UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
xQUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended SeptemberJune 30, 20172018
or
oTRANSITION 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 |
| (I.R.S. Employer |
700 Louisiana Street, Suite 700 |
| 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
As of November 3, 2017,August 1, 2018, there were 69,881,01271,306,396 of the registrant’s common units outstanding.
TC PIPELINES, LP
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Management’s Discussion and Analysis of Financial Condition and Results of Operations |
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All amounts are stated in United States dollars unless otherwise indicated.
DEFINITIONS
The abbreviations, acronyms, and industry terminology used in this quarterly report are defined as follows:
2013 Term Loan Facility |
| TC PipeLines, LP’s term loan credit facility under a term loan agreement as amended, dated September 29, 2017 |
2015 GTN Acquisition |
| Partnership’s acquisition of the remaining 30 percent interest in GTN on April 1, 2015 |
2015 Term Loan Facility |
| TC PipeLines, LP’s term loan credit facility under a term loan agreement as amended, dated September 29, 2017 |
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2017 Acquisition |
| Partnership’s acquisition of an additional 11.81 percent interest in PNGTS and 49.34 percent in Iroquois on June 1, 2017 |
2017 Great Lakes Settlement | Stipulation and Agreement of Settlement for Great Lakes regarding its rates and terms and conditions of service approved by FERC on February 22, 2018 | |
2017 Northern Border Settlement | Stipulation and Agreement of Settlement for Northern Border regarding its rates and terms and conditions of service approved by FERC on February 23, 2018 | |
2017 Tax Act | H.R.1, originally known as the Tax Cuts and Jobs Act, enacted on December 22, 2017 | |
2018 FERC Actions | FERC’s March 15, 2018 issuance of (1) a revised Policy Statement to address the treatment of income taxes for ratemaking purposes for master limited partnerships (MLPs), (2) a Notice of Proposed Rulemaking (NOPR) proposing interstate pipelines file a one-time report to quantify the impact of the federal income tax rate reduction and the revised Policy Statement could have on pipelines’ revenue requirements, and (3) a Notice of Inquiry (NOI) seeking comment on how FERC should address changes related to accumulated deferred income taxes and bonus depreciation; and FERC’s July 18, 2018 issuance of (1) an Order on Rehearing of the Revised Policy Statement dismissing rehearing related to the revised Policy Statement and (2) a Final Rule adopting procedures from, and clarifying aspects of, the NOPR | |
ASC |
| Accounting Standards Codification |
ASU |
| Accounting Standards Update |
ATM program |
| At-the-market equity issuance program |
Bison |
| Bison Pipeline LLC |
Consolidated Subsidiaries |
| GTN, Bison, North Baja, Tuscarora and PNGTS |
C2C Contracts | PNGTS’ Continent-to-Coast Contracts with several shippers for a term of 15 years for approximately 82,000 Dth/day | |
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 |
| Third Amended and Restated Agreement of Limited Partnership of the Partnership |
PHMSA |
| U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration |
PNGTS |
| Portland Natural Gas Transmission System |
PXP | Portland XPress Project | |
Term Loan Facilities |
| The 2013 Term Loan Facility and the 2015 Term Loan Facility, collectively |
SEC |
| Securities and Exchange Commission |
Senior Credit Facility |
| TC PipeLines, LP’s senior facility under revolving credit agreement as amended and restated, dated September 29, 2017 |
TransCanada |
| TransCanada Corporation and its subsidiaries |
Tuscarora |
| Tuscarora Gas Transmission Company |
U.S. |
| United States of America |
VIEs |
| Variable Interest Entities |
Unless the context clearly indicates otherwise, TC PipeLines, LP and its subsidiaries are collectively referred to in this quarterly report as “we,” “us,” “our” and “the Partnership.” We use “our pipeline systems” and “our pipelines” when referring to the Partnership’s ownership interests in Gas Transmission Northwest LLC (GTN), Northern Border Pipeline Company (Northern Border), Bison Pipeline LLC (Bison), Great Lakes Gas Transmission Limited Partnership (Great Lakes), North Baja Pipeline, LLC (North Baja), Tuscarora Gas Transmission Company (Tuscarora), Portland Natural Gas Transmission System (PNGTS) and Iroquois Gas Transmission System, LP (Iroquois).
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 the 2017 Tax Act and the 2018 FERC Actions on our future operating performance;
· other potential changes in the taxation of master limited partnerships (MLPs) by state or federal governments such as final adoption of proposed regulations narrowing the sources of income qualifying for partnership tax treatment or the elimination of pass-through taxation or tax deferred distributions;governments;
· increases in operational or compliance costs resulting from changes in laws and governmental regulations affecting our pipeline systems, particularly regulations issued by the Federal Energy Regulatory Commission (FERC), the U.S. Environmental Protection Agency (EPA) and U.S. Department of Transportation (DOT);
· the impact of downward changes in oil and natural gas prices, including the effects on the creditworthiness of our shippers;
· our ongoing ability to grow distributions through acquisitions, accretive expansions or other growth opportunities, including the timing, terms and closure of future potential acquisitions;
· potential conflicts of interest between TC PipeLines GP, Inc., our general partner (General Partner), TransCanada Corporation (TransCanada) and us;
· the impact of any impairment charges;
· the ability to maintain secure operation of our information technology including management of cybersecurity threats, acts of terrorism and related disruptions;distractions;
· the expected impact of newfuture accounting pronouncements;changes, commitments and contingent liabilities (if any);
· operating hazards, casualty losses and other matters beyond our control; and
· the level of our indebtedness, including the indebtedness of our pipeline systems, and the availability of capital;
· unfavorable conditions in capital and credit markets, inflation and fluctuations in interest rates; and
· the overall increase in the allocated management and operational expenses on our pipeline systems asfor functions performed by TransCanadaTransCanada.
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, 20162017 as filed with the SEC on February 28, 2017.26, 2018. 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.
PART I — FINANCIAL INFORMATION
TC PIPELINES, LP
CONSOLIDATED STATEMENTS OF INCOME
|
| Three months ended |
| Nine months ended |
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(unaudited) |
| September 30, |
| September 30, |
| ||||||||
(millions of dollars, except per common unit amounts) |
| 2017 |
| 2016 (a) |
| 2017 |
| 2016 (a) |
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Transmission revenues |
| 100 |
| 103 |
| 313 |
| 315 |
| ||||
Equity earnings (Note 4) |
| 27 |
| 22 |
| 87 |
| 75 |
| ||||
Operation and maintenance expenses |
| (16 | ) | (15 | ) | (47 | ) | (42 | ) | ||||
Property taxes |
| (7 | ) | (7 | ) | (21 | ) | (20 | ) | ||||
General and administrative |
| (1 | ) | (1 | ) | (6 | ) | (5 | ) | ||||
Depreciation |
| (25 | ) | (24 | ) | (73 | ) | (71 | ) | ||||
Financial charges and other (Note 14) |
| (23 | ) | (18 | ) | (59 | ) | (53 | ) | ||||
Net income before taxes |
| 55 |
| 60 |
| 194 |
| 199 |
| ||||
Income taxes (Note 18) |
| — |
| — |
| (1 | ) | (1 | ) | ||||
Net income |
| 55 |
| 60 |
| 193 |
| 198 |
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Net income attributable to non-controlling interests |
| 1 |
| 2 |
| 7 |
| 10 |
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Net income attributable to controlling interests |
| 54 |
| 58 |
| 186 |
| 188 |
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Net income attributable to controlling interest allocation (Note 8) |
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Common units |
| 42 |
| 43 |
| 164 |
| 164 |
| ||||
General Partner |
| 4 |
| 4 |
| 12 |
| 9 |
| ||||
TransCanada and its subsidiaries |
| 8 |
| 11 |
| 10 |
| 15 |
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|
| 54 |
| 58 |
| 186 |
| 188 |
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Net income per common unit (Note 8) — basic and diluted |
| $ | 0.61 |
| $ | 0.65 | (b) | $ | 2.38 |
| $ | 2.51 | (b) |
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Weighted average common units outstanding — basic and diluted (millions) |
| 69.4 |
| 66.1 |
| 68.9 |
| 65.3 |
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Common units outstanding, end of period (millions) |
| 69.6 |
| 66.6 |
| 69.6 |
| 66.6 |
| ||||
(a) Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).
(b) Net income per common unit prior to recast (Refer to Note 2).
|
| Three months ended |
| Six months ended |
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(unaudited) |
| June 30, |
| June 30, |
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(millions of dollars, except per common unit amounts) |
| 2018 |
| 2017 |
| 2018 |
| 2017 |
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Transmission revenues |
| 111 |
| 101 |
| 226 |
| 213 |
| ||||
Equity earnings (Note 5) |
| 36 |
| 24 |
| 95 |
| 60 |
| ||||
Operation and maintenance expenses |
| (17 | ) | (17 | ) | (33 | ) | (31 | ) | ||||
Property taxes |
| (7 | ) | (7 | ) | (14 | ) | (14 | ) | ||||
General and administrative |
| (1 | ) | (2 | ) | (2 | ) | (4 | ) | ||||
Depreciation |
| (24 | ) | (25 | ) | (48 | ) | (49 | ) | ||||
Financial charges and other (Note 15) |
| (23 | ) | (19 | ) | (46 | ) | (36 | ) | ||||
Net income before taxes |
| 75 |
| 55 |
| 178 |
| 139 |
| ||||
Income taxes (Note 18) |
| — |
| — |
| (1 | ) | (1 | ) | ||||
Net income |
| 75 |
| 55 |
| 177 |
| 138 |
| ||||
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Net income attributable to non-controlling interests |
| 2 |
| — |
| 8 |
| 6 |
| ||||
Net income attributable to controlling interests |
| 73 |
| 55 |
| 169 |
| 132 |
| ||||
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Net income attributable to controlling interest allocation (Note 9) |
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Common units |
| 72 |
| 50 |
| 166 |
| 122 |
| ||||
General Partner |
| 1 |
| 5 |
| 3 |
| 8 |
| ||||
TransCanada and its subsidiaries |
| — |
| — |
| — |
| 2 |
| ||||
|
| 73 |
| 55 |
| 169 |
| 132 |
| ||||
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Net income per common unit (Note 9) – basic and diluted |
| $ | 1.00 |
| $ | 0.73 |
| $ | 2.33 |
| $ | 1.78 |
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Weighted average common units outstanding – basic and diluted (millions) |
| 71.3 |
| 68.9 |
| 71.2 |
| 68.6 |
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Common units outstanding, end of period (millions) |
| 71.3 |
| 69.0 |
| 71.3 |
| 69.0 |
| ||||
The accompanying notes are an integral part of these consolidated financial statements.
TC PIPELINES, LP CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
|
| Three months ended |
| Nine months ended |
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(unaudited) |
| September 30, |
| September 30, |
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(millions of dollars) |
| 2017 |
| 2016(a) |
| 2017 |
| 2016(a) |
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Net income |
| 55 |
| 60 |
| 193 |
| 198 |
|
Other comprehensive income |
|
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Change in fair value of cash flow hedges (Note 12) |
| — |
| 2 |
| 1 |
| (1 | ) |
Amortization of realized loss on derivative financial instruments (Note 12) |
| — |
| — |
| 1 |
| 1 |
|
Reclassification to net income of gains and losses on cash flow hedges (Note 12) |
| 1 |
| — |
| — |
| — |
|
Comprehensive income |
| 56 |
| 62 |
| 195 |
| 198 |
|
Comprehensive income attributable to non-controlling interests |
| 1 |
| 2 |
| 7 |
| 10 |
|
Comprehensive income attributable to controlling interests |
| 55 |
| 60 |
| 188 |
| 188 |
|
(a) Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).
|
| Three months ended |
| Six months ended |
| ||||
(unaudited) |
| June 30, |
| June 30, |
| ||||
(millions of dollars) |
| 2018 |
| 2017 |
| 2018 |
| 2017 |
|
|
|
|
|
|
|
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|
|
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Net income |
| 75 |
| 55 |
| 177 |
| 138 |
|
Other comprehensive income |
|
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Change in fair value of cash flow hedges (Note 13) |
| (1 | ) | — |
| 6 |
| 1 |
|
Amortization of realized loss on derivative financial instruments (Note 13) |
| 2 |
| 1 |
| 2 |
| 1 |
|
Reclassification to net income of gains and losses on cash flow hedges (Note 13) |
| 3 |
| (1 | ) | 3 |
| (1 | ) |
Comprehensive income |
| 79 |
| 55 |
| 188 |
| 139 |
|
Comprehensive income attributable to non-controlling interests |
| 3 |
| — |
| 9 |
| 6 |
|
Comprehensive income attributable to controlling interests |
| 76 |
| 55 |
| 179 |
| 133 |
|
The accompanying notes are an integral part of these consolidated financial statements.
TC PIPELINES, LP
CONSOLIDATED BALANCE SHEETS
(unaudited) |
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(millions of dollars) |
| September 30, 2017 |
| December 31, 2016 (a) |
|
| June 30, 2018 |
| December 31, 2017 |
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ASSETS |
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Current Assets |
|
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Cash and cash equivalents |
| 73 |
| 64 |
|
| 51 |
| 33 |
|
Accounts receivable and other (Note 13) |
| 35 |
| 47 |
| |||||
Accounts receivable and other (Note 14) |
| 40 |
| 42 |
| |||||
Inventories |
| 7 |
| 7 |
|
| 8 |
| 8 |
|
Other |
| 6 |
| 7 |
|
| 9 |
| 7 |
|
|
| 121 |
| 125 |
|
| 108 |
| 90 |
|
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|
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Equity investments (Note 4) |
| 1,207 |
| 918 |
| |||||
Plant, property and equipment |
|
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| |||||
(Net of $1,158 accumulated depreciation; 2016 - $1,088) |
| 2,133 |
| 2,180 |
| |||||
Equity investments (Note 5) |
| 1,211 |
| 1,213 |
| |||||
Plant, property and equipment (Net of $1,229 accumulated depreciation; 2017 - $1,181) |
| 2,086 |
| 2,123 |
| |||||
Goodwill |
| 130 |
| 130 |
|
| 130 |
| 130 |
|
Other assets |
| — |
| 1 |
|
| 11 |
| 3 |
|
|
| 3,591 |
| 3,354 |
|
| 3,546 |
| 3,559 |
|
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LIABILITIES AND PARTNERS’ EQUITY |
|
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Current Liabilities |
|
|
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|
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Accounts payable and accrued liabilities |
| 31 |
| 29 |
|
| 27 |
| 31 |
|
Accounts payable to affiliates (Note 11) |
| 5 |
| 8 |
| |||||
Accounts payable to affiliates (Note 12) |
| 6 |
| 5 |
| |||||
Distribution payable |
| — |
| 3 |
|
| — |
| 1 |
|
Accrued interest |
| 21 |
| 10 |
|
| 12 |
| 12 |
|
Current portion of long-term debt (Note 5) |
| 51 |
| 52 |
| |||||
Current portion of long-term debt (Note 7) |
| 36 |
| 51 |
| |||||
|
| 108 |
| 102 |
|
| 81 |
| 100 |
|
Long-term debt, net (Note 5) |
| 2,427 |
| 1,859 |
| |||||
|
|
|
|
|
| |||||
Long-term debt, net (Note 7) |
| 2,272 |
| 2,352 |
| |||||
Deferred state income taxes (Note 18) |
| 10 |
| 10 |
|
| 10 |
| 10 |
|
Other liabilities |
| 28 |
| 28 |
|
| 28 |
| 29 |
|
|
| 2,573 |
| 1,999 |
|
| 2,391 |
| 2,491 |
|
|
|
|
|
|
| |||||
Common units subject to rescission (Note 7) |
| — |
| 83 |
| |||||
|
|
|
|
|
| |||||
Partners’ Equity |
|
|
|
|
|
|
|
|
|
|
Common units |
| 790 |
| 1,002 |
|
| 912 |
| 824 |
|
Class B units (Note 7) |
| 103 |
| 117 |
| |||||
Class B units (Note 8) |
| 95 |
| 110 |
| |||||
General partner |
| 23 |
| 27 |
|
| 22 |
| 24 |
|
Accumulated other comprehensive loss |
| — |
| (2 | ) | |||||
Accumulated other comprehensive income (AOCI) |
| 15 |
| 5 |
| |||||
Controlling interests |
| 916 |
| 1,144 |
|
| 1,044 |
| 963 |
|
|
|
|
|
|
|
|
|
|
|
|
Non-controlling interests |
| 102 |
| 97 |
|
| 111 |
| 105 |
|
Equity of former parent of PNGTS |
| — |
| 31 |
| |||||
|
| 1,018 |
| 1,272 |
|
| 1,155 |
| 1,068 |
|
|
| 3,591 |
| 3,354 |
|
| 3,546 |
| 3,559 |
|
Contingencies (Note 15)16)
Variable Interest Entities (Note 17)
Subsequent Events (Note 19)
(a) Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).
The accompanying notes are an integral part of these consolidated financial statements.
TC PIPELINES, LP
CONSOLIDATED STATEMENT OF CASH FLOWS
|
| Nine months ended |
| ||
(unaudited) |
| September 30, |
| ||
(millions of dollars) |
| 2017 |
| 2016 (a) |
|
|
|
|
|
|
|
Cash Generated From Operations |
|
|
|
|
|
Net income |
| 193 |
| 198 |
|
Depreciation |
| 73 |
| 71 |
|
Amortization of debt issue costs reported as interest expense |
| 1 |
| 1 |
|
Amortization of realized loss on derivative instrument |
| 1 |
| 1 |
|
Deferred state income tax recovery (Note 18) |
| — |
| — |
|
Equity earnings from equity investments (Notes 3 and 4) |
| (87 | ) | (75 | ) |
Distributions received from operating activities of equity investments (Note 3) |
| 106 |
| 125 |
|
Change in operating working capital (Note 10) |
| 24 |
| 11 |
|
|
| 311 |
| 332 |
|
Investing Activities |
|
|
|
|
|
Investment in Northern Border (Note 4) |
| (83 | ) | — |
|
Investment in Great Lakes (Note 4) |
| (4 | ) | (4 | ) |
Distribution received from Iroquois as return of investment (Note 4) |
| 3 |
| — |
|
Acquisition of a 49.9 percent interest in PNGTS |
| — |
| (193 | ) |
Acquisition of a 49.34 percent in Iroquois and an additional 11.81 percent in PNGTS (Note 6) |
| (646 | ) | — |
|
Capital expenditures |
| (26 | ) | (21 | ) |
Other |
| — |
| 3 |
|
|
| (756 | ) | (215 | ) |
Financing Activities |
|
|
|
|
|
Distributions paid (Note 9) |
| (210 | ) | (184 | ) |
Distributions paid to Class B units (Note 7) |
| (22 | ) | (12 | ) |
Distributions paid to non-controlling interests |
| (5 | ) | (12 | ) |
Distributions paid to former parent of PNGTS |
| (1 | ) | (9 | ) |
Common unit issuance, net (Note 7) |
| 126 |
| 35 |
|
Common unit issuance subject to rescission, net (Note 7) |
| — |
| 83 |
|
Long-term debt issued, net of discount (Note 5) |
| 732 |
| 200 |
|
Long-term debt repaid (Note 5) |
| (164 | ) | (196 | ) |
Debt issuance costs |
| (2 | ) | — |
|
|
| 454 |
| (95 | ) |
Decrease in cash and cash equivalents |
| 9 |
| 22 |
|
Cash and cash equivalents, beginning of period |
| 64 |
| 55 |
|
Cash and cash equivalents, end of period |
| 73 |
| 77 |
|
(a) Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).
|
| Six months ended |
| ||
(unaudited) |
| June 30, |
| ||
(millions of dollars) |
| 2018 |
| 2017 |
|
|
|
|
|
|
|
Cash Generated From Operations |
|
|
|
|
|
Net income |
| 177 |
| 138 |
|
Depreciation |
| 48 |
| 49 |
|
Amortization of debt issue costs reported as interest expense |
| 1 |
| 1 |
|
Amortization of realized loss on derivative instrument (Note 13) |
| 2 |
| 1 |
|
Accrual for costs related to the 2017 Acquisition |
| — |
| 1 |
|
Equity earnings from equity investments (Note 5) |
| (95 | ) | (60 | ) |
Distributions received from operating activities of equity investments (Note 5) |
| 96 |
| 68 |
|
Change in other long term liabilities |
| (1 | ) | — |
|
Change in operating working capital (Note 11) |
| (5 | ) | 7 |
|
|
| 223 |
| 205 |
|
Investing Activities |
|
|
|
|
|
Investment in Great Lakes |
| (4 | ) | (4 | ) |
Acquisition of a 49.34 percent in Iroquois and an additional 11.81 percent in PNGTS |
| — |
| (605 | ) |
Distribution received from Iroquois as return of investment (Note 5) |
| 5 |
| — |
|
Capital expenditures |
| (9 | ) | (16 | ) |
|
| (8 | ) | (625 | ) |
Financing Activities |
|
|
|
|
|
Distributions paid (Note 10) |
| (123 | ) | (135 | ) |
Distributions paid to Class B units (Note 8) |
| (15 | ) | (22 | ) |
Distributions paid to non-controlling interests |
| (3 | ) | (5 | ) |
Distributions paid to former parent of PNGTS |
| — |
| (1 | ) |
Common unit issuance, net (Note 8) |
| 40 |
| 92 |
|
Long-term debt issued, net (Note 7) |
| 130 |
| 607 |
|
Long-term debt repaid (Note 7) |
| (225 | ) | (128 | ) |
Debt issuance costs |
| (1 | ) | (1 | ) |
|
| (197 | ) | 407 |
|
Decrease in cash and cash equivalents |
| 18 |
| (13 | ) |
Cash and cash equivalents, beginning of period |
| 33 |
| 64 |
|
Cash and cash equivalents, end of period |
| 51 |
| 51 |
|
The accompanying notes are an integral part of these consolidated financial statements.
TC PIPELINES, LP
CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS’ EQUITY
|
| Limited Partners |
|
|
|
|
|
|
|
|
|
|
| ||||||
|
| Common Units |
| Class B Units |
| General |
| Accumulated |
| Non- |
| Equity of |
| Total |
| ||||
(unaudited) |
| millions |
| millions |
| millions |
| millions |
| millions |
| millions |
| millions |
| millions |
| millions |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Partners’ Equity at December 31, 2016 |
| 67.4 |
| 1,002 |
| 1.9 |
| 117 |
| 27 |
| (2 | ) | 97 |
| 31 |
| 1,272 |
|
Net income (b) |
| — |
| 164 |
| — |
| 8 |
| 12 |
| — |
| 7 |
| 2 |
| 193 |
|
Other comprehensive income |
| — |
| — |
| — |
| — |
| — |
| 2 |
| — |
| — |
| 2 |
|
ATM equity issuances, net (Note 7) |
| 2.2 |
| 124 |
| — |
| — |
| 2 |
| — |
| — |
| — |
| 126 |
|
Reclassification of common units no longer subject to rescission (Note 7) |
| — |
| 81 |
| — |
| — |
| 2 |
| — |
| — |
| — |
| 83 |
|
Acquisition of interests in PNGTS and Iroquois (Note 6) |
| — |
| (383 | ) | — |
| — |
| (8 | ) | — |
| — |
| (32 | ) | (423 | ) |
Distributions (b) |
| — |
| (198 | ) | — |
| (22 | ) | (12 | ) | — |
| (2 | ) | (1 | ) | (235 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Partners’ Equity at September 30, 2017 |
| 69.6 |
| 790 |
| 1.9 |
| 103 |
| 23 |
| — |
| 102 |
| — |
| 1,018 |
|
|
| Limited Partners |
| General |
| Accumulated |
| Non- |
|
|
| ||||||
(unaudited) |
| Common Units |
| Class B Units |
| Partner |
| Income (a) |
| Interest |
| Total Equity |
| ||||
|
| millions |
| millions of |
| millions |
| millions of |
| millions of |
| millions of |
| millions of |
| millions of |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Partners’ Equity at December 31, 2017 |
| 70.6 |
| 824 |
| 1.9 |
| 110 |
| 24 |
| 5 |
| 105 |
| 1,068 |
|
Net income |
| — |
| 166 |
| — |
| — |
| 3 |
| — |
| 8 |
| 177 |
|
Other comprehensive income |
| — |
| — |
| — |
| — |
| — |
| 10 |
| 1 |
| 11 |
|
ATM equity issuances, net (Note 8) |
| 0.7 |
| 39 |
| — |
| — |
| 1 |
| — |
| — |
| 40 |
|
Distributions |
| — |
| (117 | ) | — |
| (15 | ) | (6 | ) | — |
| (3 | ) | (141 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Partners’ Equity at June 30, 2018 |
| 71.3 |
| 912 |
| 1.9 |
| 95 |
| 22 |
| 15 |
| 111 |
| 1,155 |
|
(a) LossesGains (Losses) related to cash flow hedges reported in Accumulated Other Comprehensive LossIncome and expected to be reclassified to Net Incomeincome in the next 12 months are estimated to be $1$3 million. These estimates assume constant interest rates over time; however, the amounts reclassified will vary based on actual value of interest rates at the date of settlement.
