Enbridge Reports Strong Second Quarter

CALGARY, AB, July 29, 2020 /CNW/ - Enbridge Inc. (Enbridge or the Company) (TSX: ENB) (NYSE: ENB) today reported second quarter 2020 financial results and provided a quarterly business update.

Second Quarter 2020 Highlights
(all financial figures are unaudited and in Canadian dollars unless otherwise noted)

• GAAP earnings of $1,647 million or $0.82 earnings per common share, compared with GAAP earnings of $1,736 million or $0.86 per common share in 2019
  
  
• Adjusted earnings were $1,133 million or $0.56 per common share, compared with $1,349 million or $0.67 per common share in 2019
  
  
• Adjusted earnings before interest, income tax and depreciation and amortization (EBITDA) were $3,312 million, compared with $3,208 million in 2019
  
  
• Cash Provided by Operating Activities was $2,416 million, compared with $2,494 million in 2019
  
  
• Distributable Cash Flow (DCF) was $2,437 million, compared with $2,310 million in 2019
  
  
• Re-affirmed financial guidance range for 2020 of $4.50 to $4.80 DCF/share
  
  
• Reliably served North American energy needs through continued safe operations during the ongoing COVID-19 pandemic
  
  
• To further bolster resiliency, the Company executed several actions to enable $300 million of cost reduction in 2020
  
  
• Completed 2020 debt funding plan, with more than $14 billion of available liquidity
  
  
• Received regulatory approvals on the Algonquin Gas Transmission and B.C. Pipeline uncontested rate settlements
  
  
• Secured the Fécamp offshore wind farm in France, a 500 MW facility underpinned by a long-term fixed-price power purchase agreement
  
  
• Sanctioned four growth projects in Gas Distribution and Storage to reinforce the distribution network and expand storage capacity at the Dawn hub
  
  
• Progressing execution of $11 billion secured capital program
  
  
• Successfully completed Line 3 Minnesota Public Utilities Commission (MPUC) Petition for Reconsideration process; Minnesota Pollution Control Agency (MPCA) progressing towards November 14th permitting milestone
  
  
• Regulatory review process established by the Canada Energy Regulator (CER) for the Mainline Contract application; Enbridge responded to initial Information Requests demonstrating clear benefits to the public and shippers

CEO COMMENT - Al Monaco, President and Chief Executive Officer

"The COVID-19 pandemic has had an unprecedented impact on our society, our economies and the global energy industry. At Enbridge, we responded quickly and effectively to ensure safe and uninterrupted energy delivery to our customers across North America while protecting the health of our people. As COVID unfolded early in the year, we enacted plans to further bolster our operational and financial strength to protect against a prolonged downturn, and to mitigate the impact of lower throughput on our liquids Mainline system. We have weathered the near-term effects of the pandemic on our business well - and I'm very proud of the entire Enbridge team and how we have met the challenge.

"Over the last three years we have been focused on building an even more resilient business, which put us in a strong position coming into 2020, pre-COVID. We've materially diversified the business mix to natural gas, sold our gas gathering and processing business and significantly reduced leverage while moving to an equity self-funding model. We have also simplified our corporate structure, reduced overhead and successfully executed $30 billion of capital projects.

"This year we're taking additional action to further reinforce our financial strength and flexibility. We took advantage of strong debt markets to raise $6.9 billion of capital at attractive rates, which addresses our 2020 growth capital needs, and available liquidity has been increased to $14 billion, which means we don't need to access the capital markets through 2021. We also have now fully enabled cost reductions for 2020.

"In the face of the worst energy downturn our industry has ever experienced, the strength and resilience of our assets was demonstrated once again in the second quarter, with solid financial results. We achieved DCF per share of $1.21, which exceeded our expectations for the second quarter and for the first half of the year. While there will be headwinds in the second half of 2020, which will temper favourable first half results, we expect to achieve our full year guidance range of $4.50 to $4.80 DCF per share.

"All of our business units performed well and contributed to the strong second quarter results. Most notably, Gas Transmission along with Gas Distribution and Storage both saw high utilization and favorable decisions on rates. In Liquids Pipelines, Mainline throughput was about 400 thousand barrels per day lower than our first quarter results however, throughput has been improving steadily and in-line with our expectations. This trend reflects the strong competitive position of the Midwest and Gulf Coast refineries that take Canadian heavy barrels off of our system.

