 

 

 

 

 

Common units subject to rescission (Note 7)

 

 

83

 

 

 

 

 

 

 

Partners’ Equity

 

 

 

 

 

Common units

 

790

 

1,002

 

Class B units (Note 7)

 

103

 

117

 

General partner

 

23

 

27

 

Accumulated other comprehensive loss

 

 

(2

)

Controlling interests

 

916

 

1,144

 

 

 

 

 

 

 

Non-controlling interests

 

102

 

97

 

Equity of former parent of PNGTS

 

 

31

 

 

 

1,018

 

1,272

 

 

 

3,591

 

3,354

 

 

Contingencies (Note 15)

Variable Interest Entities (Note 17)

Subsequent Events (Note 19)

 


(a)              Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).

 

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

 

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Table of Contents

 

TC PIPELINES, LP

CONSOLIDATED STATEMENT OF CASH FLOWS

 

 

 

Nine months ended

 

(unaudited)

 

September 30,

 

(millions of dollars)

 

2017

 

2016 (a)

 

 

 

 

 

 

 

Cash Generated From Operations

 

 

 

 

 

Net income

 

193

 

198

 

Depreciation

 

73

 

71

 

Amortization of debt issue costs reported as interest expense

 

1

 

1

 

Amortization of realized loss on derivative instrument

 

1

 

1

 

Deferred state income tax recovery (Note 18)

 

 

 

Equity earnings from equity investments (Notes 3 and 4)

 

(87

)

(75

)

Distributions received from operating activities of equity investments (Note 3)

 

106

 

125

 

Change in operating working capital (Note 10)

 

24

 

11

 

 

 

311

 

332

 

Investing Activities

 

 

 

 

 

Investment in Northern Border (Note 4)

 

(83

)

 

Investment in Great Lakes (Note 4) 

 

(4

)

(4

)

Distribution received from Iroquois as return of investment (Note 4)

 

3

 

 

Acquisition of a 49.9 percent interest in PNGTS

 

 

(193

)

Acquisition of a 49.34 percent in Iroquois and an additional 11.81 percent in PNGTS (Note 6)

 

(646

)

 

Capital expenditures

 

(26

)

(21

)

Other

 

 

3

 

 

 

(756

)

(215

)

Financing Activities

 

 

 

 

 

Distributions paid (Note 9)

 

(210

)

(184

)

Distributions paid to Class B units (Note 7)

 

(22

)

(12

)

Distributions paid to non-controlling interests

 

(5

)

(12

)

Distributions paid to former parent of PNGTS

 

(1

)

(9

)

Common unit issuance, net (Note 7)

 

126

 

35

 

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

 

 

83

 

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

 

732

 

200

 

Long-term debt repaid (Note 5)

 

(164

)

(196

)

Debt issuance costs

 

(2

)

 

 

 

454

 

(95

)

Decrease in cash and cash equivalents

 

9

 

22

 

Cash and cash equivalents, beginning of period

 

64

 

55

 

Cash and cash equivalents, end of period

 

73

 

77

 

 


(a)              Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).

 

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

 

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Table of Contents

 

TC PIPELINES, LP

CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS’ EQUITY

 

 

 

Limited Partners

 

 

 

 

 

 

 

 

 

 

 

 

 

Common Units

 

Class B Units

 

General
Partner

 

Accumulated
Other
Comprehensive
Loss 
(a) (b)

 

Non-
Controlling
Interest
(b)

 

Equity of
former
parent of
PNGTS
(b)

 

Total
Equity
(b)

 

(unaudited)

 

millions
of units

 

millions
of dollars

 

millions
of units 

 

millions
of dollars

 

millions
of dollars

 

millions
of dollars

 

millions
of dollars

 

millions
of dollars

 

millions
of dollars

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Partners’ Equity at December 31, 2016

 

67.4

 

1,002

 

1.9

 

117

 

27

 

(2

)

97

 

31

 

1,272

 

Net income (b)

 

 

164

 

 

8

 

12

 

 

7

 

2

 

193

 

Other comprehensive income

 

 

 

 

 

 

2

 

 

 

2

 

ATM equity issuances, net (Note 7)

 

2.2

 

124

 

 

 

2

 

 

 

 

126

 

Reclassification of common units no longer subject to rescission (Note 7)

 

 

81

 

 

 

2

 

 

 

 

83

 

Acquisition of interests in PNGTS and Iroquois (Note 6)

 

 

(383

)

 

 

(8

)

 

 

(32

)

(423

)

Distributions (b)

 

 

(198

)

 

(22

)

(12

)

 

(2

)

(1

)

(235

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Partners’ Equity at September 30, 2017

 

69.6

 

790

 

1.9

 

103

 

23

 

 

102

 

 

1,018

 

 


(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 $1 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.

(b)             Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).

 

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

 

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Table of Contents

 

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 nine months ended September 30, 2017 and 2016 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 audited financial statements and notes thereto for the year ended December 31, 2016 included as exhibit 99.2 in our Current Report on Form 8-K dated August 3, 2017. 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 audited financial statements and notes thereto for the year ended December 31, 2016 included as exhibit 99.2 in our Current Report on Form 8-K dated August 3, 2017, except as described in Note 3, Accounting Pronouncements.

 

Basis of Presentation

 

The Partnership consolidates its interests in entities over which it is able to exercise control. To the extent there are interests owned by other parties, these interests are included in non-controlling interests. The Partnership uses the equity method of accounting for its investments in entities over which it is able to exercise significant influence.

 

Acquisitions by the Partnership from TransCanada are considered common control transactions. When businesses are acquired from TransCanada that will be consolidated by the Partnership, the historical financial statements are required to be recast, except net income per common unit, to include the acquired entities for all periods presented.

 

When the Partnership acquires an asset or an investment from TransCanada, which will be accounted for by the equity method, the financial information is not required to be recast and the transaction is accounted for prospectively from the date of the acquisition.

 

On June 1, 2017, the Partnership acquired from a subsidiary of TransCanada an additional 11.81 percent interest in PNGTS, that resulted in the Partnership owning a 61.71 percent interest in PNGTS (Refer to Note 6).  As a result of the Partnership owning 61.71 percent interest in PNGTS, the Partnership’s historical financial information has been recast, except net income (loss) per common unit, to consolidate PNGTS for all the periods presented in the Partnership’s consolidated financial statements. Additionally, this acquisition was accounted for as transaction between entities under common control, similar to pooling of interests, whereby the assets and liabilities of PNGTS were recorded at TransCanada’s carrying value.

 

Also, on June 1, 2017, the Partnership acquired from subsidiaries of TransCanada a 49.34 percent interest in Iroquois Gas Transmission, L.P. (“Iroquois”) (Refer to Note 6). Accordingly, this transaction was accounted for as a transaction between entities under common control, similar to pooling of interest, whereby the equity investment in Iroquois was recorded at TransCanada’s carrying value and was accounted for prospectively.

 

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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

 

Retrospective application of Accounting Standards Update (ASU) No 2016-15 Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments”

 

In August 2016, the Financial Accounting Standards Board (FASB) issued an amendment of previously issued guidance, which intends to reduce diversity in practice in how certain transactions are classified in the statement of cash flows. The new guidance is effective January 1, 2018, however, as early adoption is permitted, the Partnership elected to retrospectively apply this guidance effective December 31, 2016. The Partnership has elected to classify distributions received from equity method investees using the nature of distributions approach as it is more representative of the nature of the underlying activities of the investees that generated the distributions. As a result, certain comparative period distributions received from equity method investees, amounting to $50 million for the nine months ended September 30, 2016, have been reclassified from investing activities to cash generated from operations in the consolidated statement of cash flows.

 

Effective January 1, 2017

 

Inventory

 

In July 2015, the FASB issued new guidance on simplifying the measurement of inventory. The new guidance specifies that an entity should measure inventory within the scope of this update at the lower of cost and net realizable value. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. This new guidance was effective January 1, 2017, was applied prospectively and did not have a material impact on the Partnership’s consolidated balance sheet.