(b) Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).
The accompanying notes are an integral part of these consolidated financial statements.
TC PIPELINES, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
NOTE 1 ORGANIZATION
TC PipeLines, LP and its subsidiaries are collectively referred to herein as the Partnership. The Partnership was formed by TransCanada PipeLines Limited, a wholly owned subsidiary of TransCanada Corporation (TransCanada Corporation together with its subsidiaries collectively referred to herein as TransCanada), to acquire, own and participate in the management of energy infrastructure assets in North America.
The Partnership owns its pipeline assets through three intermediate limited partnerships (ILPs), TC GL Intermediate Limited Partnership, TC PipeLines Intermediate Limited Partnership and TC Tuscarora Intermediate Limited Partnership.
NOTE 2SIGNIFICANT ACCOUNTING POLICIES
The accompanying financial statements and related notes have been prepared in accordance with United States generally accepted accounting principles (GAAP) and amounts are stated in U.S. dollars. The results of operations for the three and ninesix months ended SeptemberJune 30, 20172018 and 20162017 are not necessarily indicative of the results that may be expected forover the full fiscal year.
The accompanying financial statements should be read in conjunction with the audited financial statements and notes thereto for the year ended December 31, 20162017 included as exhibit 99.2 in our CurrentAnnual Report on Form 8-K dated August 3, 2017.10-K. That report contains a more comprehensive summary of the Partnership’s significant accounting policies. In the opinion of management, the accompanying financial statements contain all of the appropriate adjustments, all of which are normally recurring adjustments unless otherwise noted, and considered necessary to present fairly the financial position of the Partnership, the results of operations and cash flows for the respective periods. Our significant accounting policies are consistent with those disclosed in our audited financial statements and notes theretoAnnual Report on Form 10-K for the year ended December 31, 2016 included as exhibit 99.2 in our Current Report on Form 8-K dated August 3, 2017, except as described in Note 3, Accounting Pronouncements.
Basis of Presentation
The Partnership consolidates its interests in entities over which it is able to exercise control. To the extent there are interests owned by other parties, these interests are included in non-controlling interests. The Partnership uses the equity method of accounting for its investments in entities over which it is able to exercise significant influence.
Acquisitions by the Partnership from TransCanada are considered common control transactions. When businesses are acquired from TransCanada that will be consolidated by the Partnership, the historical financial statements are required to be recast, except net income per common unit, to include the acquired entities for all periods presented.
When the Partnership acquires an asset or an investment from TransCanada, which will be accounted for by the equity method, the financial information is not required to be recast and the transaction is accounted for prospectively from the date of the acquisition.
On June 1, 2017, the Partnership acquired from a subsidiary of TransCanada an additional 11.81 percent interest in PNGTS, that resulted in the Partnership owning a 61.71 percent interest in PNGTS (Refer to Note 6). As a result of the Partnership owning 61.71 percent interest in PNGTS, the Partnership’s historical financial information has been recast, except net income (loss) per common unit, to consolidate PNGTS for all the periods presented in the Partnership’s consolidated financial statements. Additionally, this acquisition was accounted for as transaction between entities under common control, similar to pooling of interests, whereby the assets and liabilities of PNGTS were recorded at TransCanada’s carrying value.
Also, on June 1, 2017, the Partnership acquired from subsidiaries of TransCanada a 49.34 percent interest in Iroquois Gas Transmission, L.P. (“Iroquois”) (Refer to Note 6). Accordingly, this transaction was accounted for as a transaction between entities under common control, similar to pooling of interest, whereby the equity investment in Iroquois was recorded at TransCanada’s carrying value and was accounted for prospectively.
Use of Estimates
The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Although management believes these estimates are reasonable, actual results could differ from these estimates.
NOTE 3 ACCOUNTING PRONOUNCEMENTS
Retrospective application ofChanges in Accounting Standards Update (ASU) No 2016-15 “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments”
In August 2016, the Financial Accounting Standards Board (FASB) issued an amendment of previously issued guidance, which intends to reduce diversity in practice in how certain transactions are classified in the statement of cash flows. The new guidance isPolicies effective January 1, 2018 however, as early adoption is permitted, the Partnership elected to retrospectively apply this guidance effective December 31, 2016. The Partnership has elected to classify distributions received from equity method investees using the nature of distributions approach as it is more representative of the nature of the underlying activities of the investees that generated the distributions. As a result, certain comparative period distributions received from equity method investees, amounting to $50 million for the nine months ended September 30, 2016, have been reclassified from investing activities to cash generated from operations in the consolidated statement of cash flows.
Effective January 1, 2017
Inventory
In July 2015, the FASB issued new guidance on simplifying the measurement of inventory. The new guidance specifies that an entity should measure inventory within the scope of this update at the lower of cost and net realizable value. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. This new guidance was effective January 1, 2017, was applied prospectively and did not have a material impact on the Partnership’s consolidated balance sheet.
Equity method and joint ventures
In March 2016, the FASB issued new guidance that simplifies the transition to equity method accounting. The new guidance eliminates the requirement to retroactively apply the equity method of accounting when an increase in ownership interest in an investment qualifies for equity method accounting. The new guidance is effective January 1, 2017 and was applied prospectively. The application of this guidance did not have a material impact on the Partnership’s consolidated financial statements.
Consolidation
In October 2016, the FASB issued new guidance on consolidation relating to interests held through related parties that are under common control. The new guidance amends the consolidation requirements such that if a decision maker is required to evaluate whether it is the primary beneficiary of a variable interest entry (VIE), it will need to consider only its proportionate indirect interest in the VIE held through a common control party. The guidance was effective January 1, 2017, was applied retrospectively and did not result in any change to our consolidation conclusions.
Future accounting changes
Revenue from contracts with customers
In 2014, the FASBFinancial Accounting Standards Board (FASB) issued new guidance on revenue from contracts with customers. The new guidance requires that an entity recognize revenue from these contracts in accordance with a
prescribed model. This model is used to depict the transfer of promised goods or services to customers in an amountamounts that reflectsreflect the total consideration to which it expects to be entitled during the term of the contract in exchange for those promised goods or services. Goods or services that are promised to a customer are referred to as the Partnership’s “performance obligations.” The total consideration to which the Partnership expects to be entitled can include fixed and variable amounts. The Partnership has variable revenue that is subject to factors outside the Partnership’s influence, such as market volatility, actions of third parties and weather conditions. The Partnership considers this variable revenue to be “constrained” as it cannot be reliably estimated, and therefore recognizes variable revenue when the service is provided.
The new guidance also requires additional disclosures about the nature, amount, timing and uncertainty of revenue recognition and the related cash flows. The Partnership will adoptEffective January 1, 2018, the new standard on the effective date of January 1, 2018. There are two methods in which the new standard can be adopted: (1) a full retrospective approach with restatement of all prior periods presented, or (2) a modified retrospective approach with a cumulative-effect adjustment as of the date of adoption. The Partnership will adopt the
standardguidance was applied using the modified retrospective approach with the cumulative-effect of the adjustment recognized at the date of adoption, subject to allowabletransition method, and elected practical expedients.
The Partnership has identified all existing customer contracts that are within the scope of the new guidance and is on scheduledid not result in the process of analyzing individual contracts or groups of contracts to identify any significant changes in how revenues are recognized as a result of implementing the new guidance. While the Partnership has not identified any material differences in the amount and timing of revenue recognitionrecognition. Refer to Note 6 - Revenues, for the contracts that have been analyzedfurther information related to date, the evaluation is not complete and the Partnership has not concluded on the overall impact of adopting the new guidance. The Partnership continues its contract analysis to obtainguidance and the information necessary to quantify the cumulative-effect adjustment, if any, on prior period revenues and revenue recognized going forward.
Although consolidated revenues may not be materially impacted by the new guidance, the Partnership currently anticipates significant changes to disclosures based on the additional requirements prescribed. These new disclosures include information regarding the significant judgments used in evaluating when and how revenue is recognized and informationPartnership’s updated accounting policies related to contract assets and liabilities. In addition, the new guidance requires that the Partnership’s revenue recognition policy disclosure includes additional detail regarding the various performance obligations and the nature, amount, timing and estimates of revenue and cash flows generated from contracts with customers.
Hedge Accounting
In August 2017, the FASB issued new guidance on hedge accounting, making more financial and nonfinancial hedging strategies eligible for hedge accounting. The new guidance amends the presentation requirements relating to the change in fair value of a derivative and additional disclosure requirements include cumulative basis adjustments for fair value hedges and the effect of hedging on individual statement of income line items. This new guidance is effective January 1, 2019 with early adoption permitted. The Partnership continueshas elected to develop and evaluate disclosures required withprospectively apply this guidance effective January 1, 2018. Application of this guidance did not have a particular focusmaterial impact on the scope of contracts subject to disclosure of remaining performance obligations. The Partnership also continues to address any system and processits consolidated financial statements.
Future accounting changes necessary to compile the information to meet the recognition and disclosure requirements of the new guidance. The Partnership continues to monitor additional authoritative or interpretive guidance related to the new guidance as it becomes available.
Leases
In February 2016, the FASB issued new guidance on the accounting for leases. The new guidance amends the definition of a lease requiringsuch that, in order for the customerarrangement to qualify as a lease, the lessor 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 in order for the arrangement to qualify as a lease.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 balance sheet for all leases with a term longer than 12 months. Leases will be classified as finance or operating, with classification affecting the pattern and classification of expense recognition in the income statement. The new guidance does not make extensive changes to lessor accounting.
In January 2018, the FASB issued new guidance on accounting for land easements which provides an optional transition practical expedient to not evaluate existing or expired land easements not accounted for as leases prior to entity’s adoption of the new guidance. An entity that elects this practical expedient is required to apply it consistently to all of its existing or expired land easements not previously accounted for as leases. The Partnership continues to monitor and analyze additional guidance and clarifications provided by the FASB.
The new guidance is effective on January 1, 2019, with early adoption permitted. A modified retrospective transition approach is required for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements, with certain practical expedients available. The Partnership is continuing to identifyhas substantially completed an analysis and analyzepreliminary inventory listing of existing lease agreements, and continues to determineanalyze contracts that may contain leases. The Partnership continues to evaluate the effectfinancial impact of adoptionthe application of the new guidance on its consolidated financial statements. The Partnership has also selected a system solution and is also addressing system andin the testing stage of its implementation. The Partnership continues to assess process changes necessary to compile the information to meet the recognition and disclosure requirements of the new guidance.
Goodwill Impairment
In January 2017, the FASB issued new guidance on simplifying the test for goodwill impairment by eliminating the requirement to calculate the implied fair value of goodwill to measure the impairment charge. Instead, entities will record an impairment charge based on the excess of a reporting unit’s carrying amount over its fair value. This new guidance is effective January 1, 2020 and will be applied prospectively. Earlyprospectively, however, early adoption is permitted. The Partnership is currently evaluating the timing and impact of the adoption of this guidance.
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. 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 hashave not yet determined the effect on itsour consolidated financial statements.
Hedge AccountingNOTE 4 REGULATORY
In AugustDecember 2016, FERC issued a Notice of Inquiry (NOI) Regarding the Commission’s Policy for Recovery of Income Tax Costs (Docket No. PL17-1-000) requesting initial comments regarding how to address any “double recovery” resulting from FERC’s current income tax allowance and rate of return policies that had been in effect since 2005.
Docket No. PL17-1-000 is a direct response to United Airlines, Inc., et al. v. FERC (United), a decision issued by the U.S. Court of Appeals for the District of Columbia Circuit in July 2016 in which the D.C. Circuit directed FERC to explain how a pass-through entity such as an MLP receiving a tax allowance and a return on equity derived from the discounted cash flow (DCF) methodology did not result in “double recovery” of taxes.
On December 22, 2017, the FASBPresident of the United States signed into law H.R.1, originally known as the Tax Cuts and Jobs Act (the “2017 Tax Act”). This legislation provides for major changes to U.S. corporate federal tax law including a reduction of the federal corporate income tax rate. We are a non-taxable limited partnership for federal income tax purposes, and federal income taxes owed as a result of our earnings are the responsibility of our partners, therefore no amounts have been recorded in the Partnership’s financial statements with respect to federal income taxes as a result of the 2017 Tax Act.
On March 15, 2018, FERC issued new guidance(1) a Revised Policy Statement on hedge accounting, making more financial and nonfinancial hedging strategies eligible for hedge accounting. The new guidance amendsTreatment of Income Taxes (Revised Policy Statement) to address the presentation requirements relating to the change in fair value of a derivative and additional disclosure requirements include cumulative basis adjustments for fair value hedges and the effect of hedging on individual statementtreatment of income line items. This new guidance is effective January 1, 2019 and will be applied prospectively withtaxes for ratemaking purposes for MLPs, (2) a cumulative-effect adjustmentNotice of Proposed Rulemaking (NOPR) proposing interstate pipelines file a one-time report to opening equity on adoption. Early adoption is permitted. The Partnership is currently evaluatingquantify the impact of the adoptionfederal income tax rate reduction and the Revised Policy Statement could have on a pipeline’s Return on Equity (ROE) assuming a single-issue adjustment to a pipeline’s rates, and (3) an NOI seeking comment on how FERC should address changes related to accumulated deferred income taxes (ADIT) and bonus depreciation. On July 18, 2018, FERC issued (1) an Order on Rehearing of the Revised Policy Statement (Order on Rehearing) dismissing rehearing requests related to the Revised Policy Statement and (2) a Final Rule adopting and revising procedures from, and clarifying aspects of, the NOPR (collectively, the “2018 FERC Actions”). The Final Rule will become effective September 13, 2018, and is subject to requests for further rehearing and clarification. Each is further described below.
FERC Revised Policy Statement on Income Tax Allowance Cost Recovery in MLP Pipeline Rates
The Revised Policy Statement changes FERC’s long-standing policy allowing income tax amounts to be included in rates subject to cost-of-service rate regulation for pipelines owned by an MLP. The Revised Policy Statement creates a presumption that entities whose earnings are not taxed through a corporation should not be permitted to recover an income tax allowance in their regulated cost-of-service rates.
On July 18, 2018, FERC dismissed requests for rehearing and provided clarification of the Revised Policy Statement. In this Order on Rehearing, FERC noted that an MLP is not automatically precluded in a future proceeding from arguing and providing evidentiary support that it is entitled to an income tax allowance in its cost-of-service rates. Additionally, FERC provided guidance with regard to ADIT for MLP pipelines and other pass through entities. FERC found that to the extent an entity’s income tax allowance should be eliminated from rates, it must also eliminate its existing ADIT balance from its rate base. As a result, the Revised Policy Statement also precludes the recognition and subsequent amortization of any related regulatory assets or liabilities that might have otherwise impacted rates charged to customers as the refund or collection of excess or deficient deferred income tax assets or liabilities.
Final Rule on Tax Law Changes for Interstate Natural Gas Companies
The Final Rule established a schedule by which interstate pipelines must either (i) file a new uncontested rates settlement or (ii) file a one-time report, called FERC Form No. 501-G, that quantifies the isolated rate impact of the
2017 Tax Act on FERC regulated pipelines and the impact of the Revised Policy Statement on pipelines held by MLPs. Pipelines filing the one-time report will have four options:
· make a limited Natural Gas Act (NGA) Section 4 filing to reduce its rates by the reduction in its cost of service shown in its FERC Form No. 501-G. For any pipeline electing this option, FERC guarantees a three-year moratorium on NGA Section 5 rate investigations if the pipeline’s FERC Form 501-G shows the pipeline’s estimated ROE as being12 percent or less. Under the Final Rule and notwithstanding the Revised Policy Statement, a pipeline organized as an MLP is not required to eliminate its income tax allowance but, instead, can reduce its rates to reflect the reduction in the maximum corporate tax rate. Alternatively, the MLP pipeline can eliminate its tax allowance, along with its ADIT used for rate-making purposes. In situations where the ADIT balance is a liability, this elimination would have the effect of increasing the pipeline’s rate base used for rate-making purposes;
· commit to file either a pre-packaged uncontested rate settlement or a general Section 4 rate case if it believes that using the limited Section 4 option will not result in just and reasonable rates. If the pipeline commits to file either by December 31, 2018, FERC will not initiate a Section 5 investigation of its rates prior to that date;
· file a statement explaining its rationale for why it does not believe the pipeline’s rates must change; and
· take no other action. FERC would then consider whether to initiate a Section 5 investigation of any pipeline that has not yetsubmitted a limited Section 4 rate filing or committed to file a general Section 4 rate case.
We continue to evaluate this Final Rule and our next course of action, however, we do not expect an immediate or a retroactive impact from the Final Rule or the Revised Policy Statement described above.
NOI Regarding the Effect of the 2017 Tax Act on Commission-Jurisdictional Rates
In the NOI, FERC sought comments to determine what additional action as a result of the 2017 Tax Act, if any, is required by FERC related to the ADIT that were reserved in anticipation of being paid to the Internal Revenue Service (IRS), but which no longer accurately reflect the future income tax liability. The NOI also sought comments on the elimination of bonus depreciation for regulated natural gas pipelines and other effects of the 2017 Tax Act on regulated rates or earnings.
As noted above, FERC’s Order on Rehearing provided guidance with regard to ADIT for MLP pipelines, finding that if an MLP pipeline’s income tax allowance is eliminated from its cost-of-service rates, then its existing ADIT balance used for rate-making purposes should also be eliminated from its cost-of-service rates.
Impairment Considerations
As noted under Note 2, the preparation of financial statements in accordance with GAAP requires us to make estimates and assumptions with respect to values or conditions, which cannot be known with certainty, that affect the reported amount of assets and liabilities at the date of the financial statements. Although we believe these estimates and assumptions are reasonable, actual results could differ.
We review property, plant and equipment and equity investments for impairment whenever events or changes in circumstances indicate the carrying value of the asset may not be recoverable.
Goodwill is tested for impairment on an annual basis or more frequently if events or changes in circumstance indicate that it might be impaired. We can initially make this assessment based on qualitative factors. If we conclude that it is not more likely than not that the fair value of the reporting unit is less than its carrying value, an impairment test is not performed.
Until the 2018 FERC Actions are implemented through individual rate proceedings or settlements, and we have fully evaluated our respective alternatives to minimize any negative impact on our future operating performance and cash flows, we believe that it is not more likely than not that the fair values of our reporting units are less than their respective carrying values. Therefore, a goodwill impairment test was not performed. Also, we have determined there is no indication that the effect on its consolidated financial statements.carrying values of property, plant and equipment and equity investments potentially impacted by the 2018 FERC Actions are not recoverable.
We will continue to monitor developments and assess our goodwill for impairment. We will also review our property, plant and equipment and equity investments for recoverability as new information becomes available.
At December 31, 2017, the estimated fair value of our investment in Great Lakes exceeded its carrying value by less than 10 percent. There is a risk that the 2018 FERC Actions, once implemented through the individual rate proceeding or settlement, could result in an impairment charge to our equity method goodwill on Great Lakes which amounted to $260 million at June 30, 2018 (December 31, 2017 — $260 million). Additionally, given that the estimated fair value of Tuscarora exceeded its carrying value by less than 10 percent in its most recent valuation, there is also a risk that the $82 million goodwill at June 30, 2018 (December 31, 2017 - $82 million) related to Tuscarora could be negatively impacted by the 2018 FERC Actions once implemented through the individual rate proceeding or settlement.
NOTE 45 EQUITY INVESTMENTS
The Partnership has equity interests in Northern Border, Great Lakes and effective June 1, 2017, Iroquois. The pipeline systems owned by these entities are regulated by FERC. The pipeline systems of Northern Border and Great Lakes are operated by subsidiaries of TransCanada. The Iroquois pipeline system is operated by Iroquois Pipeline Operating Company, a wholly owned subsidiary of Iroquois. The Partnership uses the equity method of accounting for its interests in its equity investees. The Partnership’s equity investments are held through our ILPs that are considered to be variable interest entities (VIEs) (Refer to Note 17).
|
| Ownership |
| Equity Earnings |
| Equity Investments |
|
| Ownership |
| Equity Earnings |
| Equity Investments |
| ||||||||||||||||
|
| Interest at |
| Three months |
| Nine Months |
|
|
|
|
|
| Interest at |
| Three months |
| Six Months |
|
|
|
|
| ||||||||
(unaudited) |
| September 30, |
| ended September 30, |
| ended September 30, |
| September 30, |
| December 31, |
|
| June 30, |
| ended June 30, |
| ended June 30, |
| June 30, |
| December 31, |
| ||||||||
(millions of dollars) |
| 2017 |
| 2017 |
| 2016(b) |
| 2017 |
| 2016(b) |
| 2017 |
| 2016(b) |
|
| 2018 |
| 2018 |
| 2017 |
| 2018 |
| 2017 |
| 2018 |
| 2017 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Northern Border (a) |
| 50 | % | 16 |
| 18 |
| 50 |
| 52 |
| 516 |
| 444 |
|
| 50 | % | 15 |
| 15 |
| 32 |
| 34 |
| 505 |
| 512 |
|
Great Lakes |
| 46.45 | % | 2 |
| 4 |
| 24 |
| 23 |
| 469 |
| 474 |
|
| 46.45 | % | 12 |
| 6 |
| 36 |
| 23 |
| 485 |
| 479 |
|
Iroquois |
| 49.34 | % | 9 |
| — |
| 13 |
| — |
| 222 |
| — |
|
| 49.34 | % | 9 |
| 3 |
| 27 |
| 3 |
| 221 |
| 222 |
|
|
|
|
| 27 |
| 22 |
| 87 |
| 75 |
| 1,207 |
| 918 |
|
|
|
| 36 |
| 24 |
| 95 |
| 60 |
| 1,211 |
| 1,213 |
|
(a) Equity earnings from Northern Border is net of the 12-year amortization of a $10 million transaction fee paid to the operator of Northern Border at the time of the Partnership’s acquisition of an additional 20 percent interest in April 2006.
(b) Recast to eliminate equityEquity earnings from PNGTSIroquois is net of the 29-year amortization of a $10 million purchase price discrepancy assumed by the Partnership from TransCanada at the time of the 2017 Acquisition.
Distributions from Equity Investments
Distributions received from equity investments for the three and consolidate PNGTS for all periods presented (Refersix months ended June 30, 2018 were $56 million and $101 million, respectively (2017 — $40 million and $68 million) of which $2.6 million and $5.2 million, respectively, (2017 - none) 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 Notes 2 and 6)our investment in Iroquois (see further discussion below).
Northern Border
On September 1, 2017, the Partnership made an equity contribution to Northern Border amounting to $83 million. This amount represents the Partnership’s 50 percent share of $166 million capital contribution request from Northern Border to reduce the outstanding balance of its revolver debt to increase its available borrowing capacity.
The Partnership did not have undistributed earnings from Northern Border for the three and ninesix months ended SeptemberJune 30, 20172018 and 2016.2017.
