HOUSTON, Feb. 21, 2019 (GLOBE NEWSWIRE) -- TC PipeLines, LP (NYSE: TCP) (the Partnership) today reported a net loss attributable to controlling interests of $413 million and $182 million for the quarter and year ended December 31, 2018, respectively, after considering the non-cash impairment charges on Bison and Tuscarora partially offset by the revenue received from Bison’s contract buy-out described more fully below. During the quarter, the Partnership generated adjusted earnings of $86 million and distributable cash flow of $95 million. For the year ended December 31, 2018, adjusted earnings were $317 million and distributable cash flow was $391 million.
“The Partnership’s assets performed well in 2018 and generated solid operational results, benefiting from increased natural gas flows, mainly out of the Western Canadian Sedimentary Basin, and from additional contracting across our suite of assets,” said Nathan Brown, president of TC PipeLines, GP, Inc. “This positive performance was achieved despite a challenging year on the regulatory front and in the broader MLP space. As a result of these solid results, together with our prudent financial actions, we are entering 2019 with a healthy balance sheet, strong distribution coverage and a revitalized regulatory position.”
“Our pipeline assets continue to be in high demand due to their commercially favorable geographic locations and competitive positioning,” added Brown. “We continue to pursue further organic expansion opportunities and are pleased to have announced progress on PNGTS’ Westbrook XPress project last week. Ongoing development of organic growth projects like Westbrook continues to demonstrate our ability to economically and efficiently expand our existing infrastructure. At the end of 2018, we also monetized the value of certain future Bison cash flows via an up-front cash payment. Given the continued uncertainty regarding future cash flows on Bison, however, we have taken an impairment charge to earnings during the fourth quarter on this pipeline, together with a lesser charge for Tuscarora regarding its goodwill value, to bring the carrying value of these pipeline systems in line with their fair value. These non-cash charges had no impact on our cash-generating ability or debt covenants and we are pleased to report that our distributable cash flow in 2018 reached an all-time high of $391 million, a testament to the resiliency and strength of our asset portfolio.”
Full Year and Fourth Quarter Highlights (unaudited)
- Full Year Highlights
- Incurred a net loss of $182 million after accounting for non-cash impairment charge on Bison and non-cash goodwill impairment charge on Tuscarora, partially offset by Bison’s contract buy-out proceeds
- Generated adjusted earnings of $317 million and adjusted EBITDA of $526 million
- Paid cash distributions of $218 million to the common unitholders and the General Partner
- Declared cash distribution of $2.60 per common unit or $0.65 per quarter
- Generated distributable cash flow of $391 million
- Reduced long-term debt balance by $295 million
- Fourth Quarter Highlights
- Incurred a net loss of $413 million as a result of the aforementioned non-cash impairment charges partially offset by Bison’s contract buy-out proceeds
- Generated adjusted earnings of $86 million and adjusted EBITDA of $140 million
- Paid cash distributions of $47 million to the common unitholders and the General Partner
- Declared cash distribution of $0.65 per common unit, consistent with the distributions declared in the first, second and third quarters of 2018
- Generated distributable cash flow of $95 million
- Received approval from the Federal Energy Regulatory Commission (FERC) of Gas Transmission Northwest (GTN) rate settlement on November 30, 2018
- Reached settlements-in-principle on both Tuscarora and Iroquois with their respective customers, the terms of which are expected to be filed with FERC by the end of March
- Finalized regulatory approaches on all assets and obtained FERC approvals where applicable
- Fully repaid the $170 million term loan credit facility (Term Loan)
- Commenced Phase 1 of Portland XPress expansion project on November 1, 2018
The Partnership’s financial highlights for the fourth quarter and full year of 2018 compared to the same period in 2017 were:
| Three months ended | Twelve months ended | ||||||||||
| (unaudited) | December 31, | December 31, | |||||||||
| (millions of dollars, except per common unit amounts) | 2018 | 2017 | 2018 | 2017 | |||||||
| Net income (loss) attributable to controlling interests | (413) | 66 | (182) | 252 | |||||||
| Net income (loss) per common unit – basic and diluted (b) | ($5.80) | $0.77 | ($2.68) | $3.16 | |||||||
| Adjusted earnings (a) | 86 | 66 | 317 | 252 | |||||||
| Adjusted earnings per common unit – basic and diluted (a) (b) | $1.06 | $0.77 | $4.18 | $3.16 | |||||||
| Earnings before interest, taxes, depreciation and amortization (EBITDA) (a) | (359) | 117 | 27 | 445 | |||||||
| Adjusted earnings before interest, taxes, depreciation and amortization (Adjusted EBITDA) (a) | 140 | 117 | 526 | 445 | |||||||
| Cash distributions paid | (47) | (74) | (218) | (284) | |||||||
| Class B distributions paid | - | - | (15) | (22) | |||||||
| Distributable cash flow (a) | 95 | 72 | 391 | 310 | |||||||
| Cash distribution declared per common unit | $0.65 | $1.00 | $2.60 | $3.94 | |||||||
| Weighted average common units outstanding – basic and diluted (millions) (c) | 71.3 | 70.0 | 71.3 | 69.2 | |||||||