 

Equity method and joint ventures

 

In March 2016, the FASB issued new guidance 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. The new guidance is effective January 1, 2017 and was applied prospectively. The application of this guidance did not have a material impact on the Partnership’s consolidated financial statements.

 

Consolidation

 

In October 2016, the FASB issued new guidance on consolidation relating to interests held through related parties that are under common control.  The new guidance amends the consolidation requirements such that if a decision maker is required to evaluate whether it is the primary beneficiary of a variable interest entry (VIE), it will need to consider only its proportionate indirect interest in the VIE held through a common control party.  The guidance was effective January 1, 2017, was applied retrospectively and did not result in any change to our consolidation conclusions.

 

Future accounting changes

 

Revenue from contracts with customers

 

In 2014, the FASB issued new guidance on revenue from contracts with customers. The new guidance requires that an entity recognize revenue in accordance with a prescribed model. This model is used to depict the transfer of promised goods or services to customers in an amount that reflects the total consideration to which it expects to be entitled during the term of the contract in exchange for those goods or services. The new guidance also requires additional disclosures about the nature, amount, timing and uncertainty of revenue and the related cash flows. The Partnership will adopt the new standard on the effective date of January 1, 2018. There are two methods in which the new standard can be adopted: (1) a full retrospective approach with restatement of all prior periods presented, or (2) a modified retrospective approach with a cumulative-effect adjustment as of the date of adoption. The Partnership will adopt the

 

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standard using the modified retrospective approach with the cumulative-effect of the adjustment recognized at the date of adoption, subject to allowable and elected practical expedients.

 

The Partnership has identified all existing customer contracts that are within the scope of the new guidance and is on schedule in the process of analyzing individual contracts or groups of contracts to identify any significant changes in how revenues are recognized as a result of implementing the new guidance. While the Partnership has not identified any material differences in the amount and timing of revenue recognition for the contracts that have been analyzed to date, the evaluation is not complete and the Partnership has not concluded on the overall impact of adopting the new guidance. The Partnership continues its contract analysis to obtain the information necessary to quantify the cumulative-effect adjustment, if any, on prior period revenues and revenue recognized going forward.

 

Although consolidated revenues may not be materially impacted by the new guidance, the Partnership currently anticipates significant changes to disclosures based on the additional requirements prescribed. These new disclosures include information regarding the significant judgments used in evaluating when and how revenue is recognized and information related to contract assets and liabilities. In addition, the new guidance requires that the Partnership’s revenue recognition policy disclosure includes additional detail regarding the various performance obligations and the nature, amount, timing and estimates of revenue and cash flows generated from contracts with customers. The Partnership continues to develop and evaluate disclosures required with a particular focus on the scope of contracts subject to disclosure of remaining performance obligations. The Partnership also continues to address any system and process changes necessary to compile the information to meet the recognition and disclosure requirements of the new guidance. The Partnership continues to monitor additional authoritative or interpretive guidance related to the new guidance as it becomes available.

 

Leases

 

In February 2016, the FASB issued new guidance on the accounting for leases. The new guidance amends the definition of a lease requiring the customer to have both (1) the right to obtain substantially all of the economic benefits from the use of the asset and (2) the right to direct the use of the asset in order for the arrangement to qualify as a lease. The new guidance also establishes a right-of-use (ROU) model that requires a lessee to recognize a ROU asset and corresponding lease liability on the balance sheet for all leases with a term longer than 12 months. Leases will be classified as finance or operating, with classification affecting the pattern and classification of expense recognition in the income statement. The new guidance does not make extensive changes to lessor accounting.

 

The new guidance is effective on January 1, 2019, with early adoption permitted. A modified retrospective transition approach is required for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements, with certain practical expedients available. The Partnership is continuing to identify and analyze existing lease agreements to determine the effect of adoption of the new guidance on its consolidated financial statements. The Partnership is also addressing system and process changes necessary to compile the information to meet the recognition and disclosure requirements of the new guidance.

 

Goodwill Impairment

 

In January 2017, the FASB issued new guidance on simplifying the test for goodwill impairment by eliminating the requirement to calculate the implied fair value of goodwill to measure the impairment charge. Instead, entities will record an impairment charge based on the excess of a reporting unit’s carrying amount over its fair value. This new guidance is effective January 1, 2020 and will be applied prospectively. Early adoption is permitted. 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.

 

Hedge Accounting

 

In August 2017, the FASB issued new guidance on hedge accounting, making more financial and nonfinancial hedging strategies eligible for hedge accounting. The new guidance amends the presentation requirements relating to the change in fair value of a derivative and additional disclosure requirements include cumulative basis adjustments for fair value hedges and the effect of hedging on individual statement of income line items. This new guidance is effective January 1, 2019 and will be applied prospectively with a cumulative-effect adjustment to opening equity on adoption. Early adoption is permitted. 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.

 

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NOTE 4   EQUITY INVESTMENTS

 

The Partnership has equity interests in Northern Border, Great Lakes and effective June 1, 2017, Iroquois. The pipeline systems owned by these entities are regulated by FERC. The pipeline systems of Northern Border and Great Lakes are operated by subsidiaries of TransCanada. The Iroquois pipeline system is operated by Iroquois Pipeline Operating Company, a wholly owned subsidiary of Iroquois. 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 17).

 

 

 

Ownership

 

Equity Earnings

 

Equity Investments

 

 

 

Interest at

 

Three months

 

Nine Months

 

 

 

 

 

(unaudited)

 

September 30,

 

ended September 30,

 

ended September 30,

 

September 30,

 

December 31,

 

(millions of dollars)

 

2017

 

2017

 

2016(b)

 

2017

 

2016(b)

 

2017

 

2016(b)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Northern Border (a)

 

50

%

16

 

18

 

50

 

52

 

516

 

444

 

Great Lakes

 

46.45

%

2

 

4

 

24

 

23

 

469

 

474

 

Iroquois

 

49.34

%

9

 

 

13

 

 

222

 

 

 

 

 

 

27

 

22

 

87

 

75

 

1,207

 

918

 

 


(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 acquisition of an additional 20 percent interest in April 2006.

 

(b)  Recast to eliminate equity earnings from PNGTS and consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).

 

Northern Border

 

On September 1, 2017, the Partnership made an equity contribution to Northern Border amounting to $83 million. This amount represents the Partnership’s 50 percent share of $166 million capital contribution request from Northern Border to reduce the outstanding balance of its revolver debt to increase its available borrowing capacity.

 

The Partnership did not have undistributed earnings from Northern Border for the three and nine months ended September 30, 2017 and 2016.

 

The summarized financial information for Northern Border is as follows:

 

(unaudited)

 

 

 

 

 

(millions of dollars)

 

September 30, 2017

 

December 31, 2016

 

 

 

 

 

 

 

ASSETS

 

 

 

 

 

Cash and cash equivalents

 

24

 

14

 

Other current assets

 

36

 

36

 

Plant, property and equipment, net

 

1,069

 

1,089

 

Other assets

 

14

 

14

 

 

 

1,143

 

1,153

 

 

 

 

 

 

 

LIABILITIES AND PARTNERS’ EQUITY

 

 

 

 

 

Current liabilities

 

48

 

38

 

Deferred credits and other

 

30

 

28

 

Long-term debt, including current maturities, net

 

264

 

430

 

Partners’ equity

 

 

 

 

 

Partners’ capital

 

802

 

659

 

Accumulated other comprehensive loss

 

(1

)

(2

)

 

 

1,143

 

1,153

 

 

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Three months ended

 

Nine months ended

 

(unaudited)

 

September 30,

 

September 30,

 

(millions of dollars)

 

2017

 

2016

 

2017

 

2016

 

 

 

 

 

 

 

 

 

 

 

Transmission revenues

 

73

 

74

 

217

 

218

 

Operating expenses

 

(20

)

(18

)

(56

)

(53

)

Depreciation

 

(15

)

(15

)

(45

)

(44

)

Financial charges and other

 

(5

)

(5

)

(14

)

(16

)

Net income

 

33

 

36

 

102

 

105

 

 

Great Lakes

 

The Partnership made an equity contribution to Great Lakes of $4 million in the first quarter of 2017. 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 nine months ended September 30, 2017 and 2016.

