Enbridge Inc. Reports Strong Second Quarter 2019 Results

CALGARY, Aug, 2, 2019 /CNW/ - Enbridge Inc. (Enbridge or the Company) (TSX:ENB) (NYSE:ENB) today reported second quarter 2019 financial results and provided a quarterly business update.

SECOND QUARTER 2019 HIGHLIGHTS
(all financial figures are unaudited and in Canadian dollars unless otherwise noted)

• GAAP earnings of $1,736 million or $0.86 per common share for the second quarter of 2019, compared to $1,071 million or $0.63 per common share in the second quarter of 2018, both including the impact of a number of unusual, non-recurring or non-operating factors
  
  
• Adjusted earnings of $1,349 million or $0.67 per common share for the second quarter of 2019, compared to $1,094 million or $0.65 per common share in the second quarter of 2018
  
  
• Adjusted earnings before interest, income tax and depreciation and amortization (EBITDA) of $3,208 million for the second quarter of 2019, compared to $3,165 million in the second quarter of 2018
  
  
• Cash Provided by Operating Activities of $2,494 million for the second quarter of 2019, compared to $3,344 million for the second quarter of 2018
  
  
• Distributable Cash Flow (DCF) of $2,310 million for the second quarter of 2019, compared to $1,858 million for the second quarter of 2018
  
  
• Reaffirmed financial guidance range for 2019 DCF per Share of $4.30 to $4.60/share
  
  
• Launched a binding open season to secure contracted priority access transportation agreements on the Liquids Mainline System upon expiry of the Competitive Toll Settlement (CTS) agreement in June 2021
  
  
• Launched a binding open season for a 50 kbpd expansion of the Express liquids pipeline for service in the first quarter of 2020
  
  
• Announced $2 billion of new secured growth projects across the utilities and renewable power businesses
  
  
• Selected by Venture Global to serve their Plaquemines LNG project in Louisiana through a reversal and expansion of a Texas Eastern lateral pipeline, subject to achieving a positive final investment decision on the LNG plant
  
  
• Brought the US$0.2 billion Stratton Ridge Texas Eastern mainline expansion into service

CEO COMMENT

"We're very pleased to deliver another strong quarter of operating and financial results," commented Al Monaco, President and Chief Executive Officer of Enbridge. "Operationally, all of our core systems continue to run close to full capacity. We saw strong demand to move crude volumes on our system from Western Canada and the Bakken through to U.S. Gulf Coast markets; our gas transmission business remained in high demand; the Ontario gas utility saw high volumes during a colder than normal second quarter; and, we also benefited from attractive optimization opportunities in our Energy Services business. Importantly, we've added $2.5 billion of secured capital projects this year, across our businesses, with attractive commercial frameworks that align well with our low risk pipeline-utility model and extend our growth beyond 2020.

"Our operating performance, in combination with new projects that came into service over the past year, drove record second quarter EBITDA and DCF. As a result, we continue to anticipate full year results to be about the middle of our 2019 DCF guidance range of $4.30 to $4.60 per share.

"In addition to the strong results, we advanced key initiatives in each of our business units during the quarter. Liquids Pipelines launched an open season today for contracted capacity on the Mainline. Liquids Pipelines is also moving forward with Mainline system optimizations that will be ready later this year, as well as an expansion of the Express pipeline to be placed into service in early 2020.

"On the U.S. portion of our Line 3 Replacement Project execution, in Minnesota, we're awaiting further guidance from the Public Utilities Commission on the process and timing to address the Environmental Impact Statement deficiency identified by the Minnesota Appeals Court in June. The Minnesota PUC has publicly stated that it can deal with this matter expeditiously and the State permitting agencies have indicated their commitment to keep their permitting processes moving forward during this period, which we view positively.

"In Gas Transmission we continue to advance rate case discussions for the Texas Eastern and Algonquin systems. In the U.S. Gulf Coast, we are actively pursuing opportunities to support LNG development by leveraging our incumbent pipeline position in the region; a good example being our recent selection by Venture Global to provide transportation services to their Plaquemines LNG project in Louisiana.

"Within the Gas Utility business we've recently secured two new capital projects, totaling $0.2 billion, to reinforce the distribution network within our existing franchise area, which will deliver strong cost of service utility returns. We also continue to implement initiatives to drive efficiencies from the recent amalgamation.

"In our Power business, we also announced today that we're moving forward on the first of our four offshore wind farms under development in France, with our partner EDF Renouvelables. The 480MW Saint-Nazaire offshore wind farm will be located off the northwest French coast. Our $1.8 billion gross investment is underpinned by a fixed price power purchase agreement that is right in-line with our low risk business model, while providing a strong equity return. Looking ahead, we see significant potential to grow our European offshore renewable power generation business, which will help to further extend the Company's growth post-2020.

"Strategically, the actions we took over the past year to streamline, strengthen the balance sheet and move to a pure pipeline and utility model, have further de-risked the business and put us in a position of strength to capitalize on opportunities going forward. We remain focused on our key priorities for the year, which include strong operating and financial results, delivering reliable returns, adding to the secured project inventory, maintaining our financial strength and the continued self-funding of new growth capital. In seeking to extend growth, we plan to place an even greater emphasis on capturing the very best of a large suite of in-franchise organic growth opportunities. We believe that these actions will maximize shareholder value and deliver on our attractive investor value proposition.

"Finally, yesterday we experienced a rupture on one of our Texas Eastern natural gas pipelines near Danville, Kentucky. There has been one confirmed fatality, and we're deeply saddened by this. Our first concern is for those impacted by this incident and ensuring the safety of the community. Our team is on-site providing necessary support and resources to the community. In addition, the National Transportation Safety Board is on-site conducting an investigation and we are actively supporting their work. The impacted pipeline will not be returned into service until it is absolutely safe to do so. This serves as a critical reminder as to why the safety of our systems has and always will remain our number one priority.