| Common units outstanding, end of period (millions) (c) | 71.3 | 70.6 | 71.3 | 70.6 | |||||||
| (a) Distributable cash flow, EBITDA, Adjusted EBITDA, Adjusted earnings and Adjusted earnings per common unit are non-GAAP financial measures. Refer to the description of these non-GAAP financial measures in the section of this release entitled “Non-GAAP Measures” and the Supplemental Schedule for further detail. | |||||||||||
| (b) Net income (loss) per common unit is computed by dividing net income (loss) attributable to controlling interests, after deduction of net income attributed to Portland Natural Gas Transmission System’s (PNGTS) former parent and amounts attributable to the General Partner and Class B units, by the weighted average number of common units outstanding. Adjusted earnings per common unit is computed by dividing adjusted earnings, after deduction of net income attributed to PNGTS’ former parent and amounts attributable to the General Partner and Class B units, by the weighted average number of common units outstanding. Refer to Financial Summary-Consolidated Statements of Operations section of this release. | |||||||||||
| (c) Under the ATM program, the Partnership issued 732,973 units during the twelve months ended December 31, 2018 (all units were issued during the first quarter ended March 31, 2018). | |||||||||||
FERC Actions
During the fourth quarter, the Partnership completed its regulatory filings to address the issues contemplated by the 2017 Tax Cuts and Jobs Act (2017 Tax Act) and certain FERC actions that began in March of 2018, namely FERC’s Revised Policy Statement on Treatment of Income Taxes (Revised Policy Statement) and a Final Rule that established a schedule by which interstate pipelines must either (i) file a new uncontested rate settlement or (ii) file a one-time report, called FERC Form No. 501-G, that quantified the rate impact of the 2017 Tax Act on FERC-regulated pipelines and the impact of the Revised Policy Statement on pipelines held by a Master Limited Partnership (MLP) (collectively “2018 FERC Actions”).
The Final Rule issued in July 2018 allowed MLPs and other pass through entities to remove the Accumulated Deferred Income Tax (ADIT) liability from rate base, and thus increase net recoverable rate base, partially mitigating the loss of the tax allowance in cost-of-service based rates. Following the elimination of the tax allowance and ADIT liability from rate base, recent rate settlements and related filings of all the pipelines held wholly or in part by the Partnership, the estimated impact of the tax-related changes to our revenue and cash flow is a reduction of approximately $30 million per year on an annualized basis beginning in 2019.
The actions taken by our pipelines are outlined below:
| Pipeline | Form 501-G Filing Option | Impact on Maximum Rates | Moratorium, Mandatory Filing Requirements and Other Considerations | |||
| Great Lakes | Reduction in rates - limited Natural Gas Act (NGA) Section 4 filing; accepted by FERC | 2.0% rate reduction effective February 1, 2019 | No moratorium in effect; comeback provision with new rates to be effective by October 1, 2022 | |||
| GTN | Settlement approved by FERC on November 30, 2018 eliminated the requirement to file Form 501-G | A refund of $10 million to its firm customers in 2018; 10.0% rate reduction effective January 1, 2019; additional rate reduction of 6.6% effective January 1, 2020 through December 31, 2021; these reductions will replace the 8.3% rate reduction in 2020 agreed to as part of the last settlement in 2015 | Moratorium on rate changes until December 31, 2021; comeback provision with new rates to be effective by January 1, 2022 | |||
| Northern Border | Reduction in rates – limited NGA Section 4 filing; accepted by FERC | 2.0% rate reduction effective February 1, 2019; proposed additional 2.0% rate reduction effective January 1, 2020 | No moratorium in effect; comeback provision with new rates to be effective by July 1, 2024 | |||
| Tuscarora | Reduction in rates – limited NGA Section 4 filing; subsequently reached a settlement with customers and a notice of settlement-in-principle was filed with FERC on January 29, 2019 | Expected to be finalized with the settlement | Expected to be finalized with the settlement | |||
| Bison | Explained why no rate change was needed | No rate change | No moratorium or comeback provisions | |||
| Iroquois | Explained why no rate change was needed; subsequently reached a settlement with customers and a notice of settlement-in-principle was filed with FERC on January 9, 2019 | Expected to reduce rates by the impact of the 2017 Tax Act shown on Form 501-G | Likely to be reaffirmed with the settlement | |||
| PNGTS | Explained why no rate change was needed; accepted by FERC | No rate change | No moratorium or comeback provisions | |||
| North Baja | Reduction in rates – limited NGA Section 4 filing; accepted by FERC | 10.8% rate reduction effective December 1, 2018 | No moratorium or comeback provisions; approximately 90% of North Baja’s contracts are negotiated; 10.8% reduction applies to maximum rate contracts only | |||
Outlook of Our Business
With the 2018 FERC Actions and the uncertainty surrounding the magnitude of their impact substantially behind us, we believe our pipeline systems, which are largely backed by long-term take-or-pay contracts, will deliver consistent financial performance going forward and support our current quarterly distribution level of $0.65 per common unit for the foreseeable future.
