Company Quick10K Filing
Quick10K
TC Pipelines
Closing Price ($) Shares Out (MM) Market Cap ($MM)
$35.86 73 $2,630
10-Q 2019-03-31 Quarter: 2019-03-31
10-K 2018-12-31 Annual: 2018-12-31
10-Q 2018-09-30 Quarter: 2018-09-30
10-Q 2018-06-30 Quarter: 2018-06-30
10-Q 2018-03-31 Quarter: 2018-03-31
10-K 2017-12-31 Annual: 2017-12-31
10-Q 2017-09-30 Quarter: 2017-09-30
10-Q 2017-06-30 Quarter: 2017-06-30
10-Q 2017-03-31 Quarter: 2017-03-31
10-K 2016-12-31 Annual: 2016-12-31
10-Q 2016-09-30 Quarter: 2016-09-30
10-Q 2016-06-30 Quarter: 2016-06-30
10-Q 2016-03-31 Quarter: 2016-03-31
10-K 2015-12-31 Annual: 2015-12-31
10-Q 2015-09-30 Quarter: 2015-09-30
10-Q 2015-06-30 Quarter: 2015-06-30
10-Q 2015-03-31 Quarter: 2015-03-31
10-K 2014-12-31 Annual: 2014-12-31
10-Q 2014-09-30 Quarter: 2014-09-30
10-Q 2014-06-30 Quarter: 2014-06-30
10-Q 2014-03-31 Quarter: 2014-03-31
10-K 2013-12-31 Annual: 2013-12-31
8-K 2019-05-08 Earnings, Regulation FD, Exhibits
8-K 2019-04-23 Other Events, Exhibits
8-K 2019-04-16 Regulation FD, Exhibits
8-K 2019-02-21 Earnings, Exhibits
8-K 2019-02-19 Earnings, Regulation FD, Exhibits
8-K 2019-01-31 Regulation FD, Exhibits
8-K 2019-01-22 Other Events, Exhibits
8-K 2019-01-22 Other Events, Exhibits
8-K 2018-12-31 Enter Agreement, Amend Bylaw, Exhibits
8-K 2018-11-29 Regulation FD, Exhibits
8-K 2018-11-27 Officers
8-K 2018-11-19 Enter Agreement, Exhibits
8-K 2018-11-09 Earnings, Regulation FD, Exhibits
8-K 2018-11-02 Regulation FD, Exhibits
8-K 2018-10-26 Regulation FD, Exhibits
8-K 2018-10-23 Other Events, Exhibits
8-K 2018-10-17 Other Events, Exhibits
8-K 2018-09-24 Regulation FD
8-K 2018-08-02 Earnings, Regulation FD, Exhibits
8-K 2018-07-26 Other Events, Exhibits
8-K 2018-07-19 Regulation FD, Exhibits
8-K 2018-05-17 Regulation FD, Exhibits
8-K 2018-05-01 Officers, Exhibits
8-K 2018-04-27 Regulation FD, Exhibits
8-K 2018-04-16 Regulation FD, Exhibits
8-K 2018-03-19 Regulation FD, Exhibits
8-K 2018-02-23 Earnings, Exhibits
8-K 2018-02-22 Officers, Exhibits
8-K 2018-02-09 Regulation FD, Exhibits
8-K 2018-01-23 Other Events, Exhibits
TRV Travelers Companies 37,150
CSGP Costar Group 18,080
OAS Oasis Petroleum 1,710
SGC Superior Group of Companies 243
CODA Coda Octopus Group 159
TACT Transact Technologies 69
CTGO Contango Ore 0
PEYE Precision Opticsoration 0
NTVA Nexien BioPharma 0
LVYN Lvyuan Green Building Material Technology 0
TCP 2019-03-31
Part I
Part I - Financial Information
Item 1. Financial Statements
Note 1 Organization
Note 2 Significant Accounting Policies
Note 3 Accounting Pronouncements
Note 4 Regulatory
Note 5 Equity Investments
Note 6 Revenues
Note 7 Debt and Credit Facilities
Note 8 Partners' Equity
Note 9 Net Income per Common Unit
Note 10 Cash Distributions Paid To Common Units
Note 11 Change in Operating Working Capital
Note 12 Related Party Transactions
Note 13 Fair Value Measurements
Note 14 Accounts Receivable and Other
Note 15 Financial Charges and Other
Note 16 Variable Interest Entities
Note 17 Subsequent Events
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Item 4. Controls and Procedures
Part II - Other Information
Item 1. Legal Proceedings
Item 1A. Risk Factors
Item 6. Exhibits
EX-31.1 a19-6499_1ex31d1.htm
EX-31.2 a19-6499_1ex31d2.htm
EX-32.1 a19-6499_1ex32d1.htm
EX-32.2 a19-6499_1ex32d2.htm
EX-99.1 a19-6499_1ex99d1.htm
EX-99.2 a19-6499_1ex99d2.htm

TC Pipelines Earnings 2019-03-31

TCP 10Q Quarterly Report

Balance SheetIncome StatementCash Flow

10-Q 1 a19-6499_110q.htm 10-Q

Table of Contents

 

 

 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

FORM 10-Q

 

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

 

For the quarterly period ended March 31, 2019

 

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

 

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

 

Securities registered pursuant to Section 12(b) of the Exchange Act:

 

Title of each class

 

Trading
Symbol(s)

 

Name of each exchange on which registered

Common units representing limited partner interests

 

TCP

 

New York Stock Exchange

 

As of May 7, 2019, there were 71,306,396 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

2017 Tax Act

 

Public Law No. 115-97, commonly known as the Tax Cuts and Jobs Act, enacted on December 22, 2017

2018 FERC Actions

 

FERC’s 2018 issuance of Revised Policy Statement on Treatment of Income Taxes (Revised Policy Statement) and a Final Rule that established a schedule by which interstate pipelines must either (i) file a new uncontested rate settlement or (ii) file a one-time report, called FERC Form No. 501-G, that quantified the rate impact of the 2017 Tax Act on FERC-regulated pipelines and the impact of the Revised Policy Statement on pipelines held by an MLP

2019 Iroquois Settlement

 

An uncontested settlement filed by Iroquois with FERC to address the issues contemplated by the 2017 Tax Act and 2018 FERC Actions via an amendment to its prior 2016 settlement approved by FERC on May 2, 2019

2019 Tuscarora Settlement

 

An uncontested settlement filed by Tuscarora with FERC to address the issues contemplated by the 2017 Tax Act and 2018 FERC Actions via an amendment to its prior 2016 settlement approved by FERC on May 2, 2019

ADIT

 

Accumulated Deferred Income Tax

ASC

 

Accounting Standards Codification

ASU

 

Accounting Standards Update

ATM program

 

At-the-market equity issuance program

Bison

 

Bison Pipeline LLC

Class B Distribution

 

Annual distribution to TC Energy based on 30 percent of GTN’s annual distributions as follows: (i) i) 100 percent of distributions above $20 million for the year ending December 31, 2019; (ii) 43.75 percent of distributions above $20 million for the year ending December 31, 2020; and (iii) 25 percent of distributions above $20 million thereafter

Class B Reduction

 

Approximately 35 percent reduction applied to the estimated annual Class B Distribution beginning in 2018, which is equivalent to the percentage by which distributions payable to the common units were reduced in 2018. The Class B Reduction will continue to apply for any particular calendar year until distributions payable in respect of common units for such calendar year equal or exceed $3.94 per common unit

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

MLPs

 

Master limited partnerships

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

 

Fourth Amended and Restated Agreement of Limited Partnership of the Partnership

PNGTS

 

Portland Natural Gas Transmission System

PXP

 

Portland XPress Project

ROU

 

Right-of-use

 

3


Table of Contents

 

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

TC Energy

 

TC Energy Corporation formerly known as TransCanada Corporation

Tuscarora

 

Tuscarora Gas Transmission Company

U.S.

 

United States of America

VIEs

 

Variable Interest Entities

Westbrook XPress

 

Westbrook XPress Project of PNGTS that is part of a coordinated offering to transport incremental Western Canadian Sedimentary Basin natural gas supplies to the Northeast U.S. and Atlantic Canada markets through additional compression capability at an existing PNGTS facility

Wholly-owned subsidiaries

 

GTN, Bison, North Baja, and Tuscarora

 

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).

 

4


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, dropdown opportunities, 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;

·                  the impact of Public Law No. 115-97, commonly known as the Tax Cuts and Jobs Act (“2017 Tax Act”) enacted on December 22, 2017 on our future operating performance;

·                  other potential changes in the taxation of master limited partnership (MLP) investments by state or federal governments such as 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), 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, structure and closure of further potential acquisitions;

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

·                  failure to comply with debt covenants, some of which are beyond our control;

·                  the ability to maintain secure operation of our information technology including management of cybersecurity threats, acts of terrorism and related distractions;

·                  the implementation of future accounting changes and ultimate outcome of commitments and contingent liabilities (if any);

·                  the impact of any impairment charges;

·                  changes in the political environment;

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

·                  the overall increase in the allocated management and operational expenses to our pipeline systems for services performed by TC Energy Corporation; and

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

 

5


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 II, Item 1A. “Risk Factors” of this report and in Part I, Item 1A. “Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2018 as filed with the SEC on February 21, 2019. 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.