"In summary, it was another strong quarter for the Company and we're pleased with the performance across each of the business units as well as the progress being made on key priorities," concluded Mr. Monaco.

FINANCIAL RESULTS SUMMARY

Financial results for the three and six months ended June 30, 2019, are summarized in the table below:

	Three months ended June 30,			Six months ended June 30,
	2019	2018		2019	2018
(unaudited, millions of Canadian dollars, except per share amounts; number of shares in millions)
GAAP Earnings attributable to common shareholders	1,736	1,071		3,627	1,516
GAAP Earnings per common share	0.86	0.63		1.80	0.90
Cash provided by operating activities	2,494	3,344		4,670	6,538
Adjusted EBITDA^1	3,208	3,165		6,977	6,571
Adjusted Earnings^1	1,349	1,094		2,989	2,469
Adjusted Earnings per common share^1	0.67	0.65		1.48	1.47
Distributable Cash Flow^1	2,310	1,858		5,068	4,170
Weighted average common shares outstanding	2,018	1,695		2,017	1,690

1	Non-GAAP financial measures. Schedules reconciling adjusted EBITDA, adjusted earnings, adjusted earnings per common share and distributable cash flow are available as Appendices to this news release.

GAAP earnings attributable to common shareholders for the second quarter of 2019 increased by $665 million or $0.23 per share compared to the same period in 2018. The period-over-period comparability of earnings attributable to common shareholders was impacted by certain unusual and infrequent factors, the most prominent being the change in non-cash derivative fair value gains and losses between periods. Partially offsetting the increase in GAAP earnings attributable to common shareholders was a non-cash, write-down of crude oil and natural gas inventories to the lower of cost or market in the Energy Services business.

Adjusted earnings in the second quarter 2019 increased by $255 million. The increase was primarily driven by strong operating results across many of the Company's business units and from new projects placed into service in late 2018, partially offset by the loss of contributions from assets that were sold during 2018. On a per share basis, adjusted earnings increased by $0.02 per share compared to the same period in 2018, reflecting a higher share count after Enbridge's common equity financed acquisition of all of the outstanding equity securities of its sponsored vehicles not beneficially owned during the fourth quarter of 2018.

DCF for the second quarter was $2,310 million, an increase of $452 million over the comparable prior period in 2018, driven largely by the same factors noted above.

Detailed segmented financial information and analysis can be found below under Adjusted EBITDA by Segments.

SECURED PROJECT UPDATE

The Company announced today that it is proceeding with $2 billion of new growth projects across several business units, which in combination with projects announced in the first quarter, provides further visibility to the Company's growth post 2020.

Enbridge Gas Inc. (EGI) will proceed with $0.2 billion of system modernization and reinforcement work in Windsor and Owen Sound, Ontario. These new capital projects will earn a cost of service return under the newly approved incentive based rate-making structure. These projects are expected to come into service in the fourth quarter 2020.

The Company is also moving forward with its first offshore wind project in France. The Saint-Nazaire project is backed by a 20-year fixed price power purchase agreement with the French State, with unique power production protection, providing for a strong return underpinned by a solid commercial model. Enbridge is a 50% partner in the development company with EDF Renouvelables. The Company's share of the total investment in the project is $1.8 billion. Enbridge's equity contribution will be $0.3 billion, with the remainder of the construction financed through non-recourse project level debt. This project is expected to come into service in late 2022.

In the Gas Transmission business, although not included in the Company's secured capital, Enbridge recently secured the rights to serve Venture Global's Plaquemines LNG project in Louisiana through a $0.5 billion reversal and expansion of a Texas Eastern lateral pipeline, subject to achieving a positive final investment decision on the LNG plant.

MAINLINE CONTRACTING

On August 2, following several months of consultations and negotiations with the Company's shippers, Enbridge launched an open season for transportation services on the Liquids Mainline System. Following completion of the Line 3 Replacement project, Mainline capacity will be 3.225 mbpd, of which up to 2.9 mbpd will be contracted with the remaining 325 kbpd remaining in spot service. The open season will provide shippers with the opportunity to enter into long-term contracts for priority access on the Mainline System upon maturity of the current CTS agreement on June 30, 2021.

Key terms of the offering include:

• Take-or-pay and/or requirements contract structure
• 8-20 year term with discounts for larger volumes and longer duration
• 10% spot capacity availability

The offering has been structured to ensure a fair and transparent process for all potential shippers, including small volume producers. The open season will run through October 2, 2019.

WCSB EGRESS INITIATIVES

In late 2019, the Company expects to deliver approximately 85 kbpd of incremental Mainline throughput, which is near the top of its previously guided range of 50-100 kbpd. This additional throughput will be achieved within the Company's current system capacity and operating parameters through crude delivery and receipt window efficiencies, optimization of crude quality slates, as well as the recovery of Line 4 capacity, which had been previously planned for in early 2020. Together, these capital efficient initiatives will provide much needed and cost effective near-term egress for Western Canadian Sedimentary Basin (WCSB) production.

On July 3, the Company launched an open season to support a 50 kbpd expansion of the Express pipeline. This expansion will provide additional takeaway capacity out of the WCSB to serve the PADD IV market and is expected to be available by the first quarter of 2020.

PROJECT EXECUTION UPDATE

The Company now has an inventory of approximately $19 billion of secured projects at various stages of execution, which includes approximately $2.5 billion of projects secured year to date. The individual projects that make up the secured program are all 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.