As the Partnership does not anticipate further dropdown transactions from TransCanada under current market conditions, we will focus on taking advantage of North America’s abundant natural gas supply and our assets’ connectivity to premium markets to compete for organic growth within our existing footprint, such as PNGTS’ Westbrook XPress project (see below for further details). Our largest assets, GTN, Northern Border and Great Lakes, benefited from positive market conditions in 2018. We are actively seeking opportunities to further optimize their capacity through potential expansion projects or commercial, regulatory and operational changes in response to positive supply fundamentals. Our Iroquois, North Baja and Tuscarora pipelines are expected to continue to deliver steady results.
We continue to evaluate redeployment alternatives for our Bison pipeline following expiration of its remaining long-term contracts in January 2021, including the potential to repurpose it for liquids service or reverse the pipeline to transport growing associated natural gas supplies from the Bakken or low-cost supplies from the Western Canadian Sedimentary Basin (WCSB). The safe and reliable operation of our pipeline assets remains our top priority as we prudently fund ongoing capital expenditures, repay debt and manage our financial metrics.
Non-cash Impairments
Bison
During the fourth quarter of 2018, two of Bison’s customers elected to pay out the remainder of their future contracted obligations and terminate the associated transportation agreements. The termination of these agreements resulted in a $97 million cash payment in December 2018, which was used by the Partnership, together with other cash, to repay in full the balance of our $170 million Term Loan. The $97 million was recorded as revenue as the contract terminations released Bison from providing any future services.
Commercial potential exists to either reverse the direction of gas flow on Bison for deliveries on to third party pipelines ultimately connecting into the Cheyenne hub or to repurpose for liquids service. However, the recent contract termination, coupled with the persistence of market conditions which have inhibited system flows on the pipeline and the uncertainty regarding Bison’s ability to generate positive cash flows after the expiry of its remaining customer contracts in January 2021, led us to determine that the asset’s current carrying value was no longer recoverable. As a result, a non-cash impairment charge of $537 million was recorded in the fourth quarter of 2018. We continue to explore alternative transportation-related options for Bison.
Tuscarora
In the fourth quarter of 2018, Tuscarora initiated its regulatory approach in response to the 2018 FERC Actions, resulting in a reduction in maximum rates. In connection with its annual goodwill impairment analysis, we evaluated Tuscarora’s future revenues as well as changes to other valuation assumptions responsive to Tuscarora’s environment, which included estimated discount rates and earnings multiples. We also considered in our overall conclusion the outcome of the January 2019 settlement-in-principle reached by Tuscarora with its customers. As a result, it was determined that the fair value of Tuscarora was lower than its carrying value, including goodwill, and the Partnership recorded a non-cash goodwill impairment charge of $59 million in the fourth quarter of 2018 and reduced our total consolidated goodwill balance from $130 million to $71 million. The goodwill balance related to Tuscarora on December 31, 2018 was $23 million (2017 – $82 million).
Other notable business development:
Westbrook XPress Project
Westbrook XPress Project (Westbrook XPress) is an estimated $100 million multi-phase expansion project that is expected to generate approximately $30 million in revenue for PNGTS on an annualized basis when fully in service. It is part of a coordinated offering to transport incremental Western Canadian Sedimentary Basin natural gas supplies to the Northeast U.S. and Atlantic Canada markets through additional compression capability at an existing PNGTS facility. Westbrook XPress is designed to be phased in over a three-year period with Phase 1 and Phase 2 estimated in-service dates of November 2019 and 2021, respectively. These two Phases will add incremental capacity of approximately 43,000 Dth/day and 63,000 Dth/day, respectively. Westbrook XPress, together with Portland XPress, will increase PNGTS’ capacity by approximately 70 percent from 210,000 Dth/day to approximately 350,000 Dth/day.
Results of Operations
For the three months ended December 31, 2018, we incurred a net loss of $413 million primarily due to the non-cash goodwill impairment charge of $59 million related to Tuscarora and the $537 million non-cash long-lived assets impairment charge related to Bison reported as impairment of goodwill and impairment of long-lived assets, respectively, on the Consolidated Statement of Operations. These non-cash impairment charges were partially offset by Bison’s $97 million contract buy-out proceeds recognized as revenue during the quarter.