The summarized financial information forprovided to us by Northern Border is as follows:
(unaudited) |
|
|
|
|
|
|
|
|
|
|
(millions of dollars) |
| September 30, 2017 |
| December 31, 2016 |
|
| June 30, 2018 |
| December 31, 2017 |
|
|
|
|
|
|
|
|
|
|
|
|
ASSETS |
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
| 24 |
| 14 |
|
| 11 |
| 14 |
|
Other current assets |
| 36 |
| 36 |
|
| 34 |
| 36 |
|
Plant, property and equipment, net |
| 1,069 |
| 1,089 |
|
| 1,056 |
| 1,063 |
|
Other assets |
| 14 |
| 14 |
|
| 14 |
| 14 |
|
|
| 1,143 |
| 1,153 |
|
| 1,115 |
| 1,127 |
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND PARTNERS’ EQUITY |
|
|
|
|
|
|
|
|
|
|
Current liabilities |
| 48 |
| 38 |
|
| 37 |
| 38 |
|
Deferred credits and other |
| 30 |
| 28 |
|
| 33 |
| 31 |
|
Long-term debt, including current maturities, net |
| 264 |
| 430 |
| |||||
Partners’ equity |
|
|
|
|
| |||||
Long-term debt, net (a) |
| 264 |
| 264 |
| |||||
Partners’ capital |
| 802 |
| 659 |
|
| 782 |
| 795 |
|
Accumulated other comprehensive loss |
| (1 | ) | (2 | ) |
| (1 | ) | (1 | ) |
|
| 1,143 |
| 1,153 |
|
| 1,115 |
| 1,127 |
|
(a) No current maturities as of June 30, 2018 and December 31, 2017.
|
| Three months ended |
| Nine months ended |
|
| Three months ended |
| Six months ended |
| ||||||||
(unaudited) |
| September 30, |
| September 30, |
|
| June 30, |
| June 30, |
| ||||||||
(millions of dollars) |
| 2017 |
| 2016 |
| 2017 |
| 2016 |
|
| 2018 |
| 2017 |
| 2018 |
| 2017 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transmission revenues |
| 73 |
| 74 |
| 217 |
| 218 |
|
| 68 |
| 69 |
| 140 |
| 144 |
|
Operating expenses |
| (20 | ) | (18 | ) | (56 | ) | (53 | ) |
| (19 | ) | (18 | ) | (38 | ) | (36 | ) |
Depreciation |
| (15 | ) | (15 | ) | (45 | ) | (44 | ) |
| (15 | ) | (15 | ) | (30 | ) | (30 | ) |
Financial charges and other |
| (5 | ) | (5 | ) | (14 | ) | (16 | ) |
| (4 | ) | (5 | ) | (7 | ) | (9 | ) |
Net income |
| 33 |
| 36 |
| 102 |
| 105 |
|
| 30 |
| 31 |
| 65 |
| 69 |
|
Great Lakes
The Partnership made an equity contribution to Great Lakes of $4 million in the first quarter of 2017.2018. This amount represents the Partnership’s 46.45 percent share of a $9 million cash call from Great Lakes to make a scheduled debt repayment.
The Partnership did not have undistributed earnings from Great Lakes for the three and ninesix months ended SeptemberJune 30, 20172018 and 2016.2017.
The summarized financial information forprovided to us by Great Lakes is as follows:
(unaudited) |
|
|
|
|
|
|
|
|
|
|
(millions of dollars) |
| September 30, 2017 |
| December 31, 2016 |
|
| June 30, 2018 |
| December 31, 2017 |
|
|
|
|
|
|
|
|
|
|
|
|
ASSETS |
|
|
|
|
|
|
|
|
|
|
Current assets |
| 56 |
| 66 |
|
| 89 |
| 107 |
|
Plant, property and equipment, net |
| 705 |
| 714 |
|
| 695 |
| 701 |
|
|
| 761 |
| 780 |
|
| 784 |
| 808 |
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND PARTNERS’ EQUITY |
|
|
|
|
|
|
|
|
|
|
Current liabilities |
| 41 |
| 40 |
|
| 49 |
| 75 |
|
Net long-term debt, including current maturities |
| 269 |
| 278 |
|
| 250 |
| 259 |
|
Other long term liabilities |
| — |
| 1 |
| |||||
Partners’ equity |
| 451 |
| 462 |
|
| 485 |
| 473 |
|
|
| 761 |
| 780 |
|
| 784 |
| 808 |
|
|
| Three months ended |
| Nine months ended |
| ||||
(unaudited) |
| September 30, |
| September 30, |
| ||||
(millions of dollars) |
| 2017 |
| 2016 |
| 2017 |
| 2016 |
|
|
|
|
|
|
|
|
|
|
|
Transmission revenues |
| 34 |
| 36 |
| 138 |
| 133 |
|
Operating expenses |
| (19 | ) | (15 | ) | (49 | ) | (45 | ) |
Depreciation |
| (7 | ) | (7 | ) | (21 | ) | (21 | ) |
Financial charges and other |
| (5 | ) | (6 | ) | (16 | ) | (17 | ) |
Net income |
| 3 |
| 8 |
| 52 |
| 50 |
|
(a) Includes current maturities of $21 million as of June 30, 2018 (December 31, 2017 - $19 million).
|
| Three months ended |
| Six months ended |
| ||||
(unaudited) |
| June 30, |
| June 30, |
| ||||
(millions of dollars) |
| 2018 |
| 2017 |
| 2018 |
| 2017 |
|
|
|
|
|
|
|
|
|
|
|
Transmission revenues |
| 53 |
| 41 |
| 134 |
| 103 |
|
Operating expenses |
| (15 | ) | (17 | ) | (32 | ) | (30 | ) |
Depreciation |
| (8 | ) | (7 | ) | (16 | ) | (14 | ) |
Financial charges and other |
| (5 | ) | (5 | ) | (9 | ) | (10 | ) |
Net income |
| 25 |
| 12 |
| 77 |
| 49 |
|
Iroquois
On June 1, 2017, the Partnership, through its interest in TC PipeLines Intermediate Limited Partnership acquired a 49.34 percent interest in Iroquois. Also on July 27, 2017, Iroquois declared its second quarter 2017 distribution of $28 million, of whichDuring the three and six months ended June 30, 2018, the Partnership received its 49.34 percent share ordistributions from Iroquois amounting to $14 million on August 1, 2017. The distributionand $28 million, respectively, which includes the Partnership’s 49.34 percent share of the Iroquois unrestricted cash distribution amounting to approximately $2.6 million (Refer to Note 6). This amount isand $5.2 million, respectively. The unrestricted cash does not represent a 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 second quarter 2018 distribution of $29 million on July 25, 2018, of which the Partnership received its 49.34 percent share of $14 million on August 1, 2018. The distribution includes our 49.34 percent share of the Iroquois unrestricted cash distribution amounting to approximately $2.6 million. The Partnership recorded nodid not have undistributed earnings from Iroquois infor the three and ninesix months ended SeptemberJune 30, 2018 and 2017.
The summarized financial information provided to us by Iroquois for Iroquoisthe period from the June 1, 2017 acquisition date through June 30, 2018 is as follows:
(unaudited) |
|
|
|
|
|
|
|
|
|
|
(millions of dollars) |
| September 30, 2017 |
| December 31, 2016 |
|
| June 30, 2018 |
| December 31, 2017 |
|
|
|
|
|
|
|
|
|
|
|
|
ASSETS |
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
| 93 |
| 86 |
|
| 100 |
| 86 |
|
Other current assets |
| 33 |
| 34 |
|
| 26 |
| 36 |
|
Plant, property and equipment, net |
| 592 |
| 604 |
|
| 584 |
| 591 |
|
Other assets |
| 8 |
| 7 |
|
| 10 |
| 8 |
|
|
| 726 |
| 731 |
|
| 720 |
| 721 |
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND PARTNERS’ EQUITY |
|
|
|
|
|
|
|
|
|
|
Current liabilities |
| 20 |
| 18 |
|
| 17 |
| 17 |
|
Net long-term debt, including current maturities |
| 332 |
| 335 |
|
| 327 |
| 329 |
|
Other non-current liabilities |
| 9 |
| 6 |
|
| 13 |
| 9 |
|
Partners’ equity |
| 365 |
| 372 |
|
| 363 |
| 366 |
|
|
| 726 |
| 731 |
|
| 720 |
| 721 |
|
|
| Three months ended |
| Nine months ended |
| ||||
(unaudited) |
| September 30, |
| September 30, |
| ||||
(millions of dollars) |
| 2017 |
| 2016 |
| 2017 |
| 2016 |
|
|
|
|
|
|
|
|
|
|
|
Transmission revenues |
| 43 |
| 45 |
| 142 |
| 145 |
|
Operating expenses |
| (13 | ) | (13 | ) | (41 | ) | (43 | ) |
Depreciation |
| (7 | ) | (9 | ) | (22 | ) | (28 | ) |
Financial charges and other |
| (4 | ) | (4 | ) | (13 | ) | (12 | ) |
Net income |
| 19 |
| 19 |
| 66 |
| 62 |
|
(a) Includes current maturities of $145 million as of June 30, 2018 (December 31, 2017 - $4 million).
(unaudited) |
| Three months |
| One month |
| Six months |
| One month |
|
|
|
|
|
|
|
|
|
|
|
Transmission revenues |
| 44 |
| 14 |
| 105 |
| 14 |
|
Operating expenses |
| (14 | ) | (5 | ) | (28 | ) | (5 | ) |
Depreciation |
| (7 | ) | (2 | ) | (15 | ) | (2 | ) |
Financial charges and other |
| (4 | ) | (1 | ) | (7 | ) | (1 | ) |
Net income |
| 19 |
| 6 |
| 55 |
| 6 |
|
NOTE 6REVENUES
In 2014, the FASB issued new guidance on revenue from contracts with customers. The Partnership adopted the new guidance on January 1, 2018 using the modified retrospective transition method for all contracts that were in effect on the date of adoption. The reported results for all periods in 2018 reflect the application of the new guidance, while the reported results for all periods in 2017 were prepared under previous revenue recognition guidance which is referred to herein as “legacy U.S. GAAP”.
Disaggregation of Revenues
For the three and six months ended June 30, 2018, virtually 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.
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. 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.
Financial Statement Impact of Adopting Revenue from Contracts with Customers
The Partnership adopted the new guidance using the modified retrospective transition method. As a practical expedient under this transition method, the Partnership is not required to analyze completed contracts at the date of adoption. The adoption of the new guidance did not have a material impact on the Partnership’s previously reported consolidated financial statements at December 31, 2017.
Pro-forma Financial Statements under Legacy U.S. GAAP
At June 30, 2018, had legacy U.S. GAAP been applied, there would be no change in the Partnership’s reported balance sheet and income statement line items.
Contract Balances
(unaudited-millions of dollars) |
| June 30, 2018 |
| January 1, 2018 |
|
|
|
|
|
|
|
Receivables from contracts with customers(a) |
| 37 |
| 40 |
|
Contract assets(b) |
| — |
| — |
|
(a) Recorded as Trade accounts receivable and reported as Accounts receivable and other in the consolidated balance sheet (Refer also to Note 14)
(b) Contract assets primarily relate to the Partnership’s right to recognize revenues for services completed but not invoiced at the reporting date. Any change in Contract assets is primarily related to the transfer to Accounts receivable when the right to recognize revenue becomes unconditional and the customer is invoiced as well as when revenue increases but remains to be invoiced. The Partnership did not have any Contract assets at January 1, 2018 and June 30, 2018.
Future revenue from remaining performance obligations
As required by the new revenue recognition guidance, the Partnership is required to provide disclosure on future revenue allocated to remaining performance obligations on our contracts with customers that have not yet been recognized. However, all of the Partnership’s contracts qualify for the use of a practical expedient listed below and therefore no disclosure on future revenues from remaining performance obligations is necessary:
1) The original expected duration of the contract is one year or less.
2) The Partnership recognizes revenue from the contract that is equal to the amount invoiced. This is referred to as the ‘right to invoice’ practical expedient.
3) The variable revenue generated from the contract is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a single performance obligation in a series. A single performance obligation in a series occurs when the promises under a contract are a series of distinct services that are substantially the same and have the same pattern of transfer to the customer over time.
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 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. In addition, the Partnership considers interruptible transportation service revenues to be variable revenues as volumes cannot be estimated. These variable revenues are recognized on a monthly basis when the Partnership’s performance obligation of natural gas deliveries is made at the agreed-upon delivery point.
Lastly, future revenues from the Partnership’s firm capacity contracts include fixed revenues for the time periods when current rate settlements are in effect, which is approximately one to four years. Many of these contracts are long-term in nature and revenues from the remaining performance obligations on these contracts will be recognized using the FERC approved rates once the performance obligation to provide capacity has been satisfied.
NOTE 5 7DEBT AND CREDIT FACILITIES
(unaudited) |
| September 30, |
| Weighted Average |
| December 31, |
| Weighted Average |
|
|
|
|
|
|
|
|
|
|
|
TC PipeLines, LP |
|
|
|
|
|
|
|
|
|
Senior Credit Facility due 2021 |
| 255 |
| 2.34 | % | 160 |
| 1.72 | % |
2013 Term Loan Facility due October 2022 |
| 500 |
| 2.26 | % | 500 |
| 1.73 | % |
2015 Term Loan Facility due October 2020 |
| 170 |
| 2.15 | % | 170 |
| 1.63 | % |
4.65% Unsecured Senior Notes due 2021 |
| 350 |
| 4.65 | %(b) | 350 |
| 4.65 | %(b) |
4.375% Unsecured Senior Notes due 2025 |
| 350 |
| 4.375 | %(b) | 350 |
| 4.375 | %(b) |
3.90 % Unsecured Senior Notes due 2027 |
| 500 |
| 3.90 | %(b) | — |
| — |
|
GTN |
|
|
|
|
|
|
|
|
|
5.29% Unsecured Senior Notes due 2020 |
| 100 |
| 5.29 | %(b) | 100 |
| 5.29 | %(b) |
5.69% Unsecured Senior Notes due 2035 |
| 150 |
| 5.69 | %(b) | 150 |
| 5.69 | %(b) |
Unsecured Term Loan Facility due 2019 |
| 55 |
| 1.95 | % | 65 |
| 1.43 | % |
PNGTS |
|
|
|
|
|
|
|
|
|
5.90% Senior Secured Notes due December 2018 |
| 36 |
| 5.90 | %(b) | 53 |
| 5.90 | %(b) |
Tuscarora |
|
|
|
|
|
|
|
|
|
Unsecured Term Loan due 2020 |
| 25 |
| 2.18 | % | 10 |
| 1.64 | % |
3.82% Series D Senior Notes due August 2017 |
| — |
| 3.82 | %(b) | 12 |
| 3.82 | %(b) |
|
| 2,491 |
|
|
| 1,920 |
|
|
|
Less: unamortized debt issuance costs and debt discount |
| 13 |
|
|
| 9 |
|
|
|
Less: current portion |
| 51 |
|
|
| 52 |
|
|
|
|
| 2,427 |
|
|
| 1,859 |
|
|
|
(unaudited) |
| June 30, |
| Weighted Average |
| December 31, |
| Weighted Average |
|
|
|
|
|
|
|
|
|
|
|
TC PipeLines, LP |
|
|
|
|
|
|
|
|
|
Senior Credit Facility due 2021 |
| 140 |
| 2.99 | % | 185 |
| 2.41 | % |
2013 Term Loan Facility due 2022 |
| 500 |
| 3.02 | % | 500 |
| 2.33 | % |
2015 Term Loan Facility due 2020 |
| 170 |
| 2.91 | % | 170 |
| 2.22 | % |
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 |
| 2.71 | % | 55 |
| 2.02 | % |
PNGTS |
|
|
|
|
|
|
|
|
|
Revolving Credit Facility due 2023 |
| — |
| — |
| — |
| — |
|
5.90% Senior Secured Notes due 2018 |
| — |
| — |
| 30 | (b) | 5.90 | %(a) |
Tuscarora |
|
|
|
|
|
|
|
|
|
Unsecured Term Loan due 2020 |
| 25 |
| 2.87 | % | 25 |
| 2.27 | % |
|
| 2,320 |
|
|
| 2,415 |
|
|
|
Less: unamortized debt issuance costs and debt discount |
| 12 |
|
|
| 12 |
|
|
|
Less: current portion |
| 36 |
|
|
| 51 | (b) |
|
|
|
| 2,272 |
|
|
| 2,352 |
|
|
|
(a) Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).
(b) Fixed interest rate
(b) Includes the PNGTS portion due at December 31, 2017 amounting to $5.8 million that was paid on January 2, 2018.
TC Pipelines,PipeLines, LP
The Partnership’s Senior Credit Facility consists of a $500 million senior revolving credit facility with a banking syndicate, maturing November 10, 2021, under which $255$140 million was outstanding at SeptemberJune 30, 20172018 (December 31, 20162017 - $160$185 million), leaving $245$360 million available for future borrowing. The LIBOR-based interest rate on the Senior Credit Facility was 2.493.24 percent at SeptemberJune 30, 20172018 (December 31, 20162017 — 1.922.62 percent).
On September 29, 2017, the Partnership’s 2013 Term Loan Facility that was due on July 1, 2018 was amended to extend the maturity period through October 2, 2022. As of SeptemberJune 30, 2017,2018, the variable interest rate exposure related to the 2013 Term Loan Facility was hedged by fixed interest rate swap arrangements and our effective interest rate was 2.31 percent (December 31, 20162017 — 2.31 percent). Prior to hedging activities, the LIBOR-based interest rate on the 2013 Term Loan Facility was 2.493.24 percent at SeptemberJune 30, 20172018 (December 31, 20162017 — 1.872.62 percent).
On September 29, 2017, the Partnership’s 2015 Term Loan Facility that was due on October 1, 2018 was amended to extend the maturity period through October 1, 2020. The LIBOR-based interest rate on the 2015 Term Loan Facility was 2.393.13 percent at SeptemberJune 30, 20172018 (December 31, 20162017 — 1.772.51 percent).
The 2013 Term Loan Facility and the 2015 Term Loan Facility (collectively, the Term Loan Facilities) and the Senior Credit Facility require the Partnership to maintain a certain leverage ratio (debt to adjusted cash flow [net income plus cash distributions received, extraordinary losses, interest expense, expense for taxes paid or accrued, and depreciation and amortization expense less equity earnings and extraordinary gains]) no greater than 5.00 to 1.00 for each fiscal quarter, except for the fiscal quarter and the two following fiscal quarters in which one or more acquisitions has been executed, in which case the leverage ratio is to be no greater than 5.50 to 1.00. The leverage ratio was 4.764.28 to 1.00 as of SeptemberJune 30, 2017.
On May 25, 2017, the Partnership closed a $500 million public offering of senior unsecured notes bearing an interest rate of 3.90 percent maturing May 25, 2027. The net proceeds of $497 million were used to fund a portion of the 2017 Acquisition (Refer to Note 6). The indenture for the notes contains customary investment grade covenants.
PNGTS
PNGTS’ Senior Secured Notes are secured by the PNGTS long-term firm shipper contracts and its partners’ pledge of their equity and a guarantee of debt service for six months. PNGTS is restricted under the terms of its note purchase agreement from making cash distributions unless certain conditions are met. Before a distribution can be made, the debt service reserve account must be fully funded and PNGTS’ debt service coverage ratio for the preceding and succeeding twelve months must be 1.30 or greater. At September 30, 2017, the debt service coverage ratio was 1.71 for the twelve
preceding months and 5.31 for the twelve succeeding months. Therefore, PNGTS was not restricted to make any cash distributions.2018.
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 SeptemberJune 30, 20172018 was 44.242.3 percent. The LIBOR-based interest rate on the GTN’s Unsecured Term Loan Facility was 2.192.93 percent at SeptemberJune 30, 20172018 (December 31, 20162017 — 1.572.31 percent).
PNGTS
On April 5, 2018, PNGTS entered into a revolving credit agreement under which PNGTS has the ability to borrow up to $125 million with a variable interest rate based on LIBOR (Revolving Credit Facility). The credit agreement matures on April 5, 2023 and requires PNGTS to maintain a leverage ratio not greater than 5.00 to 1.00. The facility will be utilized primarily to fund the costs of the PXP expansion project and to finance PNGTS’ other funding needs.
On May 10, 2018, PNGTS paid the remaining principal balance of its 5.90% Senior Secured Notes due 2018 (2003 Senior Secured Notes) using its available cash.
Tuscarora
On August 21, 2017, Tuscarora refinanced all of its outstanding debt by amending its existing Unsecured Term Loan Facility and issuing a new $25 million variable rate term loan that will require yearly principal payments and will mature on August 21, 2020. Tuscarora’s Unsecured Term Loan contains a covenant that requires Tuscarora to maintain a debt service coverage ratio (cash available from operations divided by a sum of interest expense and principal payments) of greater than or equal to 3.00 to 1.00. As of SeptemberJune 30, 2017,2018, the ratio was 3.0811.2 to 1.00.
The LIBOR-based interest rate on the Tuscarora’s Unsecured Term Loan Facility was 2.363.11 percent at SeptemberJune 30, 20172018 (December 31, 20162017 — 1.902.49 percent).
At SeptemberJune 30, 2017,2018, the Partnership was in compliance with its financial covenants, in addition to the other covenants which include restrictions on entering into mergers, consolidations and sales of assets, granting liens, material amendments to the Third Amended and Restated Agreement of Limited Partnership (Partnership Agreement), incurring additional debt and distributions to unitholders. Refer also to Note 19 for important information relating to a distribution reduction to retain cash that will be used to fund ongoing capital expenditures and the repayment of debt to levels that prudently manage our financial metrics in response to the impact of the 2018 FERC Actions on our future operating performance and cashflows.
The principal repayments required of the Partnership on its debt are as follows:
(unaudited) |
|
|
|
(millions of dollars) |
|
|
|
|
|
|
|
2017 |
| 12 |
|
2018 |
| 45 |
|
2019 |
| 36 |
|
2020 |
| 293 |
|
2021 |
| 605 |
|
Thereafter |
| 1,500 |
|
|
| 2,491 |
|
NOTE 6ACQUISITION
2017 Acquisition
On June 1, 2017, the Partnership acquired from subsidiaries of TransCanada a 49.34 percent interest in Iroquois, including an option to acquire a further 0.66 percent interest in Iroquois, together with an additional 11.81 percent interest in PNGTS resulting in the Partnership owning a 61.71 percent interest in PNGTS (2017 Acquisition). The total purchase price of the 2017 Acquisition was $765 million plus final purchase price adjustments amounting to $50 million. The purchase price consisted of (i) $710 million for the Iroquois interest (less $164 million, which reflected our 49.34 percent share of Iroquois outstanding debt on June 1, 2017), (ii) $55 million for the additional 11.81 percent interest in PNGTS (less $5 million, which reflected our 11.81% proportionate share in PNGTS’ outstanding debt on June 1, 2017) (iii) final working capital adjustments on PNGTS and Iroquois amounting to $3 million and $19 million, respectively and (iv) additional consideration for Iroquois’ surplus cash amounting to $28 million. Additionally, the Partnership paid $1,000 for the option to acquire TransCanada’s remaining 0.66 percent interest in Iroquois. The Partnership funded the cash portion of the 2017 Acquisition through a combination of proceeds from the May 2017 public debt offering (refer to Note 5) and borrowing under our Senior Credit Facility.
At the date of the 2017 Acquisition, there was significant cash on Iroquois’ balance sheet. Pursuant to the Purchase and Sale Agreement associated with the acquisition of the Iroquois interest, as amended, the Partnership agreed to pay $28 million plus interest to TransCanada on August 1, 2017 for its 49.34 percent share of cash determined to be surplus to Iroquois’ operating needs.
Additionally, Iroquois’ partners adopted a distribution resolution to address the significant cash on Iroquois’ balance sheet post-closing. The Partnership expects to receive the $28 million of unrestricted cash as part of its quarterly
(unaudited) |
|
|
|
(millions of dollars) |
|
|
|
|
|
|
|
2018 |
| 1 |
|
2019 |
| 36 |
|
2020 |
| 293 |
|
2021 |
| 490 |
|
2022 |
| 500 |
|
Thereafter |
| 1,000 |
|
|
| 2,320 |
|
distributions from Iroquois over 11 quarters under the terms of the resolution, which began with Iroquois’ second quarter 2017 distribution on August 1, 2017. As of November 6, 2017 the Partnership has received approximately $5.2 million of the expected $28 million, of which $2.6 million was received on November 1, 2017 (Refer to Note 19).
The acquisition of a 49.34 percent interest in Iroquois was accounted for as a transaction between entities under common control, whereby the equity investment in Iroquois was recorded at TransCanada’s carrying value and the total excess purchase price paid was recorded as a reduction in Partners’ Equity.
Iroquois’ net purchase price was allocated as follows:
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| ||
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| ||
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|
(a) Total purchase price of $710 million plus final working capital adjustment of $19 million and the additional consideration on Iroquois surplus cash amounting to approximately $28 million less the assumption of $164 million of proportional Iroquois debt by the Partnership.
(b) The excess purchase price of $370 million was recorded as a reduction in Partners’ Equity.
The acquisition of an additional 11.81 percent interest in PNGTS, which resulted in the Partnership owning 61.71 percent in PNGTS, was accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby assets and liabilities of PNGTS were recorded at TransCanada’s carrying value and the Partnership’s historical financial information, except net income per common unit, was recast to consolidate PNGTS for all periods presented.