 

6


Table of Contents

 

PART I — FINANCIAL INFORMATION

 

Item 1.           Financial Statements

 

TC PIPELINES, LP

CONSOLIDATED STATEMENTS OF INCOME

 

 

 

Three months ended

 

(unaudited)

 

March 31,

 

(millions of dollars, except per common unit amounts)

 

2019

 

2018

 

 

 

 

 

 

 

Transmission revenues

 

113

 

115

 

Equity earnings (Note 5)

 

54

 

59

 

Operation and maintenance expenses

 

(16

)

(16

)

Property taxes

 

(7

)

(7

)

General and administrative

 

(2

)

(1

)

Depreciation and amortization

 

(20

)

(24

)

Financial charges and other (Note 15)

 

(22

)

(23

)

Net income before taxes

 

100

 

103

 

 

 

 

 

 

 

Income taxes

 

 

(1

)

Net Income

 

100

 

102

 

 

 

 

 

 

 

Net income attributable to non-controlling interest

 

7

 

6

 

Net income attributable to controlling interests

 

93

 

96

 

 

 

 

 

 

 

Net income attributable to controlling interest allocation (Note 9)

 

 

 

 

 

Common units

 

91

 

94

 

General Partner

 

2

 

2

 

 

 

93

 

96

 

 

 

 

 

 

 

Net income per common unit (Note 9)basic and diluted

 

$

1.28

 

$

1.32

 

 

 

 

 

 

 

Weighted average common units outstanding basic and diluted (millions)

 

71.3

 

71.2

 

 

 

 

 

 

 

Common units outstanding, end of period (millions)

 

71.3

 

71.3

 

 

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

 

7


Table of Contents

 

TC PIPELINES, LP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

 

 

 

Three months ended

 

(unaudited)

 

March 31,

 

(millions of dollars)

 

2019

 

2018

 

 

 

 

 

 

 

Net income

 

100

 

102

 

Other comprehensive income

 

 

 

 

 

Change in fair value of cash flow hedges (Note 13)

 

(5

)

7

 

Comprehensive income

 

95

 

109

 

Comprehensive income attributable to non-controlling interests

 

7

 

6

 

Comprehensive income attributable to controlling interests

 

88

 

103

 

 

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

 

8


Table of Contents

 

TC PIPELINES, LP

CONSOLIDATED BALANCE SHEETS

 

(unaudited)

 

 

 

 

 

(millions of dollars)

 

March 31, 2019

 

December 31, 2018

 

 

 

 

 

 

 

ASSETS

 

 

 

 

 

Current Assets

 

 

 

 

 

Cash and cash equivalents

 

52

 

33

 

Accounts receivable and other (Note 14)

 

41

 

48

 

Inventories

 

9

 

8

 

Other

 

5

 

8

 

 

 

107

 

97

 

 

 

 

 

 

 

Equity investments (Note 5)

 

1,196

 

1,196

 

Property, plant and equipment

     (Net of $1,128 accumulated depreciation; 2018 - $1,110)

 

1,522

 

1,529

 

Goodwill

 

71

 

71

 

Other assets

 

3

 

6

 

TOTAL ASSETS

 

2,899

 

2,899

 

 

 

 

 

 

 

LIABILITIES AND PARTNERS’ EQUITY

 

 

 

 

 

Current Liabilities

 

 

 

 

 

Accounts payable and accrued liabilities

 

29

 

36

 

Accounts payable to affiliates (Note 12)

 

7

 

6

 

Accrued interest

 

20

 

12

 

Current portion of long-term debt (Note 7)

 

36

 

36

 

 

 

92

 

90

 

 

 

 

 

 

 

Long-term debt, net (Note 7)

 

2,040

 

2,072

 

Deferred state income taxes

 

9

 

9

 

Other liabilities

 

31

 

29

 

 

 

2,172

 

2,200

 

Partners’ Equity

 

 

 

 

 

Common units

 

507

 

462

 

Class B units (Note 8)

 

95

 

108

 

General partner

 

14

 

13

 

Accumulated other comprehensive income (AOCI)

 

3

 

8

 

Controlling interests

 

619

 

591

 

 

 

 

 

 

 

Non-controlling interests

 

108

 

108

 

 

 

727

 

699

 

TOTAL LIABILITIES AND PARTNERS’ EQUITY

 

2,899

 

2,899

 

 

Variable Interest Entities (Note 16)

Subsequent Events (Note 17)

 

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

 

9


Table of Contents

 

TC PIPELINES, LP

CONSOLIDATED STATEMENT OF CASH FLOWS

 

 

 

Three months ended

 

(unaudited)

 

March 31,

 

(millions of dollars)

 

2019

 

2018

 

 

 

 

 

 

 

Cash Generated from Operations

 

 

 

 

 

Net income

 

100

 

102

 

Depreciation and amortization

 

20

 

24

 

Amortization of debt issue costs reported as interest expense

 

 

1

 

Equity earnings from equity investments (Note 5)

 

(54

)

(59

)

Distributions received from operating activities of equity investments (Note 5)

 

56

 

43

 

Change in operating working capital (Note 11)

 

13

 

6

 

 

 

135

 

117

 

Investing Activities

 

 

 

 

 

Investment in Great Lakes (Note 5)

 

(5

)

(4

)

Distribution received from Iroquois as return of investment (Note 5)

 

2

 

2

 

Capital expenditures

 

(16

)

(2

)

Customer advances for construction

 

2

 

 

 

 

(17

)

(4

)

Financing Activities

 

 

 

 

 

Distributions paid to common units, including the general partner (Note 10)

 

(47

)

(76

)

Distributions paid to Class B units (Note 8)

 

(13

)

(15

)

Distributions paid to non-controlling interests

 

(7

)

(1

)

Common unit issuance, net

 

 

40

 

Long-term debt issued, net of discount (Note 7)

 

18

 

75

 

Long-term debt repaid (Note 7)

 

(50

)

(101

)

 

 

(99

)

(78

)

Increase in cash and cash equivalents

 

19

 

35

 

Cash and cash equivalents, beginning of period

 

33

 

33

 

Cash and cash equivalents, end of period

 

52

 

68

 

 

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

 

10


Table of Contents

 

TC PIPELINES, LP

CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS’ EQUITY

 

 

 

Limited Partners

 

General

 

Accumulated
Other

Comprehensive

 

Non-

Controlling

 

Total

 

 

 

Common units

 

Class B units

 

Partner

 

Income (a)

 

Interest

 

Equity

 

(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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Partners’ Equity at December 31, 2018

 

71.3

 

462

 

1.9

 

108

 

13

 

8

 

108

 

699

 

Net income

 

 

91

 

 

 

2

 

 

7

 

100

 

Other comprehensive income

 

 

 

 

 

 

(5

)

 

(5

)

Distributions (Note 10)

 

 

(46

)

 

(13

)

(1

)

 

(7

)

(67

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Partners’ Equity at March 31, 2019

 

71.3

 

507

 

1.9

 

95

 

14

 

3

 

108

 

727

 

 


(a)     Gain (Losses) related to cash flow hedges reported in AOCI 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.

 

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

 

11


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 now known as TC Energy Corporation (TC Energy Corporation together with its subsidiaries collectively referred to herein as TC Energy), to acquire, own and participate in the management of energy infrastructure assets in North America.

 

The Partnership owns its pipeline assets through an intermediate general partnership, TC PipeLines Intermediate GP, LLC and 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 consolidated financial statements and related notes have been prepared in accordance with United States generally accepted accounting principles (GAAP) and amounts are stated in U.S. dollars. The results of operations for the three months ended March 31, 2019 and 2018 are not necessarily indicative of the results that may be expected for the full fiscal year.

 

The accompanying consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto for the year ended December 31, 2018 included in our Annual Report on Form 10-K. That report contains a more comprehensive summary of the Partnership’s significant accounting policies. In the opinion of management, the accompanying consolidated financial statements contain all of the appropriate adjustments, which are normally recurring adjustments unless otherwise noted, and considered necessary to present fairly the financial position of the Partnership, the results of operations and cash flows for the respective periods. Our significant accounting policies are consistent with those disclosed in our Annual Report on Form 10-K for the year ended December 31, 2018, 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 as 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 TC Energy are considered common control transactions. If businesses are acquired from TC Energy that will be consolidated by the Partnership, the historical consolidated financial statements are required to be recast, except net income per common unit, to include the acquired entities for all periods presented.

 

If the Partnership acquires an asset or an investment from TC Energy, 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.

 

U.S. federal and certain state income taxes are the responsibility of the partners and are not reflected in these consolidated financial statements. The tax effect of the Partnership’s activities accrues to its partners. The Partnership’s taxable income or loss, which may vary substantially from the net income or loss reported in the consolidated statement of operations, is includable in the U.S. federal income tax returns of each partner.

 

In instances where the Partnership’s consolidated entities are subject to state income taxes, the asset-liability method is used to account for taxes. This method requires the recognition of deferred tax assets and liabilities for future tax consequences attributable to the differences between the financial statement carrying amount of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are classified as non-current on our consolidated balance sheet.