Adjusted earnings were $86 million, a $20 million increase compared to the same period in 2017. The increase was primarily due to higher revenues and higher equity earnings of $14 million and $7 million, respectively.
Revenues - Excluding the $97 million revenue proceeds from Bison’s contract buy-out, our revenues increased by $14 million, largely due to the net effect of:
- Higher revenue from PNGTS primarily due to incremental contracting from PNGTS’ Continent-to-Coast contracts and the Portland XPress Phase I contracts that began in November of 2018, together with an increase in short-term firm revenue; and
- Higher net revenue from GTN primarily due to an increase in incremental long-term services sold by GTN associated with the increased available upstream capacity following debottlenecking activities on upstream pipelines owned by TransCanada, the ultimate parent company of our General Partner, partially offset by lower revenues from GTN’s short-term discretionary services compared to the prior period.
Equity Earnings - The $7 million increase in equity earnings was primarily due to higher income on Great Lakes as a result of the elimination of Great Lakes’ revenue sharing mechanism that began in 2018 as part of the settlement achieved by Great Lakes in 2017. Additionally, Great Lakes experienced an increase in seasonal sales during the current period.
Our adjusted EBITDA was $23 million higher for the fourth quarter of 2018 compared to the same period in 2017 mostly due to higher equity earnings and increased revenues during the period as discussed above.
Distributable cash flow increased by $23 million in the fourth quarter of 2018 compared to the same period in 2017 largely due to the increase in adjusted earnings as described above and reduced distributions allocated to our General Partner as a result of lower declared common unit distributions. These gains were partially offset by an increase in distributions to non-controlling interests on PNGTS as a result of the increase in revenue noted above.
Cash Flow Analysis
The Partnership’s net cash provided by operating activities increased by $164 million for the year ended December 31, 2018 compared to 2017 primarily due to the net effect of:
- Higher cash flow from operations at Bison due to the $97 million cash proceeds received related to the contract buy-out agreement reached with two of its customers;
- The addition of distributions from Iroquois for twelve months in 2018 as compared to the seven-month period from June 1 to the end of December in 2017;
- Higher distributions received from Great Lakes primarily due to an increase in its revenue as a result of its higher short-term incremental revenue during the year and the elimination of Great Lakes’ revenue sharing mechanism that began in 2018 as part of Great Lakes’ rate settlement in 2017;
- Higher cash flow from operations at PNGTS and North Baja primarily resulting from an increase in their revenues; PNGTS’ revenue was higher due to incremental contracting activity partially offset by certain expiring winter contracts while North Baja’s revenue was higher due to an increase in its short-term firm transportation services; and
- Higher interest paid attributable to additional borrowings to finance the 2017 acquisition of interests in Iroquois and PNGTS.
Net cash used in investing activities decreased by $726 million for the year ended December 31, 2018 compared to the same period in 2017 primarily due to the net effect of:
- $646 million total cash payment to TransCanada in 2017 for the Partnership’s acquisition of the 49.34% interest in Iroquois and TransCanada’s remaining 11.81% interest in PNGTS (2017 Acquisition);
- $83 million equity contribution to Northern Border in the third quarter of 2017 representing our 50 percent share of a requested capital contribution to reduce the outstanding balance of Northern Border’s revolving credit facility;
- $10 million in unrestricted cash distributions received from Iroquois for the year ended December 31, 2018 representing a return of investment, which was $5 million higher than the unrestricted cash distribution received during the seven months ended December 31, 2017;
- $11 million increase in capital expenditures in 2018 related to ongoing maintenance projects; the increase in 2018 reflected timing of payments as the scope of the maintenance work was relatively comparable in 2018 and 2017; and
- $3 million increase in customer advances for construction related to an interconnect project on GTN.
The Partnership’s net cash from financing activities decreased by $859 million during 2018 compared to 2017 due to the net effect of:
- $297 million in net debt repayments in 2018 compared to $492 million in net debt issuances in 2017 primarily due to the issuance of $500 million 3.90% Senior Notes on May 25, 2017 to partially finance the 2017 Acquisition compared to reductions in outstanding debt in 2018, including the repayment of the Partnership’s $170 million Term Loan together with repayments under our senior facility under the revolving credit agreement as amended and restated, dated September 29, 2017 (Senior Credit Facility);
- $136 million decrease in ATM equity issuances in 2018 as compared to 2017;
- $66 million decrease in distributions paid on our common units including our General Partner’s effective two percent share and its related incentive distribution rights as a result of the lower distributions declared for the first three quarters of 2018 as compared to the first three quarters of 2017;
- $7 million decrease in distributions paid to Class B units; and
- $9 million increase in distributions paid to non-controlling interests due to higher distributions from PNGTS in 2018.
