EXHIBIT 99.1
NEWS RELEASE
Enbridge Inc. Reports Fourth Quarter 2017 Results
CALGARY, ALBERTA - February 16, 2018 - Enbridge Inc. (Enbridge or the Company) (TSX:ENB) (NYSE:ENB) today reported fourth quarter 2017 financial results and provided a quarterly business update.
FOURTH QUARTER AND FULL YEAR HIGHLIGHTS
(all financial figures are unaudited and in Canadian dollars unless otherwise noted)
• | Earnings of $207 million or $0.13 per common share for the fourth quarter and earnings of $2,529 million or $1.66 per common share for the full year, both including the impact of a number of unusual, non-recurring or non-operating factors |
• | Adjusted earnings were $1,013 million or $0.61 per common share for the fourth quarter and $2,982 million or $1.96 per common share for the full year |
• | Adjusted earnings before interest, income tax and depreciation and amortization (EBITDA) was $2,963 million for the fourth quarter and $10,317 million for the full year |
• | Distributable Cash Flow (DCF) was $1,741 million for the fourth quarter and $5,614 million for the full year; Cash provided by operating activities was $1,341 million for the fourth quarter and $6,584 million for the full year |
• | Completed merger with Spectra Energy (Merger Transaction) creating the largest North American energy infrastructure company with leading liquids, natural gas transmission and natural gas distribution utilities footprints |
• | Achieved 2017 target synergy capture and progressed cost management initiatives |
• | Completed corporate simplification transactions through several sponsored vehicle actions, and filed a utility amalgamation plan with the Ontario Energy Board |
• | Brought a total of $12 billion of growth projects into service in 2017, with an additional $22 billion of secured growth projects expected to come into service through 2020 |
• | Advanced Line 3 Replacement Project construction in Canada; Minnesota regulatory process reaffirmed with the Minnesota Public Utilities Commission (MPUC), permit decisions expected in the second quarter of 2018 |
• | Executed $14 billion of new capital markets funding in 2017 and completed $2.6 billion of asset sales post the Merger Transaction announcement |
• | Announced the details of the Company’s updated 2018 to 2020 strategic business outlook and funding plan; including 2018 DCF guidance of $4.15 - $4.45/share |
• | Increased the dividend by 15% in 2017, increased the dividend by another 10% for 2018 and guided to 10% compound annual dividend per share growth through 2020 |
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CEO COMMENT
“This has been a transformational year for our company,” commented Al Monaco, President and Chief Executive Officer of Enbridge. “With the Spectra Energy assets now in the fold, we have successfully delivered on our strategy to re-balance our business mix with best in class natural gas transmission assets and further enhance and extend our growth potential. We’ve substantially integrated the two companies and are slightly ahead of target for capturing cost synergies as we streamline operations and create an even more effective and efficient organization.
“In addition to the merger, we significantly added to our leading infrastructure footprint, bringing a total of $12 billion of new assets into service, substantially on time and on budget. This marks the single largest year for project completion in our history and these assets will provide growing and predictable cash flows to support our premium dividend growth.
“Our full year financial results came in roughly where we expected and within our DCF/share guidance range. However, as we had previously identified, the timing of the closing of the merger, customer project delays and facility outages, and a weak commodity price environment affecting the gas midstream and energy services businesses impacted our full year results.
“Fourth quarter results were strong and demonstrate the earnings power of our core businesses. Liquids Pipelines volumes reached record levels in December and the demand outlook remains robust into 2018 as WCSB crude production volumes continue to rise. Our Gas Transmission business delivered another rock solid quarter with steady volumes and new projects in service, and the Gas Distribution businesses continued to have strong rate base growth within their franchises. Importantly, we accomplished all of this while maintaining our leading operational safety and reliability performance.
“We also made good progress on our priority to strengthen the balance sheet as we build out our secured growth program, raising about $5 billion of equity or equity equivalent funding during the year. And we have a readily executable plan to achieve our longer term leverage targets by the end of 2018.
“Looking forward, with our updated strategic and financial plan, we’ve set a course for the next three years that reflects the right combination of capital discipline while deleveraging the balance sheet and maintaining ample funding flexibility for our $22 billion secured project inventory. We continue to see a significant opportunity set for new low risk growth in our core footprint beyond the 2020 horizon.
“We accomplished several important milestones in 2017 and we are well positioned heading into 2018 and beyond.”
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FINANCIAL RESULTS SUMMARY
Financial results for the three and twelve months ended December 31, 2017, are summarized in the table below:
Three months ended December 31, | Year ended December 31, | ||||||||
2017 | 2016 | 2017 | 2016 | ||||||
(millions of Canadian dollars, except per share amounts; number of shares in millions) | |||||||||
Earnings | 207 | 365 | 2,529 | 1,776 | |||||
Earnings per common share | 0.13 | 0.39 | 1.66 | 1.95 | |||||
Cash provided by operating activities | 1,341 | 1,058 | 6,584 | 5,211 | |||||
Adjusted EBITDA1 | 2,963 | 1,762 | 10,317 | 6,902 | |||||
Adjusted Earnings1 | 1,013 | 522 | 2,982 | 2,078 | |||||
Adjusted Earnings per common share1 | 0.61 | 0.56 | 1.96 | 2.28 | |||||
Distributable Cash Flow1,2 | 1,741 | 879 | 5,614 | 3,713 | |||||
Weighted average common shares outstanding | 1,652 | 927 | 1,525 | 911 | |||||
1 Schedules reconciling adjusted EBITDA, adjusted earnings, adjusted earnings per common share and distributable cash flow are available as an Appendix to this news release. | |||||||||
2 Formerly referred to as Adjusted Cash Flow From Operations (ACFFO). Calculation methodology remains unchanged. | |||||||||
Earnings attributable to common shareholders for the year ended December 31, 2017 increased by $753 million relative to 2016, primarily as a result of the Merger Transaction. Earnings for the fourth quarter of 2017 decreased by $158 million relative to the comparable period in 2016. The year-over-year and fourth quarter-over-quarter comparability of earnings attributable to common shareholders was impacted by certain unusual and infrequent factors, including a non-cash accounting charge resulting from the write down of assets held for sale of $2.8 billion after tax, partially offset by a non-cash accounting benefit resulting from U.S. Tax Reform of $2.0 billion.
Adjusted earnings growth for the fourth quarter and full year 2017 benefited from the net effect of higher contributions from Enbridge’s new natural gas, liquids and utility assets. Also contributing to earnings growth was stronger crude oil throughput on the Mainline system, new projects coming into service in the Liquids Pipelines, Gas Transmission & Midstream and Gas Distribution segments, and stronger realized settlements on foreign exchange hedges. These positive contributors were partially offset by lower natural gas gathering and processing volumes and margins on certain U.S. midstream assets and weaker performance in the Energy Services segment.
DCF for the fourth quarter was $1,741 million, an increase of $862 million over the comparable prior period in 2016, driven largely by the same factors noted above.
PROJECT EXECUTION UPDATE
Enbridge continues to make good progress executing on its secured growth capital program. These projects are supported by long-term take-or-pay contracts, cost-of-service frameworks or similar low-risk commercial arrangements and are diversified across a wide range of business platforms and regulatory jurisdictions.