In the second quarter, the Company brought the US$0.2 billion Texas Eastern Stratton Ridge mainline expansion project into service. The project is underpinned by a long-term take-or-pay contracts and further advances the Company's U.S. Gulf Coast LNG export strategy.

Of the remaining projects targeted for completion in 2019, the two largest are the US$0.7 billion investment in the Gray Oak pipeline and the $1.1 billion HoHe See offshore wind power project in Germany. The Gray Oak pipeline is on track for completion by the end of the year, with volumes expected to ramp up in the first quarter of 2020 given the pressing need for incremental crude export capacity out of the Permian basin.

Execution of the 497MW HoHe See project continues to advance as planned with first power achieved in mid-July and full operations expected in the fourth quarter of 2019 as the remaining turbines are connected to the grid.

Line 3 Replacement

The $9 billion Line 3 Replacement Project is a significant component of the Company's secured project inventory. It is a critical integrity replacement project that will enhance the safety and reliability of Enbridge's Liquids Mainline System.

The Canadian segment of the pipeline replacement work is now substantially complete. In Wisconsin the replacement pipeline was placed into service in 2018 and the remainder of the U.S. portion in North Dakota, which is substantially permitted, and Minnesota is still to be constructed. In Minnesota, the permitting process is under way with all relevant federal and state agencies, including the U.S. Army Corps of Engineers, the Minnesota Department of Natural Resources, the Minnesota Pollution Control Agency, as well as other local government agencies in Minnesota.

On June 3, 2019, the Minnesota Court of Appeals rendered a decision on the Minnesota Public Utilities Commission's (MPUC) adequacy determination of the Environmental Impact Statement (EIS). While denying eight of the nine appealed items, the Minnesota Court of Appeals identified one issue that led them to reverse the adequacy determination. The Court remanded and directed the MPUC to perform spill modeling analysis within the Lake Superior Watershed. On July 3, 2019, several parties to the original appeal of the EIS, petitioned for Minnesota Supreme Court review of the Minnesota Court of Appeals June 3, 2019 decision. The MPUC and Enbridge responded to those petitions on July 23, 2019 and the Minnesota Supreme Court is expected to decide whether to accept or decline further review by September 3, 2019.

As for environmental permits, the spill modelling required by the Court of Appeals is a prerequisite to finalizing other state permits. At this time, Enbridge cannot determine when all necessary permits will be issued pending receipt of further information from the MPUC on a timeline to complete this work. The MPUC's statement on July 3, 2019 indicated that the agency will seek public comment and work expeditiously to address the EIS deficiency. Additionally, the State permitting agencies have confirmed they will continue to advance their permitting work in parallel with MPUC process. The Company expects to hear from the MPUC regarding their updated process and timelines, after which the Company expects permitting agencies to re-align their timelines to the MPUC process.

Depending on the final in-service date, there is a risk that the project may exceed the Company's total cost estimate of $9 billion for the combined Line 3 replacement project. However, at this time, the Company does not anticipate any capital cost impacts that would be material to Enbridge's financial position and outlook.

GAS TRANSMISSION REGULATORY PROCESS UPDATE

One of the Company's strategic priorities is to ensure timely and fair returns on existing and new capital additions to the Company's U.S. natural gas transmission systems. Enbridge continues to actively work with the Federal Energy Regulatory Commission (FERC) and with customers and intervenors to advance rate proceedings and settlement discussions on Texas Eastern, Algonquin and East Tennessee. For Texas Eastern, settlement discussions continue, with the expectation of achieving a negotiated settlement or commencing a rate case hearing. In either case the path to resolution is expected to be determined before the end of the year. The Company has also commenced early stage rate discussions with Algonquin customers with the expectation of a pre-packaged settlement on that system. Lastly, for East Tennessee, a settlement agreement was filed on May 23, 2019 and an order from the FERC is expected shortly.

FINANCING UPDATE

In 2018, Enbridge reached agreements to sell over $7.8 billion of non-core assets. Proceeds from these asset sales have provided the Company with significant additional financial flexibility to further strengthen the balance sheet and self-fund its secured growth program, including $2 billion of newly secured projects in the second quarter. As of June 30, 2019, the Company's consolidated Debt-to-EBITDA ratio was 4.6x on a trailing twelve month basis. This is well within the Company's long term target credit metric range of 4.5x to below 5.0x Debt-to-EBITDA.

The delay in the Line 3 Replacement project in-service date from late 2019 is not expected to have a material impact on leverage ratios. While the trajectory of further leverage reduction below the target credit metric range, absent new investments, may shift out slightly, credit metrics are expected to remain well within the Company's long-term guidance range.

SECOND QUARTER 2019 FINANCIAL RESULTS

The following table summarizes the Company's GAAP reported results for segment EBITDA, earnings attributable to common shareholders, and cash provided by operating activities for the second quarter of 2019.

GAAP SEGMENT EBITDA AND CASH FLOW FROM OPERATIONS

	Three months ended June 30,			Six months ended June 30,
	2019	2018		2019	2018
(unaudited, millions of Canadian dollars)
Liquids Pipelines	1,992	1,322		4,064	2,478
Gas Transmission and Midstream	941	1,014		1,961	1,140
Gas Distribution	390	370		1,052	1,006
Renewable Power Generation and Transmission	94	126		218	235
Energy Services	221	35		227	204
Eliminations and Other	107	(118)		355	(397)
EBITDA	3,745	2,749		7,877	4,666
Earnings attributable to common shareholders	1,736	1,071		3,627	1,516
Cash provided by operating activities	2,494	3,344		4,670	6,538

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, which allow Management and investors to more accurately compare the Company's performance across periods, normalizing for factors that are not indicative of the underlying business performance. Tables incorporating these adjustments follow below. Schedules reconciling EBITDA, adjusted EBITDA, adjusted EBITDA by segment, adjusted earnings, adjusted earnings per common share and DCF to their closest GAAP equivalent are provided in the Appendices to this news release.