 

The summarized financial information for Great Lakes is as follows:

 

(unaudited)

 

 

 

 

 

(millions of dollars)

 

September 30, 2017

 

December 31, 2016

 

 

 

 

 

 

 

ASSETS

 

 

 

 

 

Current assets

 

56

 

66

 

Plant, property and equipment, net

 

705

 

714

 

 

 

761

 

780

 

 

 

 

 

 

 

LIABILITIES AND PARTNERS’ EQUITY

 

 

 

 

 

Current liabilities

 

41

 

40

 

Net long-term debt, including current maturities

 

269

 

278

 

Partners’ equity

 

451

 

462

 

 

 

761

 

780

 

 

 

 

Three months ended

 

Nine months ended

 

(unaudited)

 

September 30,

 

September 30,

 

(millions of dollars)

 

2017

 

2016

 

2017

 

2016

 

 

 

 

 

 

 

 

 

 

 

Transmission revenues

 

34

 

36

 

138

 

133

 

Operating expenses

 

(19

)

(15

)

(49

)

(45

)

Depreciation

 

(7

)

(7

)

(21

)

(21

)

Financial charges and other

 

(5

)

(6

)

(16

)

(17

)

Net income

 

3

 

8

 

52

 

50

 

 

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Iroquois

 

On June 1, 2017, the Partnership acquired a 49.34 percent interest in Iroquois. Also on July 27, 2017, Iroquois declared its second quarter 2017 distribution of $28 million, of which the Partnership received its 49.34 percent share or $14 million on August 1, 2017. The distribution includes the Partnership’s 49.34 percent share of the Iroquois unrestricted cash distribution amounting to approximately $2.6 million (Refer to Note 6). This amount is reported as distributions received as return of investment in the Partnership’s consolidated statement of cash flows.

 

The Partnership recorded no undistributed earnings from Iroquois in the three and nine months ended September 30, 2017.

 

The summarized financial information for Iroquois is as follows:

 

(unaudited)

 

 

 

 

 

(millions of dollars)

 

September 30, 2017

 

December 31, 2016

 

 

 

 

 

 

 

ASSETS

 

 

 

 

 

Cash and cash equivalents

 

93

 

86

 

Other current assets

 

33

 

34

 

Plant, property and equipment, net

 

592

 

604

 

Other assets

 

8

 

7

 

 

 

726

 

731

 

 

 

 

 

 

 

LIABILITIES AND PARTNERS’ EQUITY

 

 

 

 

 

Current liabilities

 

20

 

18

 

Net long-term debt, including current maturities

 

332

 

335

 

Other non-current liabilities

 

9

 

6

 

Partners’ equity

 

365

 

372

 

 

 

726

 

731

 

 

 

 

Three months ended

 

Nine months ended

 

(unaudited)

 

September 30,

 

September 30,

 

(millions of dollars)

 

2017

 

2016

 

2017

 

2016

 

 

 

 

 

 

 

 

 

 

 

Transmission revenues

 

43

 

45

 

142

 

145

 

Operating expenses

 

(13

)

(13

)

(41

)

(43

)

Depreciation

 

(7

)

(9

)

(22

)

(28

)

Financial charges and other

 

(4

)

(4

)

(13

)

(12

)

Net income

 

19

 

19

 

66

 

62

 

 

NOTE 5 DEBT AND CREDIT FACILITIES

 

(unaudited)
(millions of dollars)

 

September 30,
2017

 

Weighted Average
Interest Rate for the
Nine Months Ended
September 30, 2017

 

December 31,
2016 
(a)

 

Weighted Average
Interest Rate for the
Year Ended December
31, 2016 

 

 

 

 

 

 

 

 

 

 

 

TC PipeLines, LP

 

 

 

 

 

 

 

 

 

Senior Credit Facility due 2021

 

255

 

2.34

%

160

 

1.72

%

2013 Term Loan Facility due October 2022

 

500

 

2.26

%

500

 

1.73

%

2015 Term Loan Facility due October 2020

 

170

 

2.15

%

170

 

1.63

%

4.65% Unsecured Senior Notes due 2021

 

350

 

4.65

%(b)

350

 

4.65

%(b)

4.375% Unsecured Senior Notes due 2025

 

350

 

4.375

%(b)

350

 

4.375

%(b)

3.90 % Unsecured Senior Notes due 2027

 

500

 

3.90

%(b)

 

 

GTN

 

 

 

 

 

 

 

 

 

5.29% Unsecured Senior Notes due 2020

 

100

 

5.29

%(b)

100

 

5.29

%(b)

5.69% Unsecured Senior Notes due 2035

 

150

 

5.69

%(b)

150

 

5.69

%(b)

Unsecured Term Loan Facility due 2019

 

55

 

1.95

%

65

 

1.43

%

PNGTS

 

 

 

 

 

 

 

 

 

5.90% Senior Secured Notes due December 2018

 

36

 

5.90

%(b)

53

 

5.90

%(b)

Tuscarora

 

 

 

 

 

 

 

 

 

Unsecured Term Loan due 2020

 

25

 

2.18

%

10

 

1.64

%

3.82% Series D Senior Notes due August 2017

 

 

3.82

%(b)

12

 

3.82

%(b)

 

 

2,491

 

 

 

1,920

 

 

 

Less: unamortized debt issuance costs and debt discount

 

13

 

 

 

9

 

 

 

Less: current portion

 

51

 

 

 

52

 

 

 

 

 

2,427

 

 

 

1,859

 

 

 

 

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(a)              Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).

(b)             Fixed interest rate

 

TC Pipelines, LP

 

The Partnership’s Senior Credit Facility consists of a $500 million senior revolving credit facility with a banking syndicate, maturing November 10, 2021, under which $255 million was outstanding at September 30, 2017 (December 31, 2016 - $160 million), leaving $245 million available for future borrowing. The LIBOR-based interest rate on the Senior Credit Facility was 2.49 percent at September 30, 2017 (December 31, 2016 — 1.92 percent).

 

On September 29, 2017, the Partnership’s 2013 Term Loan Facility that was due on July 1, 2018 was amended to extend the maturity period through October 2, 2022. As of September 30, 2017, the variable interest rate exposure related to the 2013 Term Loan Facility was hedged by fixed interest rate swap arrangements and our effective interest rate was 2.31 percent (December 31, 2016 — 2.31 percent). Prior to hedging activities, the LIBOR-based interest rate on the 2013 Term Loan Facility was 2.49 percent at September 30, 2017 (December 31, 2016 — 1.87 percent).

 

On September 29, 2017, the Partnership’s 2015 Term Loan Facility that was due on October 1, 2018 was amended to extend the maturity period through October 1, 2020. The LIBOR-based interest rate on the 2015 Term Loan Facility was 2.39 percent at September 30, 2017 (December 31, 2016 — 1.77 percent).

 

The 2013 Term Loan Facility and the 2015 Term Loan Facility (collectively, the 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 5.00 to 1.00 for each 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 4.76 to 1.00 as of September 30, 2017.

 

On May 25, 2017, the Partnership closed a $500 million public offering of senior unsecured notes bearing an interest rate of 3.90 percent maturing May 25, 2027. The net proceeds of $497 million were used to fund a portion of the 2017 Acquisition (Refer to Note 6). The indenture for the notes contains customary investment grade covenants.