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In 2017, $12 billion of commercially secured projects were brought into service, substantially on time and on budget. This execution success highlights Enbridge's strong project management capability and its commitment to managing all critical stakeholder relationships. These projects meaningfully contributed to DCF growth in 2017, with full contributions expected in 2018 and 2019 as contracted capacity ramps up on certain projects and all contribute a full year of earnings and cash flow.
Enbridge is also advancing the remaining $22 billion secured growth project inventory. Construction has commenced on the US$1.3 billion NEXUS gas pipeline and is expected to be in service in the third quarter of 2018. Construction on the US$1.5 billion Valley Crossing pipeline in Texas is progressing well and remains on schedule for a fourth quarter 2018 in service date. The $0.8 billion Rampion offshore wind power generation project in the United Kingdom has begun generating power and full operations are expected in the first half of 2018 as the remaining turbines are connected to the grid.
Following the receipt of all required regulatory permitting for the Line 3 Replacement in Canada, construction began in August 2017 on certain segments of the pipeline and construction will continue through the winter. Regulatory permitting is also in place in North Dakota as well as in Wisconsin where construction is substantially complete.
In Minnesota, the MPUC is expected to vote on the Certificate of Need and Route Permit at the end of the second quarter of 2018. In parallel with this process, additional clarification and analysis will be provided to support the adequacy of the Final Environmental Impact Statement, as requested by the MPUC in December. Management continues to anticipate an in-service date for the project in the second half of 2019.
STRATEGIC & FINANCIAL UPDATE
On November 29th, Enbridge released the details of its updated strategic business plan. The strategic planning process included a review of all existing businesses post-Merger Transaction. The conclusion reached was to focus Enbridge’s asset mix to a pure regulated pipeline and utility business model over time, which emphasizes low risk and strong growth in its three crown jewel businesses: liquids pipelines and terminals, natural gas transmission and storage and natural gas utilities. This focused approach will result in disciplined capital allocation for growth projects and additional non-core asset sales.
The Company also provided details on its secured funding plan designed to fund Enbridge’s secured growth program while deleveraging the balance sheet. The plan achieves strong, investment grade credit metrics throughout the three-year period, with the Company’s Debt to EBITDA metric expected to reach 5.0x by the end of 2018, and remaining below this long term target level going forward.
In 2017, close to $14 billion of new long term capital was raised across the Enbridge group, of which $5 billion was equity or equity equivalent funding. The 2018 funding plan includes the issuance of $3.5 billion of hybrid securities and sale or monetization of at least $3.0 billion of non-core assets in 2018. The remaining equity funding requirement can readily be met through a combination of additional hybrid equity, asset monetization or issuances of common shares under the Company’s DRIP program.
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Enbridge made good progress in 2017 with its strategic priority to restructure and simplify the organization by taking several sponsored vehicle actions, including: the Enbridge Energy Partners, L.P. (EEP) restructuring, Midcoast Energy privatization, DCP Midstream simplification and Spectra Energy Partners, LP (SEP) incentive distribution elimination. Enbridge plan to continue to identify and evaluate further streamlining opportunities as appropriate.
U.S. TAX REFORM
On December 22, 2017, the United States implemented U.S. Tax Reform. The "Tax Cuts and Jobs Act" (the TCJA) was signed into law and became enacted for tax purposes. Substantially all of the provisions of the TCJA are effective for taxation years beginning after December 31, 2017. The most significant change included in the TCJA with respect to Enbridge’s 2017 financial statements was a reduction in the corporate federal income tax rate from 35% to 21%. This resulted in the Company booking a $2.0 billion reduction to its deferred income tax provision for the year, which has been normalized for adjusted earnings purposes. The reduced tax rate will benefit the Company’s DCF once it becomes subject to U.S. current tax in the future.
While certain elements of the TCJA require clarification through more detailed regulation or interpretive guidance, Enbridge does not expect any material impact to consolidated DCF over the plan horizon.
US Tax Reform impacts arising from commercial arrangements at the Company’s sponsored vehicles are not expected to be significant over the 2018-2020 plan horizon. The Company estimates that EEP will realize a reduction in the income tax allowance component of its cost of service toll revenue of approximately US$55 million per year. Enbridge Income Fund would expect to realize the offsetting gain to annual revenue due to the nature of the sharing of the International Joint Toll on the Mainline system. While SEP has a portion of its revenue derived from cost of service assets, any revenue loss associated with the change in tax rate is expected to be immaterial in the event of a future rate case where many other factors would be considered.
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FOURTH QUARTER AND YEAR-END 2017 FINANCIAL RESULTS
The following table includes the Company's GAAP reported results for segment EBITDA, earnings attributable to common shareholders, and cash provided by operating activities for the fourth quarter and full year 2017.
EBITDA AND CASH FLOW FROM OPERATIONS
Three months ended December 31, | Year ended December 31, | ||||||||
2017 | 2016 | 2017 | 2016 | ||||||
(millions of Canadian dollars) | |||||||||
Liquids Pipelines | 1,555 | 1,733 | 6,395 | 4,926 | |||||
Gas Transmission and Midstream | (3,532 | ) | 95 | (1,269 | ) | 464 | |||
Gas Distribution | 453 | 238 | 1,390 | 831 | |||||
Green Power and Transmission | 102 | 78 | 372 | 344 | |||||
Energy Services | (252 | ) | (146 | ) | (263 | ) | (183 | ) | |
Eliminations and Other | (149 | ) | (207 | ) | (337 | ) | (101 | ) | |
Earnings/(loss) before interest, income taxes, depreciation and amortization | (1,823 | ) | 1,791 | 6,288 | 6,281 | ||||
Earnings | 207 | 365 | 2,529 | 1,776 | |||||
Cash provided by operating activities | 1,341 | 1,058 | 6,584 | 5,211 | |||||
For purposes of evaluating performance the Company makes adjustments for unusual, non-recurring or non-operating factors to GAAP reported earnings, segment EBITDA, and cash flow provided by operating activities, as it allows Management and investors to more accurately compare the Company’s performance across periods and the factors being adjusted for are not indicative of the underlying performance and cash flows of the business. These tables follow below. Schedules reconciling adjusted EBITDA, adjusted EBITDA by segment, adjusted earnings, adjusted earnings per common share and distributable cash flow to their closest GAAP equivalent are available as an Appendix to this news release.