"Despite the COVID disruption, we've made good progress on our strategic priorities this quarter. We are progressing our $11 billion secured capital program, including Line 3 in Minnesota, where we've now completed the regulatory process related to the Environmental Impact Statement, Certificate of Need and Route Permit. And, the Pollution Control Agency has established a firm timeline to finalize construction permits by November 14th.

"This quarter we sanctioned $1 billion of newly secured growth projects comprised of four gas utility projects and another European offshore wind project. Our Mainline contract application review is also in full swing; the CER issued a hearing order outlining the key steps in the process and we're providing evidence that demonstrates the value that Mainline contracting will deliver to customers and to ensure the value of western Canadian resources are maximized.

"In summary, the first half 2020 performance has been stronger than expected, highlighting the resiliency of our business and our ability to deliver solid results in difficult market conditions. We remain focused on executing our secured capital program, which combined with growth embedded within our business, is expected to deliver 5 to 7% annual DCF per share growth through 2022."

FINANCIAL RESULTS REVIEW AND 2020 FINANCIAL OUTLOOK

Financial results for three and six months ended June 30, 2020, are summarized in the table below:

	Three months ended June 30,		Six months ended June 30,
	2020	2019	2020	2019
(unaudited, millions of Canadian dollars, except per share amounts;   number of shares in millions)
GAAP Earnings attributable to common shareholders	1,647	1,736	218	3,627
GAAP Earnings per common share	0.82	0.86	0.11	1.80
Cash provided by operating activities	2,416	2,494	5,225	4,670
Adjusted EBITDA^1	3,312	3,208	7,075	6,977
Adjusted Earnings^1	1,133	1,349	2,801	2,989
Adjusted Earnings per common share^1	0.56	0.67	1.39	1.48
Distributable Cash Flow^1	2,437	2,310	5,143	5,068
Weighted average common shares outstanding	2,019	2,018	2,019	2,017

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 2020 decreased by $89 million or $0.04 per share compared with the same period in 2019. The period-over-period comparability of earnings attributable to common shareholders was impacted by certain unusual, infrequent factors or other non-operating factors, which are noted in the reconciliation schedule included in Appendix A of this news release.

Adjusted EBITDA in the second quarter of 2020 increased by $104 million compared with the same period in 2019.The increase was driven by strong utilization in our Gas pipelines and utility, incremental earnings from positive rate settlements on Texas Eastern, contributions from new assets that were placed into service throughout 2019 and the first quarter of 2020 and Energy Services profits from favourable storage opportunities. These positive business factors were partially offset by lower earnings from Liquids Pipelines due to lower Mainline throughput related to COVID-19 and the absence of contributions from the federally regulated Canadian natural gas gathering and processing business sold on December 31, 2019.

Adjusted earnings in the second quarter of 2020 decreased by $216 million and on a per share basis by $0.11. The decrease was primarily driven by a reduction in capitalized interest and higher depreciation from new assets placed into service throughout 2019, primarily on the Canadian Line 3 replacement program, where the Company is currently earning an interim surcharge until the U.S. portion of Line 3 is completed.

DCF for the second quarter was $2,437 million, an increase of $127 million over the second quarter of 2019 driven largely by the net impact of the operating factors noted above as well as lower maintenance capital due to timing of spend in light of COVID-19. These factors are discussed in detail under Distributable Cashflow.

Detailed segmented financial information and analysis for the second quarter of 2020 can be found below under Adjusted EBITDA by Segments.

Re-affirming 2020 Financial Guidance

Based on its solid performance in the first half and the outlook for the second half, the Company still expects to generate DCF within our original guidance range of $4.50 to $4.80 per share. The Company's outperformance in the first half of the year is expected to be offset by headwinds unique to the second half of 2020. These include the pace and magnitude of recovery in Mainline throughput, a catch up in enterprise-wide maintenance spending consistent with 2020 guidance, lower revenues on the Texas Eastern system due to temporary operating capacity restrictions, and a lower contribution from Energy Services. In addition, the Company continues to expect a favourable U.S. dollar exchange rate which will benefit unhedged cash flows, low interest rates and related financing costs, and the realization of company-wide actions to reduce costs in 2020.

In the first quarter update, the Company provided a revised outlook for Mainline volumes due to the rapid decline in refined products demand brought about by COVID-19, and the resulting cuts to crude oil refining demand. The Company forecasted Mainline volumes to decline by 400 to 600 thousand barrels per day (kbpd) for the second quarter, and an average of 300 kbpd for the last nine months of the year from average expected annual throughput of 2.84 million barrels per day (mbpd). Actual Mainline throughput for the quarter was 2.44 mbpd, which reflects a slightly faster pace of recovery in demand for refined products and higher refinery utilizations, particularly in the U.S. Midwest.