 

PNGTS

 

PNGTS’ Senior Secured Notes are secured by the PNGTS long-term firm shipper contracts and its partners’ pledge of their equity and a guarantee of debt service for six months. PNGTS is restricted under the terms of its note purchase agreement from making cash distributions unless certain conditions are met. Before a distribution can be made, the debt service reserve account must be fully funded and PNGTS’ debt service coverage ratio for the preceding and succeeding twelve months must be 1.30 or greater. At September 30, 2017, the debt service coverage ratio was 1.71 for the twelve

 

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preceding months and 5.31 for the twelve succeeding months. Therefore, PNGTS was not restricted to make any cash distributions.

 

GTN

 

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 September 30, 2017 was 44.2 percent. The LIBOR-based interest rate on the GTN’s Unsecured Term Loan Facility was 2.19 percent at September 30, 2017 (December 31, 2016 — 1.57 percent).

 

Tuscarora

 

On August 21, 2017, Tuscarora refinanced all of its outstanding debt by amending its existing Unsecured Term Loan Facility and issuing a new $25 million variable rate term loan that will require yearly principal payments and will mature on August 21, 2020. Tuscarora’s Unsecured Term Loan contains a covenant that requires 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 or equal to 3.00 to 1.00. As of September 30, 2017, the ratio was 3.08 to 1.00.

 

The LIBOR-based interest rate on the Tuscarora’s Unsecured Term Loan Facility was 2.36 percent at September 30, 2017 (December 31, 2016 — 1.90 percent).

 

At September 30, 2017, 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)

 

 

 

 

 

 

 

2017

 

12

 

2018

 

45

 

2019

 

36

 

2020

 

293

 

2021

 

605

 

Thereafter

 

1,500

 

 

 

2,491

 

 

NOTE 6 ACQUISITION

 

2017 Acquisition

 

On June 1, 2017, the Partnership acquired from subsidiaries of TransCanada a 49.34 percent interest in Iroquois, including an option to acquire a further 0.66 percent interest in Iroquois, together with an additional 11.81 percent interest in PNGTS resulting in the Partnership owning a 61.71 percent interest in PNGTS (2017 Acquisition). The total purchase price of the 2017 Acquisition was $765 million plus final purchase price adjustments amounting to $50 million. The purchase price consisted of (i) $710 million for the Iroquois interest (less $164 million, which reflected our 49.34 percent share of Iroquois outstanding debt on June 1, 2017), (ii) $55 million for the additional 11.81 percent interest in PNGTS (less $5 million, which reflected our 11.81% proportionate share in PNGTS’ outstanding debt on June 1, 2017) (iii) final working capital adjustments on PNGTS and Iroquois amounting to $3 million and $19 million, respectively and (iv) additional consideration for Iroquois’ surplus cash amounting to $28 million. Additionally, the Partnership paid $1,000 for the option to acquire TransCanada’s remaining 0.66 percent interest in Iroquois. The Partnership funded the cash portion of the 2017 Acquisition through a combination of proceeds from the May 2017 public debt offering (refer to Note 5) and borrowing under our Senior Credit Facility.

 

At the date of the 2017 Acquisition, there was significant cash on Iroquois’ balance sheet.  Pursuant to the Purchase and Sale Agreement associated with the acquisition of the Iroquois interest, as amended, the Partnership agreed to pay $28 million plus interest to TransCanada on August 1, 2017 for its 49.34 percent share of cash determined to be surplus to Iroquois’ operating needs.

 

Additionally, Iroquois’ partners adopted a distribution resolution to address the significant cash on Iroquois’ balance sheet post-closing. The Partnership expects to receive the $28 million of unrestricted cash as part of its quarterly

 

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distributions from Iroquois over 11 quarters under the terms of the resolution, which began with Iroquois’ second quarter 2017 distribution on August 1, 2017. As of November 6, 2017 the Partnership has received approximately $5.2 million of the expected $28 million, of which $2.6 million was received on November 1, 2017 (Refer to Note 19).

 

The acquisition of a 49.34 percent interest in Iroquois was accounted for as a transaction between entities under common control, whereby the equity investment in Iroquois was recorded at TransCanada’s carrying value and the total excess purchase price paid was recorded as a reduction in Partners’ Equity.

 

Iroquois’ net purchase price was allocated as follows:

 

(millions of dollars)

 

 

 

Net Purchase Price (a)

 

593

 

Less: TransCanada’s carrying value of Iroquois at June 1, 2017

 

223

 

Excess purchase price (b)

 

370

 

 


(a)              Total purchase price of $710 million plus final working capital adjustment of $19 million and the additional consideration on Iroquois surplus cash amounting to approximately $28 million less the assumption of $164 million of proportional Iroquois debt by the Partnership.

(b)             The excess purchase price of $370 million was recorded as a reduction in Partners’ Equity.

 

The acquisition of an additional 11.81 percent interest in PNGTS, which resulted in the Partnership owning 61.71 percent in PNGTS, was accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby assets and liabilities of PNGTS were recorded at TransCanada’s carrying value and the Partnership’s historical financial information, except net income per common unit, was recast to consolidate PNGTS for all periods presented.

 

The PNGTS purchase price was recorded as follows:

 

(millions of dollars)

 

 

 

Current assets

 

25

 

Property, plant and equipment, net

 

294

 

Current liabilities

 

(4

)

Deferred state income taxes

 

(10

)

Long-term debt, including current portion

 

(41

)

 

 

264

 

 

 

 

 

Non-controlling interest

 

(100

)

Carrying value of pre-existing Investment in PNGTS

 

(132

)

TransCanada’s carrying value of the acquired 11.81 percent interest at June 1, 2017

 

32

 

Excess purchase price over net assets acquired (a)

 

21

 

Total cash consideration (b)

 

53

 

 


(a)              The excess purchase price of $21 million was recorded as a reduction in Partners’ Equity.

(b)             Total purchase price of $55 million plus the final working capital adjustment of $3 million less the assumption of $5 million of proportional PNGTS debt by the Partnership.

 

NOTE 7 PARTNERS’ EQUITY

 

ATM equity issuance program (ATM program)

 

During the nine months ended September 30, 2017, we issued 2,165,162 common units under our ATM program generating net proceeds of approximately $124 million, plus $2 million contributed by the General Partner to maintain its effective two percent general partner interest. The commissions to our sales agents in the nine months ended September 30, 2017 were approximately $1 million. 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

 

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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, 2017, 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 2018. During the nine months ended September 30, 2017, 30 percent of GTN’s total distributable cash flow was $28 million. As a result of exceeding the $20 million threshold, the Class B units’ equity account was increased by $8 million (Refer to Note 8).

 

For the year ended December 31, 2016, the Class B distribution was $22 million and was declared and paid in the first quarter of 2017.

 

Common unit issuance subject to rescission

 

In connection with a late filing of an employee-related Form 8-K with the SEC in March 2016, the Partnership became ineligible to use the then effective shelf registration statement upon filing of its Annual Report on Form 10-K for the year ended December 31, 2015. As a result, it was determined that the purchasers of the 1.6 million common units that were issued from March 8, 2016 to May 19, 2016 under the Partnership’s ATM program may have had a rescission right for an amount equal to the purchase price paid for the units, plus statutory interest and less any distributions paid, upon the return of such units to the Partnership. The Securities Act of 1933, as amended (Securities Act) generally requires that any claim brought for a violation of Section 5 of the Securities Act be brought within one year of violation.

 

At December 31, 2016, $83 million was recorded as common units subject to rescission on the consolidated balance sheet.  The Partnership classified the 1.6 million common units that were sold under its ATM program from March 8, 2016 up to and including May 19, 2016, which may have been subject to rescission rights, outside of equity given the potential redemption feature which was not within the control of the Partnership. These units were treated as outstanding for financial reporting purposes.