DISTRIBUTABLE CASH FLOW

	Three months ended June 30,			Six months ended June 30,
	2019	2018		2019	2018
(unaudited, millions of Canadian dollars, except per share amounts)
Liquids Pipelines	1,766	1,629		3,495	3,256
Gas Transmission and Midstream	936	1,032		1,976	2,078
Gas Distribution	390	369		1,083	1,015
Renewable Power Generation and Transmission	100	125		223	264
Energy Services	88	62		264	84
Eliminations and Other	(72)	(52)		(64)	(126)
Adjusted EBITDA^1,3	3,208	3,165		6,977	6,571
Maintenance capital	(269)	(294)		(448)	(459)
Interest expense^1	(662)	(703)		(1,346)	(1,355)
Current income tax^1	(53)	(82)		(211)	(157)
Distributions to noncontrolling interests and redeemable noncontrolling interests	(54)	(306)		(100)	(599)
Cash distributions in excess of equity earnings^1	189	114		283	177
Preference share dividends	(96)	(87)		(191)	(174)
Other receipts of cash not recognized in revenue^2	33	28		86	104
Other non-cash adjustments	14	23		18	62
DCF^3	2,310	1,858		5,068	4,170
Weighted average common shares outstanding	2,018	1,695		2,017	1,690

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.
3	Schedules reconciling adjusted EBITDA and DCF are available as Appendices to this news release.

Second quarter 2019 DCF increased by $452 million compared to the same period in 2018. The key drivers of quarter-over-quarter growth are summarized below:

• An increase in adjusted EBITDA primarily due to strong base operating performance and incremental contributions from new projects placed into service, partially offset by the absence of contributions from non-core assets sold in 2018. For further detail on business performance refer to Adjusted EBITDA by Segments below.
• Lower distributions to noncontrolling and redeemable noncontrolling interests following the completion of Enbridge's buy-in of the publicly held interest in its sponsored vehicles, which were completed in the fourth quarter of 2018.
• Higher equity distributions in excess of equity earnings from equity investments due to strong performance as well as new equity investments placed into service.
• Lower financing costs due to interest expense savings from the application of proceeds from last year's non-core asset sales to debt reduction, partially offset by incremental debt and hybrid securities issued over the same period.
• Lower maintenance capital due to timing of maintenance requirements and spend in 2019.
• Lower current taxes due to timing of recognition of newly enacted Canadian tax legislation coming into effect in the second half of 2019.

ADJUSTED EARNINGS	Three months ended June 30,			Six months ended June 30,
	2019	2018		2019	2018
(unaudited, millions of Canadian dollars, except per share amounts)
Adjusted EBITDA^2	3,208	3,165		6,977	6,571
Depreciation and amortization	(842)	(829)		(1,682)	(1,653)
Interest expense^1	(643)	(677)		(1,311)	(1,299)
Income taxes^1	(279)	(233)		(767)	(489)
Noncontrolling interests and redeemable noncontrolling interests^1	1	(243)		(37)	(483)
Preference share dividends	(96)	(89)		(191)	(178)
Adjusted earnings^2	1,349	1,094		2,989	2,469
Adjusted earnings per common share	0.67	0.65		1.48	1.47

1	Presented net of adjusting items.
2	Schedules reconciling adjusted EBITDA and adjusted earnings are available as Appendices to this news release.

Adjusted earnings increased by $255 million for the second quarter of 2019 compared to the same period in 2018. Growth in adjusted earnings was driven by the same factors impacting business performance and adjusted EBITDA as discussed under Distributable Cash Flow above. Other notable quarter-over-quarter drivers were:

• Higher depreciation and amortization expense as a result of placing new assets into service, net of depreciation expense no longer recorded for assets which were classified as assets held for sale or sold during 2018.
• Lower financing costs due to interest expense savings from debt repayments since the second half of 2018, partially offset by incremental debt and hybrid securities issued over the same period.
• Higher income tax expense, in part due to higher earnings before tax and a higher effective income tax rate. The period-over-period increase in the effective income tax rate is partly due to the buy-in of the US Master Limited Partnerships (MLP), Enbridge Energy Partners, L.P. and Spectra Energy Partners, LP, which results in the Company being taxed on 100% of the MLP earnings rather than the Company's proportionate share of their earnings.
• Lower earnings attributable to noncontrolling interests following the completion of Enbridge's buy-in of the publicly held interest in its sponsored vehicles, which were completed in separate transactions, in the fourth quarter of 2018.

Adjusted earnings per share for the second quarter of 2019 increased by $0.02 compared with the second quarter of 2018. The increase in adjusted earnings noted above, was partially offset on a per share basis by the issuance of approximately 297 million common shares to acquire, in separate transactions, all of the outstanding equity securities of its sponsored vehicles not beneficially owned by Enbridge during the fourth quarter of 2018.

ADJUSTED EBITDA BY SEGMENTS

Adjusted EBITDA by segment is reported on a Canadian dollar basis. Adjusted EBITDA generated from U.S. dollar denominated businesses were translated at stronger average Canadian dollar exchange rates in the second quarter of 2019 (C$1.34/$US) when compared to the corresponding 2018 period (C$1.29/$US). A portion of the U.S. dollar earnings are hedged under the Company's enterprise-wide financial risk management program. The offsetting hedge settlements are reported within Eliminations and Other.