 

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, if any, as of the date of the financial statements, and the

 

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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

 

Changes in Accounting Policies effective January 1, 2019

 

Leases

 

In February 2016, the Financial Accounting Standards Board (FASB) issued new guidance on the accounting for leases. The new guidance amends the definition of a lease such that, in order for an arrangement to qualify as a lease, the lessee is required 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. 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 consolidated balance sheet for all leases with a term longer than twelve months. Leases will be classified as finance or operating, with classification affecting the pattern of expense recognition in the consolidated statements of income. The new guidance does not make extensive changes to previous lessor accounting.

 

Under the new guidance, the Partnership determines if an arrangement is a lease at inception. Operating leases are recognized as ROU assets and included in Property, plant and equipment while corresponding liabilities are included in “Accounts payable and other”, and “Other long-term liabilities” on the consolidated balance sheet.

 

Operating lease ROU assets and operating lease liabilities are recognized based on the present value of the future minimum lease payments over the lease term at commencement date. As the Partnership’s leases do not provide an implicit rate, the Partnership uses an incremental borrowing rate that approximates its borrowing cost based on the information available at commencement date in determining the present value of future payments. The operating lease ROU asset also includes any lease payments made and initial direct costs incurred and excludes lease incentives. Lease terms may include options to extend or terminate the lease when it is reasonably certain that the Partnership will exercise that option. Operating lease expense is recognized on a straight-line basis over the lease term and included in “Operation and maintenance expenses” in the consolidated statements of income.

 

The new guidance was effective January 1, 2019 and was applied using optional transition relief which allowed entities to initially apply the new lease standard at adoption and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. This transition option allowed us to not apply the new guidance, including disclosure requirements, to the comparative periods presented.

 

We elected available practical expedients and exemptions upon adoption which allowed us:

 

·                  not to reassess prior conclusions on existing leases regarding lease identification, lease classification and initial direct costs under the new standard

·                  to carry forward the historical lease classification and our accounting treatment for land easements on existing agreements

·                  to not recognize ROU assets or lease liabilities for leases that qualify for the short-term lease recognition exemption

·                  to not separate lease and non-lease components for all leases for which we are the lessee

·                  to use hindsight in determining the lease term and assessing ROU assets for impairment.

 

In the application of the new guidance, assumptions and judgements are used to determine the following:

 

·                  whether a contract contains a lease and the duration of the lease term including exercising lease renewal options. The lease term for all of the Partnership’s leases includes the non-cancellable period of the lease plus any additional periods covered by either the Partnership’s option to extend (or not to terminate) the lease that the Partnership is reasonably certain to exercise, or an option to extend (or not to terminate) the lease controlled by the lessor; and

·                  the discount rate for the lease.

 

The standard did not impact our previously reported results and did not have material impact on the Partnership’s consolidated balance sheet, consolidated statements of income or consolidated statement of cash flows at the date of adoption.

 

The most significant change as a result of the adoption was the recognition of ROU assets and lease liabilities for operating leases which was approximately $0.6 million at January 1, 2019 and $0.5 million at March 31, 2019. For the three months

 

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ended March 31, 2019, the Partnership’s operating lease cost was not material to the Partnership’s consolidated results. The weighted average remaining term and discount rate of the Partnership’s operating leases was approximately 2.63 years and 3.57 percent, respectively.

 

Fair Value Measurement

 

In August 2018, the FASB issued new guidance that amends certain disclosure requirements for the fair value measurements as part of its disclosure framework project. This new guidance is effective January 1, 2020, however, early adoption of certain or all requirements is permitted. The Partnership elected to adopt this guidance effective first quarter 2019. The guidance was applied retrospectively and did not have a material effect on the Partnership’s consolidated financial statements.

 

Future accounting changes

 

Measurement of credit losses on financial instruments

 

In June 2016, the FASB issued new guidance that significantly changes how entities measure credit losses for most financial assets and certain other financial instruments that are not measured at fair value through net income (loss). The new guidance amends the impairment model of financial instruments basing it on expected losses rather than incurred losses. These expected credit losses will be recognized as an allowance rather than as a direct write down of the amortized cost basis. The new guidance is effective January 1, 2020 and will be applied using a modified retrospective approach. We are currently evaluating the impact of the adoption of this guidance and have not yet determined the effect on our consolidated financial statements.

 

Consolidation

 

In October 2018, the FASB issued new guidance for determining whether fees paid to decision makers and service providers are variable interests for indirect interests held through related parties under common control. This new guidance is effective January 1, 2020, and will be applied on a retrospective basis, however early adoption is permitted. The Partnership is currently evaluating the timing and impact of adoption of this guidance and has not yet determined the effect on its consolidated financial statements.

 

NOTE 4  REGULATORY

 

Iroquois, Tuscarora, and Northern Border took the actions listed below to conclude the issues impacting their pipelines as contemplated by the 2017 Tax Act and certain FERC actions that began in March of 2018, namely FERC’s Revised Policy Statement on Treatment of Income Taxes (Revised Policy Statement) and a Final Rule that established a schedule by which interstate pipelines must either (i) file a new uncontested rate settlement or (ii) file a one-time report, called FERC Form No. 501-G, that quantified the rate impact of the 2017 Tax Act on FERC-regulated pipelines and the impact of the Revised Policy Statement on pipelines held by an MLP (collectively “2018 FERC Actions”).

 

Iroquois

 

On February 28, 2019, Iroquois filed an uncontested settlement with FERC to address the issues contemplated by the 2017 Tax Act and 2018 FERC Actions via an amendment to its prior 2016 settlement (2019 Iroquois Settlement). Among the terms of the 2019 Iroquois Settlement, Iroquois agreed to reduce its existing maximum system rates by 6.5 percent to be implemented in two phases, (i) effective March 1, 2019, a 3.25 percent rate reduction and (ii) effective April 1, 2020, an additional 3.25 percent rate reduction, which is the remaining one-half of the total 6.5 percent rate reduction from the 2016 settlement rates. The 2019 Iroquois Settlement, which was approved by FERC on May 2, 2019, preserved the 2016 settlement moratorium on further rate changes until September 1, 2020. Unless superseded by a subsequent rate case or settlement, Iroquois will be required to have new rates in effect on March 1, 2023.

 

Tuscarora

 

On March 15, 2019, Tuscarora filed an uncontested settlement with FERC to address the issues contemplated by the 2017 Tax Act and 2018 FERC Actions via an amendment to its prior 2016 settlement (2019 Tuscarora Settlement). Among the terms of the 2019 Tuscarora Settlement, Tuscarora agreed to reduce its existing maximum system rates by 1.7 percent effective February 1, 2019 through to July 31, 2019. The existing maximum rates will decrease by an additional 10.8 percent for the period August 1, 2019 through the term of the settlement. Tuscarora is required to have new rates in effect on February 1, 2023. Tuscarora and its customers also agreed on a moratorium on further rate changes until January 31, 2023. The 2019 Tuscarora Settlement, which was approved by FERC on May 2, 2019, will also reflect an elimination of the tax allowance previously recovered in rates along with accumulated deferred income taxes (ADIT) for rate-making purposes.

 

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Northern Border

 

On April 4, 2019, Northern Border filed a petition for approval with FERC to amend the settlement agreement reached with its customers in 2017.  Unless superseded by a subsequent rate case or settlement, effective January 1, 2020, the additional 2 percent rate reduction implemented on February 1, 2019 will be extended to July 1, 2024 as part of the amended settlement agreement. The amendment is pending approval from FERC.

 

NOTE 5    EQUITY INVESTMENTS

 

The Partnership has equity interests in Northern Border, Great Lakes and 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 TC Energy. 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 16).

 

 

 

Ownership

 

Equity Earnings

 

Equity Investments

 

 

 

Interest at

 

Three months

 

 

 

 

 

(unaudited)

 

March 31,

 

ended March 31,

 

March 31,

 

December 31,

 

(millions of dollars)

 

2019

 

2019

 

2018

 

2019

 

2018

 

 

 

 

 

 

 

 

 

 

 

 

 

Northern Border

 

50

%

21

 

17

 

489

 

497

 

Great Lakes

 

46.45

%

20

 

24

 

498

 

489

 

Iroquois

 

49.34

%

13

 

18

 

209

 

210

 

 

 

 

 

54

 

59

 

1,196

 

1,196

 

 

Distributions from Equity Investments

 

Distributions received from equity investments in the three months ended March 31, 2019 were $58 million (March 31, 2018 — $45 million) of which, $2 million (March 31, 2018 - $2 million) was considered a return of capital and is included in “Investing Activities” in the Partnership’s consolidated statement of cash flows. The return of capital was related to our investment in Iroquois (see further discussion below).

 

Northern Border

 

The Partnership did not have undistributed earnings from Northern Border for the three months ended March 31, 2019 and 2018.