 

No unitholder claimed or attempted to exercise any rescission rights prior to their expiry dates and the final rights related to the sales of such units expired on May 19, 2017. As a result of the expiration of these rights, the $83 million was reclassified back to partners’ equity. At September 30, 2017, there were no outstanding common units subject to rescission on the Partnership’s consolidated balance sheet.

 

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 net income attributable to PNGTS’ former parent, 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 2017 equals 30 percent of GTN’s distributable cash flow during the year ended December 31, 2017 less $20 million (December 31, 2016 —$20 million).

 

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Net income per common unit was determined as follows:

 

 

 

Three months ended
September 30,

 

Nine months ended
September 30,

 

(unaudited)

 

 

 

(millions of dollars, except per common unit amounts)

 

2017

 

2016 (a)

 

2017

 

2016 (a)

 

 

 

 

 

 

 

 

 

 

 

Net income attributable to controlling interests (a)

 

54

 

58

 

186

 

188

 

Net income attributable to PNGTS’ former parent (a) (b)

 

 

 

(2

)

(3

)

Net income attributable to General and Limited Partners

 

54

 

58

 

184

 

185

 

Incentive distributions allocated to the General Partner (c) 

 

(3

)

(2

)

(9

)

(5

)

Net income attributable to the Class B units (d)

 

(8

)

(11

)

(8

)

(12

)

Net income attributable to the General Partner and common units

 

43

 

45

 

167

 

168

 

Net income attributable to General Partner’s effective two percent interest

 

(1

)

(2

)

(3

)

(4

)

Net income attributable to common units

 

42

 

43

 

164

 

164

 

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

 

69.4

 

66.1

(e)

68.9

 

65.3

(e)

Net income per common unit — basic and diluted

 

$

0.61

 

$

0.65

(f)

$

2.38

 

$

2.51

(f)

 


(a)              Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).

(b)             Net income allocable to General and Limited Partners excludes net income attributed to PNGTS’ former parent as it was allocated    to TransCanada and was not allocable to either the general partner, common units or Class B units.

(c)              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.

(d)             During the three and nine months ended September 30, 2017, 30 percent of GTN’s total distributable cash flow was $28 million. As a result of exceeding the $20 million threshold, $8 million of net income attributable to controlling interests was allocated to the Class B units during the three and nine months ended September 30, 2017.  During the six months ended June 30, 2016, the threshold was exceeded and during the nine months ended September 30, 2016, 30 percent of GTN’s total distributable cash flow was $32 million. As a result, $12 million of net income attributable to controlling interests was allocated to the Class B units at September 30, 2016, of which $1 million and $11 million were allocated during the three months ended June 30, 2016 and September 30, 2016, respectively (Refer to Note 7).

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

(f)               Net income per common unit prior to recast (Refer to Note 2).

 

NOTE 9 CASH DISTRIBUTIONS

 

During the three and nine months ended September 30, 2017, the Partnership distributed $1.00 and $2.88 per common unit, respectively (September 30, 2016 — $0.94 and $2.72 per common unit) for a total of $74 million and $210 million, respectively (September 30, 2016 - $65 million and $184 million).

 

The distribution paid to our General Partner during the three months ended September 30, 2017 for its effective two percent general partner interest was $2 million along with an IDR payment of $3 million for a total distribution of $5 million (September 30, 2016 - $1 million for the effective two percent interest and a $2 million IDR payment).

 

The distribution paid to our General Partner during the nine months ended September 30, 2017 for its effective two percent general partner interest was $4 million along with an IDR payment of $7 million for a total distribution of $11 million (September 30, 2016 - $3 million for the effective two percent interest and a $4 million IDR payment).

 

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NOTE 10 CHANGE IN OPERATING WORKING CAPITAL

 

(unaudited)

 

Nine months ended September 30,

 

(millions of dollars)

 

2017

 

2016 (a)

 

 

 

 

 

 

 

Change in accounts receivable and other

 

13

 

3

 

Change in other current assets

 

1

 

2

 

Change in accounts payable and accrued liabilities(b)

 

2

 

3

 

Change in accounts payable to affiliates

 

(3

)

(2

)

Change in accrued interest

 

11

 

5

 

Change in operating working capital

 

24

 

11

 

 


(a)              Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).

(b)             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 2016 cash flow statement.

 

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. For both the three and nine months ended September 30, 2017 and 2016, total costs charged to the Partnership by the General Partner were $1 million and $3 million, respectively.

 

As operator of our pipelines except Iroquois, 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. The Iroquois pipeline system is operated by Iroquois Pipeline Operating Company, a wholly owned subsidiary of Iroquois. Therefore, Iroquois does not receive any capital and operating services from TransCanada.

 

Capital and operating costs charged to our pipeline systems, except for Iroquois, for the three and nine months ended September 30, 2017 and 2016 by TransCanada’s subsidiaries and amounts payable to TransCanada’s subsidiaries at September 30, 2017 and December 31, 2016 are summarized in the following tables:

 

 

 

Three months ended
September 30,

 

Nine months ended
September 30,

 

(unaudited)

 

 

 

(millions of dollars)

 

2017

 

2016

 

2017

 

2016

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

Great Lakes (a) 

 

10

 

8

 

27

 

22

 

Northern Border (a)

 

10

 

9

 

30

 

25

 

GTN

 

9

 

8

 

24

 

20

 

Bison

 

2

 

1

 

4

 

1

 

North Baja

 

1

 

1

 

3

 

3

 

Tuscarora

 

1

 

1

 

3

 

3

 

PNGTS

 

2

 

2

 

6

 

6

 

Impact on the Partnership’s net income:

 

 

 

 

 

 

 

 

 

Great Lakes (a)

 

4

 

3

 

11

 

9

 

Northern Border (a)

 

4

 

3

 

11

 

9

 

GTN

 

7

 

7

 

21

 

18

 

Bison

 

2

 

1

 

4

 

2

 

North Baja

 

1

 

1

 

3

 

3

 

Tuscarora

 

1

 

1

 

3

 

3

 

PNGTS (b)

 

1

 

1

 

4

 

3

 

 

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Table of Contents

 

(unaudited)

 

September 30,

 

 

 

(millions of dollars)

 

2017

 

December 31, 2016

 

 

 

 

 

 

 

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

 

 

 

 

 

Great Lakes (a)

 

3

 

4

 

Northern Border (a)

 

3

 

4

 

GTN

 

3

 

3

 

Bison

 

1

 

1

 

North Baja

 

 

1

 

Tuscarora

 

 

1

 

PNGTS

 

1

 

1

 

 


(a)              Represents 100 percent of the costs.

(b)             Recast to consolidate PNGTS for all periods presented (Refer to Note 2).

 

Great Lakes earns significant transportation revenues from TransCanada and its affiliates, some of which are provided at discounted rates and some at maximum recourse rates. For the three and nine months ended September 30, 2017, Great Lakes earned 44 percent and 53 percent of transportation revenues from TransCanada and its affiliates, respectively (September 30, 2016 — 62 percent and 69 percent).

 

At September 30, 2017, $8 million was included in Great Lakes’ receivables in regards to the transportation contracts with TransCanada and its affiliates (December 31, 2016 — $19 million).

 

Great Lakes operates under a FERC approved 2013 rate settlement that includes a revenue sharing mechanism that requires Great Lakes to share with its shippers certain percentages of any qualifying revenues earned above a certain return on equity threshold. For the year ended December 31, 2016, Great Lakes recorded an estimated 2016 revenue sharing provision of $7.2 million. For the three and nine months ended September 30, 2017, Great Lakes recorded an estimated 2017 revenue sharing provision of $12 million and $22 million, respectively. Great Lakes expects that a significant percentage of this refund will be paid to its affiliates.

 

PNGTS earns transportation revenues from TransCanada and its affiliates. For three and nine months ended September 30, 2017, PNGTS earned approximately nil million and $1 million of its transportation revenues from TransCanada and its affiliates, respectively (2016 — $1 million and $2 million, respectively).