Over the balance of 2020, the Company anticipates a continued but gradual recovery in demand, consistent with our throughput guidance, as travel and border restrictions are lifted and mobility returns to North America. This view is supported by our expectation that the refineries operating in Enbridge's core Mainline system markets (i.e. the United States Midwest, Ontario, Quebec and the United States Gulf Coast) will continue to experience higher utilization rates given their scale, complexity and cost competitiveness. The Company continues to expect that Mainline volumes will be under utilized by 200-400 kbpd in the third quarter and 100-300 kbpd in the fourth quarter, and return to full utilization in early 2021.

BUSINESS PERFORMANCE AND STRATEGIC PRIORITIES UPDATE

Executing on $11 billion of Secured Growth Capital

The Company now has an inventory of approximately $11 billion of secured projects at various stages of execution, including $0.3 billion of new projects announced in Gas Distribution and Storage and $0.7 billion in Renewable Power during the second quarter. Approximately $5 billion of the $11 billion secured growth capital remains to be spent through 2022, net of anticipated project level financing provided by third parties. Details on these newly secured projects are outlined in the "business updates" sections below.

Overall, these secured projects are scheduled to come into service between 2020 and 2023 and once placed in service will provide approximately $2.5 billion of incremental cash flows and drive highly transparent growth over the near to medium term horizon. The individual projects that make up the secured program 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.

During the second quarter, the Company has continued to advance the execution of several secured projects, while assuring that COVID-19 precautionary measures are in place to protect the health of construction crews. Execution progress includes:

• Completed Phase 1 of the Express Pipeline Expansion, adding 25 kbpd of capacity.
  
  
• Progressing construction of the $1.0 billion T-South reliability and expansion project, with over $30 million in spending directly benefiting indigenous affiliated companies. The project is on target for a phased in-service date during 2021.
  
  
• Received FERC authorization to proceed with the $0.2 billion Cameron Extension project, which will connect Texas Eastern to Venture Global's Calcasieu Pass LNG facility. The project is expected to commence construction in 2020.
  
  
• The $0.9 billion Saint Nazaire French offshore wind project is advancing as planned with major contractors selected and fabrication of key project components underway.
  
  
• Advancing planned Mainline System optimizations enabling approximately 50 kbpd of incremental throughput

Liquids Pipeline Update

Mainline Contracting

In May 2020, the CER announced its plans to immediately commence the regulatory review of the Company's application to implement contracts on the Liquids Canadian Mainline System. The proposed contract offering will replace the current Competitive Toll Settlement (CTS) that is in place until it expires on June 30, 2021.

The CER issued a hearing order outlining the timelines for the regulatory review process which includes two rounds of intervenor information requests, written evidence and Enbridge's replies, concluding in April 2021. The Company expects an oral hearing to occur sometime after April 2021, but a hearing date has not yet been set. If a replacement agreement is not in place by June 30, 2021, the CTS tolls will continue on an interim basis.

During the second quarter, Enbridge responded to its first round of information requests from the CER. The evidence further supports our view that the proposed tolls meet the regulators fair return standards and that the contract offering will serve the public interest. The Mainline contract offering supports the best netbacks for Western Canadian producers, thereby maximizing the value of Western Canadian crude. This is achieved by providing the lowest toll into the best markets and securing long-term demand for Canadian heavy and light barrels.

Line 3 Replacement

The $9 billion Line 3 Replacement Project is a critical integrity replacement project that will enhance the continued safe and reliable operations of our Mainline System well into the future and reflects the importance of protecting the environment.

In December of 2019, the Company placed the $5 billion Canadian segment of the pipeline replacement into service, with an interim surcharge of US$0.20 per barrel.

On the U.S. segment of the project, in the second quarter the MPUC issued its final order to approve the final environmental impact statement (FEIS) and reinstate the Certificate of Need and Route Permit, and subsequently denied all related petitions for reconsideration. This critical milestone substantially concludes the regulatory process and allows for construction of the pipeline, which is expected to take 6 to 9 months, following the issuance of required State and Federal permits.

The MPCA released a draft of the revised 401 Water Quality Certificate permit in February 2020. Following a public comment period, the MPCA announced on June 3, 2020 that it will conduct a contested case hearing regarding the 401 Water Quality Certificate permit. This contested case will be focused on construction methods at water crossings and the appropriate measurement of environmental impacts, rather than route and need for the project, which has already been determined by the MPUC. The contested case hearing is scheduled for August 24-28, 2020, followed by the Administrative Law Judge (ALJ) issuing their report on October 16, 2020. The ALJ's contested case hearing schedule confirms that in order to maintain jurisdiction the MPCA is required by the Clean Water Act to make a final decision regarding the 401 certification by November 14, 2020.