The PNGTS purchase price was recorded as follows:
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(a) The excess purchase price of $21 million was recorded as a reduction in Partners’ Equity.
(b) Total purchase price of $55 million plus the final working capital adjustment of $3 million less the assumption of $5 million of proportional PNGTS debt by the Partnership.
NOTE 7 8PARTNERS’ EQUITY
ATM equity issuance program (ATM program)
During the ninesix months ended SeptemberJune 30, 2017,2018, we issued 2,165,1620.7 million common units under our ATM program (none during the three months ended June 30, 2018) generating net proceeds of approximately $124$39 million, plus $2$1 million contributed by the General Partner to maintain its effective two percent general partner interest. The commissions to our sales agents in the ninesix months ended SeptemberJune 30, 20172018 were approximately $1 million.nil. The net proceeds were used for general partnership purposes.
Class B units issued to TransCanada
The Class B Units we issued on April 1, 2015 to finance a portion of the 2015 GTN Acquisition represent a limited partner interest in us and entitle TransCanada to an annual distribution based on 30 percent of GTN’s annual
distributions as follows: (i) 100 percent of distributions above $20 million through March 31, 2020; and (ii) 25 percent of distributions above $20 million thereafter. Additionally, the Class B distribution will be further reduced by the percentage by which distributions payable to the common units is reduced for the calendar year (Class B Reduction).
For the year ending December 31, 2017,2018, the Class B units’ equity account will be increased by the excess of 30 percent of GTN’s distributions overless the annual threshold of $20 million and the Class B Reduction and until such amount is declared for distribution and paid in the first quarter of 2018.2019. During the ninesix months ended SeptemberJune 30, 2017, 30 percent of GTN’s total distributable cash flow2018, the threshold was $28 million. As a result of exceeding the $20 million threshold, the Class B units’ equity account was increased by $8 million (Refer to Note 8).not exceeded.
For the year ended December 31, 2016,2017, the Class B distribution was $22$15 million and was declared and paid in the first quarter of 2017.2018.
Common unit issuance subject to rescission
In connection with a late filing of an employee-related Form 8-K with the SEC in March 2016, the Partnership became ineligible to use the then effective shelf registration statement upon filing of its Annual Report on Form 10-K for the year ended December 31, 2015. As a result, it was determined that the purchasers of the 1.6 million common units that were issued from March 8, 2016 to May 19, 2016 under the Partnership’s ATM program may have had a rescission right for an amount equal to the purchase price paid for the units, plus statutory interest and less any distributions paid, upon the return of such units to the Partnership. The Securities Act of 1933, as amended (Securities Act) generally requires that any claim brought for a violation of Section 5 of the Securities Act be brought within one year of violation.
At December 31, 2016, $83 million was recorded as common units subject to rescission on the consolidated balance sheet. The Partnership classified the 1.6 million common units that were sold under its ATM program from March 8, 2016 up to and including May 19, 2016, which may have been subject to rescission rights, outside of equity given the potential redemption feature which was not within the control of the Partnership. These units were treated as outstanding for financial reporting purposes.
No unitholder claimed or attempted to exercise any rescission rights prior to their expiry dates and the final rights related to the sales of such units expired on May 19, 2017. As a result of the expiration of these rights, the $83 million was reclassified back to partners’ equity. At September 30, 2017, there were no outstanding common units subject to rescission on the Partnership’s consolidated balance sheet.
NOTE 8 9NET INCOME PER COMMON UNIT
Net income per common unit is computed by dividing net income attributable to controlling interests, after deduction of net income attributable to PNGTS’ former parent, amounts attributable to the General Partner and Class B units, by the weighted average number of common units outstanding.
The amountsamount allocable to the General Partner equals an amount based upon the General Partner’s effective two percent general partner interest, plus an amount equal to incentive distributions. Incentive distributions are paid to the General Partner if quarterly cash distributions on the common units exceed levels specified in the Partnership Agreement.
The amount allocable to the Class B units in 20172018 equals 30 percent of GTN’s distributable cash flow during the year ended December 31, 20172018 less $20 million and the Class B Reduction (December 31, 20162017 —$20 million). During the three and six months ended June 30, 2018 and 2017, 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:
|
| Three months ended |
| Nine months ended |
| ||||||||
(unaudited) |
|
|
| ||||||||||
(millions of dollars, except per common unit amounts) |
| 2017 |
| 2016 (a) |
| 2017 |
| 2016 (a) |
| ||||
|
|
|
|
|
|
|
|
|
| ||||
Net income attributable to controlling interests (a) |
| 54 |
| 58 |
| 186 |
| 188 |
| ||||
Net income attributable to PNGTS’ former parent (a) (b) |
| — |
| — |
| (2 | ) | (3 | ) | ||||
Net income attributable to General and Limited Partners |
| 54 |
| 58 |
| 184 |
| 185 |
| ||||
Incentive distributions allocated to the General Partner (c) |
| (3 | ) | (2 | ) | (9 | ) | (5 | ) | ||||
Net income attributable to the Class B units (d) |
| (8 | ) | (11 | ) | (8 | ) | (12 | ) | ||||
Net income attributable to the General Partner and common units |
| 43 |
| 45 |
| 167 |
| 168 |
| ||||
Net income attributable to General Partner’s effective two percent interest |
| (1 | ) | (2 | ) | (3 | ) | (4 | ) | ||||
Net income attributable to common units |
| 42 |
| 43 |
| 164 |
| 164 |
| ||||
Weighted average common units outstanding (millions) — basic and diluted |
| 69.4 |
| 66.1 | (e) | 68.9 |
| 65.3 | (e) | ||||
Net income per common unit — basic and diluted |
| $ | 0.61 |
| $ | 0.65 | (f) | $ | 2.38 |
| $ | 2.51 | (f) |
|
| Three months ended |
| Six months ended |
| ||||||||
(unaudited) |
| June 30, |
| June 30, |
| ||||||||
(millions of dollars, except per common unit amounts) |
| 2018 |
| 2017 |
| 2018 |
| 2017 |
| ||||
|
|
|
|
|
|
|
|
|
| ||||
Net income attributable to controlling interests |
| 73 |
| 55 |
| 169 |
| 132 |
| ||||
Net income attributable to PNGTS’ former parent (a) |
| — |
| — |
| — |
| (2 | ) | ||||
Net income attributable to General and Limited Partners |
| 73 |
| 55 |
| 169 |
| 130 |
| ||||
Incentive distributions allocated to the General Partner (b) |
| — |
| (3 | ) | — |
| (5 | ) | ||||
Net income attributable to the General Partner and common units |
| 73 |
| 52 |
| 169 |
| 125 |
| ||||
Net income attributable to General Partner’s two percent interest |
| (1 | ) | (2 | ) | (3 | ) | (3 | ) | ||||
Net income attributable to common units |
| 72 |
| 50 |
| 166 |
| 122 |
| ||||
Weighted average common units outstanding (millions) – basic and diluted |
| 71.3 |
| 68.9 |
| 71.2 |
| 68.6 |
| ||||
Net income per common unit – basic and diluted |
| $ | 1.00 |
| $ | 0.73 |
| $ | 2.33 |
| $ | 1.78 |
|
(a) Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).
(b) Net income allocable to General and Limited Partners excludes net income attributed to PNGTS’ former parent as it was allocated to TransCanada and was not allocable to either the general partner, common units or Class B units.
(c)(b) Under the terms of the Partnership Agreement, for any quarterly period, the participation of the incentive distribution rights (IDRs) is limited to the available cash distributions declared. Accordingly, incentive distributions allocated to the General Partner are based on the Partnership’s available cash during the current reporting period, but declared and paid in the subsequent reporting period.
(d) During the three and nine months ended September 30, 2017, 30 percent of GTN’s total distributable cash flow was $28 million. As a result of exceeding the $20 million threshold, $8 million of net income attributable to controlling interests was allocated to the Class B units during the three and nine months ended September 30, 2017. During the six months ended June 30, 2016, the threshold was exceeded and during the nine months ended September 30, 2016, 30 percent of GTN’s total distributable cash flow was $32 million. As a result, $12 million of net income attributable to controlling interests was allocated to the Class B units at September 30, 2016, of which $1 million and $11 million were allocated during the three months ended June 30, 2016 and September 30, 2016, respectively (Refer to Note 7).
(e) Includes the common units subject to rescission. These units are treated as outstanding for financial reporting purposes (Refer to Note 7).
(f) Net income per common unit prior to recast (Refer to Note 2).
NOTE 910 CASH DISTRIBUTIONS
During the three and ninesix months ended SeptemberJune 30, 2017,2018, the Partnership distributed $1.00$0.65 and $2.88$1.65 per common unit, respectively, (September(June 30, 20162017 — $0.94 and $2.72$1.88 per common unit)unit, respectively) for a total of $74$47 million and $210$123 million, respectively, (September(June 30, 20162017 - $65$68 million and $184 million)$135 million, respectively).
The distribution paid to our General Partner during the three months ended SeptemberJune 30, 20172018 for its effective two percent general partner interest was $2$1 million along with an IDR payment of $3 million for a total distribution of $5 million (September(June 30, 20162017 - $1 million for the effective two percent interest and a $2 million IDR payment). The General Partner did not receive any distributions in respect of its IDRs in the second quarter 2018.
The distribution paid to our General Partner during the ninesix months ended SeptemberJune 30, 20172018 for its effective two percent general partner interest was $4$3 million along with an IDR payment of $7$3 million for a total distribution of $11$6 million (September(June 30, 20162017 - $3$2 million for the effective two percent interest and a $4 million IDR payment).
NOTE 1011 CHANGE IN OPERATING WORKING CAPITAL
(unaudited) |
| Nine months ended September 30, |
|
| Six months ended June 30, |
| ||||
(millions of dollars) |
| 2017 |
| 2016 (a) |
|
| 2018 |
| 2017 |
|
|
|
|
|
|
|
|
|
|
|
|
Change in accounts receivable and other |
| 13 |
| 3 |
|
| 2 |
| 11 |
|
Change in other current assets |
| 1 |
| 2 |
|
| (1 | ) | 2 |
|
Change in accounts payable and accrued liabilities |
| 2 |
| 3 |
|
| (6 | ) | (5 | ) |
Change in accounts payable to affiliates |
| (3 | ) | (2 | ) |
| — |
| (2 | ) |
Change in accrued interest |
| 11 |
| 5 |
|
| — |
| 1 |
|
Change in operating working capital |
| 24 |
| 11 |
|
| (5 | ) | 7 |
|
(a) RecastExcludes certain non-cash items primarily related to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).
(b) The accrual of $10 million for the construction of GTN’s Carty Lateral in December 31, 2015 was paid during the first quarter 2016. Accordingly, the payment was reported as capital expenditures in our 2016 cash flow statement.accruals.
NOTE 1112 RELATED PARTY TRANSACTIONS
The Partnership does not have any employees. The management and operating functions are provided by the General Partner. The General Partner does not receive a management fee in connection with its management of the Partnership. The Partnership reimburses the General Partner for all costs of services provided, including the costs of employee, officer and director compensation and benefits, and all other expenses necessary or appropriate to the conduct of the business
of, and allocable to, the Partnership. Such costs include (i) overhead costs (such as office space and equipment) and (ii) out-of-pocket expenses related to the provision of such services. The Partnership Agreement provides that the General Partner will determine the costs that are allocable to the Partnership in any reasonable manner determined by the General Partner in its sole discretion. For both the three and ninesix months ended SeptemberJune 30, 20172018 and 2016,2017, total costs charged to the Partnership by the General Partner were $1 million and $3$2 million, respectively.
As operator of our pipelines except Iroquois, TransCanada’s subsidiaries provide capital and operating services to our pipeline systems. TransCanada’s subsidiaries incur costs on behalf of our pipeline systems, including, but not limited to, employee salary and benefit costs, and property and liability insurance costs. The Iroquois pipeline system is operated by Iroquois Pipeline Operating Company, a wholly owned subsidiary of Iroquois. Therefore, Iroquois does not receive any capital and operating services from TransCanada.
Capital and operating costs charged to our pipeline systems, except for Iroquois, for the three and ninesix months ended SeptemberJune 30, 20172018 and 20162017 by TransCanada’s subsidiaries and amounts payable to TransCanada’s subsidiaries at SeptemberJune 30, 20172018 and December 31, 20162017 are summarized in the following tables:
|
| Three months ended |
| Nine months ended |
| ||||
(unaudited) |
|
|
| ||||||
(millions of dollars) |
| 2017 |
| 2016 |
| 2017 |
| 2016 |
|
|
|
|
|
|
|
|
|
|
|
Capital and operating costs charged by TransCanada’s subsidiaries to: |
|
|
|
|
|
|
|
|
|
Great Lakes (a) |
| 10 |
| 8 |
| 27 |
| 22 |
|
Northern Border (a) |
| 10 |
| 9 |
| 30 |
| 25 |
|
GTN |
| 9 |
| 8 |
| 24 |
| 20 |
|
Bison |
| 2 |
| 1 |
| 4 |
| 1 |
|
North Baja |
| 1 |
| 1 |
| 3 |
| 3 |
|
Tuscarora |
| 1 |
| 1 |
| 3 |
| 3 |
|
PNGTS |
| 2 |
| 2 |
| 6 |
| 6 |
|
Impact on the Partnership’s net income: |
|
|
|
|
|
|
|
|
|
Great Lakes (a) |
| 4 |
| 3 |
| 11 |
| 9 |
|
Northern Border (a) |
| 4 |
| 3 |
| 11 |
| 9 |
|
GTN |
| 7 |
| 7 |
| 21 |
| 18 |
|
Bison |
| 2 |
| 1 |
| 4 |
| 2 |
|
North Baja |
| 1 |
| 1 |
| 3 |
| 3 |
|
Tuscarora |
| 1 |
| 1 |
| 3 |
| 3 |
|
PNGTS (b) |
| 1 |
| 1 |
| 4 |
| 3 |
|
|
| Three months ended |
| Six months ended |
| |||||||||
(unaudited) |
| September 30, |
|
|
|
| June 30, |
| June 30, |
| ||||
(millions of dollars) |
| 2017 |
| December 31, 2016 |
|
| 2018 |
| 2017 |
| 2018 |
| 2017 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net amounts payable to TransCanada’s subsidiaries is as follows: |
|
|
|
|
| |||||||||
Capital and operating costs charged by TransCanada’s subsidiaries to: |
|
|
|
|
|
|
|
|
| |||||
Great Lakes (a) |
| 3 |
| 4 |
|
| 16 |
| 9 |
| 24 |
| 17 |
|
Northern Border (a) |
| 3 |
| 4 |
|
| 9 |
| 10 |
| 18 |
| 20 |
|
GTN |
| 3 |
| 3 |
|
| 8 |
| 9 |
| 16 |
| 16 |
|
Bison |
| 1 |
| 1 |
|
| 1 |
| 1 |
| 3 |
| 2 |
|
North Baja |
| — |
| 1 |
|
| 1 |
| 1 |
| 2 |
| 2 |
|
Tuscarora |
| — |
| 1 |
|
| 1 |
| 1 |
| 2 |
| 2 |
|
PNGTS |
| 1 |
| 1 |
|
| 2 |
| 2 |
| 4 |
| 4 |
|
Impact on the Partnership’s net income: |
|
|
|
|
|
|
|
|
| |||||
Great Lakes (a) |
| 7 |
| 4 |
| 11 |
| 7 |
| |||||
Northern Border (a) |
| 4 |
| 4 |
| 8 |
| 7 |
| |||||
GTN |
| 7 |
| 7 |
| 14 |
| 14 |
| |||||
Bison |
| 1 |
| 1 |
| 3 |
| 2 |
| |||||
North Baja |
| 1 |
| 1 |
| 2 |
| 2 |
| |||||
Tuscarora |
| 1 |
| 1 |
| 2 |
| 2 |
| |||||
PNGTS |
| 1 |
| 1 |
| 2 |
| 2 |
|
(unaudited) |
|
|
|
|
|
(millions of dollars) |
| June 30, 2018 |
| December 31, 2017 |
|
|
|
|
|
|
|
Net amounts payable to TransCanada’s subsidiaries is as follows: |
|
|
|
|
|
Great Lakes (a) (b) |
| 3 |
| 3 |
|
Northern Border (a) |
| 3 |
| 4 |
|
GTN |
| 3 |
| 3 |
|
Bison |
| 1 |
| 1 |
|
North Baja |
| — |
| — |
|
Tuscarora |
| — |
| — |
|
PNGTS(a) |
| 1 |
| 1 |
|
(a) Represents 100 percent of the costs.
(b) RecastExcludes any amounts owed to consolidate PNGTS for all periods presented (Referaffiliates relating to Note 2).revenue sharing. See discussion below.
Great Lakes
Great Lakes earns significant transportation revenues from TransCanada and its affiliates, some of which are provided at discounted rates and some at maximum recourse rates. For the three and ninesix months ended SeptemberJune 30, 2017,2018, Great
Lakes earned 4472 percent and 5370 percent, respectively, of transportation revenues from TransCanada and its affiliates respectively (September 30, 2016(2017 — 6243 percent and 69 percent)57 percent, respectively).
At SeptemberJune 30, 2017, $82018, $3 million was included in Great Lakes’ receivables in regards to the transportation contracts with TransCanada and its affiliates (December 31, 20162017 — $19$20 million).
During 2017, Great Lakes operatesoperated under a FERC approved 2013 rate settlement that includesincluded a revenue sharing mechanism that requiresrequired Great Lakes to share with its shipperscustomers certain percentages of any qualifying revenues earned above a certain return on equity threshold.ROEs. For the year ended December 31, 2016, Great Lakes recorded an estimated 2016 revenue sharing provision of $7.2 million. For the three and nine months ended September 30, 2017, Great Lakes recorded an estimated 2017 revenue sharing provision amounting to $40 million. During the second quarter of $12 million2018, the refund was settled with its customers and $22 million, respectively.a significant portion of the refund was with its affiliates. Under the terms of the 2017 Great Lakes expects thatSettlement, beginning in 2018, its revenue sharing provision was eliminated (Refer to our Annual Report on Form 10-K for the year ended December 31, 2017).
During the second quarter of 2018, Great Lakes reached an agreement on the terms of a significant percentagenew long-term transportation capacity contracts with its affiliate, ANR Pipeline Company (ANR). The contracts are for a term of this refund will be paid15 years from November 2021 to its affiliates.October 31, 2036 with a total contract value of approximately $1.3 billion. The contracts contain reduction options (i) at anytime on or before April 1, 2019 for any reason and (ii) anytime before April 2021, if ANR is not able to secure the required regulatory approval related to anticipated expansion projects.
PNGTS
PNGTS earns transportation revenues from TransCanada and its affiliates. For both three and ninesix months ended SeptemberJune 30, 2017,2018, PNGTS earned approximately nil million and $1 million of its transportation revenues from TransCanada and its affiliates respectively (2016(2017 — $1 million and $2 million, respectively)nil).
At SeptemberJune 30, 2017,2018, nil million was included in PNGTS’ receivables in regards to the transportation contracts with TransCanada and its affiliates (December 31, 20162017 — 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 SeptemberJune 30, 2017, PNGTS does not have an obligation for reimbursement under this arrangement.2018, the total costs incurred by these affiliates was approximately $15 million.
NOTE 1213 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.
Long-term debt is recorded at amortized cost and classified inas Level 2 of the fair value hierarchy for fair value disclosure purposes. Interest rate derivative assets and liabilities are classified inas 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 SeptemberJune 30, 20172018 and December 31, 20162017 was $2,555$2,311 million and $1,962$2,475 million, respectively.
Market risk is the risk that changes in market interest rates may result in fluctuations in the fair values or cash flows of financial instruments. The Partnership’s floating rate debt is subject to LIBOR benchmark interest rate risk. The Partnership uses interest rate derivatives to manage its exposure to interest rate risk. We regularly assess the impact of interest rate fluctuations on future cash flows and evaluate hedging opportunities to mitigate our interest rate risk.
The Partnership’s interest rate swaps are structured such that the cash flows of the derivative instruments match those of the variable rate of interest on the 2013 Term Loan Facility. The Partnership hedged interest payments on the variable-rate 2013 Term Loan Facility with interest rate swaps maturing July 1, 2018, at a weighted average fixed interest rate of 2.31 percent. At SeptemberJune 30, 2018, the fair value of the interest rate swaps accounted for as cash flow hedges was an asset of $15 million (both on a gross and net basis). At December 31, 2017, the fair value of the interest rate swaps accounted for as cash flow hedges was an asset of $2$5 million (both on a(on both gross and net basis). At December 31, 2016, the fair value of the interest rate swaps accounted for as cash flow hedges was an asset of $1 million and a liability of $1 million (on a gross basis) and an asset of nil million (on a net basis). The Partnership did not record any amounts in net income related to ineffectiveness for interest rate hedges for the three and nine months ended September 30, 2017 and 2016. The change in fair value of interest rate derivative instruments recognized in other comprehensive income was nila loss of $1 million and a gain of $1$6 million for the three and ninesix months ended SeptemberJune 30, 2017,2018, respectively (September 30, 2016(2017 — nil and gain of $2$1 million). During the three and six months ended June 30, 2018, gain of $3 million and awas reclassified from other comprehensive income to net income (2017 — loss of $1 million). For the three and ninesix months ended SeptemberJune 30, 2017,2018, the net realized lossgain related to the interest rate swaps was nil,$1 million and $2 million, respectively, and was included in financial charges and other (September 30, 2016 —$1 million and $2 million)(2017 - nil) (Refer to Note 14) 15).
As discussed in Note 5, theThe Partnership’s $500 million 2013 Term Loan that was dueis hedged using fixed interest rate swaps until July 1, 2018 was amended to extendat an average rate of 2.31 percent. During the maturity period through October 2, 2022. At September 30,fourth quarter of 2017, the entire $500 million 2013 Term Loan was hedged until July 1, 2018. As a result of this extension, the Partnership implemented an interest rate hedging strategy during the fourth quarter andthat hedged the entire $500 million 2013 Term Loan until its October 2, 2022 maturity using forward starting swaps at an average rate of 3.26 percent.
The Partnership has no master netting agreements; however, it has derivative contracts containing provisions with rights of offset. The Partnership has elected to present the fair value of derivative instruments with the right to offset on a gross basis in the balance sheet. Had the Partnership elected to present these instruments on a net basis, there would be no effect on the consolidated balance sheet as of SeptemberJune 30, 20172018 (net asset of nil$5 million as of December 31, 2016)2017).
In anticipation of a debt refinancing in 2003, PNGTS entered into forward interest rate swap agreements to hedge the interest rate on its Senior Secured Notes due in 2018. These interest rate swaps were used to manage the impact of interest rate fluctuations and qualified as derivative financial instruments in accordance with ASCAccounting Standards Codification (ASC) 815, Derivatives and Hedging. PNGTS settled its position with a payment of $20.9 million to counterparties at the time of the refinancing and recorded the realized loss in accumulated other comprehensive income as of the termination date. The previously recorded loss is currently beingwas amortized against earnings over the life of the PNGTS Senior Secured Notes. At September 30, 2017, On May 10, 2018, PNGTS paid the remaining principal balance of its 2003 Senior Secured Notes using its available cash and, as a result, our 61.71 percent proportionate share of the net unamortized loss on PNGTS included in other comprehensive income was $1 millionall amortized against earnings (December 31, 20162017 - $2$1 million). For the three and ninesix months ended SeptemberJune 30, 2017,2018, our 61.71 percent proportionate share of the amortization of realized loss on derivative instruments was nil and $1 million respectively (September 30, 2016 —nil and(2017 - $1 million).
NOTE 1314 ACCOUNTS RECEIVABLE AND OTHER
(unaudited) |
|
|
|
|
|
|
|
|
|
|
(millions of dollars) |
| September 30, 2017 |
| December 31, 2016 (a) |
|
| June 30, 2018 |
| December 31, 2017 |
|
|
|
|
|
|
|
|
|
|
|
|
Trade accounts receivable, net of allowance of nil |
| 34 |
| 44 |
|
| 37 |
| 40 |
|
Imbalance receivable from affiliates |
| — |
| 2 |
|
| 1 |
| 1 |
|
Other |
| 1 |
| 1 |
|
| 2 |
| 1 |
|
|
| 35 |
| 47 |
|
| 40 |
| 42 |
|
(a) Recast as discussed in Notes 2 and 6.