LIQUIDS PIPELINES

	Three months ended June 30,			Six months ended June 30,
	2019	2018		2019	2018
(unaudited, millions of Canadian dollars)
Mainline System^1	950	956		1,914	1,898
Regional Oil Sands System	203	207		430	428
Gulf Coast and Mid-Continent System	265	161		481	339
Other^2	348	305		670	591
Adjusted EBITDA^3	1,766	1,629		3,495	3,256
Operating Data (average deliveries – thousands of bpd)
Mainline System - ex-Gretna volume^4	2,661	2,636		2,689	2,631
Regional Oil Sands System^5	1,818	1,719		1,785	1,751
International Joint Tariff (IJT)^6	$4.15	$4.07		$4.15	$4.07

1	Mainline System includes the Canadian Mainline and the Lakehead System, which were previously reported separately.
2	Included within Other are Southern Lights Pipeline, Express-Platte System, Bakken System and Feeder Pipelines & Other.
3	Schedules reconciling adjusted EBITDA are provided in the Appendices to this news release.
4	Mainline System throughput volume represents mainline system deliveries ex-Gretna, Manitoba which is made up of United States and eastern Canada deliveries originating from Western Canada.
5	Volumes are for the Athabasca mainline, Athabasca Twin, Waupisoo Pipeline and Woodland Pipeline and exclude laterals on the Regional Oil Sands System.
6	The IJT benchmark toll and its components are set in U.S. dollars and the majority of the Company's foreign exchange risk on the Canadian portion of the Mainline is hedged. The Canadian portion of the Mainline represents approximately 45% of total Mainline System revenue and the average effective FX rate for the Canadian portion of the Mainline during the second quarter of 2019 was US$1.19 (Q2 2018: US$1.26).
	The US portion of the Mainline System is subject to FX translation similar to the Company's other US based businesses, which are translated at the average spot rate for a given period. A portion of this US dollar translation exposure is hedged under the Company's enterprise-wide financial risk management program. The offsetting hedge settlements are reported within Eliminations and Other.

Liquids Pipelines adjusted EBITDA increased by $137 million for the second quarter of 2019 when compared to the same period in 2018. The key quarter-over-quarter performance drivers are summarized below:

• Mainline System EBITDA reflected higher throughput, driven by strong supply and continued optimizations of the system as well as a period-over-period increase in the IJT. However, these increases to EBITDA were more than offset by a lower foreign exchange rate on contracts used to hedge U.S. dollar denominated revenues from the Canadian portion of the Mainline System.
• Gulf Coast and Mid-Continent System growth was driven by higher volumes on Flanagan South and Seaway pipelines due to the redirection of volumes to the Gulf Coast resulting from PADD II refinery outages.
• Other increased primarily as a result of strong throughput on the Bakken Pipeline System.

GAS TRANSMISSION AND MIDSTREAM

	Three months ended June 30,			Six months ended June 30,
	2019	2018		2019	2018
(unaudited, millions of Canadian dollars)
US Gas Transmission	645	668		1,363	1,318
Canadian Gas Transmission^1	191	245		406	526
US Midstream	51	86		103	168
Other	49	33		104	66
Adjusted EBITDA^2	936	1,032		1,976	2,078

1	Canadian Gas Transmission includes Alliance Pipeline, which was previously reported separately.
2	Schedules reconciling adjusted EBITDA are available as Appendices to this news release.

Gas Transmission and Midstream adjusted EBITDA decreased by $96 million for the second quarter of 2019 when compared to the same period in 2018. The key quarter-over-quarter performance drivers are summarized below:

• US Gas Transmission adjusted EBITDA decreased due to higher planned integrity expenditures that are expected to continue over the remainder of the year, partially offset by incremental contributions from new pipelines placed into service in late 2018, including Valley Crossing.
• Canadian Gas Transmission EBITDA period-over-period results primarily reflect the absence of contributions from the provincially regulated Canadian natural gas gathering and processing business which was sold on October 1, 2018. The sale of the remaining NEB regulated assets is expected to close in the second half of 2019.
• US Midstream adjusted EBITDA primarily reflects the absence of EBITDA from Midcoast Operating, L.P. which was sold on August 1, 2018.
• Other adjusted EBITDA growth is driven by contributions from the Big Foot Oil and Gas offshore pipelines which was placed into service during 2018.

GAS DISTRIBUTION

	Three months ended June 30,			Six months ended June 30,
	2019	2018		2019	2018
(unaudited, millions of Canadian dollars)
Enbridge Gas Inc. (EGI)	373	354		1,015	926
Other	17	15		68	89
Adjusted EBITDA^1	390	369		1,083	1,015
Operating Data
EGI
Volumes (billions of cubic feet)	340	350		1,059	1,019
Number of active customers (thousands)^2				3,723	3,679
Heating degree days^3
Actual	593	557		2,639	2,457
Forecast based on normal weather^4	516	517		2,438	2,437

1	Schedules reconciling adjusted EBITDA are available as Appendices to this news release.
2	Number of active customers at the end of the reported period.
3	Heating degree days is a measure of coldness that is indicative of volumetric requirements for natural gas utilized for heating purposes in EGI's distribution franchise areas.
4	As per Ontario Energy Board approved methodology used in setting rates.

Enbridge Gas Distribution and Union Gas were amalgamated on January 1, 2019. The amalgamated company has been renamed Enbridge Gas Inc. (EGI). Post amalgamation the financial results of EGI reflect the combined performance of the two legacy utility operations.

Gas Distribution adjusted EBITDA will typically follow a seasonal profile. It is generally highest in the first and fourth quarters of the year reflecting greater volumetric usage during the heating season, and lowest in the third quarter as there is generally less volumetric usage during the summer. The magnitude of the seasonal EBITDA fluctuations will vary from year-to-year reflecting the impact of colder or warmer than normal weather on distribution volumes in a given quarter.