 

The summarized financial information provided to us by Northern Border is as follows:

 

(unaudited)

 

 

 

 

 

(millions of dollars)

 

March 31, 2019

 

December 31, 2018

 

 

 

 

 

 

 

ASSETS

 

 

 

 

 

Cash and cash equivalents

 

14

 

10

 

Other current assets

 

38

 

36

 

Property, plant and equipment, net

 

1,023

 

1,037

 

Other assets

 

13

 

13

 

 

 

1,088

 

1,096

 

 

 

 

 

 

 

LIABILITIES AND PARTNERS’ EQUITY

 

 

 

 

 

Current liabilities

 

41

 

34

 

Deferred credits and other

 

35

 

35

 

Long-term debt, net (a)

 

264

 

264

 

Partners’ equity

 

 

 

 

 

Partners’ capital

 

749

 

764

 

Accumulated other comprehensive loss

 

(1

)

(1

)

 

 

1,088

 

1,096

 

 

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Three months ended

 

(unaudited)

 

March 31,

 

(millions of dollars)

 

2019

 

2018

 

 

 

 

 

 

 

Transmission revenues

 

81

 

72

 

Operating expenses

 

(20

)

(19

)

Depreciation

 

(15

)

(15

)

Financial charges and other

 

(4

)

(4

)

Net income

 

42

 

34

 

 


(a)                   No current maturities as of March 31, 2019 and December 31, 2018. At March 31, 2019, Northern Border is in compliance with all its financial covenants.

 

Great Lakes

 

The Partnership made an equity contribution to Great Lakes of $5 million in the first quarter of 2019 (March 31, 2018 - $4 million). This amount represents the Partnership’s 46.45 percent share of an $11 million cash call from Great Lakes to make a scheduled debt repayment.

 

The Partnership did not have undistributed earnings from Great Lakes for the three months ended March 31, 2019 and 2018.

 

The summarized financial information provided to us by Great Lakes is as follows:

 

(unaudited)

 

 

 

 

 

(millions of dollars)

 

March 31, 2019

 

December 31, 2018

 

 

 

 

 

 

 

ASSETS

 

 

 

 

 

Current assets

 

86

 

75

 

Property, plant and equipment, net

 

685

 

689

 

 

 

771

 

764

 

 

 

 

 

 

 

LIABILITIES AND PARTNERS’ EQUITY

 

 

 

 

 

Current liabilities

 

25

 

26

 

Net long-term debt, including current maturities (a)

 

229

 

240

 

Other long-term liabilities

 

4

 

4

 

Partners’ equity

 

513

 

494

 

 

 

771

 

764

 

 

 

 

Three months ended

 

(unaudited)

 

March 31,

 

(millions of dollars)

 

2019

 

2018

 

 

 

 

 

 

 

Transmission revenues

 

72

 

81

 

Operating expenses

 

(16

)

(17

)

Depreciation

 

(8

)

(8

)

Financial charges and other

 

(4

)

(4

)

Net income

 

44

 

52

 

 


(a)                   Includes current maturities of $21 million as of March 31, 2019 and as of December 31, 2018. At March 31, 2019, Great Lakes is in compliance with all its financial covenants.

 

Iroquois

 

During the three months ended March 31, 2019, the Partnership received distributions from Iroquois amounting to $14 million (March 31, 2018 - $14 million) which includes the Partnership’s 49.34 percent share of the Iroquois unrestricted cash distribution amounting to approximately $2 million (March 31, 2018 - $2 million). The unrestricted cash did not represent a

 

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distribution of Iroquois’ cash from operations during the period and therefore it was reported as distributions received as return of investment in the Partnership’s consolidated statement of cash flows.

 

Iroquois declared its first quarter 2019 distribution of $28 million on April 24, 2019, of which the Partnership received its 49.34 percent share or $14 million on May 1, 2019. The distribution includes our 49.34 percent share of the Iroquois unrestricted cash distribution amounting to approximately $2 million. The Partnership did not have undistributed earnings from Iroquois for the three months ended March 31, 2019 and 2018.

 

The summarized financial information provided to us by Iroquois is as follows:

 

(unaudited)

 

 

 

 

 

(millions of dollars)

 

March 31, 2019

 

December 31, 2018

 

 

 

 

 

 

 

ASSETS

 

 

 

 

 

Cash and cash equivalents

 

84

 

80

 

Other current assets

 

30

 

32

 

Property, plant and equipment, net

 

576

 

581

 

Other assets

 

16

 

8

 

 

 

706

 

701

 

 

 

 

 

 

 

LIABILITIES AND PARTNERS’ EQUITY

 

 

 

 

 

Current liabilities

 

19

 

19

 

Long-term debt, net (a)

 

325

 

325

 

Other non-current liabilities

 

20

 

14

 

Partners’ equity

 

342

 

343

 

 

 

706

 

701

 

 

 

 

Three months ended

 

(unaudited)

 

March 31,

 

(millions of dollars)

 

2019

 

2018

 

 

 

 

 

 

 

Transmission revenues

 

52

 

60

 

Operating expenses

 

(15

)

(14

)

Depreciation

 

(7

)

(7

)

Financial charges and other

 

(3

)

(4

)

Net income

 

27

 

35

 

 


(a)              Includes current maturities of $146 million as of March 31, 2019 and as of December 31, 2018. At March 31, 2019, Iroquois is in compliance with all its financial covenants.

 

NOTE 6    REVENUES

 

Disaggregation of Revenues

 

For the three months ended March 31, 2019 and March 31, 2018, effectively all of the Partnership’s revenues were from capacity arrangements and transportation contracts with customers as discussed in more detail below.

 

Capacity Arrangements and Transportation Contracts

 

The Partnership’s performance obligations in its contracts with customers consist primarily of capacity arrangements and natural gas transportation contracts.

 

The Partnership’s revenues are generated from contractual arrangements for committed capacity and from transportation of natural gas which are treated as a bundled performance obligation. Revenues earned from firm contracted capacity arrangements are recognized ratably over the term of the contract regardless of the amount of natural gas that is transported. Transportation revenues for interruptible or volumetric-based services are recognized when the service is performed. The Partnership has elected to utilize the practical expedient of recognizing revenue as invoiced.

 

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The Partnership’s pipeline systems are subject to FERC regulations and, as a result, a portion of revenues collected may be subject to refund if invoiced during an interim period when a rate proceeding is ongoing. Allowances for these potential refunds are recognized using management’s best estimate based on the facts and circumstances of the proceeding. Any allowances that are recognized during the proceeding process are refunded or retained, as applicable, at the time a regulatory decision becomes final. As of March 31, 2019, the Partnership does not have any outstanding refund obligations related to any rate proceedings. Revenues are invoiced and paid on a monthly basis. The Partnership’s pipeline systems do not take ownership of the natural gas that is transported for customers. Revenues from contracts with customers are recognized net of any taxes collected from customers, which are subsequently remitted to governmental authorities.

 

Contract Balances

 

All of the Partnership’s contract balances pertain to receivables from contracts with customers amounting to $35 million at March 31, 2019 (December 31, 2018 - $44 million) and are recorded as Trade accounts receivable and reported as “Accounts receivable and other” in the Partnership’s consolidated balance sheet (Refer to Note 14).

 

Additionally, our accounts receivable represents the Partnership’s unconditional right to consideration for services completed which includes billed and unbilled accounts.

 

Future revenue from remaining performance obligations

 

When the right to invoice practical expedient is applied, the guidance does not require disclosure of information related to future revenue from remaining performance obligations; therefore, no additional disclosure is required.

 

Additionally, in the application of the right to invoice practical expedient, the Partnership’s revenues from regulated capacity arrangements are recognized based on rates specified in the contract. Therefore, the amount invoiced, which includes the capacity contracted and variable volume of natural gas transported, corresponds directly to the value the customer received. These revenues are recognized on a monthly basis once the Partnership’s performance obligation to provide capacity has been satisfied.

 

NOTE 7    DEBT AND CREDIT FACILITIES

 

(unaudited)
(millions of dollars)

 

March 31,
2019

 

Weighted Average
Interest Rate for the
Three Months Ended
March 31, 2019

 

December 31,
2018

 

Weighted Average
Interest Rate for the
Year Ended December
31, 2018

 

 

 

 

 

 

 

 

 

 

 

TC PipeLines, LP

 

 

 

 

 

 

 

 

 

Senior Credit Facility due 2021

 

 

3.61

%

40

 

3.14%

 

2013 Term Loan Facility due 2022

 

500

 

3.73

%

500

 

3.23%

 

4.65% Unsecured Senior Notes due 2021

 

350

 

4.65

%(a)

350

 

4.65%(a)

 

4.375% Unsecured Senior Notes due 2025

 

350

 

4.375

%(a)

350

 

4.375%(a)

 

3.90 % Unsecured Senior Notes due 2027

 

500

 

3.90

%(a)

500

 

3.90%(a)

 

 

 

 

 

 

 

 

 

 

 

GTN

 

 

 

 

 

 

 

 

 

5.29% Unsecured Senior Notes due 2020

 

100

 

5.29

%(a)

100

 

5.29%(a)

 

5.69% Unsecured Senior Notes due 2035

 

150

 

5.69

%(a)

150

 

5.69%(a)

 

Unsecured Term Loan Facility due 2019

 

35

 

3.45

%

35

 

2.93%

 

 

 

 

 

 

 

 

 

 

 

PNGTS

 

 

 

 

 

 

 

 

 

Revolving Credit Facility due 2023

 

27

 

3.75

%

19

 

3.55%

 

 

 

 

 

 

 

 

 

 

 

Tuscarora

 

 

 

 

 

 

 

 

 

Unsecured Term Loan due 2020

 

24

 

3.63

%

24

 

3.10%

 

 

 

 

 

 

 

 

 

 

 

North Baja

 

 

 

 

 

 

 

 

 

Unsecured Term Loan due 2021

 

50

 

3.56

%

50

 

3.54%

 

 

 

2,086

 

 

 

2,118

 

 

 

Less: unamortized debt issuance costs and debt discount

 

10

 

 

 

10

 

 

 

Less: current portion

 

36

 

 

 

36

 

 

 

 

 

2,040

 

 

 

2,072

 

 

 

 


(a)                   Fixed interest rate

 

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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. During the three months ended March 31, 2019, the Partnership repaid all amounts outstanding under its Senior Credit Facility and there was no outstanding balance at March 31, 2019 (December 31, 2018 - $40 million).