NOTE 1415 FINANCIAL CHARGES AND OTHER
|
| Three months ended |
| Nine months ended |
| ||||
(unaudited) |
|
|
| ||||||
(millions of dollars) |
| 2017 |
| 2016(b) |
| 2017 |
| 2016(b) |
|
|
|
|
|
|
|
|
|
|
|
Interest expense (a) |
| 23 |
| 17 |
| 59 |
| 52 |
|
PNGTS’ amortization of derivative loss on derivative instruments (Note 12) (b) |
| — |
| — |
| 1 |
| 1 |
|
Net realized loss related to the interest rate swaps |
| — |
| 1 |
| — |
| 2 |
|
Other income |
| — |
| — |
| (1 | ) | (2 | ) |
|
| 23 |
| 18 |
| 59 |
| 53 |
|
|
| Three months ended |
| Six months ended |
| ||||
(unaudited) |
| June 30, |
| June 30, |
| ||||
(millions of dollars) |
| 2018 |
| 2017 |
| 2018 |
| 2017 |
|
|
|
|
|
|
|
|
|
|
|
Interest Expense (a) |
| 24 |
| 19 |
| 48 |
| 36 |
|
PNGTS’ amortization of loss on derivative instruments (Note 13) |
| 2 |
| 1 |
| 2 |
| 1 |
|
Net realized gain related to the interest rate swaps |
| (1 | ) | — |
| (2 | ) | — |
|
Other Income |
| (2 | ) | (1 | ) | (2 | ) | (1 | ) |
|
| 23 |
| 19 |
| 46 |
| 36 |
|
(a) Includes amortization of debt issuance costs and discount costs.
(b) Recast to consolidate PNGTS for all periods presented (Refer to Note 2).
NOTE 1516 CONTINGENCIESCONTINGENCIES
Great Lakes v. Essar Steel Minnesota LLC, et al. — On October 29, 2009, Great Lakes filed suit in the U.S. District Court, District of Minnesota, against Essar Minnesota LLC (Essar Minnesota) and certain Foreign Essar Affiliates (collectively, Essar) for breach of its monthly payment obligation under its transportation services agreement with Great Lakes. Great Lakes sought to recover approximately $33 million for past and future payments due under the agreement. OnIn September 16, 2015, following a jury trial, the federal district court judge entered a judgment in the amount of $32.9 million in favor of Great Lakes. On September 20, 2015, Essar successfully appealed thethis decision to the United States Court of Appeals for the Eighth Circuit (Eighth Circuit) based on an allegation of improper jurisdiction and a number ofvarious other rulings by the federal district judge. Essar was required to post a performance bond for the full value of the judgment pending appeal. The Eighth Circuit heard the appeal on October 20, 2016. A decision on the appeal was received in December 2016 and the Eighth Circuit vacated Great Lakes’ judgment against Essar finding that there was no federal jurisdiction. Great Lakes filed a Request for Rehearing with the Eighth Circuit and it was denied in January 2017. Before the Circuit Court issued its decision, Essar Minnesota filed for bankruptcy in July 2016. The Foreign Essar Affiliates have not filed for bankruptcy. Following the Circuit Court’s decision, the performance bond was released into the bankruptcy court proceedings. Great Lakes filed a claim against Essar Minnesota in the bankruptcy court and its case against the Foreign Essar Affiliates in Minnesota state court remains pending. In April 2017, after Great Lakes agreement with creditors on an allowed claim, the bankruptcy court approved Great Lakes’ claim in the amount of $31.5 million. On May 20, 2017, the federal district court awarded Essar Minnesota approximately $1.2 million for costs, including recovery of the premium for the performance bond premium,Essar was required to be paid bypost pending appeal.
Essar Minnesota filed for bankruptcy in July 2016. Following Essar’s successful appeal and award of $1.2 million of costs, Great Lakes.Lakes was required to release the $1.2 million into the bankruptcy estates. Great Lakes filed a motion with the bankruptcy court to offset the $1.2 million award of costs against its claim against Essar Minnesota in the bankruptcy proceeding. Ifcourt. The bankruptcy court approved Great Lakes’ motion to offset the federal district court’s award of costs is against itsunsecured claim in the bankruptcy proceeding is not successful, Great Lakes will be responsible to the bankruptcy estate for paymentamount of the award.$31.5 million in April 2017. Great Lakes is unable to estimate the timing or the extent to which its claim will be recoverable in the bankruptcy proceedings.
NOTE 16REGULATORYThe Foreign Essar Affiliates have not filed for bankruptcy and Great Lakes’ case against the Foreign Essar Affiliates in Minnesota state court remains pending. The Foreign Essar Affiliates gave an offer of judgment (Offer of Judgment) in the federal district court proceeding whereby the Foreign Essar Affiliates agreed to satisfy any judgment awarded to Great Lakes. The Foreign Essar Affiliates dispute that the Offer of Judgment is enforceable because the federal court judgment was vacated on appeal. Great Lakes has obtained a consent order from the bankruptcy court permitting it to petition the state court to enforce the Offer of Judgment. If unsuccessful in state court, Great Lakes can return to bankruptcy court for an order permitting it to proceed to trial in state court on its claims under the transportation services agreement against the Foreign Essar Affiliates.
North Baja —On January 6, 2017, North Baja notified FERC that current market conditions doAt June 30, 2018, Great Lakes is unable to estimate the timing or the extent to which its claim will be recoverable in the bankruptcy proceedings, therefore, it did not support the replacement of the compression that was temporarily abandoned in 2013 and requested authorization to permanently abandon two compressor units and a nominal volume of unsubscribed firm capacity. FERC approved the permanent abandonment requestrecognize any gain contingency on February 16, 2017. The abandonments will not have any impact on existing firm transportation service.its outstanding claim against Essar.
Great Lakes - On April 24, 2017, Great Lakes reached an agreement onAdditionally, at June 30, 2018, the termsPartnership is not aware of a new long-term transportation capacity contract with its affiliate, TransCanada. The contract, which was subject to Canada’s National Energy Board (NEB) approval, is for a term of 10 years and allows TransCanada the ability to transport up to 0.711 billion cubic feet of natural gas per day on the Great Lakes system from the Manitoba/U.S. border to the U.S. border near Dawn Ontario. On September 21, 2017, TransCanada received approval from the NEB and as a result, this contract commenced on November 1, 2017. This contract contains volume reduction options up to full contract quantity beginning in year three.
On October 30, 2017, Great Lakes filed a rate settlement with FERC to satisfy its obligations from its 2013 rate settlement for new rates to be in effect by January 1, 2018 (2017 Great Lakes Settlement). The 2017 Great Lakes Settlement, if approved by FERC, will decrease Great Lakes’ maximum transportation rates by 27 percent beginning October 1, 2017. Great Lakes expectsany contingent liabilities that the impact from other changes, including: the recent long-term transportation contract with TransCanada as described above, other revenue opportunities on the system and the elimination of the revenue sharing mechanism with its customers, will more than offset the full year impact of the reduction in Great Lakes’ rates beginning in 2018. The 2017 Great Lakes Settlement does not contain any moratorium and Great Lakes will be required to file for new rates no later than March 31, 2022, with new rates to be effective October 1, 2022.
Northern Border- Northern Border and its shippers have been engaged in settlement discussions, and have recently agreed to a settlement-in-principle addressing all rate and service related issues raised during the settlement discussions. Northern Border plans to file a settlement agreement with FERC before the end of the year, reflecting the settlement-in-principle, precluding the need to file a general rate case as contemplated by its 2012 Settlement. Northern Border anticipates that the Commission will accept the settlement agreement and that it will be unopposed. This will provide Northern Border with rate stability over the longer term. At this time, we do not believe that the final outcome of the settlement willwould have a material impact toadverse effect on the Partnership’s results. Northern Border remains a key competitive pipeline and continues to operate at full capacity connecting major supply basins with communities in Midwestern U.S.financial condition, results of operations or cash flows.
NOTE 17 VARIABLE INTEREST ENTITIES
In the normal course of business, the Partnership must re-evaluate its legal entities under the current consolidation guidance to determine if those that are considered to be VIEs are appropriately consolidated or if they should be accounted for under other GAAP. A variable interest entity (VIE) is a legal entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support or is structured such that equity investors lack the ability to make significant decisions relating to the entity’s operations through voting rights or do not substantively participate in the gains or losses of the entity. A VIE is appropriately consolidated if the Partnership is considered to be the primary beneficiary. The VIE’s primary beneficiary is the entity that has both (1) the power to direct the activities of the VIE that most significantly impact the VIEs economic performance and (2) the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE.
As a result of its analysis, the Partnership continues to consolidate all legal entities in which it has a variable interest and for which it is considered to be the primary beneficiary. VIEs where the Partnership is not the primary beneficiary, but has a variable interest in the entity, are accounted for as equity investments.
Consolidated VIEs
The Partnership’s consolidated VIEs consist of the Partnership’s ILPs that hold interests in the Partnership’s pipeline systems. After considering the purpose and design of the ILPs and the risks that they were designed to create and pass through to the Partnership, the Partnership has concluded that it is the primary beneficiary of these ILPs because of the significant amount of variability that it absorbs from the ILPs’ economic performance.
The assets and liabilities held through these VIEs that are not available to creditors of the Partnership and whose investors have no recourse to the credit of the Partnership are held through GTN, Tuscarora, Northern Border, Great
Lakes, PNGTS and Iroquois due to their third party debt. The following table presents the total assets and liabilities of these entities that are included in the Partnership’s consolidated balance sheets:
(unaudited) |
|
|
|
|
|
|
|
|
|
|
(millions of dollars) |
| September 30, 2017 |
| December 31, 2016(a) |
|
| June 30, 2018 |
| December 31, 2017 |
|
|
|
|
|
|
|
|
|
|
|
|
ASSETS (LIABILITIES) * |
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
| 19 |
| 14 |
|
| 7 |
| 19 |
|
Accounts receivable and other |
| 23 |
| 33 |
|
| 27 |
| 30 |
|
Inventories |
| 6 |
| 6 |
|
| 7 |
| 6 |
|
Other current assets |
| 4 |
| 6 |
|
| 6 |
| 5 |
|
Equity investments |
| 1,207 |
| 918 |
|
| 1,211 |
| 1,213 |
|
Plant, property and equipment |
| 1,132 |
| 1,146 |
| |||||
Plant, property and equipment, net |
| 1,117 |
| 1,133 |
| |||||
Other assets |
| 1 |
| 2 |
|
| 2 |
| 1 |
|
Accounts payable and accrued liabilities |
| (21 | ) | (21 | ) |
| (18 | ) | (24 | ) |
Accounts payable to affiliates, net |
| (25 | ) | (32 | ) |
| (44 | ) | (42 | ) |
Distributions payable |
| — |
| (3 | ) |
| — |
| (1 | ) |
Other taxes payable |
| (1 | ) | — |
| |||||
Accrued interest |
| (5 | ) | (2 | ) |
| (3 | ) | (2 | ) |
Current portion of long-term debt |
| (51 | ) | (52 | ) |
| (36 | ) | (51 | ) |
Long-term debt |
| (314 | ) | (337 | ) |
| (273 | ) | (308 | ) |
Other liabilities |
| (26 | ) | (25 | ) |
| (27 | ) | (26 | ) |
Deferred state income tax |
| (10 | ) | (10 | ) |
| (10 | ) | (10 | ) |
*North Baja and Bison, which are also assets held through our consolidated VIEs, are excluded as the assets of these entities can be used for purposes other than the settlement of the VIE’s obligations.
(a) Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).
NOTE 18 INCOME TAXES
The Partnership’s income taxes relate to business profits tax (BPT) levied at the partnership (PNGTS) level by the state of New Hampshire. As a result of the BPT, PNGTS recognizes deferred taxes related to temporary differences between the financial statement carrying amount of existing assets and liabilities and their respective tax bases. The deferred taxes at SeptemberJune 30, 20172018 and December 31, 20162017 relate primarily to utility plant. At SeptemberJune 30, 20172018 and December 31, 20162017 the New Hampshire BPT effective tax rate was 3.8 percent for both periods and was applied to PNGTS’ taxable income.
|
| Three months ended |
| Nine months ended |
| ||||
(unaudited) |
|
|
| ||||||
(millions of dollars) |
| 2017 |
| 2016(a) |
| 2017 |
| 2016(a) |
|
|
|
|
|
|
|
|
|
|
|
State income taxes |
|
|
|
|
|
|
|
|
|
Current |
| — |
| (7 | ) | 1 |
| 1 |
|
Deferred |
| — |
| 7 |
| — |
| — |
|
|
| — |
| — |
| 1 |
| 1 |
|
(a) Recast to consolidate PNGTS for all periods presented (Refer to Note 2 and 6).
|
| Three months ended |
| Six months ended |
| ||||
(unaudited) |
| June 30, |
| June 30, |
| ||||
(millions of dollars) |
| 2018 |
| 2017 |
| 2018 |
| 2017 |
|
|
|
|
|
|
|
|
|
|
|
State income taxes |
|
|
|
|
|
|
|
|
|
Current |
| — |
| — |
| 1 |
| 1 |
|
Deferred |
| — |
| — |
| — |
| — |
|
|
| — |
| — |
| 1 |
| 1 |
|
NOTE 19 SUBSEQUENT EVENTS
Management of the Partnership has reviewed subsequent events through November 6, 2017,August 2, 2018, the date the financial statements were issued, and concluded there were no events or transactions during this period that would require recognition or disclosure in the consolidated financial statements other than what is disclosed here and/or those already disclosed in the preceding notes.
On October 24, 2017,July 26, 2018, the board of directors of the General Partner declared the Partnership’s thirdsecond quarter 20172018 cash distribution in the amount of $1.00$0.65 per common unit payable on November 14, 2017August 15, 2018 to unitholders of record as of November 3, 2017.August 6, 2018. The declared distribution totaled $75$47 million and is payable in the following manner: $70$46 million to common unitholders (including $6$4 million to the General Partner as a holder of 5,797,106 common units and $11$7 million to another subsidiary of TransCanada as holder of 11,287,725 common units) and $5$1 million to the General Partner which included $2 million for its effective two percent general partner interest and $3 millioninterest. The General Partner did not receive any distributions in respect of its IDRs.IDRs for the second quarter 2018. This distribution and our first quarter 2018 distribution each represent a 35 percent reduction compared to the Partnership’s fourth quarter 2017 distribution of $1.00 per common unit. Cash retained by the Partnership will be used to fund ongoing capital expenditures and the repayment of debt to levels that prudently manage our financial metrics in response to the impact of the 2018 FERC Actions on our future operating performance and cash flows.
Northern Border declared its September 2017June 2018 distribution of $14$12 million on October 9, 2017,July 11, 2018, of which the Partnership will receivereceived its 50 percent share or $7$6 million on OctoberJuly 31, 2017.2018.
Great Lakes declared its thirdsecond quarter 20172018 distribution of $2$29 million on October 19, 2017, of which the Partnership will receive its 46.45 percent share or $1 million on November 1, 2017.
Iroquois declared its third quarter 2017 distribution of $28 million on October 23, 2017,July 17, 2018, of which the Partnership received its 49.3446.45 percent share or $14$13 million on NovemberAugust 1, 2017. The2018.
PNGTS declared its second quarter 2018 distribution includes our 49.34 percent share of the Iroquois unrestricted cash distribution amounting$3 million on July 20, 2018, of which $1 million will be paid to approximately $2.6 million (Refer to Note 6).its non-controlling interest owner on August 1, 2018.
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis should be read in conjunction with the unaudited financial statements and notes included in Item 1.1 “Financial Statements” of this Quarterly Report on Form 10-Q, as well as our Annual Report on Form 10-K for the year ended December 31, 2016, in which certain parts of the report were amended through the Partnership’s filing of Current Report on Form 8-K dated August 3, 2017 to give retrospective adjustments to include the results of operations and financial position of PNGTS for all periods presented (Refer to Notes 2 and 6 within Item 1. “Financial Statements” of this Quarterly Report on Form 10-Q).2017.
RECENT BUSINESS DEVELOPMENTS
In December 2016, FERC issued Docket No. PL17-1-000 requesting initial comments regarding how to address any “double recovery” resulting from FERC’s current income tax allowance and rate of return policies that had been in effect since 2005.
Docket No. PL17-1-000 is a direct response to Cash Distributions —United Airlines, Inc., et al. v. FERC, a decision issued by the U.S. Court of Appeals for the District of Columbia Circuit in July 2016 in which the D.C. Circuit directed FERC to explain how a pass-through entity such as an MLP receiving a tax allowance and a return on equity derived from the DCF methodology did not result in “double recovery” of taxes.
On April 25,December 22, 2017, the boardPresident of directorsthe United States signed into law the 2017 Tax Act. This legislation provides for major changes to U.S. corporate federal tax law including a reduction of the federal corporate income tax rate. We are a non-taxable limited partnership for federal income tax purposes, and federal income taxes owed as a result of our General Partner declaredearnings are the responsibility of our partners, therefore no amounts have been recorded in the Partnership’s first quarter 2017 cash distribution in the amount of $0.94 per common unit, payable on May 15, 2017financial statements with respect to unitholders of record as of May 5, 2017. The declared distribution totaled $68 million and was paid in the following manner: $65 million to common unitholders (including $5 million to the General Partnerfederal income taxes as a holderresult of 5,797,106 common unitsthe 2017 Tax Act.
On March 15, 2018, FERC issued the following: (1) the Revised Policy Statement, (2) the NOPR and $11 million(3) the NOI. On July 18, 2018, FERC issued (1) Order on Rehearing and (2) a Final Rule adopting and revising procedures from, and clarifying aspects of, the NOPR. The Final Rule will become effective September 13, 2018, and is subject to another subsidiaryrequests for further rehearing and clarification. Each of TransCanada as holder of 11,287,725 common units) and $3 millionthe 2018 FERC Actions is further described below.
FERC Revised Policy Statement on Income Tax Allowance Cost Recovery in MLP Pipeline Rates
The Revised Policy Statement changes FERC’s long-standing policy allowing income tax amounts to our General Partner, whichbe included $1 millionin rates subject to cost-of-service rate regulation for its effective two percent general partner interest and $2 millionpipelines owned by an MLP. The Revised Policy Statement creates a presumption that entities whose earnings are not taxed through a corporation should not be permitted to recover an income tax allowance in respect of its IDRs.their regulated cost-of-service rates.
On July 20,18, 2018, FERC dismissed requests for rehearing and provided clarification of the Revised Policy Statement. In this Order on Rehearing, FERC noted that an MLP is not automatically precluded in a future proceeding from arguing and providing evidentiary support that it is entitled to an income tax allowance in its cost-of-service rates. Additionally, FERC provided guidance with regard to ADIT for MLP pipelines and other pass through entities. FERC found that to the extent an entity’s income tax allowance should be eliminated from rates, it must also eliminate its existing ADIT balance from its rate base. As a result, the Revised Policy Statement also precludes the recognition and subsequent amortization of any related regulatory assets or liabilities that might have otherwise impacted rates charged to customers as the refund or collection of excess or deficient deferred income tax assets or liabilities.
Final Rule on Tax Law Changes for Interstate Natural Gas Companies
The Final Rule established a schedule by which interstate pipelines must either (i) file a new uncontested rates settlement or (ii) file a one-time report, called FERC Form No. 501-G, that quantifies the rate impact of the 2017 Tax Act on FERC regulated pipelines and the boardimpact of directorsthe Revised Policy Statement on pipelines held by MLPs. Pipelines filing the one-time report will have four options:
· make a limited NGA Section 4 filing to reduce its rates by the reduction in its cost of our General Partner declaredservice shown in its FERC Form No. 501-G. For any pipeline electing this option, FERC guarantees a three-year moratorium on NGA Section 5 rate investigations if the Partnership’s second quarter 2017 cash distributionpipeline’s FERC Form 501-G shows the pipeline’s estimated ROE as being 12 percent or less. Under the Final Rule and notwithstanding the Revised Policy Statement, a pipeline organized as an MLP is not required to eliminate its income tax allowance but, instead can reduce its rates to reflect the reduction in the amountmaximum corporate tax rate. Alternatively, the MLP pipeline can eliminate its tax allowance, along with its ADIT used for rate-making purposes. In situations where the ADIT balance is a
liability, this elimination would have the effect of $1.00 per common unit, payable on August 11, 2017increasing the pipeline’s rate base used for rate-making purposes;
· commit to unitholders of record as of August 1, 2017. The declared distribution totaled $74 millionfile either a pre-packaged uncontested rate settlement or a general Section 4 rate case if it believes that using the limited Section 4 option will not result in just and was paid inreasonable rates. If the following manner: $69 millionpipeline commits to common unitholders (including $6 million to the General Partner asfile either by December 31, 2018, FERC will not initiate a holder of 5,797,106 common units and $11 million to another subsidiary of TransCanada as holder of 11,287,725 common units) and $5 million to our General Partner, which included $2 million for its effective two percent general partner interest and $3 million in respectSection 5 investigation of its IDRs.rates prior to that date;
· file a statement explaining its rationale for why it does not believe the pipeline’s rates must change; and
· take no action. FERC would then consider whether to initiate a Section 5 investigation of any pipeline that has not submitted a limited Section 4 rate filing or committed to file a general Section 4 rate case.
On October 24, 2017,We continue to evaluate this Final Rule and our next course of action, however, we do not expect an immediate or a retroactive impact from the board of directors of our General Partner declaredFinal Rule or the Partnership’s third quarter 2017 cash distribution in the amount of $1.00 per common unit, payable on November 14, 2017 to unitholders of record as of November 3, 2017. The declared distribution totaled $75 million and is payable in the following manner: $70 million to common unitholders (including $6 million to the General Partner as a holder of 5,797,106 common units and $11 million to another subsidiary of TransCanada as holder of 11,287,725 common units) and $5 million to our General Partner, which included $2 million for its effective two percent general partner interest and $3 million in respect of its IDRs.Revised Policy Statement described above.
Pipeline updatesNOI Regarding the Effect of the 2017 Tax Act on Commission-Jurisdictional Rates
Great Lakes Contracting and Settlement- On April 24, 2017, Great Lakes reached an agreement onIn the terms of a new long-term transportation capacity contract with its affiliate, TransCanada. The contract, which was subjectNOI, FERC sought comments to Canada’s National Energy Board (NEB) approval, is for a term of 10 years and allows TransCanada the ability to transport up to 0.711 billion cubic feet of natural gas per day on the Great Lakes system from the Manitoba/U.S. border to the U.S. border near Dawn Ontario. On September 21, 2017, TransCanada received approval from the NEB anddetermine what additional action as a result this contract commenced on November 1, 2017. This contract contains volume reduction options up to full contract quantity beginning in year three.
On October 30,of the 2017 Great Lakes filed a rate settlement with FERC to satisfy its obligations from its 2013 rate settlement for new rates to be in effect by January 1, 2018. The 2017 Great Lakes Settlement,Tax Act, if approvedany, is required by FERC will decrease Great Lakes’ maximum transportation rates by 27 percent beginning October 1, 2017. Great Lakes expectsrelated to the ADIT that were reserved in anticipation of being paid to the impact from other changes, including:IRS, but which no longer accurately reflect the recent long-term transportation contract with TransCanada as described above, other revenue opportunitiesfuture income tax liability. The NOI also sought comments on the system and the elimination of the revenue sharing mechanism with its customers, will more than offset the full year impactbonus depreciation for regulated natural gas pipelines and other effects of the 2017 Tax Act on regulated rates or earnings.
As noted above, FERC’s Order on Rehearing provided guidance with regard to ADIT for MLP pipelines, finding that if an MLP pipeline’s income tax allowance is eliminated from its cost-of-service rates, then its existing ADIT balance used for rate-making purposes should also be eliminated from its cost-of-service rates.
Partnership Specific Considerations
While certain uncertainties exist with respect to changes resulting from the 2018 FERC Actions, the net effect of the potential reduction in Great Lakes’of our pipeline systems’ maximum allowable or recourse rates beginning in 2018.on the Partnership’s revenues could have a material negative impact on the earnings, cash flow, and financial position of the Partnership and could diminish its relative ability to attract capital to fund future growth. The 2017 Great Lakes Settlement doesPartnership’s pipeline systems do not contain any moratorium and Great Lakes will be requiredcurrently have a requirement to file for new rates no laterearlier than March 31, 2022 as a result of their existing rate settlements. However, the timing may be accelerated by the Final Rule and represents a revision of our previous expectations. Proceedings related the 2018 FERC Actions could begin as early as late 2018 and could result in a reset of certain of our pipelines’ maximum allowable rates.