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DISTRIBUTABLE CASH FLOW
Three months ended December 31, | Year ended December 31, | ||||||||
2017 | 2016 | 2017 | 2016 | ||||||
(unaudited, millions of Canadian dollars, except per share amounts) | |||||||||
Liquids Pipelines | 1,482 | 1,355 | 5,484 | 5,327 | |||||
Gas Transmission and Midstream | 1,020 | 166 | 3,350 | 659 | |||||
Gas Distribution | 450 | 238 | 1,379 | 833 | |||||
Green Power and Transmission | 109 | 91 | 379 | 355 | |||||
Energy Services | (21 | ) | (4 | ) | (52 | ) | 30 | ||
Eliminations and Other | (77 | ) | (84 | ) | (223 | ) | (302 | ) | |
Adjusted EBITDA1 | 2,963 | 1,762 | 10,317 | 6,902 | |||||
Maintenance Capital | (345 | ) | (205 | ) | (1,261 | ) | (671 | ) | |
Interest expense1 | (665 | ) | (403 | ) | (2,421 | ) | (1,545 | ) | |
Current income tax1 | (49 | ) | (31 | ) | (154 | ) | (92 | ) | |
Distributions to noncontrolling interests and redeemable noncontrolling interests1 | (272 | ) | (236 | ) | (1,042 | ) | (922 | ) | |
Cash distributions in excess of equity earnings1 | 118 | 67 | 279 | 183 | |||||
Preference share dividends | (84 | ) | (76 | ) | (330 | ) | (293 | ) | |
Other receipts of cash not recognized in revenue2 | 25 | 37 | 196 | 119 | |||||
Other non-cash adjustments | 50 | (36 | ) | 30 | 32 | ||||
Distributable cash flow | 1,741 | 879 | 5,614 | 3,713 | |||||
Weighted average common shares outstanding | 1,652 | 927 | 1,525 | 911 | |||||
1 | Presented net of adjusting items. |
2 | Consists of cash received net of revenue recognized for contracts under make-up rights and similar deferred revenue arrangements. |
• | DCF for both the fourth quarter and full year of 2017 increased significantly compared to the prior period primarily as a result of adjusted EBITDA from assets acquired in the Merger Transaction. |
• | Adjusted EBITDA also increased as a result of higher throughput on the Liquids Pipelines Mainline system in 2017 and from the contribution of $12 billion of new projects placed into service across the business segments throughout the year. |
• | For further detail on business performance refer to Adjusted EBITDA by Segments. |
• | The increase in DCF from higher EBITDA was partially offset by higher maintenance capital expenditures, higher interest expense and higher current income tax, all as a result of the Merger Transaction. |
• | The increase in DCF was also offset by the increased distributions to noncontrolling interests related to assets acquired in the Merger Transaction, increased public ownership in Enbridge Income Fund Holdings Inc, offset by reduced distributions at EEP. |
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ADJUSTED EARNINGS | Three months ended December 31, | Year ended December 31, | |||||||
2017 | 2016 | 2017 | 2016 | ||||||
(unaudited, millions of Canadian dollars, except per share amounts) | |||||||||
Adjusted EBITDA | 2,963 | 1,762 | 10,317 | 6,902 | |||||
Depreciation and amortization expense | (764 | ) | (564 | ) | (3,152 | ) | (2,240 | ) | |
Interest expense | (638 | ) | (403 | ) | (2,305 | ) | (1,545 | ) | |
Income taxes | (252 | ) | (136 | ) | (805 | ) | (520 | ) | |
Noncontrolling interests and redeemable noncontrolling interests | (212 | ) | (61 | ) | (743 | ) | (226 | ) | |
Preference share dividends | (84 | ) | (76 | ) | (330 | ) | (293 | ) | |
Adjusted earnings | 1,013 | 522 | 2,982 | 2,078 | |||||
Adjusted earnings per common share | 0.61 | 0.56 | 1.96 | 2.28 | |||||
• | The year-over-year growth in Adjusted Earnings was driven by the same business performance factors as discussed in Distributable Cash Flow above. |
• | Depreciation and amortization expense, interest expense, income taxes, preference share dividends and noncontrolling interest and redeemable noncontrolling interest all increased period-over-period due to the Merger Transaction. |
• | On a per share basis, adjusted earnings per share for 2017 was lower relative to the corresponding 2016 period due to the mildly dilutive impact of having a full year of shares issued as part of the Spectra merger transaction. However, business performance, growth projects coming into service and the realization of cost savings and merger synergies throughout 2017 has increased fourth quarter earnings per share above the corresponding period in 2016. |
ADJUSTED EBITDA BY SEGMENTS
The following adjusted EBITDA by segment is reported on a Canadian dollar basis. Adjusted EBITDA generated from US dollar denominated businesses were translated at stronger average Canadian dollar exchange rates both in the fourth quarter and full year 2017 when compared to the corresponding 2016 periods negatively impacting results. A portion of the US dollar earnings are hedged under the Company's enterprise-wide financial risk management program. The offsetting hedge settlements are reported within Eliminations and Other.
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LIQUIDS PIPELINES
Three months ended December 31, | Year ended December 31, | ||||||||||||
2017 | 2016 | 2017 | 2016 | ||||||||||
(millions of Canadian dollars) | |||||||||||||
Canadian Mainline | 367 | 318 | 1,342 | 1,240 | |||||||||
Lakehead System | 441 | 507 | 1,786 | 1,905 | |||||||||
Regional Oil Sands System | 182 | 129 | 600 | 510 | |||||||||
Gulf Coast and Mid-Continent | 200 | 188 | 681 | 800 | |||||||||
Other1 | 292 | 213 | 1,075 | 872 | |||||||||
Adjusted EBITDA2 | 1,482 | 1,355 | 5,484 | 5,327 | |||||||||
Operating Data (average deliveries – thousands of bpd) | |||||||||||||
Canadian Mainline3 | 2,586 | 2,481 | 2,530 | 2,405 | |||||||||
Lakehead System4 | 2,724 | 2,624 | 2,673 | 2,574 | |||||||||
Regional Oil Sands System5 | 1,392 | 1,197 | 1,301 | 1,032 | |||||||||
International Joint Tariff | 4.07 | 4.05 | 4.06 | 4.06 | |||||||||
Lakehead System Local Toll | 2.43 | 2.58 | 2.47 | 2.55 | |||||||||
Canadian Mainline IJT Residual Toll | 1.64 | 1.47 | 1.59 | 1.51 | |||||||||
Canadian Mainline Apportionment | 10% | 21% | 20% | 13% | |||||||||
Canadian Mainline Effective FX Rate | $1.07 | $1.06 | $1.06 | $1.07 | |||||||||
1 | Included within Other are Southern Lights Pipeline, Express-Platte System, Bakken System and Feeder Pipelines & Other |