At December 31, 2018, our cash and cash equivalents were unchanged from our position at December 31, 2017 but our leverage was significantly lower. In 2018, we reduced the outstanding balance of our Senior Credit Facility by 78 percent, from $185 million at December 31, 2017 to $40 million at December 31, 2018, and repaid the Partnership’s 2015 $170 million Term Loan using the proceeds from the Bison contract buy-outs and cash on hand such that the Partnership’s overall consolidated total debt was reduced by 12.3 percent, from $2,403 million in December 31, 2017 to $2,108 million at December 31, 2018. As of February 21, 2019, the available borrowing capacity under our Senior Credit Facility is $475 million. We believe our cash position, remaining borrowing capacity under our Senior Credit Facility, and our operating cash flows are adequate to fund our short-term liquidity requirements, including distributions to our unitholders, ongoing capital expenditures and required debt repayments.
Non-GAAP Financial Measures
The following non-GAAP financial measures are presented as a supplement to our financial statements:
- EBITDA
- Adjusted EBITDA
- Adjusted earnings
- Adjusted earnings per common unit
- Total distributable cash flow
- Distributable cash flow
EBITDA is an approximate measure of our operating profitability during the current earnings period and reconciles directly to the net income amount presented. It measures our earnings before deducting interest, taxes, depreciation and amortization and net income attributable to non-controlling interests and includes earnings from our equity investments.
We do not believe our net income or our EBITDA is reflective of our underlying operations during the periods presented and, therefore, we present adjusted earnings and adjusted EBITDA as non-GAAP measures that exclude the impact of the following non-recurring items from earnings and EBITDA, respectively:
- Bison’s contract buy-out proceeds amounting to $97 million recognized as revenue during the fourth quarter of 2018;
- $537 million non-cash impairment charge related to Bison’s remaining balance of property, plant and equipment on Bison; and
- $59 million non-cash impairment charge related to Tuscarora’s goodwill.
Total distributable cash flow and distributable cash flow provide measures of distributable cash generated during the current earnings period and reconcile directly to the net income amounts presented.
Total distributable cash flow includes Adjusted 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 two percent interest plus an amount equal to incentive distributions. For the year ended December 31, 2018, distributions allocable to the Class B units (30 percent of GTN’s 2018 distributable cash flow less $20 million), was further reduced by 35 percent, which is equivalent to the percentage by which distributions payable to the common units were reduced in 2018 (Class B Reduction). The Class B Reduction was implemented during the first quarter of 2018 following the Partnership’s common unit distribution reduction of 35 percent. The Class B Reduction will apply to any calendar year during which distributions payable in respect of common units for such calendar year are less than $3.94 per common unit.
The non-GAAP financial measures described above are performance measures presented to assist investors in evaluating our business performance. We believe these measures provide additional meaningful information in evaluating our financial performance and cash generating capacity.
The non-GAAP financial measures presented as part of this release are provided as a supplement to GAAP financial results and are not meant to be considered in isolation or as substitutes for financial information prepared in accordance with GAAP. Additionally, these measures as presented may not be comparable to similarly titled measures of other companies.
For a reconciliation of these non-GAAP financial measures to GAAP measures, please see the tables captioned "Reconciliation of Net income (loss) to Distributable Cash Flow”, “Reconciliation of net income (loss) attributable to controlling interest to adjusted earnings” and “Reconciliation of net income (loss) per common unit interest to adjusted earnings per common unit” included at the end of this release.
Conference Call
Members of the investment community and other interested parties are invited to participate in a teleconference by calling 800.273.9672 on Thursday, February 21, 2019 at 10 a.m. CT/11 a.m. ET. Nathan Brown, president of the General Partner, will discuss the fourth quarter financial results and provide an update on the Partnership’s business, followed by a question and answer session. Please dial in 10 minutes prior to the start of the call. No pass code is required. A live webcast of the conference call will also be available through the Partnership’s website at www.tcpipelineslp.com or via the following URL: http://www.gowebcasting.com/9862. Slides for the presentation will be posted on the Partnership’s website under “Events and Presentations” prior to the webcast.
A replay of the teleconference will also be available two hours after the conclusion of the call and until 11 p.m. CT and midnight ET on February 28, 2019, by calling 800.408.3053, then entering pass code 9718021#.
About TC PipeLines, LP
TC PipeLines, LP is a Delaware master limited partnership with interests in eight federally regulated U.S. interstate natural gas pipelines which serve markets in the Western, Midwestern and Northeastern United States. The Partnership is managed by its general partner, TC PipeLines GP, Inc., a subsidiary of TransCanada Corporation (NYSE: TRP). For more information about TC PipeLines, LP, visit the Partnership’s website at www.tcpipelineslp.com.