 

The LIBOR-based interest rate on the Senior Credit Facility was 3.77 percent at December 31, 2018.

 

As of March 31, 2019, the variable interest rate exposure related to the 2013 Term Loan Facility was hedged using interest rate swaps at an average rate of 3.26 percent (December 31, 2018 — 3.26 percent). Prior to hedging activities, the LIBOR-based interest rate on the 2013 Term Loan Facility was 3.74 percent at March 31, 2019 (December 31, 2018 — 3.60 percent).

 

The Senior Credit Facility and the 2013 Term Loan 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 3.03 to 1.00 as of March 31, 2019.

 

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 March 31, 2019 was 42.5 percent.

 

The LIBOR-based interest rate on GTN’s Unsecured Term Loan Facility was 3.44 percent at March 31, 2019 (December 31, 2018 — 3.30 percent).

 

PNGTS

 

PNGTS’ Revolving Credit Facility requires PNGTS to maintain a leverage ratio not greater than 5.00 to 1.00. The leverage ratio was 0.47 to 1.00 as of March 31, 2019.

 

The LIBOR-based interest rate on PNGTS’ Revolving Credit Facility was 3.74 percent at March 31, 2019 (December 31, 2018 — 3.60 percent).

 

Tuscarora

 

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 March 31, 2019, the ratio was 10.14 to 1.00.

 

The LIBOR-based interest rate on the Tuscarora’s Unsecured Term Loan Facility was 3.61 percent at March 31, 2019 (December 31, 2018 — 3.47 percent).

 

North Baja

 

North Baja’s Term Loan Facility contains a covenant that limits total debt to no greater than 70 percent of North Baja’s total capitalization.  North Baja’s total debt to total capitalization ratio at March 31, 2019 was 38.11 percent.

 

The LIBOR-based interest rate on North Baja’s Term Loan Facility was 3.56 percent at March 31, 2019 (December 31, 2018 - 3.54 percent).

 

Partnership (TC PipeLines, LP and its subsidiaries)

 

At March 31, 2019, 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

 

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Fourth 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)

 

Principal payments

 

 

 

 

 

2019

 

36

 

2020

 

123

 

2021

 

400

 

2022

 

500

 

2023

 

27

 

Thereafter

 

1,000

 

 

 

2,086

 

 

NOTE 8           PARTNERS’ EQUITY

 

ATM equity issuance program (ATM program)

 

During the three months ended March 31, 2019, no common units were issued under this program.

 

Class B units issued to TC Energy

 

The Class B units entitle TC Energy to an annual distribution based on 30 percent of GTN’s annual distributions as follows: (i) 100 percent of distributions above $20 million for the year ending December 31, 2019; (ii) 43.75 percent of distributions above $20 million for the year ending December 31, 2020; and (iii) 25 percent of distributions above $20 million thereafter (Class B Distribution). Additionally, the Class B Distribution will be further reduced by 35 percent, which is equivalent to the percentage by which distributions payable to the common units were reduced in 2018 (Class B Reduction). The Class B Reduction was implemented during the first quarter of 2018 following the Partnership’s common unit distribution reduction of 35 percent. The Class B Reduction will continue to apply for any particular calendar year until distributions payable in respect of common units for such calendar year equal or exceed $3.94 per common unit.

 

For the year ended December 31, 2019, the Class B units’ equity account will be increased by the Class B Distribution, less the Class B Reduction, until such amount is declared for distribution and paid in the first quarter of 2020. During the three months ended March 31, 2019, the Class B threshold was not exceeded.

 

For the year ended December 31, 2018, the Class B distribution was $13 million and was declared and paid in the first quarter of 2019.

 

NOTE 9           NET INCOME PER COMMON UNIT

 

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

 

The amount allocable to the General Partner equals an amount based upon the General Partner’s 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 2019 equals 30 percent of GTN’s distributable cash flow during the year ended December 31, 2019 less $20 million and is further reduced by the estimated Class B Reduction for 2019 (December 31, 2018 —$20 million less Class B Reduction). During the three months ended March 31, 2019 and 2018, no amounts were allocated to the Class B units as the annual threshold was not exceeded.

 

Net income per common unit was determined as follows:

 

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(unaudited)

 

Three months ended March 31,

 

(millions of dollars, except per common unit amounts)

 

2019

 

2018

 

 

 

 

 

 

 

Net income attributable to controlling interests

 

93

 

96

 

Net income attributable to the General Partner

 

(2

)

(2

)

Net income attributable to common units

 

91

 

94

 

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

 

71.3

 

71.2

 

Net income per common unit — basic and diluted

 

$

1.28

 

$

1.32

 

 

NOTE 10    CASH DISTRIBUTIONS PAID TO COMMON UNITS

 

During the three months ended March 31, 2019, the Partnership distributed $0.65 per common unit (March 31, 2018 — $1.00 per common unit) for a total of $47 million (March 31, 2018 - $76 million).

 

The distribution paid to our General Partner during the three months ended March 31, 2019 for its two percent general partner interest was $1 million (March 31, 2018 - $2 million). The General Partner did not receive any distributions in respect of its IDRs during the three months ended March 31, 2019 (March 31, 2018 - $3 million).

 

NOTE 11    CHANGE IN OPERATING WORKING CAPITAL

 

(unaudited)

 

Three months ended March 31,

 

(millions of dollars)

 

2019

 

2018

 

 

 

 

 

 

 

Change in accounts receivable and other

 

7

 

 

Change in inventories

 

(1

)

 

Change in other current assets

 

2

 

(3

)

Change in accounts payable and accrued liabilities

 

(4

)

 

Change in accounts payable to affiliates

 

1

 

 

Change in accrued interest

 

8

 

9

 

Change in operating working capital

 

13

 

6

 

 

NOTE 12    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 conduct 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 months ended March 31, 2019 and 2018, total costs charged to the Partnership by the General Partner were $1 million.

 

As operator of our pipelines, except Iroquois, TC Energy’s subsidiaries provide capital and operating services to our pipeline systems. TC Energy’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. Iroquois does not receive any capital and operating services from TC Energy (Refer to Note 5).

 

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Capital and operating costs charged to our pipeline systems, except for Iroquois, for the three months ended March 31, 2019 and 2018 by TC Energy’s subsidiaries and amounts payable to TC Energy’s subsidiaries at March 31, 2019 and December 31, 2018 are summarized in the following tables:

 

 

 

Three months ended

 

(unaudited)

 

March 31,

 

(millions of dollars)

 

2019

 

2018

 

 

 

 

 

 

 

Capital and operating costs charged by TC Energy’s subsidiaries to:

 

 

 

 

 

Great Lakes (a) 

 

11

 

9

 

Northern Border (a)

 

9

 

9

 

GTN

 

10

 

8

 

Bison

 

1

 

2

 

North Baja

 

1

 

1

 

Tuscarora

 

1

 

1

 

PNGTS (a)

 

2

 

2

 

Impact on the Partnership’s net income:

 

 

 

 

 

Great Lakes

 

5

 

4

 

Northern Border

 

4

 

4

 

GTN

 

8

 

8

 

Bison

 

1

 

2

 

North Baja

 

1

 

1

 

Tuscarora

 

1

 

1

 

PNGTS

 

1

 

1

 

 

(unaudited)

 

 

 

 

 

(millions of dollars)

 

March 31, 2019

 

December 31, 2018

 

 

 

 

 

 

 

Net amounts payable to TC Energy’s subsidiaries are as follows:

 

 

 

 

 

Great Lakes (a) 

 

5

 

3

 

Northern Border (a)

 

4

 

3

 

GTN

 

4

 

4

 

Bison

 

 

1

 

North Baja

 

1

 

 

Tuscarora

 

 

1

 

PNGTS (a)

 

1

 

1

 

 


(a)              Represents 100 percent of the costs.

 

Great Lakes

 

Great Lakes earns significant transportation revenues from TC Energy and its affiliates, some of which are provided at discounted rates and some at maximum recourse rates. For the three months ended March 31, 2019, Great Lakes earned 73 percent of transportation revenues from TC Energy and its affiliates (March 31, 2018 — 68 percent).

 

At March 31, 2019, $18 million was included in Great Lakes’ receivables with regard to the transportation contracts with TC Energy and its affiliates (December 31, 2018 — $18 million).

 

During the second quarter of 2018, Great Lakes reached an agreement on the terms of new long-term transportation capacity contracts with its affiliate, ANR Pipeline Company. The contracts are for a term of 15 years from November 2021 to October 31, 2036 with a total contract value of approximately $1.3 billion. The contracts contain reduction options (i) at any time on or before April 1, 2019 for any reason and (ii) any time before April 2021, if TC Energy is not able to secure the required regulatory approval related to anticipated expansion projects. During the first quarter of 2019, Great Lakes reached an agreement to amend volume reduction “for any reason” option by extending the period “on or before” April 1, 2019 to “on or before” April 1, 2020. All the other terms remained the same.