2 Schedules reconciling adjusted EBITDA are available as an Appendix to this news release.
3 | Canadian Mainline throughput volume represents mainline system deliveries ex-Gretna, Manitoba which is made up of United States and eastern Canada deliveries originating from western Canada |
4 | Lakehead System throughput volume represents mainline system deliveries to the United States mid-west and eastern Canada |
5 | Volumes are for the Athabasca mainline, Athabasca Twin, Waupisoo Pipeline and Woodland Pipeline and exclude laterals on the Regional Oil Sands System |
Liquids Pipelines adjusted EBITDA increased by $127 million and $157 million for the fourth quarter and full year 2017, respectively, compared to the same periods in 2016. The key period-over-period performance drivers were as follows:
• | Canadian Mainline 2017 fourth quarter and full year adjusted EBITDA increased as a result of a higher toll and strong throughput supported by continued growth in oil sands production and capacity optimization initiatives enabled in the third quarter of 2017. |
• | Regional Oil Sands adjusted EBITDA growth was driven by contributions from new projects placed into service in 2017, most recently the Wood Buffalo Extension Pipeline in December, which supports the Fort Hills oil sands project. |
• | Lakehead System adjusted EBITDA decreased as a result of a lower Lakehead System Toll and higher operating costs, which were partially offset by higher throughput as noted above. |
• | Gulf Coast and Mid-Continent year-over-year adjusted EBITDA decreased largely due to a change in reporting practice. As of January 1, 2017 the impact of cash collected under take-or-pay contracts with make-up rights are no longer reflected in adjusted EBITDA, however they continue to be included as a component of DCF. Higher apportionment in 2017 compared with 2016, primarily during the first half of the year also contributed to lower adjusted EBITDA as Mainline apportionment allows relief on certain take or pay obligations on the Flanagan South pipeline. |
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GAS TRANSMISSION AND MIDSTREAM
Three months ended December 31, | Year ended December 31, | ||||||||
2017 | 2016 | 2017 | 2016 | ||||||
(millions of Canadian dollars) | |||||||||
US Gas Transmission | 650 | 10 | 2,215 | 31 | |||||
Canadian Gas Transmission & Midstream | 196 | 41 | 575 | 142 | |||||
Alliance Pipeline | 56 | 40 | 205 | 184 | |||||
US Midstream | 69 | 48 | 218 | 207 | |||||
Other | 49 | 27 | 137 | 95 | |||||
Adjusted EBITDA1 | 1,020 | 166 | 3,350 | 659 | |||||
1 Schedules reconciling adjusted EBITDA are available as an Appendix to this news release.
• |
Gas Transmission and Midstream adjusted EBITDA increased by $854 million and $2,691 million for the fourth quarter and full year 2017, respectively, compared to the same periods in 2016. The key period-over-period performance drivers were as follows:
• | US Gas Transmission’s operating results were primarily driven by contributions from the legacy Spectra assets. During the year, this segment also benefitted from contributions from expansion projects completed in 2016 and 2017 on the Texas Eastern and Algonquin systems. |
• | Canadian Gas Transmission & Midstream results increased primarily as a result of the legacy Spectra assets. |
• | US Midstream results reflected the addition of earnings from DCP Midstream as well as an improving commodity price environment and stronger fractionation margins driving higher equity earnings from Aux Sable, offset by weaker processing volumes and margins in the legacy Midcoast business. |
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GAS DISTRIBUTION
Three months ended December 31, | Year ended December 31, | ||||||||
2017 | 2016 | 2017 | 2016 | ||||||
(millions of Canadian dollars) | |||||||||
Enbridge Gas Distribution Inc. (EGD) | 201 | 199 | 701 | 709 | |||||
Union Gas Limited (Union Gas) | 208 | — | 551 | — | |||||
Other Gas Distribution and Storage | 41 | 39 | 127 | 124 | |||||
Adjusted EBITDA1 | 450 | 238 | 1,379 | 833 | |||||
Operating Data | |||||||||
Enbridge Gas Distribution | |||||||||
Volumes (billions of cubic feet) | 135 | 119 | 421 | 414 | |||||
Number of active customers (thousands)3 | 2,190 | 2,158 | 2,190 | 2,158 | |||||
Heating degree days4 | |||||||||
Actual | 1,285 | 1,129 | 3,499 | 3,412 | |||||
Forecast based on normal weather | 1,226 | 1,243 | 3,639 | 3,617 | |||||
Union Gas2 | |||||||||
Volumes (billions of cubic feet) | 370 | — | 944 | — | |||||
Number of active customers (thousands)3 | 1,475 | — | 1,475 | — | |||||
Heating degree days4, 2 | |||||||||
Actual | 1,433 | — | 2,688 | — | |||||
Forecast based on normal weather | 1,377 | — | 2,636 | — | |||||
1 Schedules reconciling adjusted EBITDA are available as an Appendix to this news release.
2 | Reflects operating data post-Spectra Merger. |
3 | Number of active customers is the number of EGD and Union Gas customers at the end of the period. |
4 | Heating degree days is a measure of coldness that is indicative of volumetric requirements for natural gas utilized for heating purposes in EGD’s and Union Gas’s franchise area. It is calculated by accumulating, for the fiscal period, the total number of degrees each day by which the daily mean temperature falls below 18 degrees Celsius. |
Gas Distribution adjusted EBITDA increased by $212 million and $546 million for the fourth quarter and full year 2017, respectively, compared to the same periods in 2016. The key period-over-period performance drivers were as follows:
• | The primary driver of the Adjusted EBITDA increase is the inclusion of Union Gas assets acquired through the Merger Transaction. During the year, Union Gas also benefited from increased contributions from the Dawn-Parkway expansion projects, increased storage optimization and increases in delivery rates. |
• | EGD full year 2017 adjusted EBITDA contribution was slightly lower than the comparable period due to lower distribution revenues, reflecting warmer than normal weather in the first quarter, partially offset by colder than normal weather in the fourth quarter. Prior to 2017, EGD adjusted for the effect of warmer/colder weather for the purposes of Adjusted EBITDA. Had EGD continued its policy of adjusting for the effects of warmer/colder weather, adjusted EBITDA for 2017 would have been $15 million higher. |
• | Union is subject to similar weather impacts as EGD. For the 10 month period post-Merger Transaction, Union Gas adjusted EBITDA would have been $3 million higher had the company adjusted for the effects of weather. |
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GREEN POWER AND TRANSMISSION
Three months ended December 31, | Year ended December 31, | ||||||||
2017 | 2016 | 2017 | 2016 | ||||||
(millions of Canadian dollars) | |||||||||
Adjusted EBITDA1 | 109 | 91 | 379 | 355 | |||||
1 Schedules reconciling adjusted EBITDA are available as an Appendix to this news release.
Green Power & Transmission adjusted EBITDA increased by $18 million and $24 million in the fourth quarter and full year 2017, respectively, compared to the same periods in 2016. The key period-over-period performance drivers were as follows:
• | Stronger wind resources across the Company’s North American portfolio drove higher EBITDA for both the quarter and full year. |
• | Also contributing to higher EBITDA were contributions from new assets, including the Chapman Ranch wind farm placed into service in the fourth quarter of 2017. |
ENERGY SERVICES
Three months ended December 31, | Year ended December 31, | ||||||||
2017 | 2016 | 2017 | 2016 | ||||||
(millions of Canadian dollars) | |||||||||
Adjusted earnings/(loss) before interest, income taxes, depreciation and amortization1 | (21 | ) | (4 | ) | (52 | ) | 30 | ||