Forward-Looking Statements
Certain non-historical statements in this release relating to future plans, projections, events or conditions are intended to be “forward-looking statements”. These statements are based on current expectations and, therefore, subject to a variety of risks and uncertainties that could cause actual results to differ materially from the projections, anticipated results or other expectations expressed in this release, including, without limitation to the ability of these assets to generate ongoing value to our unitholders, impact of potential impairment charges, decreases in demand on our pipeline systems, increases in operating and compliance costs, the outcome of rate proceedings, the impact of recently issued and future accounting updates and other changes in accounting policies, potential changes in the taxation of MLP investments by state or federal governments such as the elimination of pass-through taxation or tax deferred distributions, our ability to identify and complete expansion and growth opportunities, operating hazards beyond our control, and our ability to access debt and equity markets that negatively impacts the Partnership’s ability to finance its capital spending. These and other factors that could cause future results to differ materially from those anticipated are discussed in Item 1A in our Annual Report on Form 10-K for the year-ended December 31, 2018 filed with the Securities and Exchange Commission (the SEC), as updated and supplemented by subsequent filings with the SEC. 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.
Media Inquiries:
Grady Semmens
403.920.7859 or 800.608.7859
Unitholder and Analyst Inquiries:
Rhonda Amundson
877.290.2772
investor_relations@tcpipelineslp.com
TC PipeLines, LP
Financial Summary
Consolidated Statements of Operations
| Three months ended | Twelve months ended | |||||||||||
| (unaudited) | December 31, | December 31, | ||||||||||
| (millions of dollars, except per common unit amounts) | 2018 | 2017 | 2018 | 2017 | ||||||||
| Transmission revenues, net | 220 | 109 | 549 | 422 | ||||||||
| Equity earnings | 44 | 37 | 173 | 124 | ||||||||
| Impairment of long-lived assets | (537) | - | (537) | - | ||||||||
| Impairment of goodwill | (59) | - | (59) | - | ||||||||
| Operation and maintenance expenses | (19) | (19) | (67) | (67) | ||||||||
| Property taxes | (7) | (7) | (28) | (28) | ||||||||
| General and administrative | (2) | (3) | (6) | (8) | ||||||||
| Depreciation | (24) | (24) | (97) | (97) | ||||||||
| Financial charges and other | (23) | (23) | (92) | (82) | ||||||||
| Net income (loss) before taxes | (406) | 70 | (164) | 264 | ||||||||
| Income taxes | - | - | (1) | (1) | ||||||||
| Net income (loss) | (406) | 70 | (165) | 263 | ||||||||
| Net income attributable to non-controlling interests | 7 | 4 | 17 | 11 | ||||||||
| Net income (loss) attributable to controlling interests | (413) | 66 | (182) | 252 | ||||||||
| Net income (loss) attributable to controlling interest allocation | ||||||||||||
| Common units | (414) | 54 | (191) | 219 | ||||||||
| General Partner | (8) | 5 | (4) | 16 | ||||||||
| TransCanada and its subsidiaries | 9 | 7 | 13 | 17 | ||||||||
| (413) | 66 | (182) | 252 | |||||||||
| Net income (loss) per common unit – basic and diluted (a) | ($5.80) | $0.77 | ($2.68) | $3.16 | ||||||||
| Weighted average common units outstanding – basic and diluted (millions) | 71.3 | 70.0 | 71.3 | 69.2 | ||||||||
| Common units outstanding, end of period (millions) | 71.3 | 70.6 | 71.3 | 70.6 | ||||||||
| (a) Net income (loss) per common unit is computed by dividing net income (loss) attributable to controlling interests, after deduction of amounts attributable to the General Partner and Class B units, by the weighted average number of common units outstanding. The amount allocable to the General Partner equals an amount based upon the General Partner’s effective two percent general partner interest, plus an amount equal to incentive distributions. For the year ended December 31, 2018, the amount allocable to the Class B units is equal to 30 percent of GTN’s annual distributable cash flow, less the threshold amount of $20 million and is further reduced by the Class B Reduction for 2018 (2017 – less the threshold of $20 million; the Class B Reduction was not required). During the three and twelve months ended December 31, 2018, $9 million and $13 million were allocated to the Class B units, respectively (2017 - $7 million and $15 million). | ||||||||||||