Gas Distribution adjusted EBITDA increased by $21 million for the second quarter 2019 when compared to the same period in 2018. The key quarter-over-quarter performance drivers are summarized below:

• Increased earnings of $4 million resulting from colder weather in EGI's franchise areas in the second quarter of 2019 driving higher utilization relative to 2018, along with higher distribution charges primarily resulting from increases in distribution rates and customer base.
• The colder weather in the second quarter of 2019 when compared to the normal weather forecast embedded in rates, positively impacted EBITDA by approximately $19 million.

RENEWABLE POWER GENERATION AND TRANSMISSION

	Three months ended June 30,			Six months ended June 30,
	2019	2018		2019	2018
(unaudited, millions of Canadian dollars)
Adjusted EBITDA^1	100	125		223	264

1	Schedules reconciling adjusted EBITDA are available as Appendices to this news release.

Renewable Power Generation and Transmission adjusted EBITDA decreased by $25 million for the second quarter of 2019 when compared to the same period in 2018. The key quarter-over-quarter performance drivers are summarized below:

• Weaker wind resources primarily at US wind farms and weaker solar radiance at the Company's solar facilities.
• These impacts were partially offset by higher contributions from the Rampion Offshore Wind Project and stronger operating performance at certain Canadian wind farms.

ENERGY SERVICES

	Three months ended June 30,			Six months ended June 30,
	2019	2018		2019	2018
(unaudited, millions of Canadian dollars)
Adjusted EBITDA^1	88	62		264	84

1	Schedules reconciling adjusted EBITDA are available as Appendices to this news release.

Energy Services adjusted EBITDA increased by $26 million for the second quarter of 2019 when compared to the same period in 2018. The key quarter-over-quarter performance drivers are summarized below:

• Higher EBITDA contributions from Energy Services crude operations due to the widening of certain location and quality differentials during the second half of 2018 and into the first quarter of 2019, which increased opportunities to generate profitable transportation margins that were realized during the first and second quarters of 2019.

ELIMINATIONS AND OTHER

	Three months ended June 30,			Six months ended June 30,
	2019	2018		2019	2018
(unaudited, millions of Canadian dollars)
Operating and administrative	(11)	1		52	(31)
Realized foreign exchange hedge settlements	(61)	(53)		(116)	(95)
Adjusted loss before interest, income taxes, and
depreciation and amortization^1	(72)	(52)		(64)	(126)

1	Schedules reconciling adjusted EBITDA are available as Appendices to this news release.

Operating and administrative costs captured in this segment reflect the cost of centrally delivered services (including depreciation of corporate assets) net of amounts recovered from business units for the provision of those services. Also, as previously noted, U.S. dollar denominated earnings within the segment results are translated at average foreign exchange rates during the quarter. The offsetting impact of settlements made under the Company's enterprise foreign exchange hedging program is captured in this segment.

Eliminations and Other adjusted loss before interest, income taxes and depreciation and amortization decreased by $20 million for the second quarter of 2019, when compared to the same period in 2018. The key quarter-over-quarter performance drivers are summarized below:

• Higher operating and administrative costs in 2019 due to timing of the recovery of certain operating and administrative costs allocated to the business segments in 2018.
• Higher realized foreign exchange hedge settlement losses primarily due to higher notional amount of foreign currency derivatives, partially offset by a smaller unfavourable spread between the average exchange rate of $1.34 for the second quarter of 2019 (Q2 2018: $1.29) and the second quarter 2019 hedge rate of $1.24 (Q2 2018: $1.16).

CONFERENCE CALL

Enbridge will host a conference call and webcast on August 2, 2019 at 9:00 a.m. Eastern Time (7:00 a.m. Mountain Time) to provide an enterprise wide business update and review 2019 second quarter financial results. Analysts, members of the media and other interested parties can access the call toll free at [phone] or within and outside North America at [phone] using the access code of 8543168#. The call will be audio webcast live at https://edge.media-server.com/mmc/p/jiy5jnxx. 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 [phone] or within and outside North America at [phone] (access code 8543168#).

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.

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 cost of capital and costs related to announced projects and projects under construction; expected in-service dates for announced projects and projects under construction; expected capital expenditures; expected equity funding requirements for our commercially secured growth program; expected future growth and expansion opportunities, including optimization plans; expectations about the Company's joint venture partners' ability to complete and finance projects under construction; expected closing of acquisitions and dispositions and the timing thereof; expected future actions of regulators and courts; expectations regarding commodity prices; supply forecasts; expectations regarding the impact of transactions, including the transactions undertaken to simplify our corporate structure; plans to launch binding open seasons, including the terms and timing thereof; toll and rate case discussions and filings; 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 timing and closing of acquisitions and dispositions; the realization of anticipated benefits and synergies of transactions; governmental legislation; litigation; the success of integration plans; impact of our dividend policy 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 expected EBITDA, expected adjusted EBITDA, earnings/(loss), expected adjusted earnings/(loss), expected DCF and associated per share amounts, or estimated future dividends. The most relevant assumptions associated with forward-looking statements regarding 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 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 realization of anticipated benefits and synergies of projects and transactions, operating performance, our dividend policy, regulatory parameters, changes in regulations applicable to our business, acquisitions and dispositions, litigation, 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 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.