1 Schedules reconciling adjusted EBITDA are available as an Appendix to this news release.
Energy Services adjusted loss before interest, income taxes, depreciation and amortization increased by $17 million and $82 million, respectively, for the fourth quarter and full year 2017 when compared to the same periods in 2016. The key period-over-period performance drivers were as follows:
• | For both the fourth quarter and full year, Energy Services results were negatively impacted by low commodity prices which affected location and quality differentials and resulted in fewer opportunities to achieve profitable margins for assets on which capacity obligations are held. |
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ELIMINATIONS AND OTHER
Three months ended December 31, | Year ended December 31, | ||||||||
2017 | 2016 | 2017 | 2016 | ||||||
(millions of Canadian dollars) | |||||||||
Operating and administrative | (52 | ) | (8 | ) | (39 | ) | (5 | ) | |
Realized foreign exchange hedge settlements | (25 | ) | (76 | ) | (184 | ) | (297 | ) | |
Adjusted loss before interest, income taxes, depreciation and amortization1 | (77 | ) | (84 | ) | (223 | ) | (302 | ) | |
1 Schedules reconciling adjusted EBITDA are available as an Appendix to this news release.
Eliminations and Other adjusted loss before interest, income taxes, depreciation and amortization decreased by $7 million and $79 million for the fourth quarter and full year 2017, respectively, when compared to the same periods in 2016. The key period-over-period performance drivers were as follows:
• | Eliminations and Other benefited from reduced hedge settlement losses in 2017 relative to 2016 due to a stronger Canadian dollar and more favourable hedge rates. On a consolidated basis, this benefit partially offset the effect of less favourable US dollar currency translation impacts in the business segment results. |
• | This was partially offset by higher unallocated operating and administrative costs net of corporate synergies. |
CONFERENCE CALL
Enbridge will host a joint conference call and webcast on February 16, 2018 at 9:00 a.m. Eastern Time (7:00 a.m. Mountain Time) with Enbridge Income Fund Holdings Inc., Enbridge Energy Partners, L.P. and Spectra Energy Partners, LP to provide an enterprise wide business update and review 2017 fourth quarter and year end financial results. Analysts, members of the media and other interested parties can access the call toll free at (877) 930-8043 or within and outside North America at (253) 336-7522 using the access code of 4939158#. The call will be audio webcast live at https://edge.media-server.com/m6/p/rudushbf. A webcast replay and podcast will be available approximately two hours after the conclusion of the event and a transcript will be posted to the website within 24 hours. The replay will be available for seven days after the call toll-free (855) 859-2056 or within and outside North America at (404) 537-3406 (access code 4939158#).
The conference call format will include prepared remarks from the executive team followed by a question and answer session for the analyst and investor community only. Enbridge’s media and investor relations teams will be available after the call for any additional questions.
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FORWARD-LOOKING INFORMATION
Forward-looking information, or forward-looking statements, have been included in this news release to provide information about the Company and its subsidiaries and affiliates, including management’s assessment of Enbridge and its subsidiaries’ future plans and operations. This information may not be appropriate for other purposes. Forward-looking statements are typically identified by words such as ‘‘anticipate’’, ‘‘expect’’, ‘‘project’’, ‘‘estimate’’, ‘‘forecast’’, ‘‘plan’’, ‘‘intend’’, ‘‘target’’, ‘‘believe’’, “likely” and similar words suggesting future outcomes or statements regarding an outlook. Forward-looking information or statements included or incorporated by reference in this document include, but are not limited to, statements with respect to the following: expected EBITDA or expected adjusted EBITDA; expected earnings/(loss) or adjusted earnings/(loss); expected earnings/(loss) or adjusted earnings/(loss) per share; expected DCF or DCF per share; expected future cash flows; expected performance of the Company’s businesses; financial strength and flexibility; expectations on sources of liquidity and sufficiency of financial resources; expected credit metrics and debt to EBITDA levels; expected costs related to announced projects and projects under construction; expected in-service dates for announced projects and projects under construction; expected capital expenditures; expected impact on cash flows of the Company’s commercially secured growth program; expected future growth and expansion opportunities; expectations about the Company’s joint venture partners’ ability to complete and finance projects under construction; expected closing of acquisitions and dispositions; estimated future dividends; expected outcome of the Minnesota Public Utilities Commission review of the Line 3 Replacement Project; expected future actions of regulators; expectations regarding commodity prices; supply forecasts; expectations regarding the impact of the Merger Transaction including the combined Company’s scale, financial flexibility, growth program, future business prospects and performance and streamlining opportunities; expected impact of U.S. Tax Reform; dividend payout policy; and dividend growth and dividend payout expectation.
Although Enbridge believes these forward-looking statements are reasonable based on the information available on the date such statements are made and processes used to prepare the information, such statements are not guarantees of future performance and readers are cautioned against placing undue reliance on forward-looking statements. By their nature, these statements involve a variety of assumptions, known and unknown risks and uncertainties and other factors, which may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Material assumptions include assumptions about the following: the expected supply of and demand for crude oil, natural gas, natural gas liquids (NGL) and renewable energy; prices of crude oil, natural gas, NGL and renewable energy; exchange rates; inflation; interest rates; availability and price of labour and construction materials; operational reliability; customer and regulatory approvals; maintenance of support and regulatory approvals for the Company’s projects; anticipated in-service dates; weather; the realization of anticipated benefits and synergies of the Merger Transaction; governmental legislation; acquisitions and the timing thereof; the success of integration plans; impact of capital project execution on the Company’s future cash flows; credit ratings; capital project funding; expected EBITDA or expected adjusted EBITDA; expected earnings/(loss) or adjusted earnings/(loss); expected earnings/(loss) or adjusted earnings/(loss) per share; expected future cash flows and expected future DCF and DCF per share; and estimated future dividends. Assumptions regarding the expected supply of and demand for crude oil, natural gas, NGL and renewable energy, and the prices of these commodities, are material to and underlie all forward-looking statements, as they may impact current and future levels of demand for the Company’s services. Similarly, exchange rates, inflation and interest rates impact the economies and business environments in which the Company operates and may impact levels of demand for the Company’s services and cost of inputs, and are therefore inherent in all forward-looking statements. Due to the interdependencies and correlation of these macroeconomic factors, the impact of any one assumption on a forward-looking statement cannot be determined with certainty, particularly with respect to the impact of the Merger Transaction on the Company, expected EBITDA, adjusted EBITDA, earnings/(loss), adjusted earnings/(loss) and associated per share amounts, or estimated future dividends. The most relevant assumptions associated with forward-looking statements on announced projects and projects under construction, including estimated completion dates and expected capital expenditures, include the following: the availability and price of labour and construction materials; the effects of inflation
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and foreign exchange rates on labour and material costs; the effects of interest rates on borrowing costs; the impact of weather and customer, government and regulatory approvals on construction and in-service schedules and cost recovery regimes.
Enbridge’s forward-looking statements are subject to risks and uncertainties pertaining to the impact of the Merger Transaction, operating performance, regulatory parameters, dividend policy, project approval and support, renewals of rights of way, weather, economic and competitive conditions, public opinion, changes in tax laws and tax rates, changes in trade agreements, exchange rates, interest rates, commodity prices, political decisions and supply of and demand for commodities, including but not limited to those risks and uncertainties discussed in this news release and in the Company’s other filings with Canadian and United States securities regulators. The impact of any one risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as these are interdependent and Enbridge’s future course of action depends on management’s assessment of all information available at the relevant time. Except to the extent required by applicable law, Enbridge assumes no obligation to publicly update or revise any forward-looking statements made in this news release or otherwise, whether as a result of new information, future events or otherwise. All subsequent forward-looking statements, whether written or oral, attributable to Enbridge or persons acting on the Company’s behalf, are expressly qualified in their entirety by these cautionary statements.