 

At September 30, 2017, nil million was included in PNGTS’ receivables in regards to the transportation contracts with TransCanada and its affiliates (December 31, 2016 — nil).

 

In connection with anticipated future commercial opportunities, PNGTS has entered into an arrangement with its affiliates regarding the construction of certain facilities on their systems that will be required to fulfill future contracts on the PNGTS’ system. In the event the anticipated developments do not proceed, PNGTS will be required to reimburse its affiliates for any costs incurred related to the development of these facilities. At September 30, 2017, PNGTS does not have an obligation for reimbursement under this arrangement.

 

NOTE 12 FAIR VALUE MEASUREMENTS

 

(a) Fair Value Hierarchy

 

Under Accounting Standards Codification (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

 

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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 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 September 30, 2017 and December 31, 2016 was $2,555 million and $1,962 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 Partnership’s 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 September 30, 2017, the fair value of the interest rate swaps accounted for as cash flow hedges was an asset of $2 million (both on a gross and net basis). At December 31, 2016, the fair value of the interest rate swaps accounted for as cash flow hedges was an asset of $1 million and a liability of $1 million (on a gross basis) and an asset of nil million (on a net basis). The Partnership did not record any amounts in net income related to ineffectiveness for interest rate hedges for the three and nine months ended September 30, 2017 and 2016. The change in fair value of interest rate derivative instruments recognized in other comprehensive income was nil and a gain of $1 million for the three and nine months ended September 30, 2017, respectively (September 30, 2016 — gain of $2 million and a loss of $1 million). For the three and nine months ended September 30, 2017, the net realized loss related to the interest rate swaps was nil, and was included in financial charges and other (September 30, 2016 —$1 million and $2 million) (Refer to Note 14) .

 

As discussed in Note 5, the Partnership’s $500 million 2013 Term Loan that was due July 1, 2018, was amended to extend the maturity period through October 2, 2022. At September 30, 2017, the entire $500 million 2013 Term Loan was hedged until July 1, 2018. As a result of this extension, the Partnership implemented an interest rate hedging strategy during the fourth quarter and hedged the entire $500 million until its October 2, 2022 maturity using forward starting swaps at an average rate of 3.26 percent.

 

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 September 30, 2017 (net asset of nil million as of December 31, 2016).

 

In anticipation of a debt refinancing in 2003, PNGTS entered into forward interest rate swap agreements to hedge the interest rate on its Senior Secured Notes due in 2018. These interest rate swaps were used to manage the impact of interest rate fluctuations and qualified as derivative financial instruments in accordance with ASC 815, Derivatives and Hedging. PNGTS settled its position with a payment of $20.9 million to counterparties at the time of the refinancing and recorded the realized loss in accumulated other comprehensive income as of the termination date. The previously recorded loss is currently being amortized against earnings over the life of the PNGTS Senior Secured Notes.  At September 30, 2017, our 61.71 percent proportionate share of net unamortized loss on PNGTS included in other comprehensive income was $1 million (December 31, 2016 - $2 million). For the three and nine months ended September 30, 2017, our 61.71 percent proportionate share of the amortization of realized loss on derivative instruments was nil and $1 million, respectively (September 30, 2016 —nil and $1 million).

 

NOTE 13 ACCOUNTS RECEIVABLE AND OTHER

 

(unaudited)

 

 

 

 

 

(millions of dollars)

 

September 30, 2017

 

December 31, 2016 (a)

 

 

 

 

 

 

 

Trade accounts receivable, net of allowance of nil

 

34

 

44

 

Imbalance receivable from affiliates

 

 

2

 

Other

 

1

 

1

 

 

 

35

 

47

 

 

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(a)              Recast as discussed in Notes 2 and 6.

 

NOTE 14 FINANCIAL CHARGES AND OTHER

 

 

 

Three months ended
September 30,

 

Nine months ended
September 30,

 

(unaudited)

 

 

 

(millions of dollars)

 

2017

 

2016(b)

 

2017

 

2016(b)

 

 

 

 

 

 

 

 

 

 

 

Interest expense (a)

 

23

 

17

 

59

 

52

 

PNGTS’ amortization of derivative loss on derivative instruments (Note 12) (b)

 

 

 

1

 

1

 

Net realized loss related to the interest rate swaps

 

 

1

 

 

2

 

Other income

 

 

 

(1

)

(2

)

 

 

23

 

18

 

59

 

53

 

 


(a)              Includes amortization of debt issuance costs and discount costs.

(b)             Recast to consolidate PNGTS for all periods presented (Refer to Note 2).

 

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 (Essar Minnesota) and certain Foreign 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 Eighth Circuit (Eighth 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.  The Eighth Circuit heard the appeal on October 20, 2016.  A decision on the appeal was received in December 2016 and the Eighth Circuit vacated Great Lakes’ judgment against Essar finding that there was no federal jurisdiction. Great Lakes filed a Request for Rehearing with the Eighth Circuit and it was denied in January 2017. Before the Circuit Court issued its decision, Essar Minnesota filed for bankruptcy in July 2016. The Foreign Essar Affiliates have not filed for bankruptcy. Following the Circuit Court’s decision, the performance bond was released into the bankruptcy court proceedings. Great Lakes filed a claim against Essar Minnesota in the bankruptcy court and its case against the Foreign Essar Affiliates in Minnesota state court remains pending. In April 2017, after Great Lakes agreement with creditors on an allowed claim, the bankruptcy court approved Great Lakes’ claim in the amount of $31.5 million.  On May 20, 2017, the federal district court awarded Essar Minnesota approximately $1.2 million for costs, including recovery of the performance bond premium, to be paid by Great Lakes. Great Lakes filed a motion with the bankruptcy court to offset the $1.2 million award of costs against its claim against Essar Minnesota in the bankruptcy proceeding.  If Great Lakes’ motion to offset the federal district court’s award of costs is against its claim in the bankruptcy proceeding is not successful, Great Lakes will be responsible to the bankruptcy estate for payment of the award. Great Lakes is unable to estimate the timing or the extent to which its claim will be recoverable in the bankruptcy proceedings.

 

NOTE 16 REGULATORY

 

North Baja —On January 6, 2017, North Baja notified FERC that current market conditions do not support the replacement of the compression that was temporarily abandoned in 2013 and requested authorization to permanently abandon two compressor units and a nominal volume of unsubscribed firm capacity. FERC approved the permanent abandonment request on February 16, 2017. The abandonments will not have any impact on existing firm transportation service.

 

Great Lakes - On April 24, 2017, Great Lakes reached an agreement on the terms of a new long-term transportation capacity contract with its affiliate, TransCanada. The contract, which was subject to Canada’s National Energy Board (NEB) approval, is for a term of 10 years and allows TransCanada the ability to transport up to 0.711 billion cubic feet of natural gas per day on the Great Lakes system from the Manitoba/U.S. border to the U.S. border near Dawn Ontario. On September 21, 2017, TransCanada received approval from the NEB and as a result, this contract commenced on November 1, 2017. This contract contains volume reduction options up to full contract quantity beginning in year three.

 

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On October 30, 2017, Great Lakes filed a rate settlement with FERC to satisfy its obligations from its 2013 rate settlement for new rates to be in effect by January 1, 2018 (2017 Great Lakes Settlement). The 2017 Great Lakes Settlement, if approved by FERC, will decrease Great Lakes’ maximum transportation rates by 27 percent beginning October 1, 2017.  Great Lakes expects that the impact from other changes, including: the recent long-term transportation contract with TransCanada as described above, other revenue opportunities on the system and the elimination of the revenue sharing mechanism with its customers, will more than offset the full year impact of the reduction in Great Lakes’ rates beginning in 2018. The 2017 Great Lakes Settlement does not contain any moratorium and Great Lakes will be required to file for new rates no later than March 31, 2022, with new rates to be effective October 1, 2022.