ABOUT ENBRIDGE INC.
Enbridge Inc. is a leading North American energy infrastructure company. We safely and reliably deliver the energy people need and want to fuel quality of life. Our core businesses include Liquids Pipelines, which transports approximately 25 percent of the crude oil produced in North America; Gas Transmission and Midstream, which transports approximately 20 percent of the natural gas consumed in the U.S.; and Utilities and Power Operations, which serves approximately 3.7 million retail customers in Ontario, Quebec, and New Brunswick, and generates approximately 1,600 MW of net renewable power in North America and Europe. The Company's common shares trade on the Toronto and New York stock exchanges under the symbol ENB. 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.

DIVIDEND DECLARATION

On August 1, 2019, the Company's Board of Directors declared the following quarterly dividends. All dividends are payable on September 1, 2019, to shareholders of record on August 15, 2019.

	Dividend per share
Common Shares	$0.73800
Preference Shares, Series A	$0.34375
Preference Shares, Series B	$0.21340
Preference Shares, Series C^1	$0.25647
Preference Shares, Series D	$0.27875
Preference Shares, Series F	$0.29306
Preference Shares, Series H	$0.27350
Preference Shares, Series J	US$0.30540
Preference Shares, Series L	US$0.30993
Preference Shares, Series N	$0.31788
Preference Shares, Series P^2	$0.27369
Preference Shares, Series R^3	$0.25456
Preference Shares, Series 1	US$0.37182
Preference Shares, Series 3	$0.25000
Preference Shares, Series 5^4	US$0.33596
Preference Shares, Series 7^5	$0.27806
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	$0.30625

1	The quarterly dividend per share paid on Series C was decreased to $0.25395 from $0.25459 on March 1, 2019 and was increased to $0.25647 from $0.25395 on June 1, 2019, due to reset on a quarterly basis following the date of issuance of the Series C Preference Shares
2	The quarterly dividend per share paid on Series P was increased to $0.27369 from $0.25000 on March 1, 2019, due to reset of the annual dividend on March 1, 2019, and every five years thereafter
3	The quarterly dividend per share paid on Series R was increased to $0.25456 from $0.25000 on June 1, 2019, due to the reset of the annual dividend on June 1, 2019, and every five years thereafter
4	The quarterly dividend per share paid on Series 5 was increased to US$0.33596 from US$0.27500 on March 1, 2019, due to reset of the annual dividend on March 1, 2019, and every five years thereafter
5	The quarterly dividend per share paid on Series 7 was increased to $0.27806 from $0.27500 on March 1, 2019, due to reset of the annual dividend on March 1, 2019, and every five years thereafter

NON-GAAP RECONCILIATIONS APPENDICES

This news release contains references to adjusted EBITDA, adjusted earnings, adjusted earnings per common share, and DCF. Management believes the presentation of these metrics 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 and its Business Units.

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 measure of the Company's ability to generate earnings.

DCF is defined as cash flow provided by operating activities before the impact of 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 certain contingent liabilities, and non-cash unrealized derivative fair value losses and gains which are subject to market variability. Because of those challenges, a reconciliation of forward looking non-GAAP financial measures 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.

APPENDIX A
NON-GAAP RECONCILIATIONS – ADJUSTED EBITDA AND ADJUSTED EARNINGS

CONSOLIDATED EARNINGS

	Three months ended June 30,		Six months ended June 30,
	2019	2018	2019	2018
(unaudited, millions of Canadian dollars)
Liquids Pipelines	1,992	1,322	4,064	2,478
Gas Transmission and Midstream	941	1,014	1,961	1,140
Gas Distribution	390	370	1,052	1,006
Renewable Power Generation and Transmission	94	126	218	235
Energy Services	221	35	227	204
Eliminations and Other	107	(118)	355	(397)
EBITDA	3,745	2,749	7,877	4,666
Depreciation and amortization	(842)	(829)	(1,682)	(1,653)
Interest expense	(637)	(690)	(1,322)	(1,346)
Income tax (expense)/recovery	(436)	97	(1,020)	170
(Earnings)/loss attributable to noncontrolling interests and
redeemable noncontrolling interests	2	(167)	(35)	(143)
Preference share dividends	(96)	(89)	(191)	(178)
Earnings attributable to common shareholders	1,736	1,071	3,627	1,516

ADJUSTED EBITDA TO ADJUSTED EARNINGS

	Three months ended June 30,		Six months ended June 30,
	2019	2018	2019	2018
(unaudited, millions of Canadian dollars, except per share amounts)
Liquids Pipelines	1,766	1,629	3,495	3,256
Gas Transmission and Midstream	936	1,032	1,976	2,078
Gas Distribution	390	369	1,083	1,015
Renewable Power Generation and Transmission	100	125	223	264
Energy Services	88	62	264	84
Eliminations and Other	(72)	(52)	(64)	(126)
Adjusted EBITDA	3,208	3,165	6,977	6,571
Depreciation and amortization	(842)	(829)	(1,682)	(1,653)
Interest expense	(643)	(677)	(1,311)	(1,299)
Income taxes	(279)	(233)	(767)	(489)
Noncontrolling interests and redeemable noncontrolling interests	1	(243)	(37)	(483)
Preference share dividends	(96)	(89)	(191)	(178)
Adjusted earnings	1,349	1,094	2,989	2,469
Adjusted earnings per common share	0.67	0.65	1.48	1.47