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ABOUT ENBRIDGE INC.
Enbridge Inc. is North America’s premier energy infrastructure company with strategic business platforms that include an extensive network of crude oil, liquids and natural gas pipelines, regulated natural gas distribution utilities and renewable power generation. The Company safely delivers an average of 2.8 million barrels of crude oil each day through its Mainline and Express Pipeline; accounts for approximately 65% of U.S.-bound Canadian crude oil exports; and moves approximately 20% of all natural gas consumed in the U.S., serving key supply basins and demand markets. The Company’s regulated utilities serve approximately 3.7 million retail customers in Ontario, Quebec and New Brunswick. Enbridge also has interests in more than 2,500 MW of net renewable generating capacity in North America and Europe. The Company has ranked on the Global 100 Most Sustainable Corporations index for the past eight years; its common shares trade on the Toronto and New York stock exchanges under the symbol ENB.
Life takes energy and Enbridge exists to fuel people’s quality of life. For more information, visit www.enbridge.com.
None of the information contained in, or connected to, Enbridge’s website is incorporated in or otherwise part of this news release.
FOR FURTHER INFORMATION PLEASE CONTACT: | ||
Enbridge Inc. – Media | Enbridge Inc. – Investment Community | |
Suzanne Wilton | Jonathan Gould | |
(403) 231-7385 or Toll Free: (888) 992-0997 | (403) 231-3916 or Toll Free: (800) 481-2804 | |
Email: suzanne.wilton@enbridge.com | Email: jonathan.gould@enbridge.com | |
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DIVIDEND DECLARATION
Our Board of Directors has declared the following quarterly dividends. All dividends are payable on March 1, 2018 to shareholders of record on February 15, 2018.
Common Shares | 0.67100 | |||
Preference Shares, Series A | 0.34375 | |||
Preference Shares, Series B1 | 0.21340 | |||
Preference Shares, Series C2 | 0.20342 | |||
Preference Shares, Series D | 0.25000 | |||
Preference Shares, Series F | 0.25000 | |||
Preference Shares, Series H | 0.25000 | |||
Preference Shares, Series J3 | US$0.30540 | |||
Preference Shares, Series L4 | US$0.30993 | |||
Preference Shares, Series N | 0.25000 | |||
Preference Shares, Series P | 0.25000 | |||
Preference Shares, Series R | 0.25000 | |||
Preference Shares, Series 1 | US$0.25000 | |||
Preference Shares, Series 3 | 0.25000 | |||
Preference Shares, Series 5 | US$0.27500 | |||
Preference Shares, Series 7 | 0.27500 | |||
Preference Shares, Series 9 | 0.27500 | |||
Preference Shares, Series 11 | 0.27500 | |||
Preference Shares, Series 13 | 0.27500 | |||
Preference Shares, Series 15 | 0.27500 | |||
Preference Shares, Series 17 | 0.32188 | |||
Preference Shares, Series 19 | 0.26850 | |||
1 | The quarterly dividend amount of Series B was decreased to $0.21340 from $0.25000 on June 1, 2017, due to the reset of the annual dividend rate on every fifth anniversary of the date of issuance of the Series B Preference Shares. |
2 | The quarterly dividend amount of Series C was set at $0.18600 on June 1, 2017, $0.19571 on September 1, 2017 and $0.20342 on December 1, 2017, due to reset on a quarterly basis following the date of issuance of the Series C Preference Shares. |
3 | The quarterly dividend amount of Series J was increased to US$0.30540 from US$0.25000 on June 1, 2017, due to the reset of the annual dividend rate on every fifth anniversary of the date of issuance of the Series J Preference Shares. |
4 The quarterly dividend amount of Series L was increased to US$0.30993 from US$0.25000 on September 1, 2017, due to the reset of the annual dividend rate on every fifth anniversary of the date of issuance of the Series L Preference Shares.
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NON-GAAP RECONCILATIONS APPENDICES
This news release contains references to adjusted EBITDA, adjusted earnings, adjusted earnings per common share, and DCF. Management believes the presentation of adjusted EBITDA, adjusted earnings, adjusted earnings per common share and DCF gives useful information to investors and shareholders as they provide increased transparency and insight into the performance of the Company.
Adjusted EBITDA represents EBITDA adjusted for unusual, non-recurring or non-operating factors on both a consolidated and segmented basis. Management uses adjusted EBITDA to set targets and to assess the performance of the Company.
Adjusted earnings represent earnings attributable to common shareholders adjusted for unusual, non-recurring or non-operating factors included in adjusted EBITDA, as well as adjustments for unusual, non-recurring or non-operating factors in respect of depreciation and amortization expense, interest expense, income taxes, noncontrolling interests and redeemable noncontrolling interests on a consolidated basis. Management uses adjusted earnings as another reflection of the Company’s ability to generate earnings.
DCF is defined as cash flow provided by operating activities before changes in operating assets and liabilities (including changes in environmental liabilities) less distributions to noncontrolling interests and redeemable noncontrolling interests, preference share dividends and maintenance capital expenditures, and further adjusted for unusual, non-recurring or non-operating factors. Management also uses DCF to assess the performance of the Company and to set its dividend payout target.
Reconciliations of forward looking non-GAAP financial measures to comparable GAAP measures are not available due to the challenges and impracticability with estimating some of the items, particularly with estimates for certain contingent liabilities, and estimating non-cash unrealized derivative fair value losses and gains and ineffectiveness on hedges which are subject to market variability and therefore a reconciliation is not available without unreasonable effort.
Our non-GAAP measures described above are not measures that have standardized meaning prescribed by generally accepted accounting principles in the United States of America (U.S. GAAP) and are not U.S. GAAP measures. Therefore, these measures may not be comparable with similar measures presented by other issuers.
The tables below provide a reconciliation of the non-GAAP measures to comparable GAAP measures.