 

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PNGTS

 

PNGTS earns transportation revenues from TC Energy and its affiliates. For the three months ended March 31, 2019, PNGTS earned approximately nil of its transportation revenues from TC Energy and its affiliates (March 31, 2018 — $1 million).

 

At March 31, 2019, PNGTS had nil outstanding receivables with regard to the transportation contracts with TC Energy and its affiliates (December 31, 2018 — 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 March 31, 2019, the total costs incurred by these affiliates was approximately $71 million.

 

NOTE 13    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 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.

 

The Partnership has classified the fair value of natural gas imbalances as a Level 2 of the fair value hierarchy for fair value disclosure purposes, as the valuation approach includes quoted prices in the market index and observable volumes for the imbalance.

 

Long-term debt is recorded at amortized cost and classified as Level 2 of the fair value hierarchy for fair value disclosure purposes. Interest rate derivative assets and liabilities are classified as 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 March 31, 2019 and December 31, 2018 was $2,119 million and $2,101 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 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 mature on October 2, 2022 and 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 fixed weighted average interest rate on these instruments is 3.26 percent.

 

At March 31, 2019, the fair value of the interest rate swaps accounted for as cash flow hedges was an asset of $3 million (both on a gross and net basis) (December 31, 2018 — asset of $8 million).

 

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The change in fair value of interest rate derivative instruments recognized in other comprehensive income was a loss of $5 million for the three months ended March 31, 2019 (March 31, 2018 — gain of $7 million). For the three months ended March 31, 2019, the net realized gain related to the interest rate swaps was $1 million, and was included in “financial charges and other” (March 31, 2018 — gain of $1 million) (Refer to Note 15).

 

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 consolidated balance sheet. Had the Partnership elected to present these instruments on a net basis, there would be no effect on the consolidated balance sheet as of March 31, 2019 and December 31, 2018.

 

NOTE 14    ACCOUNTS RECEIVABLE AND OTHER

 

(unaudited)

 

 

 

 

 

(millions of dollars)

 

March 31, 2019

 

December 31, 2018

 

 

 

 

 

 

 

Trade accounts receivable, net of allowance of nil

 

35

 

44

 

Imbalance receivable from affiliates

 

4

 

2

 

Other

 

2

 

2

 

 

 

41

 

48

 

 

NOTE 15    FINANCIAL CHARGES AND OTHER

 

 

 

Three months ended

 

(unaudited)

 

March 31,

 

(millions of dollars)

 

2019

 

2018

 

 

 

 

 

 

 

Interest expense (a)

 

23

 

24

 

Net realized gain related to the interest rate swaps

 

(1

)

(1

)

 

 

22

 

23

 

 


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

 

NOTE 16    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 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 intermediate partnerships and mainly 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 it absorbs from the ILPs’ economic performance.

 

The assets and liabilities held through these VIEs that are not available to creditors of the Partnership and whose investors have no recourse to the credit of the Partnership are held through GTN, Tuscarora, Northern Border, Great Lakes, PNGTS, Iroquois

 

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and North Baja 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)

 

March 31, 2019

 

December 31, 2018

 

 

 

 

 

 

 

ASSETS (LIABILITIES) (a) 

 

 

 

 

 

Cash and cash equivalents

 

25

 

16

 

Accounts receivable and other

 

37

 

39

 

Inventories

 

9

 

8

 

Other current assets

 

5

 

6

 

Equity investments

 

1,196

 

1,196

 

Property, plant and equipment, net

 

1,237

 

1,240

 

Other assets

 

1

 

1

 

Accounts payable and accrued liabilities

 

(26

)

(33

)

Accounts payable to affiliates, net

 

(38

)

(40

)

Accrued interest

 

(5

)

(2

)

Current portion of long-term debt

 

(36

)

(36

)

Long-term debt

 

(349

)

(341

)

Other liabilities

 

(28

)

(27

)

Deferred state income tax

 

(9

)

(9

)

 


(a)              Bison, an asset held through our consolidated VIEs, is excluded at March 31, 2019 and at December 31, 2018 as the assets of this entity can be used for purposes other than the settlement of the VIE’s obligations.

 

NOTE 17    SUBSEQUENT EVENTS

 

Management of the Partnership has reviewed subsequent events through May 8, 2019, the date the consolidated financial statements were issued, and concluded there were no events or transactions during this period that would require recognition or disclosure in the consolidated financial statements other than what is disclosed here and/or those already disclosed in the preceding notes.

 

On April 23, 2019, the board of directors of the General Partner declared the Partnership’s first quarter 2019 cash distribution in the amount of $0.65 per common unit payable on May 13, 2019 to unitholders of record as of May 3, 2019. The declared distribution totaled $47 million and is payable in the following manner: $46 million to common unitholders (including $4 million to the General Partner as a holder of 5,797,106 common units and $7 million to another subsidiary of TC Energy as holder of 11,287,725 common units) and $1 million to the General Partner for its two percent general partner interest. The General Partner did not receive any distributions in respect of its IDRs for the first quarter 2019.

 

Northern Border declared its March 2019 distribution of $15 million on April 9, 2019, of which the Partnership received its 50 percent share or $7 million on April 30, 2019.

 

Great Lakes declared its first quarter 2019 distribution of $49 million on April 16, 2019, of which the Partnership received its 46.45 percent share or $23 million on May 1, 2019.

 

Iroquois declared its first quarter 2019 distribution of $28 million on April 24, 2019, of which the Partnership received its 49.34 percent share or $14 million on May 1, 2019.  The $14 million includes our proportionate share of Iroquois’ unrestricted cash amounting to $2 million (refer to Note 5).

 

PNGTS declared its first quarter 2019 distribution of $19 million on April 9, 2019, of which $7 million was paid to its non-controlling interest owner on April 30, 2019.

 

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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 consolidated 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, 2018.

 

RECENT BUSINESS DEVELOPMENTS

 

Cash Distributions — On April 23, 2019, the board of directors of our General Partner declared the Partnership’s first quarter 2019 cash distribution in the amount of $0.65 per common unit, payable on May 13, 2019 to unitholders of record as of May 3, 2019. The declared distribution totaled $47 million and was payable in the following manner: $46 million to common unitholders (including $4 million to the General Partner as a holder of 5,797,106 common units and $7 million to another subsidiary of TC Energy as holder of 11,287,725 common units) and $1 million to our General Partner for its two percent general partner interest.

 

2018 FERC Actions Updates:

 

Iroquois, Tuscarora, and Northern Border took the actions listed below to conclude the issues impacting their pipelines as contemplated by the 2017 Tax Act and the 2018 FERC Actions:

 

Iroquois -  On February 28, 2019, Iroquois filed an uncontested settlement with FERC to address the issues contemplated by the 2017 Tax Act and 2018 FERC Actions via an amendment to its prior 2016 settlement. Among the terms of the 2019 Iroquois Settlement, Iroquois agreed to reduce its existing maximum system rates by 6.5 percent to be implemented in two phases, (i) effective March 1, 2019, a 3.25 percent rate reduction and (ii) effective April 1, 2020, an additional 3.25 percent rate reduction, which is the remaining one-half of the total 6.5 percent rate reduction from the 2016 settlement rates. The 2019 Iroquois Settlement, which was approved by FERC on May 2, 2019, preserved the 2016 settlement moratorium on further rate changes until September 1, 2020. Unless superseded by a subsequent rate case or settlement, Iroquois will be required to have new rates in effect by March 1, 2023.

 

Tuscarora - On March 15, 2019, Tuscarora filed an uncontested settlement with FERC to address the issues contemplated by the 2017 Tax Act and 2018 FERC Actions via an amendment to its prior 2016 settlement. Among the terms of the 2019 Tuscarora Settlement, Tuscarora agreed to reduce its existing maximum system rates by 1.7 percent effective February 1, 2019 through to July 31, 2019. The existing maximum rates will decrease by an additional 10.8 percent for the period August 1, 2019 through the term of the settlement. Tuscarora is required to have new rates in effect on February 1, 2023. Tuscarora and its customers also agreed on a moratorium on rate changes until January 31, 2023. The 2019 Tuscarora Settlement, which was approved by FERC on May 2, 2019, will also reflect an elimination of the tax allowance previously recovered in rates along with ADIT for rate-making purposes.

 

Northern Border - On April 4, 2019, Northern Border filed a petition for approval with FERC to amend the settlement agreement reached with its customers in 2017.  Unless superseded by a subsequent rate case or settlement, effective January 1, 2020, the 2 percent rate reduction implemented on February 1, 2019 will be extended to July 1, 2024 as part of the amended settlement agreement. The amendment is pending approval from FERC.

 

Growth Projects:

 

North Baja XPress Project (North Baja XPress) - North Baja XPress is an estimated $90 million project to transport additional volumes of natural gas along North Baja’s mainline system. The project was initiated in response to market demand to provide firm transportation service of up to approximately 495,000 Dth/day between Ehrenberg, Arizona and Ogilby, California. The binding open season for the project was concluded in April of 2019 and the estimated in-service date is February 1, 2023, subject to the satisfaction or waiver of certain conditions precedent.