TC PipeLines, LP
Financial Summary
Consolidated Balance Sheets
| (unaudited) | ||||||
| (millions of dollars) | December 31, 2018 | December 31, 2017 | ||||
| ASSETS | ||||||
| Current Assets | ||||||
| Cash and cash equivalents | 33 | 33 | ||||
| Accounts receivable and other | 48 | 42 | ||||
| Inventories | 8 | 8 | ||||
| Other | 8 | 7 | ||||
| 97 | 90 | |||||
| Equity investments | 1,196 | 1,213 | ||||
| Property, plant and equipment | ||||||
| (Net of $1,110 accumulated depreciation; 2017 - $1,181) | 1,529 | 2,123 | ||||
| Goodwill | 71 | 130 | ||||
| Other assets | 6 | 3 | ||||
| 2,899 | 3,559 | |||||
| LIABILITIES AND PARTNERS’ EQUITY | ||||||
| Current Liabilities | ||||||
| Accounts payable and accrued liabilities | 36 | 31 | ||||
| Accounts payable to affiliates | 6 | 5 | ||||
| Accrued interest | 12 | 12 | ||||
| Distributions payable | - | 1 | ||||
| Current portion of long-term debt | 36 | 51 | ||||
| 90 | 100 | |||||
| Long-term debt, net | 2,072 | 2,352 | ||||
| Deferred state income taxes | 9 | 10 | ||||
| Other liabilities | 29 | 29 | ||||
| 2,200 | 2,491 | |||||
| Partners’ Equity | ||||||
| Common units | 462 | 824 | ||||
| Class B units | 108 | 110 | ||||
| General partner | 13 | 24 | ||||
| Accumulated other comprehensive income (AOCI) | 8 | 5 | ||||
| Controlling interests | 591 | 963 | ||||
| Non-controlling interest | 108 | 105 | ||||
| 699 | 1,068 | |||||
| 2,899 | 3,559 |
TC PipeLines, LP
Financial Summary
Consolidated Statement of Cash Flows
| Twelve months ended | ||||||
| (unaudited) | December 31, | |||||
| (millions of dollars) | 2018 | 2017 | ||||
| Cash Generated from Operations | ||||||
| Net income (loss) | (165) | 263 | ||||
| Depreciation | 97 | 97 | ||||
| Impairment of long-lived assets | 537 | - | ||||
| Impairment of goodwill | 59 | - | ||||
| Amortization of debt issue costs reported as interest expense | 2 | 2 | ||||
| Amortization of realized loss on derivative instrument | 1 | 1 | ||||
| Equity earnings from equity investments | (173) | (124) | ||||
| Distributions received from operating activities of equity investments | 188 | 140 | ||||
| Change in other long-term liabilities | (2) | - | ||||
| Equity allowance for funds used during construction | (1) | (1) | ||||
| Change in operating working capital | (3) | (2) | ||||
| 540 | 376 | |||||
| Investing Activities | ||||||
| Investment in Northern Border | - | (83) | ||||
| Investment in Great Lakes | (9) | (9) | ||||
| Distribution received from Iroquois as return of investment | 10 | 5 | ||||
| Acquisition of a 49.34 percent in Iroquois and an additional 11.81 percent in PNGTS | - | (646) | ||||
| Capital expenditures | (40) | (29) | ||||
| Other | 4 | 1 | ||||
| (35) | (761) | |||||
| Financing Activities | ||||||
| Distributions paid | (218) | (284) | ||||
| Distributions paid to Class B units | (15) | (22) | ||||
| Distributions paid to non-controlling interests | (14) | (5) | ||||
| Distributions paid to former parent of PNGTS | - | (1) | ||||
| Common unit issuance, net | 40 | 176 | ||||
| Long-term debt issued, net of discount | 219 | 802 | ||||
| Long-term debt repaid | (516) | (310) | ||||
| Debt issuance costs | (1) | (2) | ||||
| (505) | 354 | |||||
| Increase/(decrease) in cash and cash equivalents | - | (31) | ||||
| Cash and cash equivalents, beginning of period | 33 | 64 | ||||
| Cash and cash equivalents, end of period | 33 | 33 | ||||
TC PipeLines, LP
Supplemental Schedule
Non-GAAP Measures
Reconciliations of Net income (loss) to Distributable Cash Flow
| Three months ended | Twelve months ended | |||||||||||
| (unaudited) | December 31, | December 31, | ||||||||||
| (millions of dollars) | 2018 | 2017 | 2018 | 2017 | ||||||||
| Net income (loss) | (406) | 70 | (165) | 263 | ||||||||
| Add: | ||||||||||||
| Interest expense (a) | 23 | 23 | 94 | 84 | ||||||||
| Depreciation and amortization | 24 | 24 | 97 | 97 | ||||||||
| Income taxes | - | - | 1 | 1 | ||||||||
| EBITDA | (359) | 117 | 27 | 445 | ||||||||
| Add: | ||||||||||||
| Impairment of goodwill | 59 | - | 59 | - | ||||||||
| Impairment of long-lived assets | 537 | - | 537 | - | ||||||||
| Bison contract buyout | (97) | - | (97) | - | ||||||||
| ADJUSTED EBITDA | 140 | 117 | 526 | 445 | ||||||||
| Add: | ||||||||||||
| Distributions from equity investments (b) | ||||||||||||
| Northern Border | 25 | 22 | 85 | 82 | ||||||||
| Great Lakes | 17 | 9 | 66 | 38 | ||||||||