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APPENDIX A
NON- GAAP RECONCILATIONS: ADJUSTED EBITDA AND ADJUSTED EARNINGS
CONSOLIDATED EARNINGS
Three months ended December 31, | Year ended December 31, | ||||||||
2017 | 2016 | 2017 | 2016 | ||||||
(millions of Canadian dollars) | |||||||||
Liquids Pipelines | 1,555 | 1,733 | 6,395 | 4,926 | |||||
Gas Transmission and Midstream | (3,532 | ) | 95 | (1,269 | ) | 464 | |||
Gas Distribution | 453 | 238 | 1,390 | 831 | |||||
Green Power and Transmission | 102 | 78 | 372 | 344 | |||||
Energy Services | (252 | ) | (146 | ) | (263 | ) | (183 | ) | |
Eliminations and Other | (149 | ) | (207 | ) | (337 | ) | (101 | ) | |
Earnings/(loss) before interest, income taxes, depreciation and amortization | (1,823 | ) | 1,791 | 6,288 | 6,281 | ||||
Depreciation and amortization | (775 | ) | (564 | ) | (3,163 | ) | (2,240 | ) | |
Interest expense | (852 | ) | (412 | ) | (2,556 | ) | (1,590 | ) | |
Income taxes | 3,515 | 32 | 2,697 | (142 | ) | ||||
Earnings attributable to noncontrolling interests and redeemable noncontrolling interests | 226 | (406 | ) | (407 | ) | (240 | ) | ||
Preference share dividends | (84 | ) | (76 | ) | (330 | ) | (293 | ) | |
Earnings attributable to common shareholders | 207 | 365 | 2,529 | 1,776 | |||||
ADJUSTED EBITDA TO ADJUSTED EARNINGS
Three months ended December 31, | Year ended December 31, | ||||||||
2017 | 2016 | 2017 | 2016 | ||||||
(millions of Canadian dollars, except per share amounts) | |||||||||
Liquids Pipelines | 1,482 | 1,355 | 5,484 | 5,327 | |||||
Gas Transmission and Midstream | 1,020 | 166 | 3,350 | 659 | |||||
Gas Distribution | 450 | 238 | 1,379 | 833 | |||||
Green Power and Transmission | 109 | 91 | 379 | 355 | |||||
Energy Services | (21 | ) | (4 | ) | (52 | ) | 30 | ||
Eliminations and Other | (77 | ) | (84 | ) | (223 | ) | (302 | ) | |
Adjusted EBITDA | 2,963 | 1,762 | 10,317 | 6,902 | |||||
Depreciation and amortization expense | (764 | ) | (564 | ) | (3,152 | ) | (2,240 | ) | |
Interest expense | (638 | ) | (403 | ) | (2,305 | ) | (1,545 | ) | |
Income taxes | (252 | ) | (136 | ) | (805 | ) | (520 | ) | |
Noncontrolling interests and redeemable noncontrolling interests | (212 | ) | (61 | ) | (743 | ) | (226 | ) | |
Preference share dividends | (84 | ) | (76 | ) | (330 | ) | (293 | ) | |
Adjusted earnings | 1,013 | 522 | 2,982 | 2,078 | |||||
Adjusted earnings per common share | 0.61 | 0.56 | 1.96 | 2.28 | |||||
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EBITDA TO ADJUSTED EARNINGS
Three months ended December 31, | Year ended December 31, | ||||||||
2017 | 2016 | 2017 | 2016 | ||||||
(millions of Canadian dollars, except per share amounts) | |||||||||
Earnings/(loss) before interest, income taxes, depreciation and amortization | (1,823 | ) | 1,791 | 6,288 | 6,281 | ||||
Adjusting items: | |||||||||
Changes in unrealized derivative fair value (gain)/loss | 130 | 277 | (1,109 | ) | (543 | ) | |||
Asset and investment write-down loss | 4,565 | 433 | 4,565 | 1,630 | |||||
Gain on sale of asset | — | (850 | ) | (27 | ) | (850 | ) | ||
Alberta wildfire pipeline and facilities restart costs | — | 8 | — | 47 | |||||
Losses on sale of non-core assets and investment, net of gains | 9 | — | 9 | 4 | |||||
Unrealized intercompany foreign exchange (gain)/loss | 9 | (10 | ) | 29 | 43 | ||||
Hydrostatic testing | — | (1 | ) | — | (15 | ) | |||
Make-up rights adjustment | — | (1 | ) | — | 130 | ||||
Leak remediation costs, net of leak insurance recoveries | 1 | (11 | ) | 10 | (8 | ) | |||
Warmer than normal weather | — | 10 | — | 18 | |||||
Project development and transaction costs | (1 | ) | 56 | 205 | 86 | ||||
Employee severance and restructuring costs | 70 | 52 | 354 | 82 | |||||
Other | 3 | 8 | (7 | ) | (3 | ) | |||
Total adjusting items | 4,786 | (29 | ) | 4,029 | 621 | ||||
Adjusted earnings before interest, income taxes, depreciation and amortization | 2,963 | 1,762 | 10,317 | 6,902 | |||||
Depreciation and amortization | (775 | ) | (564 | ) | (3,163 | ) | (2,240 | ) | |
Interest expense | (852 | ) | (412 | ) | (2,556 | ) | (1,590 | ) | |
Income taxes | 3,515 | 32 | 2,697 | (142 | ) | ||||
Earnings attributable to noncontrolling interests and redeemable noncontrolling interests | 226 | (406 | ) | (407 | ) | (240 | ) | ||
Preference share dividends | (84 | ) | (76 | ) | (330 | ) | (293 | ) | |
Adjusting items in respect of: | |||||||||
Depreciation and amortization | 11 | — | 11 | — | |||||
Interest expense | 214 | 9 | 251 | 45 | |||||
Income taxes | (3,767 | ) | (168 | ) | (3,502 | ) | (378 | ) | |
Noncontrolling interests and redeemable noncontrolling interests | (438 | ) | 345 | (336 | ) | 14 | |||
Adjusted earnings | 1,013 | 522 | 2,982 | 2,078 | |||||
Adjusted earnings per common share | 0.61 | 0.56 | 1.96 | 2.28 | |||||
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APPENDIX B NON-GAAP RECONCILIATION – SEGMENTED EBITDA TO ADJUSTED EBITDA
LIQUIDS PIPELINES
Three months ended December 31, | Year ended December 31, | ||||||||
2017 | 2016 | 2017 | 2016 | ||||||
(millions of Canadian dollars) | |||||||||
Adjusted earnings before interest, income taxes, depreciation and amortization | 1,482 | 1,355 | 5,484 | 5,327 | |||||
Changes in unrealized derivative fair value gain/(loss) | 94 | (92 | ) | 875 | 474 | ||||
Leak remediation costs, net of leak insurance recoveries | (1 | ) | 11 | (10 | ) | 8 | |||
Hydrostatic testing | — | 1 | — | 15 | |||||
Employee severance and restructuring costs | (9 | ) | — | (30 | ) | — | |||
Alberta wildfire pipelines and facility restart cost | — | (8 | ) | — | (47 | ) | |||
Make-up rights adjustment | — | 1 | — | (129 | ) | ||||
Asset and investment impairment loss | — | (383 | ) | — | (1,561 | ) | |||
Gain on sale of pipe and project wind-down costs | 6 | — | 72 | — | |||||
Gain on sale of asset | — | 850 | 27 | 850 | |||||
Derecognition of regulatory balances | — | — | — | (6 | ) | ||||
Project development and transaction costs | 2 | (2 | ) | (4 | ) | (5 | ) | ||
Other | (19 | ) | — | (19 | ) | — | |||
Total adjustments | 73 | 378 | 911 | (401 | ) | ||||
Earnings before interest, income taxes, depreciation and amortization | 1,555 | 1,733 | 6,395 | 4,926 | |||||
GAS TRANSMISSION AND MIDSTREAM
Three months ended December 31, | Year ended December 31, | ||||||||
2017 | 2016 | 2017 | 2016 | ||||||
(millions of Canadian dollars) | |||||||||
Adjusted earnings before interest, income taxes, depreciation and amortization | 1,020 | 166 | 3,350 | 659 | |||||