 

Westbrook XPress Project (Westbrook XPress) - In addition to Phases 1 and 2 of the Westbrook XPress project as disclosed in our Annual Report of the Form 10-K for the year ended December 31, 2018, we have now signed precedent agreements with certain shippers that will result in a Phase 3 expansion for an additional 18,000 Dth/day. Westbrook XPress is an estimated $100 million multi-phase expansion project that is expected to generate approximately $35 million in revenue for PNGTS on an annualized basis when fully in service. It is part of a coordinated offering to transport incremental Western Canadian Sedimentary Basin natural gas supplies to the Northeast U.S. and Atlantic Canada markets through additional compression capability at an existing PNGTS facility. Westbrook XPress is designed to be phased in over a four-year period with Phases 1, 2 and 3 estimated in-service dates of November 2019, 2021, and 2022, respectively. These three Phases will add incremental

 

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capacity of approximately 43,000 Dth/day, 63,000 Dth/day, and 18,000 Dth/day respectively. Westbrook XPress, together with Portland XPress, will increase PNGTS’ capacity by approximately 90 percent from 210,000 Dth/day to almost 400,000 Dth/day.

 

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 ownership interests in eight pipelines were our only material sources of income during the period. Therefore, our results of operations and cash flows were influenced by, and reflect the same factors that influenced, our pipeline systems.

 

 

 

Three months ended

 

 

 

 

 

(unaudited)

 

March 31,

 

$

 

%

 

(millions of dollars)

 

2019

 

2018

 

Change (a)

 

Change (a)

 

 

 

 

 

 

 

 

 

 

 

Transmission revenues

 

113

 

115

 

(2

)

(2

)

Equity earnings

 

54

 

59

 

(5

)

(8

)

Operating, maintenance and administrative costs

 

(25

)

(24

)

(1

)

(4

)

Depreciation

 

(20

)

(24

)

4

 

17

 

Financial charges and other

 

(22

)

(23

)

1

 

4

 

Net income before taxes

 

100

 

103

 

(3

)

(3

)

 

 

 

 

 

 

 

 

 

 

State income taxes

 

 

(1

)

1

 

100

 

Net Income

 

100

 

102

 

(2

)

(2

)

 

 

 

 

 

 

 

 

 

 

Net income attributable to non-controlling interests

 

7

 

6

 

(1

)

(17

)

Net income attributable to controlling interests

 

93

 

96

 

(3

)

(3

)

 


(a)              Positive number represents a favorable change; bracketed or negative number represents an unfavorable change.

 

Three Months Ended March 31, 2019 compared to Same Period in 2018

 

The Partnership’s net income attributable to controlling interests decreased by $3 million in the three months ended March 31, 2019 compared to 2018, mainly due to the following:

 

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Transmission revenues — Revenues were lower due largely to the decrease in revenue from Bison. During the fourth quarter of 2018, two of Bison’s customers elected to pay out the remainder of their contracted obligations on Bison and terminate the associated transportation agreements.  The decrease was offset by the following:

 

·                  increased contracting from GTN, partially offset by its scheduled 10 percent rate decrease effective January 1, 2019 as part of the settlement reached with its customers in 2018; and

·                  additional revenue from PNGTS from Phase 1 of its Portland XPress (PXP) project that went into service November 1, 2018.

 

Equity Earnings - The $5 million decrease was primarily due to the net effect of the following:

 

·                  decrease in Iroquois’ and Great Lakes’ equity earnings during the first quarter of 2019 compared to the first quarter of 2018, during which sustained cold temperatures resulted in incremental seasonal winter sales that were not achieved in the same period of 2019; and

·                  higher earnings from Northern Border resulting from an increase in its short-term firm services, partially offset by its scheduled rate reduction that became effective April 1, 2018.

 

Depreciation — The decrease in depreciation expense during the first quarter of 2019 was a direct result of the long-lived asset impairment recognized during the fourth quarter of 2018 on Bison which effectively eliminated the depreciable base of the pipeline.

 

Financial charges and other - The $1 million decrease was primarily attributable to the repayment of our $170 million Term Loan during the fourth quarter of 2018 and repayment of our Senior Credit Facility during the first quarter of 2019.

 

Net income attributable to non-controlling interests - The Partnership’s net income attributable to non-controlling interests was higher in the first quarter of 2019 than the first quarter of 2018 due to the increase in revenue earned on PNGTS as described above.

 

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

 

As discussed in Note 9 within Item 1. “Financial Statements,” we will allocate a portion of the Partnership’s income to the Class B units after the annual threshold is exceeded which will effectively reduce the income allocable to the common units and net income per common unit. Currently, we expect to allocate a portion of the Partnership’s income to the Class B units at the end of the fourth quarter of 2019. Please also read Note 8 within Item 1. “Financial Statements,” for additional disclosures on the Class B units.

 

LIQUIDITY AND CAPITAL RESOURCES

 

Overview

 

Our principal sources of liquidity and cash flows include distributions received from our equity investments, operating cash flows from our subsidiaries, public offerings of debt and equity, term loans and our Senior Credit Facility. The Partnership funds its operating expenses, debt service and cash distributions (including those distributions made to TC Energy through our General Partner and as holder of all our Class B units) primarily with operating cash flow.

 

At March 31, 2019, the balance of our cash and cash equivalents was higher than our position at December 31, 2018 by approximately $19 million and our long-term debt balance was lower by $32 million. We continue to use available cash to fund ongoing capital expenditures and the repayment of debt to levels that prudently manage our financial metrics.

 

We believe our cash position, remaining borrowing capacity on our Senior Credit Facility (see table below), and our operating cash flows are sufficient to fund our short-term liquidity requirements, including distributions to our unitholders, ongoing capital expenditures and required debt repayments.

 

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

 

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(unaudited)
(millions of dollars)

 

March 31, 2019

 

December 31, 2018

 

 

 

 

 

 

 

Total capacity under the Senior Credit Facility

 

500

 

500

 

Less: Outstanding borrowings under the Senior Credit Facility

 

 

40

 

Available capacity under the Senior Credit Facility

 

500

 

460

 

 

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

 

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

 

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

 

Cash Flow Analysis for the Three Months Ended March 31, 2019 compared to Same Period in 2018

 

 

 

Three months ended

 

(unaudited)

 

March 31,

 

(millions of dollars)

 

2019

 

2018

 

 

 

 

 

 

 

Net cash provided by (used in):

 

 

 

 

 

Operating activities

 

135

 

117

 

Investing activities

 

(17

)

(4

)

Financing activities

 

(99

)

(78

)

Net increase in cash and cash equivalents

 

19

 

35

 

Cash and cash equivalents at beginning of the period

 

33

 

33

 

Cash and cash equivalents at end of the period

 

52

 

68

 

 

Operating Cash Flows

 

The Partnership’s net cash provided by operating activities increased by $18 million in the three months ended March 31, 2019 compared to the same period in 2018 primarily due to the net effect of:

 

·   lower net cash flow from operations of our subsidiaries primarily due to the decrease in Bison’s revenue partially offset by an increase in GTN’s and PNGTS’ revenue;

·   lower interest expense attributable to repayment of the $170 million Term Loan and the Senior Credit Facility;

·    higher distributions received from our equity investment in Northern Border as a result of its increased revenue; and

·    lower distributions received from our equity investment in Great Lakes due to lower revenue from seasonal winter sales.

 

Investing Cash Flows

 

Net cash used in investing activities increased by $13 million in the three months ended March 31, 2019 compared to the same period in 2018 primarily due to our consolidated subsidiaries’ higher capital maintenance expenditures in 2019 and continued capital spending on our PXP project.

 

Financing Cash Flows

 

The Partnership’s net cash used for financing activities was approximately $21 million higher in the three months ended March 31, 2019 compared to the same period in 2018 primarily due to the net effect of:

 

·   $6 million increase in net debt repayments;

 

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·    $29 million decrease in distributions paid primarily due to the $0.35 per common unit reduction in distribution payments during the first quarter of 2019 related to performance during the fourth quarter of 2018 as compared to the same period in 2018 in response to the 2018 FERC Actions;

·    $2 million decrease in distributions paid to Class B units in 2019 as compared to 2018;

·    $40 million decrease in our ATM equity issuances in the first quarter of 2019 as compared to the same period in 2018; and

·    $6 million increase in distributions paid to non-controlling interests during the three months ended March 31, 2019 compared to the three months ended March 31, 2018 resulting from PNGTS’ higher revenue in the fourth quarter of 2018 compared to its revenue in the fourth quarter of 2017.

 

Short-Term Cash Flow Outlook

 

Operating Cash Flow Outlook

 

Northern Border declared its March 2019 distribution of $15 million on April 9, 2019, of which the Partnership received its 50 percent share or $7 million. The distribution was paid on April 30, 2019.

 

Great Lakes declared its first quarter 2019 distribution of $49 million on April 16, 2019, of which the Partnership received its 46.45 percent share or $23 million. The distribution was paid on May 1, 2019.

 

Iroquois declared its first quarter 2019 distribution of $28 million on April 24, 2019, of which the Partnership received its 49.34 percent share or $14 million on May 1, 2019.