| Iroquois (c) | 14 | 14 | 56 | 41 | ||||||||
| 56 | 45 | 207 | 161 | |||||||||
| Less: | ||||||||||||
| Equity earnings: | ||||||||||||
| Northern Border | (19) | (17) | (68) | (67) | ||||||||
| Great Lakes | (14) | (7) | (59) | (31) | ||||||||
| Iroquois | (11) | (13) | (46) | (26) | ||||||||
| (44) | (37) | (173) | (124) | |||||||||
| Less: | ||||||||||||
| Equity AFUDC | (1) | - | (1) | (1) | ||||||||
| Interest expense (a) | (23) | (23) | (94) | (84) | ||||||||
| Income taxes | - | - | (1) | (1) | ||||||||
| Distributions to non-controlling interest (d) | (8) | (4) | (20) | (14) | ||||||||
| Distributions allocated to TransCanada as PNGTS’ former parent (e) | - | - | - | (1) | ||||||||
| Maintenance capital expenditures (f) | (15) | (14) | (36) | (38) | ||||||||
| (47) | (41) | (152) | (139) | |||||||||
| Total Distributable Cash Flow | 105 | 84 | 408 | 343 | ||||||||
| General Partner distributions declared (g) | (1) | (5) | (4) | (18) | ||||||||
| Distributions allocable to Class B units (h) | (9) | (7) | (13) | (15) | ||||||||
| Distributable Cash Flow | 95 | 72 | 391 | 310 | ||||||||
| (a) Interest expense as presented includes net realized loss related to the interest rate swaps and amortization of realized loss on PNGTS’ derivative instruments. | ||||||||||||
| (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. | ||||||||||||
| (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 $10.3 million, respectively, for the three and twelve months ended December 31, 2018 (2017-$2.6 million and $7.8 million). | ||||||||||||
| (d) Distributions to non-controlling interests represent the respective share of our consolidated entities’ distributable cash from earnings not owned by us during the periods presented. | ||||||||||||
| (e) Distributions to TransCanada as PNGTS’ former parent represent TransCanada’s respective share of PNGTS’ distributable cash from earnings not owned by us during the periods presented. | ||||||||||||
| (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. | ||||||||||||
| (g) Distributions declared to the General Partner for the three and twelve months ended December 31, 2018 did not warrant or include any incentive distributions (2017 – $3 million and $12 million). | ||||||||||||
| (h) Distributions allocable to the Class B units is based on 30 percent of GTN’s distributable cashflow during the current reporting period, but declared and paid in the subsequent reporting period. | ||||||||||||
Reconciliation of net income (loss) attributable to controlling interest to Adjusted earnings
| Three months ended | Twelve months ended | ||||||
| (unaudited) | December 31, | December 31, | |||||
| (millions of dollars) | 2018 | 2017 | 2018 | 2017 | |||
| Net income (loss) attributable to controlling interests | (413) | 66 | (182) | 252 | |||
| Add: Impairment of goodwill | 59 | - | 59 | - | |||
| Add: Impairment of long-lived assets | 537 | - | 537 | - | |||
| Less: Bison contract buyout | (97) | - | (97) | - | |||
| Adjusted earnings | 86 | 66 | 317 | 252 | |||
Reconciliation of net income (loss) per common unit to Adjusted earnings per common unit
| Three months ended | Twelve months ended | ||||||
| December 31, | December 31, | ||||||
| (unaudited) | 2018 | 2017 | 2018 | 2017 | |||
| Net income (loss) per common unit – basic and diluted | $ (5.80) | $ 0.77 | $ (2.68) | $ 3.16 | |||
| Add: Impairment of goodwill (a) | 0.81 | - | 0.81 | - | |||
| Add: Impairment of long-lived assets (b) | 7.38 | - | 7.38 | - | |||
| Less: Bison contract buyout (c) | (1.33) | - | (1.33) | - | |||
| Adjusted earnings per common unit | $ 1.06 | $ 0.77 | $ 4.18 | $ 3.16 | |||
| (a) Computed by dividing the $59 million impairment charge, after deduction of amounts attributable to the General Partner with respect to its two percent interest, by the weighted average number of common units outstanding during the period. | |||||||
| (b) Computed by dividing the $537 million impairment charge, after deduction of amounts attributable to the General Partner with respect to its two percent interest, by the weighted average number of common units outstanding during the period. | |||||||
| (c) Computed by dividing the $97 million revenue, after deduction of amounts attributable to the General Partner with respect to its two percent interest, by the weighted average number of common units outstanding during the period. | |||||||
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