 

Northern Border- Northern Border and its shippers have been engaged in settlement discussions, and have recently agreed to a settlement-in-principle addressing all rate and service related issues raised during the settlement discussions. Northern Border plans to file a settlement agreement with FERC before the end of the year, reflecting the settlement-in-principle, precluding the need to file a general rate case as contemplated by its 2012 Settlement.  Northern Border anticipates that the Commission will accept the settlement agreement and that it will be unopposed. This will provide Northern Border with rate stability over the longer term.  At this time, we do not believe that the final outcome of the settlement will have a material impact to the Partnership’s results. Northern Border remains a key competitive pipeline and continues to operate at full capacity connecting major supply basins with communities in Midwestern U.S.

 

NOTE 17 VARIABLE INTEREST ENTITIES

 

In the normal course of business, the Partnership must re-evaluate its legal entities under the current 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

 

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Table of Contents

 

Lakes, PNGTS and Iroquois 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)

 

September 30, 2017

 

December 31, 2016(a)

 

 

 

 

 

 

 

ASSETS (LIABILITIES) *

 

 

 

 

 

Cash and cash equivalents

 

19

 

14

 

Accounts receivable and other

 

23

 

33

 

Inventories

 

6

 

6

 

Other current assets

 

4

 

6

 

Equity investments

 

1,207

 

918

 

Plant, property and equipment

 

1,132

 

1,146

 

Other assets

 

1

 

2

 

Accounts payable and accrued liabilities

 

(21

)

(21

)

Accounts payable to affiliates, net

 

(25

)

(32

)

Distributions payable

 

 

(3

)

Other taxes payable

 

(1

)

 

Accrued interest

 

(5

)

(2

)

Current portion of long-term debt

 

(51

)

(52

)

Long-term debt

 

(314

)

(337

)

Other liabilities

 

(26

)

(25

)

Deferred state income tax

 

(10

)

(10

)

 


*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.

 

(a) Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).

 

NOTE 18 INCOME TAXES

 

The Partnership’s income taxes relate to business profits tax (BPT) levied at the partnership (PNGTS) level by the state of New Hampshire. As a result of the BPT, PNGTS recognizes deferred taxes related to temporary differences between the financial statement carrying amount of existing assets and liabilities and their respective tax bases. The deferred taxes at September 30, 2017 and December 31, 2016 relate primarily to utility plant. At September 30, 2017 and December 31, 2016 the New Hampshire BPT effective tax rate was 3.8 percent for both periods and was applied to PNGTS’ taxable income.

 

 

 

Three months ended
September 30,

 

Nine months ended
September 30,

 

(unaudited)

 

 

 

(millions of dollars)

 

2017

 

2016(a)

 

2017

 

2016(a)

 

 

 

 

 

 

 

 

 

 

 

State income taxes

 

 

 

 

 

 

 

 

 

Current

 

 

(7

)

1

 

1

 

Deferred

 

 

7

 

 

 

 

 

 

 

1

 

1

 

 


(a)         Recast to consolidate PNGTS for all periods presented (Refer to Note 2 and 6).

 

NOTE 19 SUBSEQUENT EVENTS

 

Management of the Partnership has reviewed subsequent events through November 6, 2017, 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.

 

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On October 24, 2017, the board of directors of the General Partner declared the Partnership’s third quarter 2017 cash distribution in the amount of $1.00 per common unit payable on November 14, 2017 to unitholders of record as of November 3, 2017. The declared distribution totaled $75 million and is payable in the following manner: $70 million to common unitholders (including $6 million to the General Partner as a holder of 5,797,106 common units and $11 million to another subsidiary of TransCanada as holder of 11,287,725 common units) and $5 million to the General Partner, which included $2 million for its effective two percent general partner interest and $3 million in respect of its IDRs.

 

Northern Border declared its September 2017 distribution of $14 million on October 9, 2017, of which the Partnership will receive its 50 percent share or $7 million on October 31, 2017.

 

Great Lakes declared its third quarter 2017 distribution of $2 million on October 19, 2017, of which the Partnership will receive its 46.45 percent share or $1 million on November 1, 2017.

 

Iroquois declared its third quarter 2017 distribution of $28 million on October 23, 2017, of which the Partnership received its 49.34 percent share or $14 million on November 1, 2017. The distribution includes our 49.34 percent share of the Iroquois unrestricted cash distribution amounting to approximately $2.6 million (Refer to Note 6).

 

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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, 2016, in which certain parts of the report were amended through the Partnership’s filing of Current Report on Form 8-K dated August 3, 2017 to give retrospective adjustments to include the results of operations and financial position of PNGTS for all periods presented (Refer to Notes 2 and 6 within Item 1. “Financial Statements” of this Quarterly Report on Form 10-Q).

 

RECENT BUSINESS DEVELOPMENTS

 

Cash Distributions —

 

On April 25, 2017, the board of directors of our General Partner declared the Partnership’s first quarter 2017 cash distribution in the amount of $0.94 per common unit, payable on May 15, 2017 to unitholders of record as of May 5, 2017. The declared distribution totaled $68 million and was paid in the following manner: $65 million to common unitholders (including $5 million to the General Partner as a holder of 5,797,106 common units and $11 million to another subsidiary of TransCanada as holder of 11,287,725 common units) and $3 million to our General Partner, which included $1 million for its effective two percent general partner interest and $2 million in respect of its IDRs.

 

On July 20, 2017, the board of directors of our General Partner declared the Partnership’s second quarter 2017 cash distribution in the amount of $1.00 per common unit, payable on August 11, 2017 to unitholders of record as of August 1, 2017. The declared distribution totaled $74 million and was paid in the following manner: $69 million to common unitholders (including $6 million to the General Partner as a holder of 5,797,106 common units and $11 million to another subsidiary of TransCanada as holder of 11,287,725 common units) and $5 million to our General Partner, which included $2 million for its effective two percent general partner interest and $3 million in respect of its IDRs.

 

On October 24, 2017, the board of directors of our General Partner declared the Partnership’s third quarter 2017 cash distribution in the amount of $1.00 per common unit, payable on November 14, 2017 to unitholders of record as of November 3, 2017. The declared distribution totaled $75 million and is payable in the following manner: $70 million to common unitholders (including $6 million to the General Partner as a holder of 5,797,106 common units and $11 million to another subsidiary of TransCanada as holder of 11,287,725 common units) and $5 million to our General Partner, which included $2 million for its effective two percent general partner interest and $3 million in respect of its IDRs.

 

Pipeline updates

 

Great Lakes Contracting and Settlement- On April 24, 2017, Great Lakes reached an agreement on the terms of a new long-term transportation capacity contract with its affiliate, TransCanada. The contract, which was subject to Canada’s National Energy Board (NEB) approval, is for a term of 10 years and allows TransCanada the ability to transport up to 0.711 billion cubic feet of natural gas per day on the Great Lakes system from the Manitoba/U.S. border to the U.S. border near Dawn Ontario. On September 21, 2017, TransCanada received approval from the NEB and as a result, this contract commenced on November 1, 2017. This contract contains volume reduction options up to full contract quantity beginning in year three.

 

On October 30, 2017, Great Lakes filed a rate settlement with FERC to satisfy its obligations from its 2013 rate settlement for new rates to be in effect by January 1, 2018. The 2017 Great Lakes Settlement, if approved by FERC, will decrease Great Lakes’ maximum transportation rates by 27 percent beginning October 1, 2017.  Great Lakes expects that the impact from other changes, including: the recent long-term transportation contract with TransCanada as described above, other revenue opportunities on the system and the elimination of the revenue sharing mechanism with its customers, will more than offset the full year impact of the reduction in Great Lakes’ rates beginning in 2018. The 2017 Great Lakes Settlement does not contain any moratorium and Great Lakes will be required to file for new rates no later than March 31, 2022, with new rates to be effective October 1, 2022.