 

Investing Cash Flow Outlook

 

The Partnership made an equity contribution to Great Lakes of $5 million in the first quarter of 2019. This amount represents the Partnership’s 46.45 percent share of an $11 million cash call from Great Lakes to make a scheduled debt repayment. The Partnership expects to make an additional $5 million equity contribution to Great Lakes in the fourth quarter of 2019 to further fund debt repayments. This is consistent with prior years.

 

Our equity investee Iroquois has $6 million of scheduled debt repayments for the remainder of 2019 and Iroquois’ debt repayments are expected to be funded through a combination of cash flow from operations and debt refinancing.

 

Our consolidated entities have commitments of $17 million as of March 31, 2019 in connection with various maintenance and general plant projects.

 

In 2019, our pipeline systems expect to invest approximately $107 million in maintenance of existing facilities and approximately $32 million in growth projects, of which the Partnership’s share would be $82 million and $18 million, respectively.

 

Financing Cash Flow Outlook

 

On April 23, 2019, the board of directors of our General Partner declared the Partnership’s first quarter 2019 cash distribution in the amount of $0.65 per common unit payable on May 13, 2019 to unitholders of record as of May 3, 2019.  Please see Note 17 of the “Financial Statements” within Item 1 and “Recent Business Developments” within Item 2 and for additional disclosures.

 

Non-GAAP Financial Measures: EBITDA and Distributable Cash Flow

 

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

 

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

 

Total distributable cash flow includes EBITDA plus:

 

·                  Distributions from our equity investments

 

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less:

 

·                  Earnings from our equity investments,

·                  Equity allowance for funds used during construction (if any),

·                  Interest expense,

·                  Income taxes,

·                  Distributions to non-controlling interests, and

·                  Maintenance capital expenditures from consolidated subsidiaries.

 

Distributable cash flow is computed net of distributions declared to the General Partner and any distributions allocable to Class B units. Distributions declared to the General Partner are based on its two percent interest plus, if applicable, an amount equal to incentive distributions. Distributions allocable to the Class B units in 2019 equal 30 percent of GTN’s distributable cash flow less $20 million and the Class B Reduction.

 

Distributable cash flow and EBITDA are performance measures presented to assist investors in evaluating our business performance. We believe these measures provide additional meaningful information in evaluating our financial performance and cash generating capacity.

 

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

 

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Reconciliations of Net Income to EBITDA and Distributable Cash Flow

 

The following table represents a reconciliation of the non-GAAP financial measures of EBITDA, total distributable cash flow and distributable cash flow, to the most directly comparable GAAP financial measure of Net Income:

 

 

 

Three months ended

 

(unaudited)

 

March 31,

 

(millions of dollars)

 

2019

 

2018

 

Net income

 

100

 

102

 

 

 

 

 

 

 

Add:

 

 

 

 

 

Interest expense (a)

 

22

 

23

 

Depreciation and amortization

 

20

 

24

 

Income taxes

 

 

1

 

 

 

 

 

 

 

EBITDA

 

142

 

150

 

 

 

 

 

 

 

Add:

 

 

 

 

 

Distributions from equity investments (b) (e)

 

 

 

 

 

Northern Border

 

27

 

19

 

Great Lakes

 

23

 

26

 

Iroquois (c)

 

14

 

14

 

 

 

64

 

59

 

Less:

 

 

 

 

 

Equity earnings:

 

 

 

 

 

Northern Border

 

(21

)

(17

)

Great Lakes

 

(20

)

(24

)

Iroquois

 

(13

)

(18

)

 

 

(54

)

(59

)

Less:

 

 

 

 

 

Interest expense (a)

 

(22

)

(23

)

Income taxes

 

 

(1

)

Distributions to non-controlling interest (d)

 

(7

)

(7

)

Maintenance capital expenditures (e)

 

(6

)

(6

)

 

 

(35

)

(37

)

 

 

 

 

 

 

Total Distributable Cash Flow

 

117

 

113

 

General Partner distributions declared (f)

 

(1

)

(1

)

Distributions allocable to Class B units (g)

 

 

 

Distributable Cash Flow

 

116

 

112

 

 


(a)         Interest expense as presented includes net realized loss or gain related to the interest rate swaps.

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

(c)         This amount represents our proportional 49.34 percent share of the distribution declared by our equity investee, Iroquois, for the current reporting period and includes our 49.34 percent share of the Iroquois unrestricted cash distribution amounting to approximately $2 million for the three months ended March 31, 2019 and 2018.

(d)        Distributions to non-controlling interests represent the respective share of our consolidated entities’ distributable cash not owned by us for the periods presented.

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

 

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(f)          No incentive distributions were declared to the General Partner for both the three months ended March 31, 2019 and 2018.

(g)         For the three months ended March 31, 2019, 30 percent of GTN’s total distributions amounted to $12 million (March 31, 2018 - $10 million); therefore, no distributions were allocated to the Class B units as the 2019 threshold was not exceeded. We expect the 2019 threshold will be exceeded during the fourth quarter of 2019. Please read Notes 8 and 9 within Item 1. “Financial Statements” for additional disclosures on the Class B units.

 

Three months ended March 31, 2019 Compared to Same Period in 2018

 

Our EBITDA was lower for the first quarter of 2019 compared to the same period in 2018. The $8 million decrease was due to lower revenue and equity earnings during the period as discussed in more detail under the “Results of Operations” section.

 

However, our distributable cash flow increased by $4 million in the first quarter of 2019 compared to the same period in 2018 due to the net effect of:

 

·    higher distributions from our equity investment in Northern Border due to the increase in revenue previously described in “Results of Operations” section and timing of capital spending related to compressor station maintenance costs;

·    lower distributions from our equity investment in Great Lakes primarily due to the decrease in its revenue as explained in the “Results of Operations” section; and

·    decreased interest expense due to repayment of the $170 million Term Loan during the fourth quarter of 2018 and the repayment of the Senior Credit Facility in the first quarter of 2019.

 

Contractual Obligations

 

The Partnership’s Contractual Obligations

 

The Partnership’s contractual obligations as of March 31, 2019 included the following:

 

 

 

Payments Due by Period

 

(unaudited)
(millions of dollars)

 

Total

 

Less than
1 Year

 

1-3
Years

 

4-5
Years

 

More than 5
Years

 

Weighted Average
Interest Rate for
the Three Months
Ended March 31,
2019

 

TC PipeLines, LP

 

 

 

 

 

 

 

 

 

 

 

 

 

Senior Credit Facility due 2021

 

 

 

 

 

 

3.61%

 

2013 Term Loan Facility due 2022

 

500

 

 

 

500

 

 

3.73%

 

4.65% Senior Notes due 2021

 

350

 

 

350

 

 

 

4.65%(a)

 

4.375% Senior Notes due 2025

 

350

 

 

 

 

350

 

4.375%(a)

 

3.90% Senior Notes due 2027

 

500

 

 

 

 

500

 

3.90%(a)

 

GTN

 

 

 

 

 

 

 

 

 

 

 

 

 

5.29% Unsecured Senior Notes due 2020

 

100

 

 

100

 

 

 

5.29%(a)

 

5.69% Unsecured Senior Notes due 2035

 

150

 

 

 

 

150

 

5.69%(a)

 

Unsecured Term Loan Facility due 2019

 

35

 

35

 

 

 

 

3.45%

 

PNGTS

 

 

 

 

 

 

 

 

 

 

 

 

 

Revolving Credit Facility due 2023

 

27

 

 

 

27

 

 

3.75%

 

North Baja

 

 

 

 

 

 

 

 

 

 

 

 

 

Unsecured Term Loan due 2021

 

50

 

 

50

 

 

 

3.56%

 

Tuscarora

 

 

 

 

 

 

 

 

 

 

 

 

 

Unsecured Term Loan due 2020

 

24

 

1

 

23

 

 

 

3.63%

 

Partnership (TC PipeLines, LP and its subsidiaries)

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest on Debt Obligations(b)

 

514

 

84

 

151

 

101

 

178

 

 

 

Operating Leases

 

1

 

 

1

 

 

 

 

 

Right of way Commitments

 

4

 

1

 

 

1

 

2

 

 

 

 

 

2,605

 

121

 

675

 

629

 

1,180

 

 

 

 


(a)              Fixed interest rate.

(b)             Future interest payments on our fixed rate debt are based on scheduled maturities. Future interest payments on floating rate debt are estimated using debt levels and interest rates at March 31, 2019 and are therefore subject to change beyond 2019.

 

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

 

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The fair value of the Partnership’s long-term debt is estimated by discounting the future cash flows of each instrument at estimated current borrowing rates. The estimated fair value of the Partnership’s debt at March 31, 2019 was $2,119 million.

 

Please read Note 7 within Item 1. “Financial Statements” for additional information regarding the Partnership’s debt.

 

Summary of Northern Border’s Contractual Obligations

 

Northern Border’s contractual obligations as of March 31, 2019 included the following:

 

 

 

Payments Due by Period (a)

 

(unaudited)
(millions of dollars)

 

Total

 

Less than
1 Year

 

1-3
Years

 

4-5
Years

 

More than 5
Years

 

Weighted Average
Interest Rate for the
Three Months Ended
March 31, 2019

 

$200 million Credit Agreement due 2020

 

15

 

 

15

 

 

 

3.57%

 

7.50% Senior Notes due 2021

 

250

 

 

250