While the Partnership does not anticipate any FERC mandated action to reduce recourse rates in 2018, the Partnership believes that any impact would take effect prospectively upon the completion or settlement of a rate case, including one that may be initiated by the FERC or customers. Should the Partnership choose to proactively address the issues contemplated by the 2018 FERC Actions, prospective changes in our pipeline systems’ revenues could occur as early as late 2018.
The 2018 FERC Actions directly address two components of our pipeline systems’ cost of service based rates: the allowance for income taxes and the amount of ADIT. The 2018 FERC Actions also noted that precise treatment of entities with new rates tomore ambiguous ownership structures must be effective October 1, 2022.
separately resolved on a case-by-case basis, including those partially owned by corporations such as Great Lakes, Northern Border, Rate Case- Northern BorderIroquois and its shippers have been engaged in settlement discussions,PNGTS pipelines. Additionally, FERC has indicated that any rate reduction is not expected to affect negotiated rate or non-recourse rate contracts.
Given the potential variability of outcomes arising from the 2018 FERC Actions, we are unable to precisely quantify the ultimate timing and have recently agreed to a settlement-in-principle addressing all rate and service related issues raised during the settlement discussions. Northern Border plans to file a settlement agreement with FERC before the endamount of the year, reflectingreductions in revenue and earnings on our future operating performance and cash flows. The Partnership continues to re-examine its next steps following the settlement-in-principle, precludingchanges noted above and alternatives now available under the needFinal Rule. As noted above, the change in the Final Rule to file a generalallow MLPs to remove the ADIT liability from rate case as contemplated by its 2012 Settlement. Northern Border anticipates thatbase, and thus increase net recoverable rate base, would partially mitigate the Commission will acceptloss of the settlement agreement and that it will be unopposed. This will provide Northern Border with rate stability over the longer term. At this time,tax allowance in cost-of-service based rates. Various uncertainties still exist around an optimized approach for our assets, however, we do not believe that the final outcomerange of possible outcomes has improved when compared to the estimated outcomes based on the 2018 FERC Actions proposed in March 2018. Currently, the estimated overall impact of the settlement willtax-related changes to our revenue and cashflow is in a range of negative $40 million to $60 million per year as we execute our regulatory strategies through the process initiated by these FERC Actions. These estimates could change due to numerous assumptions around the resolution of related issues as they are applied individually across our pipeline systems. In addition, approximately half of the Partnership’s share of revenues (including those accounted for in the earnings of our equity investments) are derived from contracts that are non-recourse, which are not expected to be impacted by the 2018
FERC Actions. Accordingly, any reduction to the recourse rates would not have a material impactproportional reduction on overall revenues.
Partnership Response and Outlook of Our Business
While revenues from our pipeline systems are not expected to decrease prior to individual rate proceedings, the Partnership took proactive measures to conserve capital for near-term capital requirements and to manage its leverage metrics given the magnitude and timing of the potential future cash flow decreases as a result of the 2018 FERC Actions.
Accordingly, the Partnership reduced its first and second quarter 2018 cash distributions to unitholders to $0.65 per quarter representing a 35 percent reduction from its fourth quarter 2017 distribution of $1.00 per common unit. Cash retained by the Partnership will be used to fund ongoing capital expenditures and the repayment of debt to levels that prudently manage our financial metrics in anticipation of the reduction of revenues should our pipeline systems’ rates be reset in response to the Partnership’s results. Northern Border remains2018 FERC Actions that could begin as early as late 2018.
TransCanada, the ultimate parent company of our General Partner, has historically viewed us as an element of its capital financing strategy. Following the 2018 FERC Actions initially proposed in March 2018, TransCanada stated that further dropdowns to the Partnership were no longer considered to be a key competitive pipeline andviable funding lever. As a result of the Final Rule issued on July 18, 2018, TransCanada continues to operatemonitor developments in the Partnership in order to determine whether the Partnership might be restored as a competitive financing option in the future. Therefore, our traditional source of growth is currently not accessible under the current circumstances, and our options for further growth could be significantly limited. We are continuing to consider various options that would best position the Partnership for the long term to further minimize any negative effects of the 2018 FERC Actions. To respond to new information or changes in strategies in the future, the Partnership may consider further distribution level changes, either as a standalone action or in combination with other strategies.
Our focus remains on safe and reliable operations of our pipeline assets and we expect our assets to continue to serve their customers as designed.
Impairment Considerations
The preparation of financial statements in accordance with GAAP requires us to make estimates and assumptions with respect to values or conditions, which cannot be known with certainty, that affect the reported amount of assets and liabilities and the disclosure of contingent assets and liabilities at full capacity connecting major supply basins with communitiesthe date of the financial statements. Such estimates and assumptions also affect the reported amounts of revenue and expenses during the reporting period. Although we believe these estimates and assumptions are reasonable, actual results could differ.
We review property, plant and equipment and equity investments for impairment whenever events or changes in Midwestern U.S.circumstances indicate the carrying value of the asset may not be recoverable.
Goodwill is tested for impairment on an annual basis or more frequently if events or changes in circumstance indicate that it might be impaired. We can initially make this assessment based on qualitative factors. If we conclude that it is not more likely than not that the fair value of the reporting unit is less than its carrying value, an impairment test is not performed.
Until the 2018 FERC Actions are implemented through individual proceedings or settlements, and we have fully evaluated our respective alternatives to minimize any negative impact, we believe that it is not more likely than not that the fair values of our reporting units are less than their respective carrying values. Therefore, a goodwill impairment test was not performed. Also, we have determined there is no indication that the carrying values of property, plant and equipment and equity investments potentially impacted by the 2018 FERC Actions are not recoverable. We will continue to monitor developments and assess our goodwill for impairment. We will also review our property, plant and equipment and equity investments for recoverability as new information becomes available.
At December 31, 2017, the estimated fair value of our investment in Great Lakes exceeded its carrying value by less than 10 percent. There is a risk that the 2018 FERC Actions, once implemented through the individual rate proceeding or settlement, could result to an impairment charge to our equity method goodwill on Great Lakes amounting to $260 million at June 30, 2018 (December 31, 2017 — $260 million). Additionally, since the estimated fair value of Tuscarora exceeded its carrying value by less than 10 percent in its most recent valuation, there is also a risk that the $82 million goodwill at June 30, 2018 (December 31, 2017 - $82 million) related to Tuscarora could be negatively impacted by the 2018 FERC Actions once implemented through the individual rate proceeding or settlement.
Other Business Developments
Northern Border ContractingNOI on Certificate Policy Statement - — Northern Border revenuesFERC issued a Notice of Inquiry on April 19, 2018 (“Certificate Policy Statement NOI”), thereby initiating a review of its policies on certification of natural gas pipelines, including an examination of its long-standing Policy Statement on Certification of New Interstate Natural Gas Pipeline Facilities, issued in 1999, that is used to determine whether to grant certificates for new pipeline projects. We are now substantially supported by firm transportation contracts through March 2020. The continued successful renewalsunable to predict what, if any, changes may be proposed as a result of these contracts providethe Certificate Policy Statement NOI that will affect our natural gas pipeline business or when such proposals, if any, might become effective. Any proposed changes to the current policy will be prospective only and it is expected that FERC will take many months to determine whether it will change anything for proposed natural gas pipeline projects. We do not expect that any change in this policy would affect us in a strong indication of Northern Border’s attractiveness to its customers.
PNGTS Projectsmaterially different manner than any other similarly sized natural gas pipeline company operating in the United States.
Continent to Coast (C2C) Project
As previously reported in our 2016 Annual Report on the Form 10-K dated February 28, 2017, PNGTS filed to increase its FERC-certificated capacity as contemplated in its Continent-to-Coast (C2C) contracts, bringing its capacity capability up to 210,000 Dth/day effective November 1, 2017. PNGTS has not received full regulatory approvals to date but will cooperatively work with C2C shippers while awaiting approvals.
Portland XPress Project
PNGTS has executed Precedent Agreements with several Local Distribution Companies - As noted in New England and Atlantic Canada to re-contract certain system capacity set to expire in 2019 as well as expandour Annual Report for the PNGTS system to bring its certificated capacity up to 0.3 Bcf/d. The approximately $80 million Portland XPress Project (PXP) will proceed concurrently with upstream capacity expansions. Theyear ended December 31, 2017, the in-service dates of PXP are being phased-in over a three-year period beginning November 1, 2018.
Acquisitions and Financing
Debt Offering — On May 25, 2017, During the Partnership closed a $500 million public offering of senior unsecured notes bearing an interest rate of 3.90 percent maturing May 25, 2027. The net proceeds of $497 million were used to fund a portionsecond quarter, PNGTS filed the required applications with FERC for all three phases of the 2017 Acquisition (Referproject, which includes an amendment to Note 6 within Item 1. “Financial Statements” of this Quarterly Report on Form 10Q).
2017 Acquisition — On June 1, 2017, the Partnership completed the acquisitions of a 49.34 percent interestits Presidential Permit and an increase in Iroquois from subsidiaries of TransCanada including an option to acquire a further 0.66 percent interest in Iroquois, together with an additional 11.81 percent interest in PNGTS that resulted in the Partnership owning a 61.71 percent interest in PNGTS. The total purchase price of the 2017 Acquisition was $765 million plus the final purchase price adjustments amounting to approximately $50 million. The purchase price consisted of (i) $710 million for the Iroquois interest (less $164 million, which reflected the Partnership’s 49.34 percent share of Iroquois outstanding debt at the time of the 2017 Acquisition (ii) $55 million for the additional 11.81 percent in PNGTS (less $5 million, which reflected our 11.81 percent share in PNGTS’ outstanding debt at the time of the 2017 Acquisition) (iii) final working capital adjustments on PNGTS and Iroquois amounting to $3 million and $19 million, respectively and (iv) additional consideration on Iroquois’ surplus cash amounting to $28 million. The Partnership funded the cash portion of the 2017 Acquisitionits certificated capacity through a combination of proceeds from the May 25, 2017 public debt offering and borrowing under its Senior Credit Facility
As at the date of the 2017 Acquisition, there was significant cash on Iroquois’ balance sheet. Pursuant to the Purchase and Sale Agreement associated with the acquisition of the Iroquois interest, as amended, the Partnership agreed to pay $28 million plus interest to TransCanada on August 1, 2017 for its 49.34 percent share of cash determined to be surplus to Iroquois’ operating needs.
Additionally, Iroquois’ partners adopted a distribution resolution to address the significant cash on Iroquois’ balance sheet post-closing. The Partnership expects to receive the $28 million of unrestricted cash as part of its quarterly distributions from Iroquois over 11 quarters under the terms of the resolution, which began with Iroquois’ second quarter 2017 distribution on August 1, 2017. As of November 6, 2017 the Partnership has received approximately $5.2 million of the expected $28 million, of which $2.6 million was received on November 1, 2017.
The Iroquois pipeline transports natural gas under long-term contracts and extends from the TransCanada Mainline system at the U.S. border near Waddington, New York to markets in the U.S. northeast, including New York City, Long Island and Connecticut. Iroquois provides service to local gas distribution companies, electric utilities and electric power generators, as well as marketers and other end users, directly or indirectly, through interconnecting pipelines and exchanges throughout the northeastern U.S. Both the Iroquois and PNGTS pipelines are critical natural gas infrastructure systems in the Northeast U.S. market and the addition of Iroquoisa compressor unit at its jointly owned facility with Maritimes and Northeast Pipeline LLC to the Partnership’s asset portfolio will further diversify our cash flow.
Tuscarora Refinancing — On August 21, 2017, Tuscarora refinanced allbring additional volumes of its outstanding debt by amending its existing Unsecured Term Loan Facility and issuing a new $25 million variable rate term loan that will require yearly principal payments and will mature on August 21, 2020. Tuscarora’s Unsecured Term Loan contains a covenant that requires Tuscaroranatural gas to maintain a debt service coverage ratio (cash available from operations divided by a sum of interest expense and principal payments) of greater than or equal to 3.00 to 1.00. As of September 30, 2017, the ratio was 3.08 to 1.00.
2013 Term Loan Facility - On September 29, 2017, the Partnership’s variable rate 2013 $500 million Term loan facility that was due on July 1, 2018 was amended to extend the maturity period through October 2, 2022. At September 30, 2017, the $500 million 2013 Term loan facility is hedged by fixed interest rate swap arrangements at an effective interest rate of 2.31 percent, expiring July 1, 2018. As a result of this extension, the Partnership implemented an interest rate hedging strategy during the fourth quarter and hedged the entire $500 million until its October 2, 2022 maturity using forward starting swaps at an average rate of 3.26 percent.
2015 Term Loan Facility-On September 29, 2017, the Partnership’s 2015 $170 million Term loan facility that was due on October 1, 2018 was amended to extend the maturity period through October 1, 2020.New England.
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 equityownership interests in Northern Border, Great Lakes, and effective June 1, 2017, Iroquois and full ownerships of GTN, Bison, North Baja and Tuscarora and beginning also on June 1, 2017, 61.71 percent ownership in PNGTSeight 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.
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(unaudited) |
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(millions of dollars) |
| 2017 |
| 2016(a) |
| Change* |
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| 2017 |
| 2016(a) |
| Change* |
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| 2018 |
| 2017 |
| Change (a) |
| Change(a) |
| 2018 |
| 2017 |
| Change(a) |
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Transmission revenues |
| 100 |
| 103 |
| (3 | ) | (3 | ) | 313 |
| 315 |
| (2 | ) | (1 | ) |
| 111 |
| 101 |
| 10 |
| 10 |
| 226 |
| 213 |
| 13 |
| 6 |
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Equity earnings |
| 27 |
| 22 |
| 5 |
| 23 |
| 87 |
| 75 |
| 12 |
| 16 |
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| 36 |
| 24 |
| 12 |
| 50 |
| 95 |
| 60 |
| 35 |
| 58 |
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Operating, maintenance and administrative |
| (24 | ) | (23 | ) | (1 | ) | (4 | ) | (74 | ) | (67 | ) | (7 | ) | (10 | ) |
| (25 | ) | (26 | ) | 1 |
| 4 |
| (49 | ) | (49 | ) | — |
| — |
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Depreciation |
| (25 | ) | (24 | ) | (1 | ) | (4 | ) | (73 | ) | (71 | ) | (2 | ) | (3 | ) |
| (24 | ) | (25 | ) | 1 |
| 4 |
| (48 | ) | (49 | ) | 1 |
| 2 |
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Financial charges and other |
| (23 | ) | (18 | ) | (5 | ) | (3 | ) | (59 | ) | (53 | ) | (6 | ) | (11 | ) |
| (23 | ) | (19 | ) | (4 | ) | (21 | ) | (46 | ) | (36 | ) | (10 | ) | (28 | ) |
Net income before taxes |
| 55 |
| 60 |
| (5 | ) | (8 | ) | 194 |
| 199 |
| (5 | ) | (3 | ) |
| 75 |
| 55 |
| 20 |
| 36 |
| 178 |
| 139 |
| 39 |
| 28 |
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State income taxes |
| — |
| — |
| — |
| — |
| (1 | ) | (1 | ) | — |
| — |
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| — |
| — |
| — |
| — |
| (1 | ) | (1 | ) | — |
| — |
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Net income |
| 55 |
| 60 |
| (5 | ) | (8 | ) | 193 |
| 198 |
| (5 | ) | (3 | ) |
| 75 |
| 55 |
| 20 |
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| 177 |
| 138 |
| 39 |
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Net income attributable to non-controlling interests |
| 1 |
| 2 |
| 1 |
| 50 |
| 7 |
| 10 |
| 3 |
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30 |
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| 2 |
| — |
| 2 |
| — |
| 8 |
| 6 |
| 2 |
| (33 | ) |
Net income attributable to controlling interests |
| 54 |
| 58 |
| (4 | ) | 7 |
| 186 |
| 188 |
| (2 | ) | 1 |
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| 73 |
| 55 |
| 18 |
| 33 |
| 169 |
| 132 |
| 37 |
| 28 |
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*(a) Positive number represents a favorable change; bracketed or negative number represents an unfavorable change.
(a) Financial information was recast to consolidate PNGTS for all periods presented (Refer to Note 2 and 6 within Item 1. “Financial Statements”).
Three Months Ended SeptemberJune 30, 20172018 compared to Same Period in 20162017
Net income attributable to controlling interests - The Partnership’s net income attributable to controlling interests was lowerincreased by $4$18 million in the three months ended June 30, 2018 compared to prior period2017, an increase of $0.27 per common unit, mainly due to the net effect of lower revenues and overall higher costs partially offset by higher equity earnings.following:
Transmission revenues — Revenues were lowerhigher due largely to lower discretionary revenues on short-term services sold by PNGTS.
Equity Earnings - The $5 million increase was primarily due to the addition of equity earnings from Iroquois, resulting from the addition of Iroquois to our portfolio of assets effective June 1, 2017 partially offset by lower equity earnings from Northern Border and Great Lakes due to higher pipeline integrity program spending and other operating costs. The increase in pipeline integrity work at Great Lakes is in relation to the increase in natural gas flows which have been ramping up during the year.
Operating, maintenance and administrative costs - The $1 million increase was mainly attributable to higher pipeline integrity on GTN and overall higher allocated management and operational expenses on our pipeline systems as performed by TransCanada.
Financial charges and other - The $5 million increase was mainly attributable to additional borrowings to finance the 2017 Acquisition.
Net-income attributable to non-controlling interests - The Partnership’s net income attributable to non- controlling interests was lower due to lower earnings from PNGTS during the period.
Nine Months Ended September 30, 2017 compared to Same Period in 2016
Net income attributable to controlling interests - The Partnership’s net income attributable to controlling interests was lower by $2 million compared to prior period due to the net effect of lower revenues and overall higher costs partially offset by higher equity earnings.
Transmission revenues — Comparable to prior year primarily due to higher discretionary revenues on short-termincremental long-term services sold by GTN associated with the increased available upstream capacity following debottlenecking activities on TransCanada’s pipelines offset by lower revenues from GTN’s short-term discretionary revenues on short-term services sold by PNGTS and lower transportation rates on Tuscarora asservices. Additionally, PNGTS’ revenue increased primarily due to incremental contracting from PNGTS’ Continent-to-Coast contracts with several shippers for a resultterm of settlement reached with its customers effective August 1, 2016.15 years for approximately 82,000 Dth/day (C2C contracts).
Equity Earnings - The $12 million increase was primarily due to the additioninclusion of equity earnings from Iroquois for the full three months of the second quarter of 2018 compared to only one month in 2017 (our 49.34 percent ownership was effective June 1, 2017.
Operating, maintenance2017) and administrative costs - The $7 million increase was mainly attributable to higher pipeline integrity on GTNequity earnings from Great Lakes as a result of incremental seasonal winter sales during the current period and overall higher allocated management and operational expenses on our pipeline systemsthe elimination of Great Lakes’ revenue sharing mechanism beginning in 2018 as performed by TransCanada.part of the 2017 Great Lakes Settlement.
Financial charges and other - The $6$4 million increase was mainlyprimarily attributable to additional borrowings to finance the 2017 Acquisition.
Net-incomeNet income attributable to non-controlling interests - The Partnership’s net income attributable to non-non-controlling interests was higher due to the increase in PNGTS’ net income as a result of its higher revenue.
Six Months Ended June 30, 2018 compared to Same Period in 2017
The Partnership’s net income attributable to controlling interests was lowerincreased by $37 million in the six months ended June 30, 2018 compared to 2017, an increase of $0.55 per common unit, mainly due to lowerthe following:
Transmission revenues — Revenues were higher due largely to incremental long-term services sold by GTN associated with the increased available upstream capacity following debottlenecking activities on TransCanada’s pipelines. Additionally, PNGTS’ revenue increased primarily due to incremental contracting from PNGTS’ C2C contracts partially offset by certain expiring winter contracts and North Baja experienced an increase in short-term firm transportation services.
Equity Earnings - The $35 million increase was primarily due to the inclusion of equity earnings from PNGTSIroquois for the full six months of 2018 compared to only one month in 2017 (our 49.34 percent ownership was effective June 1, 2017), as well as the increase in Iroquois’ short-term discretionary services during the period.2018 period as a result of the colder winter weather in the Northeast. Additionally, equity earnings from Great Lakes increased as a result of incremental
seasonal winter sales during the current period and the elimination of Great Lakes’ revenue sharing mechanism beginning in 2018 as part of the 2017 Great Lakes Settlement. The additional earnings were partially offset by lower revenues and earnings from Northern Border resulting from its rate reduction as part of the 2017 Northern Border Settlement.
Financial charges and other - The $10 million increase was primarily attributable to additional borrowings to finance the 2017 Acquisition.
Net income attributable to non-controlling interests - The Partnership’s net income attributable to non-controlling interests was higher due to the increase in PNGTS’ net income as a result of its higher revenue.
Net Income Attributable to Common Units and Net Income per Common Unit
2017
As discussed in Note 89 within Item 1.1 “Financial Statements,” we allocated $8 millionwill 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 attributableper common unit. Currently, we expect to controlling interestsallocate a portion of the Partnership’s income to the Class B units inat the three and nine months ended September 30, 2017, respectively, representing the excess of 30 percent of GTN’s distribution over the 2017 threshold level of $20 million. This allocation reduced net income attributable to the common units and accordingly, reduced net income per common unit by approximately 12 cents for both the three and nine months ended September 30, 2017, respectively.
2016
We allocated $11 million and $12 millionend of the Partnership’s net income attributable to controlling interests tothird quarter of 2018. Please also read Note 8 within Item 1 “Financial Statements,” for additional disclosures on the Class B units in the three and nine months ended September 30, 2016, respectively, representing the excess of 30 percent of GTN’s distribution over the 2016 threshold level of $20 million. This allocation reduced net income
attributable to the common units and accordingly, reduced net income per common unit by approximately 17 cents and 19 cents for the three and nine months ended September 30, 2016, respectively.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 TransCanada through our General Partner and as holder of all our Class B units) primarily with operating cash flow. Long-term
The Partnership reduced its 2018 quarterly distribution to $0.65 per common unit, a 35 percent reduction from the fourth quarter 2017 distribution of $1.00 per common unit. Cash retained by the Partnership will be used to fund ongoing capital needs may be met throughexpenditures and the issuancerepayment of long-term debt and/or equity. Overall, we believeto levels that our pipeline systems’ ability to obtain financing at reasonable rates, together with a historyprudently manage its financial metrics given the magnitude and timing of consistentthe potential future cash flow decreases as a result of the 2018 FERC Actions.
As of June 30, 2018, we had $51 million of cash and cash equivalents, an increase of $18 million or 55 percent from December 31, 2017, and we have reduced the outstanding balance of our Senior Credit Facility by 24 percent, from $185 million at December 31, 2017 to $140 million at June 30, 2018. We believe our cash position, remaining borrowing capacity on our Senior Credit Facility (see table below), and our operating activities, provide a solid foundation to meet future liquidity and capital requirements. We expect to be ablecash flows are adequate to fund our liquidity requirements over the next twelve months, including the revised distributions to our distributionsunitholders, ongoing capital expenditures and required debt repayments, at the Partnership level over the next 12 months utilizing our cash flow and, if required, our existing Senior Credit Facility.repayments.
The following table sets forth the available borrowing capacity under the Partnership’s Senior Credit Facility:
(unaudited) |
| September 30, 2017 |
| December 31, 2016 |
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|
|
|
|
Total capacity under the Senior Credit Facility |
| 500 |
| 500 |
|
| 500 |
| 500 |
|
Less: Outstanding borrowings under the Senior Credit Facility |
| 255 |
| 160 |
|
| 140 |
| 185 |
|
Available capacity under the Senior Credit Facility |
| 245 |
| 340 |
|
| 360 |
| 315 |
|
Our pipeline systems’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. Additionally, on September 1, 2017, the Partnership made an equity contribution to Northern Border of $83 million. This amount represents the Partnership’s 50 percent share of a one time $166 million capital contribution request from Northern Border to reduce the outstanding balance of its revolver debt to increase its available borrowing capacity.