EBITDA TO ADJUSTED EARNINGS

	Three months ended June 30,		Six months ended June 30,
	2019	2018	2019	2018
(unaudited, millions of Canadian dollars, except per share amounts)
EBITDA	3,745	2,749	7,877	4,666
Adjusting items:
Change in unrealized derivative fair value (gain)/loss	(695)	282	(1,131)	559
Asset write-down loss	—	10	—	1,067
Employee severance, transition and transformation costs	21	29	65	126
Equity investment asset impairment	—	—	—	33
Asset monetization costs	—	20	—	20
Write-down of inventory to the lower of cost or market	138	16	144	16
Other	(1)	59	22	84
Total adjusting items	(537)	416	(900)	1,905
Adjusted EBITDA	3,208	3,165	6,977	6,571
Depreciation and amortization	(842)	(829)	(1,682)	(1,653)
Interest expense	(637)	(690)	(1,322)	(1,346)
Income tax (expense)/recovery	(436)	97	(1,020)	170
(Earnings)/loss attributable to noncontrolling interests
and redeemable noncontrolling interests	2	(167)	(35)	(143)
Preference share dividends	(96)	(89)	(191)	(178)
Adjusting items in respect of:
Interest expense	(6)	13	11	47
Income taxes	157	(330)	253	(659)
Noncontrolling interests and redeemable noncontrolling interests	(1)	(76)	(2)	(340)
Adjusted earnings	1,349	1,094	2,989	2,469
Adjusted earnings per common share	0.67	0.65	1.48	1.47

APPENDIX B
NON-GAAP RECONCILIATION – SEGMENTED EBITDA TO ADJUSTED EBITDA

LIQUIDS PIPELINES

	Three months ended June 30,		Six months ended June 30,
	2019	2018	2019	2018
(unaudited, millions of Canadian dollars)
Adjusted EBITDA	1,766	1,629	3,495	3,256
Change in unrealized derivative fair value gain/(loss)	227	(275)	570	(573)
Asset write-down loss - asset held for sale	—	(10)	—	(154)
Employee severance, transition and transformation costs	—	(2)	—	(28)
Other	(1)	(20)	(1)	(23)
Total adjustments	226	(307)	569	(778)
EBITDA	1,992	1,322	4,064	2,478

GAS TRANSMISSION AND MIDSTREAM

	Three months ended June 30,		Six months ended June 30,
	2019	2018	2019	2018
(unaudited, millions of Canadian dollars)
Adjusted EBITDA	936	1,032	1,976	2,078
Change in unrealized derivative fair value gain/(loss)	—	(4)	—	2
Asset write-down loss - US Midstream	—	—	—	(913)
Employee severance, transition and transformation costs	—	—	—	(7)
Other	5	(14)	(15)	(20)
Total adjustments	5	(18)	(15)	(938)
EBITDA	941	1,014	1,961	1,140

GAS DISTRIBUTION

	Three months ended June 30,		Six months ended June 30,
	2019	2018	2019	2018
(unaudited; millions of Canadian dollars)
Adjusted EBITDA	390	369	1,083	1,015
Change in unrealized derivative fair value gain	4	2	8	3
Noverco Inc. equity earnings adjustment	—	—	—	(9)
Employee severance, transition and transformation costs	(4)	(1)	(39)	(3)
Total adjustments	—	1	(31)	(9)
EBITDA	390	370	1,052	1,006

RENEWABLE POWER GENERATION AND TRANSMISSION

	Three months ended June 30,		Six months ended June 30,
	2019	2018	2019	2018
(unaudited, millions of Canadian dollars)
Adjusted EBITDA	100	125	223	264
Change in unrealized derivative fair value gain	1	1	2	4
Equity investment asset impairment	—	—	—	(33)
Other	(7)	—	(7)	—
Total adjustments	(6)	1	(5)	(29)
EBITDA	94	126	218	235

ENERGY SERVICES

	Three months ended June 30,		Six months ended June 30,
	2019	2018	2019	2018
(unaudited, millions of Canadian dollars)
Adjusted EBITDA	88	62	264	84
Change in unrealized derivative fair value gain/(loss)	271	(11)	107	136
Write-down of inventory to the lower of cost or market	(138)	(16)	(144)	(16)
Total adjustments	133	(27)	(37)	120
EBITDA	221	35	227	204

ELIMINATIONS AND OTHER

	Three months ended June 30,		Six months ended June 30,
	2019	2018	2019	2018
(unaudited, millions of Canadian dollars)
Adjusted loss before interest, income taxes, and
depreciation and amortization	(72)	(52)	(64)	(126)
Change in unrealized derivative fair value gain/(loss)	192	5	444	(131)
Asset monetization costs	—	(20)	—	(20)
Employee severance, transition and transformation costs	(17)	(26)	(26)	(88)
Other	4	(25)	1	(32)
Total adjustments	179	(66)	419	(271)
Earnings/(loss) before interest, income taxes, and
depreciation and amortization	107	(118)	355	(397)

APPENDIX C
NON-GAAP RECONCILIATION – CASH PROVIDED BY OPERATING ACTIVITIES TO DCF

	Three months ended June 30,		Six months ended June 30,
	2019	2018	2019	2018
(unaudited, millions of Canadian dollars)
Cash provided by operating activities	2,494	3,344	4,670	6,538
Adjusted for changes in operating assets and liabilities^1	12	(978)	679	(1,600)
	2,506	2,366	5,349	4,938
Distributions to noncontrolling interests and redeemable noncontrolling interests	(54)	(306)	(100)	(599)
Preference share dividends	(96)	(87)	(191)	(174)
Maintenance capital expenditures^2	(269)	(294)	(448)	(459)
Significant adjusting items:
Other receipts of cash not recognized in revenue^3	33	28	86	104
Employee severance, transition and transformation costs	27	38	71	170
Distributions from equity investments in excess of cumulative earnings^4	129	75	190	188
Other items	34	38	111	2
DCF	2,310	1,858	5,068	4,170

1	Changes in operating assets and liabilities, net of recoveries.
2	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.
3	Consists of cash received net of revenue recognized for contracts under make-up rights and similar deferred revenue arrangements.
4	Presented net of adjusting items.

SOURCE Enbridge Inc.

Related Links

http://www.enbridge.com