Asset write-down loss | (4,552 | ) | (37 | ) | (4,552 | ) | (51 | ) | |
Changes in unrealized derivative fair value loss | (8 | ) | (34 | ) | (1 | ) | (139 | ) | |
DCP Midstream equity earnings adjustment | (7 | ) | — | (28 | ) | — | |||
Grizzly Valley flood | 12 | — | 16 | — | |||||
Inspection, repair and other costs | 13 | — | (26 | ) | — | ||||
Loss on disposal of non-core assets | — | — | — | (4 | ) | ||||
Make-up rights adjustment | — | — | — | (1 | ) | ||||
Project development and transaction costs | 1 | — | (4 | ) | — | ||||
Employee severance and restructuring costs | (11 | ) | — | (24 | ) | — | |||
Total adjustments | (4,552 | ) | (71 | ) | (4,619 | ) | (195 | ) | |
Earnings/(loss) before interest, income taxes, depreciation and amortization | (3,532 | ) | 95 | (1,269 | ) | 464 | |||
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GAS DISTRIBUTION
Three months ended December 31, | Year ended December 31, | ||||||||
2017 | 2016 | 2017 | 2016 | ||||||
(millions of Canadian dollars) | |||||||||
Adjusted earnings before interest, income taxes, depreciation and amortization | 450 | 238 | 1,379 | 833 | |||||
Warmer than normal weather | — | (10 | ) | — | (18 | ) | |||
Changes in unrealized derivative fair value gain/(loss) | 3 | — | 16 | (6 | ) | ||||
Asset impairment loss | — | — | — | (5 | ) | ||||
Other regulatory adjustments | — | — | — | 17 | |||||
Employee severance and restructuring costs | — | 10 | (5 | ) | 10 | ||||
Total adjustments | 3 | — | 11 | (2 | ) | ||||
Earnings before interest, income taxes, depreciation and amortization | 453 | 238 | 1,390 | 831 | |||||
GREEN POWER AND TRANSMISSION
Three months ended December 31, | Year ended December 31, | ||||||||
2017 | 2016 | 2017 | 2016 | ||||||
(millions of Canadian dollars) | |||||||||
Adjusted earnings before interest, income taxes, depreciation and amortization | 109 | 91 | 379 | 355 | |||||
Changes in unrealized derivative fair value gain | 2 | — | 2 | 2 | |||||
Loss on sale of investment | (9 | ) | — | (9 | ) | — | |||
Investment impairment loss | — | (13 | ) | — | (13 | ) | |||
Total adjustments | (7 | ) | (13 | ) | (7 | ) | (11 | ) | |
Earnings before interest, income taxes, depreciation and amortization | 102 | 78 | 372 | 344 | |||||
ENERGY SERVICES
Three months ended December 31, | Year ended December 31, | ||||||||
2017 | 2016 | 2017 | 2016 | ||||||
(millions of Canadian dollars) | |||||||||
Adjusted earnings/(loss) before interest, income taxes, depreciation and amortization | (21 | ) | (4 | ) | (52 | ) | 30 | ||
Changes in unrealized derivative fair value loss | (222 | ) | (134 | ) | (200 | ) | (205 | ) | |
Employee severance and restructuring costs | (1 | ) | — | (3 | ) | — | |||
Other | (8 | ) | (8 | ) | (8 | ) | (8 | ) | |
Total adjustments | (231 | ) | (142 | ) | (211 | ) | (213 | ) | |
Loss before interest, income taxes, depreciation and amortization | (252 | ) | (146 | ) | (263 | ) | (183 | ) | |
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ELIMINATIONS AND OTHER
Three months ended December 31, | Year ended December 31, | ||||||||
2017 | 2016 | 2017 | 2016 | ||||||
(millions of Canadian dollars) | |||||||||
Adjusted loss before interest, income taxes, depreciation and amortization | (77 | ) | (84 | ) | (223 | ) | (302 | ) | |
Changes in unrealized derivative fair value gain/(loss) | 1 | (17 | ) | 417 | 417 | ||||
Unrealized intercompany foreign exchange gain/(loss) | (9 | ) | 10 | (29 | ) | (43 | ) | ||
Asset and investment impairment loss | (13 | ) | — | (13 | ) | — | |||
Project development and transaction costs | (2 | ) | (54 | ) | (197 | ) | (81 | ) | |
Employee severance and restructuring costs | (49 | ) | (62 | ) | (292 | ) | (92 | ) | |
Total adjustments | (72 | ) | (123 | ) | (114 | ) | 201 | ||
Loss before interest, income taxes, depreciation and amortization | (149 | ) | (207 | ) | (337 | ) | (101 | ) | |
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APPENDIX C NON-GAAP RECONCILIATION – CASH PROVIDED BY OPERATNG ACTIVITIES TO DCF
Three months ended December 31, | Year ended December 31, | ||||||||
2017 | 2016 | 2017 | 2016 | ||||||
(millions of Canadian dollars) | |||||||||
Cash provided by operating activities | 1,341 | 1,058 | 6,584 | 5,211 | |||||
Adjusted for changes in operating assets and liabilities1 | 461 | 272 | 412 | 362 | |||||
1,802 | 1,330 | 6,996 | 5,573 | ||||||
Distributions to noncontrolling interests and redeemable noncontrolling interests2 | (272 | ) | (236 | ) | (1,042 | ) | (922 | ) | |
Preference share dividends | (84 | ) | (76 | ) | (330 | ) | (293 | ) | |
Maintenance capital expenditures3 | (345 | ) | (205 | ) | (1,261 | ) | (671 | ) | |
Significant adjusting items: | |||||||||
Pre-issuance hedge settlement4 | 431 | — | 431 | — | |||||
Weather normalization | — | 7 | — | 13 | |||||
Other receipts of cash not recognized in revenue5 | 25 | 36 | 196 | 249 | |||||
Project development and transaction costs | 9 | 44 | 210 | 74 | |||||
Realized inventory revaluation allowance6 | (17 | ) | 1 | (56 | ) | (345 | ) | ||
Employee severance, transition and restructuring costs | 81 | 43 | 359 | 73 | |||||
Other items | 111 | (65 | ) | 111 | (38 | ) | |||
Distributable cash flow | 1,741 | 879 | 5,614 | 3,713 | |||||
1 | Changes in operating assets and liabilities include changes in environmental liabilities, net of recoveries. |
2 Presented net of adjusting items.
3 | Maintenance capital expenditures are expenditures that are required for the ongoing support and maintenance of the existing pipeline system or that are necessary to maintain the service capability of the existing assets (including the replacement of components that are worn, obsolete or completing their useful lives). For the purpose of DCF, maintenance capital excludes expenditures that extend asset useful lives, increase capacities from existing levels or reduce costs to enhance revenues or provide enhancements to the service capability of the existing assets. |
4 Related to termination of interest rate swaps as not highly probable to issue long-term debt.
5 Consists of cash received net of revenue recognized for contracts under make-up rights and similar deferred revenue arrangements.
6 | Realized inventory revaluation allowance relates to losses on sale of previously written down inventory for which there is an approximate offsetting realized derivative gain in DCF. |
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