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 NineSix Months Ended SeptemberJune 30, 20172018 compared to Same Period in 20162017
|
| Nine months ended |
|
| Six months ended |
| ||||
(unaudited) |
| September 30, |
|
| June 30, |
| ||||
(millions of dollars) |
| 2017 |
| 2016 (a) |
|
| 2018 |
| 2017 |
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in): |
|
|
|
|
|
|
|
|
|
|
Operating activities |
| 311 |
| 332 |
|
| 223 |
| 205 |
|
Investing activities |
| (756 | ) | (215 | ) |
| (8 | ) | (625 | ) |
Financing activities |
| 454 |
| (95 | ) |
| (197 | ) | 407 |
|
Net decrease in cash and cash equivalents |
| 9 |
| 22 |
| |||||
Net increase in cash and cash equivalents |
| 18 |
| (13 | ) | |||||
Cash and cash equivalents at beginning of the period |
| 64 |
| 55 |
|
| 33 |
| 64 |
|
Cash and cash equivalents at end of the period |
| 73 |
| 77 |
|
| 51 |
| 51 |
|
(a) Financial information was recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6 within Item 1. “Financial Statements”).
Operating Cash Flows
Net cash provided by operating activities decreasedincreased by $21$18 million in the ninesix months ended SeptemberJune 30, 20172018 compared to the same period in 20162017 primarily due to lower distributionsthe net effect of:
· higher cash flow from Great Lakesoperations at GTN, PNGTS and Northern BorderNorth Baja primarily resulting from an increase in 2017 partially offset bytheir revenues;
· distributions received from Iroquois resulting from the addition of Iroquois to our portfolio of assets effective June 1, 2017. Distributions2017;
· higher interest expense attributable to additional borrowings to finance the acquisition of a 49.34 percent interest in Iroquois and an additional 11.81 percent interest in PNGTS (the 2017 Acquisition); and
· higher distributions received in the first quarter of 2016 from Great Lakes were higher than on a run-rate basis due to the resolution of certain regulatory proceedingsan increase in its revenue in the fourth quarter of 2015 which inflated its results during that period2017 and resulted in higher cash flow which was paid to the Partnership in the first quarter of 2016 and not applicable in the first quarter of 2017. Additionally, the Partnership received lower distributions from Northern Border in the current 2017 period2018 compared to the same period in 2016 primarily due to higher maintenance capital expenditures duringperiods of the current 2017 period together with the change in Northern Border’s distribution policy during 2016 from a lagged quarterly distribution to a more timely monthly distribution that resulted in a larger distribution in the third quarter of 2016.previous years.
Investing Cash Flows
Net cash used in investing activities increaseddecreased by $541$617 million induring the ninesix months ended SeptemberJune 30, 20172018 compared to the same period in 2016. On January 1, 2016, we invested $1932017 due to the net effect of:
· $605 million to acquire a 49.9 percent interest in PNGTS andcash payment on June 1, 2017 we invested $593 million to acquire a 49.34 percent interestTransCanada for the 2017 Acquisition;
· lower capital maintenance expenditures in Iroquois and $53 million to acquire an additional 11.81 percentthe first six months of PNGTS. During the nine months ended September 30, 20172018 compared to 2016, we incurred higher maintenance capital expenditures related to2017, during which period there were major compression equipment overhauls on GTN’s pipeline systemGTN; and
· and on September 1, 2017,$5 million unrestricted cash distribution we contributed $83 million to Northern Borderreceived from Iroquois during the six months ended June 30, 2018 representing our 50 percent sharea return of a requested capital contribution to reduce the outstanding balance of its revolving credit facility.investment (none received in 2017).
Financing Cash Flows
The net changeincrease in cash from ourused in financing activities was approximately $549$604 million in the ninesix months ended SeptemberJune 30, 20172018 compared to the same period in 20162017 primarily due to the net effect of:
· $564$95 million increase in net issuances of debt repayments in 2018 compared to $479 million net debt issuance in 2017 primarily due to the issuance of $500 million 3.90% Senior Notes on May 25, 2017 to partially finance the 2017 Acquisition;
· $26$12 million increasedecrease in distributions paid toon our common units and to our General Partner in respect of its two percent general partner interest and IDRs;
· $10 million increaseIDRs as a result of the reduction in distributions declared and paid to Class B units in 2017for the first quarter of 2018 as compared to 2016;
· $8 million increase in our ATM equity issuances in 2017 as compared to 2016;2017;
· $7 million decrease in distributions paid to Class B units in 2018 as compared to 2017;
· $52 million decrease in our ATM equity issuances in the six months ended June 30, 2018, as compared to the same period in 2017;
· $2 million decrease in distributions paid to non-controlling interestinterests due to lower revenues ondistributions from PNGTS in the first six months of 2018 as compared to the previous periods;first six months of 2017 to retain cash to repay the remaining balance on its Senior Notes; and
· $8$1 million decrease in distributions paid to TransCanada as the former parent of PNGTS primarily due to the Partnership’s acquisition of a 49.9TransCanada’s then-remaining 11.81 percent interest in PNGTS effective January 1, 2016 and additional 11.81 percent effective June 1, 2017.
Short-Term Cash Flow Outlook
Operating Cash Flow Outlook
Northern Border declared its September 2017June 2018 distribution of $14$12 million on October 7, 2017,July 11, 2018, of which the Partnership received its 50 percent share or $7$6 million. The distribution was paid on OctoberJuly 31, 2017.2018.
Great Lakes declared its thirdsecond quarter 20172018 distribution of $2$29 million on October 19, 2017,July 17, 2018, of which the Partnership received its 46.45 percent share or $1$13 million. The distribution was paid on NovemberAugust 1, 2017.2018.
Iroquois declared its thirdsecond quarter 20172018 distribution of $28$29 million on October 23, 2017,July 25, 2018, of which the Partnership received its 49.34 percent share or $14 million on NovemberAugust 1, 2017.2018.
Our equity investee Iroquois has $2.8$2 million of scheduled debt repayments for the remainder of 20172018 and Iroquois’ debt repayments are expected to be funded through its cash flow from operations.
Investing Cash Flow Outlook
The Partnership made an equity contribution to Great Lakes of $4 million in the first quarter of 2017.2018. This amount represents the Partnership’s 46.45 percent share of a $9 million cash call from Great Lakes to make a scheduled debt
repayment. The Partnership expects to make an additional $5 million equity contribution to Great Lakes in the fourth quarter of 20172018 to further fund debt repayments. This is consistent with prior years.
Our consolidated entities have commitments of $7$3 million as of SeptemberJune 30, 20172018 in connection with various maintenance and general plant projects.
Our expected total growth and maintenance capital expenditures on our pipeline systems as outlined in the Management Discussion and Analysis of Financial Condition and Results of Operations for the year ended December 31, 2016 Consolidated Financial Statements and Notes thereto included as Exhibit 99.3 of the Current Report on Form 8-K filed with the SEC on August 3, 2017 remain materially unchanged.
Financing Cash Flow Outlook
On October 24, 2017,July 26, 2018, the board of directors of our General Partner declared the Partnership’s thirdsecond quarter 20172018 cash distribution in the amount of $1.00$0.65 per common unit payable on November 14, 2017August 15, 2018 to unitholders of record as of November 3, 2017.August 6, 2018. Please see “Recent Business Developments.”Developments” and Note 19 within Item 1 “Financial Statements” for additional disclosures.
On April 5, 2018, PNGTS entered into a $125 million Revolving Credit Facility. The facility will be utilized primarily to fund the costs of the PXP expansion project and to finance PNGTS’ other funding needs. As of August 2, 2018, PNGTS has not utilized its $125 million Revolving Credit Facility.
On May 10, 2018, PNGTS paid the remaining principal balance of its 2003 Senior Secured Notes using available cash.
PNGTS declared its second quarter 2018 distribution of $3 million on July 20, 2018, of which $1 million will be paid to its non-controlling interest owner on August 1, 2018.
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, taxes, depreciation and amortization, 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 amount presented.
Total distributable cash flow includes EBITDA plus:
· Distributions from our equity investments
less:
· Earnings from our equity investments,
· Equity allowance for funds used during construction (Equity AFUDC),
· Interest expense,
· Income taxes,
· Distributions to non-controlling interests,
· Distributions to TransCanada as the former parent of PNGTS, and
· Maintenance capital expenditures from consolidated subsidiaries.
Distributable cash flow is computed net of distributions declared to the General Partner and distributions allocable to Class B units. Distributions declared to the General Partner are based on its effective two percent interest plus an amount equal to incentive distributions. Distributions allocable to the Class B units in 20172018 equal 30 percent of GTN’s distributable cash flow less $20 million.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 performance.
The non-GAAP measures described above are provided as a supplement to GAAP financial results and are not meant to be considered in isolation or as substitutes for financial results prepared in accordance with GAAP. Additionally, these measures as presented may not be comparable to similarly titled measures of other companies.
Reconciliations of Non-GAAP Financial MeasuresNet 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 |
| Nine months ended |
| ||||
(unaudited) |
| September 30, |
| September 30, |
| ||||
(millions of dollars) |
| 2017 |
| 2016 (a) |
| 2017 |
| 2016(a) |
|
Net income |
| 55 |
| 60 |
| 193 |
| 198 |
|
|
|
|
|
|
|
|
|
|
|
Add: |
|
|
|
|
|
|
|
|
|
Interest expense(b) |
| 23 |
| 18 |
| 60 |
| 55 |
|
Depreciation and amortization |
| 25 |
| 24 |
| 73 |
| 71 |
|
Income taxes |
| — |
| — |
| 1 |
| 1 |
|
|
|
|
|
|
|
|
|
|
|
EBITDA |
| 103 |
| 102 |
| 327 |
| 325 |
|
|
|
|
|
|
|
|
|
|
|
Add: |
|
|
|
|
|
|
|
|
|
Distributions from equity investments(c) |
|
|
|
|
|
|
|
|
|
Northern Border |
| 21 |
| 23 |
| 61 |
| 67 |
|
Great Lakes |
| 1 |
| 5 |
| 28 |
| 28 |
|
Iroquois (d) |
| 14 |
| — |
| 28 |
| — |
|
|
| 36 |
| 28 |
| 117 |
| 95 |
|
Less: |
|
|
|
|
|
|
|
|
|
Equity earnings: |
|
|
|
|
|
|
|
|
|
Northern Border |
| (16 | ) | (18 | ) | (50 | ) | (52 | ) |
Great Lakes |
| (2 | ) | (4 | ) | (24 | ) | (23 | ) |
Iroquois |
| (9 | ) | — |
| (13 | ) | — |
|
|
| (27 | ) | (22 | ) | (87 | ) | (75 | ) |
Less: |
|
|
|
|
|
|
|
|
|
Interest expense(b) |
| (23 | ) | (18 | ) | (60 | ) | (55 | ) |
Income taxes |
| — |
| — |
| (1 | ) | (1 | ) |
Distributions to non-controlling interests(e) |
| (2 | ) | (3 | ) | (10 | ) | (11 | ) |
Distributions to TransCanada as PNGTS’ former parent(f) |
| — |
| — |
| (1 | ) | (3 | ) |
Maintenance capital expenditures (g) |
| (9 | ) | (3 | ) | (26 | ) | (9 | ) |
|
| (34 | ) | (24 | ) | (98 | ) | (79 | ) |
|
|
|
|
|
|
|
|
|
|
Total Distributable Cash Flow |
| 78 |
| 84 |
| 259 |
| 266 |
|
General Partner distributions declared (h) |
| (5 | ) | (4 | ) | (13 | ) | (9 | ) |
Distributions allocable to Class B units (i) |
| (8 | ) | (11 | ) | (8 | ) | (12 | ) |
Distributable Cash Flow |
| 65 |
| 69 |
| 238 |
| 245 |
|
|
| Three months ended |
| Six months ended |
| ||||
(unaudited) |
| June 30, |
| June 30, |
| ||||
(millions of dollars) |
| 2018 |
| 2017 |
| 2018 |
| 2017 |
|
Net income |
| 75 |
| 55 |
| 177 |
| 138 |
|
|
|
|
|
|
|
|
|
|
|
Add: |
|
|
|
|
|
|
|
|
|
Interest expense(a) |
| 25 |
| 20 |
| 48 |
| 37 |
|
Depreciation and amortization |
| 24 |
| 25 |
| 48 |
| 49 |
|
Income taxes |
| — |
| — |
| 1 |
| 1 |
|
|
|
|
|
|
|
|
|
|
|
EBITDA |
| 124 |
| 100 |
| 274 |
| 225 |
|
|
|
|
|
|
|
|
|
|
|
Add: |
|
|
|
|
|
|
|
|
|
Distributions from equity investments(b) |
|
|
|
|
|
|
|
|
|
Northern Border |
| 18 |
| 20 |
| 37 |
| 40 |
|
Great Lakes |
| 14 |
| 7 |
| 39 |
| 27 |
|
Iroquois (c) |
| 14 |
| 14 |
| 28 |
| 14 |
|
|
| 46 |
| 41 |
| 104 |
| 81 |
|
Less: |
|
|
|
|
|
|
|
|
|
Equity earnings: |
|
|
|
|
|
|
|
|
|
Northern Border |
| (15 | ) | (15 | ) | (32 | ) | (34 | ) |
Great Lakes |
| (12 | ) | (6 | ) | (36 | ) | (23 | ) |
Iroquois |
| (9 | ) | (3 | ) | (27 | ) | (3 | ) |
|
| (36 | ) | (24 | ) | (95 | ) | (60 | ) |
Less: |
|
|
|
|
|
|
|
|
|
Interest expense |
| (25 | ) | (20 | ) | (48 | ) | (37 | ) |
Income taxes |
| — |
| — |
| (1 | ) | (1 | ) |
Distributions to non-controlling interests(d) |
| (2 | ) | (3 | ) | (9 | ) | (8 | ) |
Distributions to TransCanada as PNGTS’ former parent(e) |
| — |
| — |
| — |
| (1 | ) |
Maintenance capital expenditures (f) |
| (5 | ) | (7 | ) | (10 | ) | (17 | ) |
|
| (32 | ) | (30 | ) | (68 | ) | (64 | ) |
|
|
|
|
|
|
|
|
|
|
Total Distributable Cash Flow |
| 102 |
| 87 |
| 215 |
| 182 |
|
General Partner distributions declared (g) |
| (1 | ) | (5 | ) | (2 | ) | (8 | ) |
Distributions allocable to Class B units (h) |
| — |
| — |
| — |
| — |
|
Distributable Cash Flow |
| 101 |
| 82 |
| 213 |
| 174 |
|
(a) Financial information was recast to consolidate PNGTS for all periods presented. Refer to Notes 2 and 6 within Item 1.” Financial Statements”.
(b) Interest expense as presented includes net realized loss or gain related to the interest rate swaps and amortization of realized loss on PNGTS’ derivative instruments. Refer to Note 1415 within Item 1.” Financial1 “Financial Statements”.
(c)(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 during the current reporting period.
(d)(c) This amount represents our proportional 49.34 percent share of the distribution declared by our equity investee Iroquois during the current reporting period and includes our 49.34 percent share of the Iroquois unrestricted cash distribution amounting to approximately $2.6 million and $5.2 million, respectively, for the three and ninesix months ending Septemberended June 30, 2017, respectively. Refer to Note 6 within Item 1. “Financial Statements”2018 (2017 - $2.6 million for both periods).
(e)(d) Distributions to non-controlling interests represent the respective share of our consolidated entities’ distributable cash not owned by us during the periods presented.
(f)(e) Distributions to TransCanada as PNGTS’ former parent represent TransCanada’s respective share of PNGTS’ distributable cash not owned by us during the periods presented.
(g)(f) The Partnership’s maintenance capital expenditures include cash 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.
(h)(g) Distributions declared to the General Partner for the three and ninesix months ended SeptemberJune 30, 2017 included an2018 did not trigger any incentive distribution of approximately(2017 — $3 million and $9 million, respectively (September 30, 2016 — $2 million and $5 million).
(i)(h) During the ninesix months ended SeptemberJune 30, 2018 and 2017, 30 percent of GTN’s totalno distributions amounted to $28 million. As a result of exceeding the $20 million threshold during this quarter, $8 million waswere allocated to the Class B units for bothas the three and nine months ended September 30, 2017.
Duringannual threshold had not been exceeded. We expect the nine months ended September 30, 2016, 30 percent of GTN’s total distributions amounted to $32 million. As a result of exceeding the $20 million2018 threshold sincewill be exceeded at the end of the secondthird quarter of 2016, $12 million was allocated to the Class B units at September 30, 2016, of which $1 million and $11 million were allocated during the three months ended June 30, 2016 and September 30, 2016, respectively.
2018. Please read Notes 78 and 89 within Item 1.1 “Financial Statements” for additional disclosures on the Class B units.
Three months ended SeptemberJune 30, 20172018 Compared to Same Period in 20162017
Our EBITDA was comparablehigher for the second quarter of 2018 compared to the same period in 2016. The slight increase was2017 primarily due to the addition of ourhigher equity interest on Iroquois effective June 1, 2017 offset by lower revenuesearnings and an overall increase in operational costsour revenues during the period as discussed in more detail under the Results of Operations section.
Our distributable cash flow decreasedincreased by $4$19 million in the thirdsecond quarter of 20172018 compared to the same period in 20162017 due to the net effect of:
· additionhigher EBITDA from GTN and PNGTS due to an increase in their revenues generated during the second quarter of 49.34 percent share2018;
· higher distributions from Great Lakes due to the increase in revenue during the second quarter of Iroquois’ third quarter 2017 distribution;2018;
· lower distributions from Great Lakes and Northern Border due to their higher pipeline integrity and other operating costs;
· higher maintenance capital expenditures relatedcompared to the second quarter of 2017, during which there were major compression equipment overhauls on GTN’s pipeline system;GTN;
· increased interest expense due to additional borrowings to finance the 2017 Acquisition; and
· higher IDRsreduction in our declared distributions which did not result in any IDR allocation to our General Partner during the current period; and
· lower distributions allocable to the Class B units during the periodperiod.
Nine Months Ended SeptemberSix months ended June 30, 20172018 Compared to Same Period in 20162017
Our EBITDA was comparablehigher for the six months ended June 30, 2018 compared to the same period in prior year2017 primarily due to the addition ofhigher equity earnings on Iroquois effective June 1, 2017 offset by lower revenues and an overall increase in operational costsour revenues during the period as discussed in more detail under the Results of Operations section.
Our distributable cash flow decreasedincreased by $7$39 million in the ninesix months ended SeptemberJune 30, 20172018 compared to the same period in 20162017 due to the net effect of:
· additionhigher EBITDA from GTN, PNGTS and North Baja due to an increase in their revenues generated during the six months ended June 30, 2018;
· two quarters of distributions received from Iroquois during the six months ended June 30, 2018 compared to one distribution received during the previous period (ownership of 49.34 percent share of Iroquois’ second and third quarter 2017 distribution;was effective June 1, 2017);
· higher distributions from Great Lakes due to the increase in revenue generated during the six months ended June 30, 2018;
· lower maintenance capital expenditures relatedcompared to 2017 during which there were major compression equipment overhauls on GTN’s pipeline system;GTN;
· lower distributable cash flow from Northern Border primarilyincreased interest expense due to its higher operating costsadditional borrowings to finance the 2017 Acquisition; and higher maintenance capital expenditures;
· higher IDRsreduction in declared distributions which did not result in any IDR allocation to our General Partner during the current period; and
· lower distributions allocable to the Class B units during the period.
Contractual Obligations
The Partnership’s Contractual Obligations
The Partnership’s contractual obligations related to debt as of SeptemberJune 30, 20172018 included the following:
|
| Payments Due by Period |
|
| Payments Due by Period |
| ||||||||||||||||||||
(unaudited) |
| Total |
| Less |
| 1-3 |
| 4-5 |
| More |
| Weighted |
|
| Total |
| Less |
| 1-3 |
| 4-5 |
| More |
| Weighted Average |
|
TC PipeLines, LP |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Senior Credit Facility due 2021 |
| 255 |
| — |
| — |
| — |
| 255 |
| 2.34% |
|
| 140 |
| — |
| — |
| 140 |
| — |
| 2.99 | % |
2013 Term Loan Facility due October 2022 |
| 500 |
| — |
| — |
| — |
| 500 |
| 2.26% |
| |||||||||||||
2015 Term Loan Facility due October 2020 |
| 170 |
| — |
| — |
| 170 |
| — |
| 2.15% |
| |||||||||||||
2013 Term Loan Facility due 2022 |
| 500 |
| — |
| — |
| 500 |
| — |
| 3.02 | % | |||||||||||||
2015 Term Loan Facility due 2020 |
| 170 |
| — |
| 170 |
| — |
| — |
| 2.91 | % | |||||||||||||
4.65% Senior Notes due 2021 |
| 350 |
| — |
| — |
| 350 |
| — |
| 4.65%(a) |
|
| 350 |
| — |
| 350 |
| — |
| — |
| 4.65 | %(a) |
4.375% Senior Notes due 2025 |
| 350 |
| — |
| — |
| — |
| 350 |
| 4.375%(a) |
|
| 350 |
| — |
| — |
| — |
| 350 |
| 4.375 | %(a) |
3.9% Senior Notes due 2027 |
| 500 |
| — |
| — |
| — |
| 500 |
| 3.90%(a) |
|
| 500 |
| — |
| — |
| — |
| 500 |
| 3.90 | %(a) |
GTN |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5.29% Unsecured Senior Notes due 2020 |
| 100 |
| — |
| 100 |
| — |
| — |
| 5.29%(a) |
|
| 100 |
| — |
| 100 |
| — |
| — |
| 5.29 | %(a) |
5.69% Unsecured Senior Notes due 2035 |
| 150 |
| — |
| — |
| — |
| 150 |
| 5.69%(a) |
|
| 150 |
| — |
| — |
| — |
| 150 |
| 5.69 | %(a) |
Unsecured Term Loan Facility due 2019 |
| 55 |
| 20 |
| 35 |
| — |
| — |
| 1.95% |
|
| 35 |
| 35 |
| — |
| — |
| — |
| 2.71 | % |
PNGTS |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5.90% Senior Secured Notes due December 2018 |
| 36 |
| 30 |
| 6 |
| — |
| — |
| 5.90%(a) |
| |||||||||||||
Revolving Credit Facility due 2023 |
|
|
| — |
| — |
| — |
|
|
| — |
| |||||||||||||
Tuscarora |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unsecured Term Loan due August 2020 |
| 25 |
| 1 |
| 24 |
| — |
| — |
| 2.18% |
| |||||||||||||
Unsecured Term Loan due 2020 |
| 25 |
| 1 |
| 24 |
| — |
| — |
| 2.87 | % | |||||||||||||
|
| 2,491 |
| 51 |
| 165 |
| 520 |
| 1,755 |
|
|
|
| 2,320 |
| 36 |
| 644 |
| 640 |
| 1,000 |
|
|
|
(a) Fixed interest rate
The Partnership’s long-term debt results in exposures to changing interest rates. The Partnership uses derivatives to assist in managing its exposure to interest rate risk. Refer to Item 3. “Quantitative and Qualitative Disclosures About Market Risk” for additional information regarding the derivatives.
The fair value of the Partnership’s long-term debt is estimated by discounting the future cash flows of each instrument at estimated current borrowing rates. The estimated fair value of the Partnership’s debt at SeptemberJune 30, 20172018 was $2,555$2,311 million.
Please read Note 57 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 related to debt as of SeptemberJune 30, 20172018 included the following:
|
| Payments Due by Period (a) |
|
| Payments Due by Period (a) |
| ||||||||||||||||||||
(unaudited) |
| Total |
| Less |
| 1-3 |
| 4-5 |
| More |
| Weighted |
|
| Total |
| Less |
| 1-3 |
| 4-5 |
| More |
| Weighted |
|
$200 million Credit Agreement due 2020 |
| 16 |
| — |
| — |
| 16 |
| — |
| 2.11% |
|
| 15 |
| — |
| 15 |
| — |
| — |
| 2.94 | % |
7.50% Senior Notes due 2021 |
| 250 |
| — |
| — |
| 250 |
| — |
| 7.50%(b) |
|
| 250 |
| — |
| — |
| 250 |
| — |
| 7.50 | %(b) |
|
| 266 |
| — |
| — |
| 266 |
| — |
|
|
|
| 265 |
| — |
| 15 |
| 250 |
| — |
|
|
|
(a) Represents 100 percent of Northern Border’s debt obligations.obligations
(b)Fixed interest rate
On September 1, 2017, Northern Border’s $100 million 364-day revolving credit facility was terminated.
As of SeptemberJune 30, 2017, $162018, $15 million was outstanding under Northern Border’s $200 million revolving credit agreement, leaving $184$185 million available for future borrowings. At SeptemberJune 30, 2017,2018, Northern Border was in compliance with all of its financial covenants.
Northern Border has commitments of $12$5 million as of SeptemberJune 30, 20172018 in connection with the meter station growth project, the compressor station overhaul project and other capital projects.