 

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Northern Border Rate Case- Northern Border and its shippers have been engaged in settlement discussions, and have recently agreed to a settlement-in-principle addressing all rate and service related issues raised during the settlement discussions. Northern Border plans to file a settlement agreement with FERC before the end of the year, reflecting the settlement-in-principle, precluding the need to file a general rate case as contemplated by its 2012 Settlement.  Northern Border anticipates that the Commission will accept the settlement agreement and that it will be unopposed. This will provide Northern Border with rate stability over the longer term.  At this time, we do not believe that the final outcome of the settlement will have a material impact to the Partnership’s results. Northern Border remains a key competitive pipeline and continues to operate at full capacity connecting major supply basins with communities in Midwestern U.S.

 

Northern Border Contracting — Northern Border revenues are now substantially supported by firm transportation contracts through March 2020. The continued successful renewals of these contracts provide a strong indication of Northern Border’s attractiveness to its customers.

 

PNGTS Projects

 

Continent to Coast (C2C) Project

 

As previously reported in our 2016 Annual Report on the Form 10-K dated February 28, 2017, PNGTS filed to increase its FERC-certificated capacity as contemplated in its Continent-to-Coast (C2C) contracts, bringing its capacity capability up to 210,000 Dth/day effective November 1, 2017. PNGTS has not received full regulatory approvals to date but will cooperatively work with C2C shippers while awaiting approvals.

 

Portland XPress Project

 

PNGTS has executed Precedent Agreements with several Local Distribution Companies in New England and Atlantic Canada to re-contract certain system capacity set to expire in 2019 as well as expand the PNGTS system to bring its certificated capacity up to 0.3 Bcf/d. The approximately $80 million Portland XPress Project (PXP) will proceed concurrently with upstream capacity expansions. The in-service dates of PXP are being phased-in over a three-year period beginning November 1, 2018.

 

Acquisitions and Financing

 

Debt Offering — On May 25, 2017, the Partnership closed a $500 million public offering of senior unsecured notes bearing an interest rate of 3.90 percent maturing May 25, 2027. The net proceeds of $497 million were used to fund a portion of the 2017 Acquisition (Refer to Note 6 within Item 1. “Financial Statements” of this Quarterly Report on Form 10Q).

 

2017 Acquisition — On June 1, 2017, the Partnership completed the acquisitions of a 49.34 percent interest in Iroquois from subsidiaries of TransCanada including an option to acquire a further 0.66 percent interest in Iroquois, together with an additional 11.81 percent interest in PNGTS that resulted in the Partnership owning a 61.71 percent interest in PNGTS. The total purchase price of the 2017 Acquisition was $765 million plus the final purchase price adjustments amounting to approximately $50 million. The purchase price consisted of  (i) $710 million for the Iroquois interest (less $164 million, which reflected the Partnership’s 49.34 percent share of Iroquois outstanding debt at the time of the 2017 Acquisition   (ii) $55 million for the additional 11.81 percent in PNGTS (less $5 million, which reflected our 11.81 percent share in PNGTS’ outstanding debt at the time of the 2017 Acquisition) (iii) final working capital adjustments on PNGTS and Iroquois amounting to $3 million and $19 million, respectively and (iv) additional consideration on Iroquois’ surplus cash amounting to $28 million. The Partnership funded the cash portion of the 2017 Acquisition through a combination of proceeds from the May 25, 2017 public debt offering and borrowing under its Senior Credit Facility

 

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As at the date of the 2017 Acquisition, there was significant cash on Iroquois’ balance sheet.  Pursuant to the Purchase and Sale Agreement associated with the acquisition of the Iroquois interest, as amended, the Partnership agreed to pay $28 million plus interest to TransCanada on August 1, 2017 for its 49.34 percent share of cash determined to be surplus to Iroquois’ operating needs.

 

Additionally, Iroquois’ partners adopted a distribution resolution to address the significant cash on Iroquois’ balance sheet post-closing. The Partnership expects to receive the $28 million of unrestricted cash as part of its quarterly distributions from Iroquois over 11 quarters under the terms of the resolution, which began with Iroquois’ second quarter 2017 distribution on August 1, 2017. As of November 6, 2017 the Partnership has received approximately $5.2 million of the expected $28 million, of which $2.6 million was received on November 1, 2017.

 

The Iroquois pipeline transports natural gas under long-term contracts and extends from the TransCanada Mainline system at the U.S. border near Waddington, New York to markets in the U.S. northeast, including New York City, Long Island and Connecticut.  Iroquois provides service to local gas distribution companies, electric utilities and electric power generators, as well as marketers and other end users, directly or indirectly, through interconnecting pipelines and exchanges throughout the northeastern U.S. Both the Iroquois and PNGTS pipelines are critical natural gas infrastructure systems in the Northeast U.S. market and the addition of Iroquois to the Partnership’s asset portfolio will further diversify our cash flow.

 

Tuscarora Refinancing — On August 21, 2017, Tuscarora refinanced all of its outstanding debt by amending its existing Unsecured Term Loan Facility and issuing a new $25 million variable rate term loan that will require yearly principal payments and will mature on August 21, 2020. Tuscarora’s Unsecured Term Loan contains a covenant that requires 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 or equal to 3.00 to 1.00. As of September 30, 2017, the ratio was 3.08 to 1.00.

 

2013 Term Loan Facility - On September 29, 2017, the Partnership’s variable rate 2013 $500 million Term loan facility that was due on July 1, 2018 was amended to extend the maturity period through October 2, 2022. At September 30, 2017, the $500 million 2013 Term loan facility is hedged by fixed interest rate swap arrangements at an effective interest rate of 2.31 percent, expiring July 1, 2018. As a result of this extension, the Partnership implemented an interest rate hedging strategy during the fourth quarter and hedged the entire $500 million until its October 2, 2022 maturity using forward starting swaps at an average rate of 3.26 percent.

 

2015 Term Loan Facility-On September 29, 2017, the Partnership’s 2015 $170 million Term loan facility that was due on October 1, 2018 was amended to extend the maturity period through October 1, 2020.

 

HOW WE EVALUATE OUR OPERATIONS

 

We use certain non-GAAP financial measures that do not have any standardized meaning under GAAP as 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.

 

Please see “Non-GAAP Financial Measures: EBITDA and Distributable Cash Flow” for more information.

 

RESULTS OF OPERATIONS

 

Our equity interests in Northern Border, Great Lakes, and effective June 1, 2017, Iroquois and full ownerships of GTN, Bison, North Baja and Tuscarora and beginning also on June 1, 2017, 61.71 percent ownership in PNGTS 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

 

 

 

 

 

Nine months
ended

 

 

 

 

 

(unaudited)

 

September 30,

 

$

 

%

 

September 30,

 

$

 

%

 

(millions of dollars)

 

2017

 

2016(a)

 

Change*

 

Change*

 

2017

 

2016(a)

 

Change*

 

Change*

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Transmission revenues

 

100

 

103

 

(3

)

(3

)

313

 

315

 

(2

)

(1

)

Equity earnings

 

27

 

22

 

5

 

23

 

87

 

75

 

12

 

16

 

Operating, maintenance and administrative

 

(24

)

(23

)

(1

)

(4

)

(74

)

(67

)

(7

)

(10

)

Depreciation

 

(25

)

(24

)

(1

)

(4

)

(73

)

(71

)

(2

)

(3

)

Financial charges and other

 

(23

)

(18

)

(5

)

(3

)

(59

)

(53

)

(6

)

(11

)

Net income before taxes

 

55

 

60

 

(5

)

(8

)

194

 

199

 

(5

)

(3

)

State income taxes

 

 

 

 

 

(1

)

(1

)

 

 

Net income

 

55

 

60

 

(5

)

(8

)

193

 

198

 

(5

)

(3

)

Net income attributable to non-controlling interests

 

1

 

2

 

1