Summary of Great Lakes’ Contractual Obligations
Great Lakes’ contractual obligations related to debt as of SeptemberJune 30, 20172018 included the following:
|
| Payments Due by Period (a) |
| ||||||||||
(unaudited) |
| Total |
| Less |
| 1-3 |
| 4-5 |
| More |
| Weighted |
|
6.73% series Senior Notes due 2017 to 2018 |
| 9 |
| 9 |
| — |
| — |
| — |
| 6.73%(b) |
|
9.09% series Senior Notes due 2017 and 2021 |
| 50 |
| 10 |
| 20 |
| 20 |
| — |
| 9.09%(b) |
|
6.95% series Senior Notes due 2019 and 2028 |
| 110 |
| — |
| 22 |
| 22 |
| 66 |
| 6.95%(b) |
|
8.08% series Senior Notes due 2021 and 2030 |
| 100 |
| — |
| — |
| 20 |
| 80 |
| 8.08%(b) |
|
|
| 269 |
| 19 |
| 42 |
| 62 |
| 146 |
|
|
|
|
| Payments Due by Period (a) |
| ||||||||||
(unaudited) |
| Total |
| Less than |
| 1-3 |
| 4-5 |
| More |
| Weighted |
|
9.09% series Senior Notes due 2018 - 2021 |
| 40 |
| 10 |
| 20 |
| 10 |
| — |
| 9.09 | %(b) |
6.95% series Senior Notes due 2019 - 2028 |
| 110 |
| 11 |
| 22 |
| 22 |
| 55 |
| 6.95 | %(b) |
8.08% series Senior Notes due 2021 - 2030 |
| 100 |
| — |
| 10 |
| 20 |
| 70 |
| 8.08 | %(b) |
|
| 250 |
| 21 |
| 52 |
| 52 |
| 125 |
|
|
|
(a) Represents 100 percent of Great Lakes’ debt obligations.obligations
(b)Fixed interest rate
Great Lakes is required to comply with certain financial, operational and legal covenants. Under the most restrictive covenants in the senior note agreements, approximately $145$135 million of Great Lakes’ partners’ capital was restricted as to distributions as of SeptemberJune 30, 20172018 (December 31, 20162017 — $150$139 million). Great Lakes was in compliance with all of its financial covenants at SeptemberJune 30, 2017.2018.
Great Lakes has commitments of $2$3 million as of SeptemberJune 30, 20172018 in connection with pipeline integrity program spending, major overhaul projects, and right of way renewals.
Summary of Iroquois’ Contractual Obligations
Iroquois’ contractual obligations related to debt as of SeptemberJune 30, 20172018 included the following:
|
| Payments Due by Period (a) |
|
| Payments Due by Period (a) |
| ||||||||||||||||||||
(unaudited) |
| Total |
| Less |
| 1-3 |
| 4-5 |
| More |
| Weighted |
|
| Total |
| Less |
| 1-3 |
| 4-5 |
| More |
| Weighted |
|
6.63% series Senior Notes due 2019 |
| 140 |
| — |
| 140 |
| — |
| — |
| 6.63%(b) |
|
| 140 |
| 140 |
| — |
| — |
| — |
| 6.63 | %(b) |
4.84% series Senior Notes due 2020 |
| 150 |
| — |
| 150 |
| — |
| — |
| 4.84%(b) |
|
| 150 |
| — |
| 150 |
| — |
| — |
| 4.84 | %(b) |
6.10% series Senior Notes due 2027 |
| 42 |
| 5 |
| 10 |
| 7 |
| 20 |
| 6.10%(b) |
|
| 37 |
| 5 |
| 9 |
| 7 |
| 16 |
| 6.10 | %(b) |
|
| 332 |
| 5 |
| 300 |
| 7 |
| 20 |
|
|
|
| 327 |
| 145 |
| 159 |
| 7 |
| 16 |
|
|
|
(a) Represents 100 percent of Iroquois’ debt obligations.
(b) Fixed interest rate
Iroquois has commitments of $2 million as of SeptemberJune 30, 20172018 relative to procurement of materials on its expansion project.
Iroquois is restricted under the terms of its note purchase agreement from making cash distributions to its partners unless certain conditions are met. Before a distribution can be made, the debt/capitalization ratio must be below 75%, and, the debt service coverage ratio must be at least 1.25 times for the four preceding quarters. At SeptemberJune 30, 2017,2018, the
debt/capitalization ratio was 47.6%47.4% and the debt service coverage ratio was 8.046.24 times, therefore, Iroquois was not restricted from making any cash distributions.
Critical Accounting Policies and Estimates
The preparation of financial statements in accordance with GAAP requires us to make estimates and assumptions with respect to values or conditions, which cannot be known with certainty, that affect the reported amount of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements. Such estimates and assumptions also affect the reported amounts of revenue and expenses during the reporting period. Although we believe these estimates and assumptions are reasonable, actual results could differ. There were no significant changes to the Partnership’s critical accounting estimates during the three and nine months ended September 30, 2017. Information about our critical accounting estimates is included in our Annual Report on Form 10-K for the year ended December 31, 2016.
Our significant accounting policies have remained unchanged since December 31, 2016 except as described in Note 3 within Item 1. “Financial Statements,” of this quarterly report on Form 10-Q. A summary of our significant accounting policies can be found in our audited financial statements and notes thereto for the year ended December 31, 2016 included as exhibit 99.2 in our Current Report on Form 8-Kdated August 3, 2017. (Refer also to Note 2 in Item 1. “Financial Statements” of this Quarterly Report on Form 10-Q).
RELATED PARTY TRANSACTIONS
Please read Notes 6 and 11Note 12 within Item 1. “Financial Statements” for information regarding related party transactions.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
OVERVIEW
The Partnership and our pipeline systems are exposed to market risk, counterparty credit risk, and liquidity risk. Our exposure to market risk discussed below includes forward-looking statements and is not necessarily indicative of actual results, which may not represent the maximum possible gains and losses that may occur, since actual gains and losses will differ from those estimated, based on actual market conditions.
Our primary risk management objective is to mitigate the impact of these risks on earnings and cash flow, and ultimately, unitholder value. We do not use financial instruments for trading purposes.
We record derivative financial instruments on the balance sheet as assets and liabilities at fair value. We estimate the fair value of derivative financial instruments using available market information and appropriate valuation techniques. Changes in the fair value of derivative financial instruments are recognized in earnings unless the instrument qualifies as a hedge and meets specific hedge accounting criteria. Qualifying derivative financial instruments’ gains and losses may offset the hedged items’ related results in earnings for a fair value hedge or be deferred in accumulated other comprehensive income for a cash flow hedge.
MARKET RISK
From time to time, and in order to finance our business and that of our pipeline systems, the Partnership and our pipeline systems issue debt to invest in growth opportunities and provide for ongoing operations. The issuance of floating rate debt exposes the Partnership and our pipeline systems to market risk from changes in interest rates which affect earnings and the value of the financial instruments we hold.
Market risk is the risk that changes in market interest rates may result in fluctuations in the fair values or cash flows of financial instruments. We regularly assess the impact of interest rate fluctuations on future cash flows and evaluate hedging opportunities to mitigate our interest rate risk.
As of SeptemberJune 30, 2017,2018, the Partnership’s interest rate exposure resulted from our floating rate Senior Credit Facility, 2015 Term Loan Facility, GTN’s Unsecured Term Loan Facility, PNGTS’ Revolving Credit Facility and Tuscarora’s Unsecured Term Loan Facility, under which $505$370 million, or 2016 percent, of our outstanding debt was subject to variability in LIBOR interest rates.rates (December 31, 2017- $435 million or 18 percent). As of December 31, 2016, the Partnership’s interest rate exposure resulted from our floating rate Senior Credit Facility, 2015 Term Loan Facility, GTN’s Unsecured Term Loan Facility and Tuscarora’s Unsecured Term Loan Facility, under which $405 million or 21 percent of our outstanding debt was subject to variability in LIBOR interest rates.
As of SeptemberJune 30, 2017,2018, the variable interest rate exposure related to 2013 Term Loan Facility was hedged by fixed interest rate swap arrangements and our effective interest rate was 2.31 percent.
If interest rates hypothetically increased (decreased) on these facilities by one percent 100(100 basis points,points), compared with rates in effect at SeptemberJune 30, 2017,2018, our annual interest expense would increase (decrease) and net income would decrease (increase) by approximately $5$4 million.
As of SeptemberJune 30, 2017, $162018, $15 million, or 6 percent, of Northern Border’s outstanding debt was at floating rates. If interest rates hypothetically increased (decreased) by one percent 100(100 basis points,points), compared with rates in effect at SeptemberJune 30, 2017,2018, Northern Border’s annual interest expense would increase (decrease) and its net income would decrease (increase) by approximately nil million.
GTN’s Unsecured Senior Notes, Northern Border’s and Iroquois’ Senior Notes, and all of Great Lakes’ and PNGTS’ Notes represent fixed-rate debt; therefore, they are not exposed to market risk due to floating interest rates. Interest rate risk does not apply to Bison and North Baja, as they currently do not have any debt.
The Partnership and our pipeline systems use derivatives as part of our overall risk management policy to assist in managing exposures to market risk resulting from these activities within established policies and procedures. Derivative contracts used to manage market risk generally consist of the following:
· Swaps — contractual agreements between two parties to exchange streams of payments over time according to specified terms.
· Options — contractual agreements to convey the right, but not the obligation, for the purchaser to buy or sell a specific amount of a financial instrument at a fixed price, either at a fixed date or at any time within a specified period.
The Partnership’s interest rate swaps are structured such that the cash flows of the derivative instruments match those of the variable rate of interest on the 2013 Term Loan Facility. The Partnership hedged interest payments on the variable-rate 2013 Term Loan Facility with interest rate swaps maturing July 1, 2018, at a weighted average fixed interest rate of 2.31 percent. At SeptemberJune 30, 2018, the fair value of the interest rate swaps accounted for as cash flow hedges was an asset of $15 million (both on a gross and net basis). At December 31, 2017, the fair value of the interest rate swaps accounted for as cash flow hedges was an asset of $2$5 million (both on a(on both gross and net basis). At December 31, 2016, the fair value of the interest rate swaps accounted for as cash flow hedges was an asset of $1 million and a liability of $1 million (on a gross basis) and an asset of nil million (on a net basis). The Partnership did not record any amounts in net income related to ineffectiveness for interest rate hedges for the three and nine months ended September 30, 2017 and 2016. The change in fair value of interest rate derivative instruments recognized in other comprehensive income was nila loss of $1 million and a gain of $1$6 million for the three and ninesix months ended SeptemberJune 30, 2017,2018, respectively (September 30, 2016(2017 — nil and gain of $2$1 million). During the three and six months ended June 30, 2018, a gain of $3 million and awas reclassified from other comprehensive income to net income (2017 — loss of $1 million). For the three and ninesix months ended SeptemberJune 30, 2017,2018, the net realized lossgain related to the interest rate swaps was nil,$1 million and $2 million, respectively, and was included in financial charges and other (September 30, 2016 —$(2017 - nil).
The Partnership’s $500 million 2013 Term Loan is hedged using fixed interest rate swaps until July 1, 2018 at an average rate of 2.31 percent. During the fourth quarter of 2017, the Partnership implemented an interest rate hedging strategy that hedged the $500 million and $2 million). Refer to Note 14 within Item 1. “Financial Statements”.2013 Term Loan until its October 2, 2022 maturity using forward starting swaps at an average rate of 3.26 percent.
The Partnership has no master netting agreements; however, it has derivative contracts containing provisions with rights of offset. The Partnership has elected to present the fair value of derivative instruments with the right to offset on a gross basis in the balance sheet. Had the Partnership elected to present these instruments on a net basis, there would be no effect on the consolidated balance sheet as of SeptemberJune 30, 20172018 (net asset of nil$5 million as of December 31, 2016)2017).
As discussed in Note 5 within Item 1. Financial Statements, the Partnership’s 2013 Term Loan that was due July 1, 2018, was amended to extend the maturity period through October 2, 2022. As a result of this extension, the Partnership implemented an interest rate hedging strategy during the fourth quarter and hedged the entire $500 million until its October 2, 2022 maturity using forward starting swaps at an average rate of 3.26 percent.
In anticipation of a debt refinancing in 2003, PNGTS entered into forward interest rate swap agreements to hedge the interest rate on its Senior Secured Notes due in 2018. These interest rate swaps were used to manage the impact of interest rate fluctuations and qualified as derivative financial instruments in accordance with ASC 815, Derivatives and Hedging.Hedging. PNGTS settled its position with a payment of $20.9 million to counterparties at the time of the refinancing and recorded the realized loss in accumulated other comprehensive income as of the termination date. The previously recorded loss is currently beingwas amortized against earnings over the life of the PNGTS Senior Secured Notes. At September 30, 2017,On May 10, 2018, PNGTS paid the remaining principal balance of its 2003 Senior Secured Notes using its available cash and, as a result, our 61.71 percent proportionate share of the net unamortized loss on PNGTS included in other comprehensive income was $1 millionall amortized against earnings (December 31, 20162017 - $2$1 million). For the three and ninesix months ended SeptemberJune 30, 2017,2018, our 61.71 percent proportionate share of the amortization of realized loss on derivative instruments was nil and $1 million respectively (September 30, 2016 —nil and(2017 - $1 million).
OTHER RISKS
Counterparty credit risk represents the financial loss that the Partnership and our pipeline systems would experience if a counterparty to a financial instrument failed to meet its obligations in accordance with the terms and conditions of the financial instruments with the Partnership or its pipeline systems. The Partnership and our pipeline systems have significant credit exposure to financial institutions as they provide committed credit lines and critical liquidity in the interest rate derivative market, as well as letters of credit to mitigate exposures to non-creditworthy customers. The Partnership closely monitors the creditworthiness of our counterparties, including financial institutions. However, we cannot predict to what extent our business would be impacted by uncertainty in energy commodity prices, including possible declines in our customers’ creditworthiness.
Our maximum counterparty credit exposure with respect to financial instruments at the balance sheet date consists primarily of the carrying amount, which approximates fair value, of non-derivative financial assets, such as accounts receivable as well as the fair value of derivative financial assets. We review our accounts receivable regularly and record allowances for doubtful accounts using the specific identification method. At SeptemberJune 30, 2017,2018, we had not incurred any significant credit losses and had no significant amounts past due or impaired. At SeptemberJune 30, 2017, we had a credit risk concentration on one of our customers,2018 Anadarko Energy Services Company which owed us approximately $4 million and this amountwhich represented greater than 10 percent of our trade accounts receivable.
Liquidity risk is the risk that the Partnership and our pipeline systems will not be able to meet our financial obligations as they become due. Our approach to managing liquidity risk is to ensure that we always have sufficient cash and credit facilities to meet our obligations when due, under both normal and stressed conditions, without incurring unacceptable losses or damage to our reputation.
At SeptemberJune 30, 2017,2018, the Partnership had a Senior Credit Facility of $500 million maturing in 2021 and the outstanding balance on this facility was $255$140 million. In addition, PNGTS has a $125 million Revolving Credit Facility maturing in 2023 that has not been utilized at June 30, 2018 and Northern Border had a committed revolving bank line of $200 million maturing in 2020 with $16$15 million drawn at SeptemberJune 30, 2017. Both the2018. The Senior Credit Facility, and the Northern Border $200 million credit facility and the PNGTS $125 million credit facility all have accordion features for additional capacity of $500 million, $100 million and $100$50 million, respectively, subject to lender consent.
Item 4. Controls and Procedures
EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES
As required by Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (“Exchange Act”)(Exchange Act) the management of our General Partner, including the principal executive officer and principal financial officer, evaluated as of the end of the period covered by this report the effectiveness of our disclosure controls and procedures. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. The Partnership’s disclosure controls and procedures are designed to provide reasonable assurance of achieving their objectives. Based upon and as of the date of the evaluation, the management of our General Partner, including the principal executive officer and principal financial officer, concluded that the Partnership’s disclosure controls and procedures as of the end of the period covered by this quarterly report were effective to provide reasonable assurance that the information required to be disclosed by the Partnership in the reports that it files or submits under the Exchange Act, is (a) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and (b) accumulated and communicated to the management of our General Partner, including the principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.
Changes in Internal Control Over Financial Reporting
During the quarter ended SeptemberJune 30, 2017,2018, there was no change in the Partnership’s internal control over financial reporting that has materially affected or is reasonably likely to materially affect our internal control over financial reporting.
We are involved in various legal proceedings that arise in the ordinary course of business, as well as proceedings that we consider material under federal securities regulations. For additional information on other legal and environmental proceedings affecting the Partnership, please refer to Part 1 - Item 3 of the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2016.2017.
Great Lakes v. Essar Steel Minnesota LLC, et al. —
A description of this legal proceeding can be found in Note 1516 within Item 1 “Financial Statements” of this Quarterly Report on Form 10-Q, and is incorporated herein by reference.
In addition to the above written matter, we and our pipeline systems are parties to lawsuits and governmental proceedings that arise in the ordinary course of our business.
The following updated risk factors should be read in conjunction with the risk factors disclosed in Part I, Item 1A.1A “Risk Factors,” in our Annual Report on Form 10-K for the year ended December 31, 2016.2017.
FollowingWe are exploring and evaluating potential mitigation strategies to the closing of the 2017 Acquisition, we will not own2018 FERC Actions and other factors, including a controlling interestpossible reorganization that could result in Iroquois, and we will be unable to cause certain actions to take place without the agreement of the other partners.us no longer being a master limited partnership.
The major policiesGiven the effects of Iroquoisa number of factors, including the 2017 Tax Act and the 2018 FERC Actions, which resulted in an uncertainty of whether we could be restored as a viable funding lever for TransCanada, we are established by its management committee, which consistsevaluating potential strategic alternatives for the Partnership, including whether remaining a master limited partnership is the appropriate structure for us.
No decision has been made with respect to any mitigation strategies and we cannot assure you that the exploration of individuals who are designated by eachmitigation strategies will result in the identification or consummation of any transaction that allows our unitholders to realize an increase in the value of their common units or provide any guidance on the timing of such action, if any. We also cannot assure you that any mitigation strategy, if identified, evaluated and consummated, will provide greater value to our unitholders than that reflected in the current price of our common units.
We do not intend to comment regarding the evaluation of strategic alternatives until such time as the board of directors of our general partner has determined the outcome of the partners and includes one individual designated by us. The management committee requires at least the affirmative vote ofprocess or otherwise has deemed that disclosure is appropriate. As a majority of the partners’ percentage interestsconsequence, perceived uncertainties related to take any action. Because of these provisions, without the concurrence of other partners, we would be unable to cause Iroquois to take or not to take certain actions, even though those actionsour future may beresult in the best interestsloss of potential business opportunities and volatility in the Partnership or Iroquois. Further, Iroquois may seek additional capital contributions. Our fundingmarket price of these capital contributions would reduce the amount of cash otherwise available for distribution to our unitholders. In the event we elected not to, or were unable to, make a capital contribution to Iroquois; our ownership interest would be diluted.common units.
Changes in TransCanada’s costs or their cost allocation practices could have an effectOur strategy of providing stable cash distributions on our results of operations, financial position and cash flows.common units by expanding our business may be significantly inhibited by the 2018 FERC Actions.
TransCanada has historically sold certain FERC-regulated assets to the Partnership, subject to TransCanada’s funding needs and market conditions. Absent these dropdowns from TransCanada, our options for further growth could be significantly limited and there is uncertainty in whether we could be restored as a viable funding lever for TransCanada as a result of the 2018 FERC Actions. Also, market response to the 2018 FERC Actions has increased the relative cost of equity that the Partnership would incur to partially fund acquisitions or expansions in the future. Further deterioration of financial conditions could also raise the borrowing costs of the Partnership.
If we cannot successfully finance and complete expansion projects or make and integrate acquisitions that are accretive and the earnings of our existing pipeline systems are materially and adversely impacted as a result of the 2018 FERC Actions, we will not be able to maintain historical levels of cash flow and distributions. For example, if we are unable to replace revenues from Bison once its contracts expire in January of 2021 or we are unable to replace cash flow that may be reduced through future rate proceedings, we could be required to take additional proactive measures, including further reductions in distributions from the current level of $0.65 per common unit, to facilitate repayments of debt as may be needed to maintain compliance with financial covenants, in addition to taking other significant strategic actions.
Rates and other terms of service for our pipeline systems are subject to approval and potential adjustment by FERC, which could limit their ability to recover all costs of capital and operations and negatively impact their rate of return, results of operations and cash available for distribution.
Our pipeline systems are subject to extensive regulation over virtually all aspects of their business, including the types and terms of services they may offer to their customers, construction of new facilities, creation, modification or abandonment of services or facilities, and the rates that they can charge to shippers. Under the Natural Gas Act, their rates must be just, reasonable and not unduly discriminatory. Actions by FERC could adversely affect our pipeline systems’ ability to recover all of their current or future costs and could negatively impact their rate of return, results of operations and cash available for distribution.
Due to the uncertainties surrounding the 2018 FERC Actions, implementation of our regulatory strategy to minimize any negative impact on our future operating performance and cash flows will take time. Moreover, we believe that future results of operations, cash flows and financial position of the Partnership Agreement,could be materially and negatively impacted once our pipelines’ rates are ultimately adjusted following these decisions. Our assumptions around the Partnership’spotential outcomes of the 2018 FERC Actions could be incorrect such that cash available for distribution in the future would be lower than anticipated, which could necessitate further action beyond our immediate responses described under Item 2 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Quarterly Report on Form 10-Q.
Future events, such as the outcome of the 2018 FERC Actions, could negatively impact our estimates of fair value of our pipeline systems operatedand equity investments, necessitating recognition of impairment.
We consider the carrying value of our assets, including goodwill and our equity method investments, whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. For the investments that we account for under the equity method, the impairment test requires us to consider whether the fair value of the equity investment as a whole, not the underlying net assets, has declined and whether that decline is other than temporary. Our assumptions related to the estimated fair value of our remaining carrying value of each of our pipeline systems could be negatively impacted by TransCanada are allocated certain costsnear and long-term conditions including:
· future regulatory rate action or settlement,
· valuation of operations at TransCanada’s sole discretion. Accordingly, revisionsassets in future transactions,
· changes in customer demand for pipeline capacity and services,
· changes in North American natural gas production in the allocation processmajor producing basins,
· changes in natural gas prices and natural gas storage market conditions, and
· changes in other long-term strategic objectives.
There is a risk that adverse changes in these key assumptions as a result of the 2018 FERC Actions or changesother circumstances could result in future impairment of the carrying value of our pipeline systems.
The development of fair value estimates requires significant judgment including estimates of future cash flows, which are dependent on internal forecasts, estimates of the long-term rate of growth, estimates of the useful life over which cash flows will occur, and determination of weighted average cost of capital. Following the 2018 FERC Actions, many of these elements will be revisited as individual rate proceedings clarify specific applications of the new policies and rules. At this time, we are unable to corporate structure mayprecisely calculate the impact on fair value, if any, due to uncertainties surrounding the Partnership’s operating results. TransCanada reviews any changes and their prospective impact for reasonableness, however there can be no assurance that allocated operating costs will remain consistent from period to period.2018 FERC Actions.
Exhibits designated by an asterisk (*) are filed herewith and those designated with asterisks (**) are furnished herewith; all exhibits not so designated are incorporated herein by reference to a prior filing as indicated.
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Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on this 6th day of November 2017.
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Exhibits designated by an asterisk (*) are filed herewith and those designated with asterisks (**) are furnished herewith; all exhibits not so designated are incorporated herein by reference to a prior filing as indicated.
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| XBRL Instance Document. |
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| XBRL Taxonomy Extension Schema Document. |
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| XBRL Taxonomy Extension Calculation Linkbase Document. |
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| XBRL Taxonomy Definition Linkbase Document. |
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| XBRL Taxonomy Extension Label Linkbase Document. |
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| XBRL Taxonomy Extension Presentation Linkbase Document. |
49Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on this 2nd day of August 2018.
TC PIPELINES, LP | ||
(A Delaware Limited Partnership) | ||
by its General Partner, TC PipeLines GP, Inc. | ||
By: | /s/ Nathaniel A. Brown | |
Nathaniel A. Brown | ||
President | ||
TC PipeLines GP, Inc. (Principal Executive Officer) | ||
By: | /s/ William C. Morris | |
William C. Morris | ||
Vice President and Treasurer | ||
TC PipeLines GP, Inc. (Principal Financial Officer) |