U.S. Army Corps of Engineers (USACE) and the Minnesota Department of Natural Resources (DNR) permitting processes are ongoing and continue to progress in parallel.

At this time, Enbridge cannot determine when all necessary permits to commence construction will be issued and as such has not provided an update to the in-service date for Line 3.

Line 5 Dual Pipelines

Great Lake Tunnel Project

As part of Enbridge's agreement with the State of Michigan, the Company plans to replace its existing Line 5 dual pipelines at the Straits of Mackinac with a pipeline secured in a state-of-the-art tunnel under the Straits. The Michigan Courts have now twice confirmed the constitutionality of the legislation underpinning the agreements and the State of Michigan did not file for leave to appeal to the Supreme Court of Michigan within the requisite time period so this lawsuit has concluded.

This project will make a safe pipeline even safer, demonstrating our ongoing commitment to protect Michigan and the Great Lakes' natural resource. The Company has completed an extensive geotechnical investigation and the engineering design of the tunnel continues to progress on schedule.

Enbridge has filed for all major regulatory and environmental permits, including the joint permit application (JPA) with the Michigan Department of Environment, Great Lakes and Energy (EGLE) and the Army Corps. The JPA covers wetlands and waterway permit requirements from both state and federal agencies and allows for concurrent review of the application by both agencies. In addition, the Company filed a regulatory application to the Michigan Public Service Commission for replacement of the Line 5 pipeline into a tunnel. The Commission has scheduled a public hearing date for August 24, 2020.

Upon receipt of all required permits Enbridge will begin construction of the Line 5 tunnel. Construction and commissioning of the tunnel and pipeline is expected to be completed in late 2024.

East Segment - Line 5

On June 18, 2020, during seasonal maintenance work on Line 5, Enbridge discovered that a screw anchor support had shifted from its original position on the east segment of the dual Straits crossing pipelines. As a preliminary precaution, both the east and west segment of the crossing were immediately shut down and the Company promptly notified the State and its federal regulator, the Pipeline and Hazardous Materials Safety Administration (PHMSA). Following the identification of the shifted anchor, the Company assessed the parallel west segment and the inspections confirmed that the west segment of the crossing is safe and fit for service. PHMSA was notified prior to normal operations commencing on the west segment of Line 5 on June 20, 2020 and did not object to the re-start.

Despite the Company following standard protocol and being in full compliance with its 1953 easement, the west segment was subsequently shut down on June 25, 2020 for five days due to a Temporary Restraining Order issued by the Michigan Circuit Court. On July 1, the Temporary Restraining Order was amended allowing Enbridge to resume service of the west segment and perform an in-line inspection which reconfirmed that the line is safe to operate as there was no damage to the pipeline. The east segment of Line 5 remains shut down as we work with the PHMSA to ensure all safety assessments are complete prior to restarting the east segment of Line 5.

Gas Transmission and Midstream Update

The Company has made several advancements on the regulatory front, further optimizing the base business by ensuring fair and timely cost recovery through rate proceedings. Following on the successful Texas Eastern settlement in the first quarter, the Company received approval from the FERC of its uncontested rate settlement on its Algonquin Gas Transmission pipeline, and approval by the CER of our uncontested rate settlement on the B.C. Pipeline, during the second quarter, resulting in a good outcome for both Enbridge and shippers. The Company has also initiated rate proceedings on East Tennessee Natural Gas and the U.S portions of both the Alliance Pipeline and the Maritimes & Northeast Pipeline.

On May 4, 2020, a rupture occurred on Line 10, a 30-inch natural gas pipeline that makes up part of the Texas Eastern natural gas pipeline system in Fleming County, Kentucky. There were no reported injuries or damaged structures as a result of the rupture. Texas Eastern crews isolated all three pipelines in this corridor as part of the initial incident response and investigation. The Line 25 36-inch pipeline has since been returned to service. The National Transportation Safety Board is working with the Pipeline and Hazardous Materials Safety Administration (PHMSA) and Enbridge to investigate the incident. On June 1, 2020, the PHMSA issued an amendment to the Lincoln County Corrective Action Order (CAO) addressing the Fleming County rupture. Texas Eastern is currently performing precautionary integrity assessments in compliance with the CAO and the Company is focused on restoring the pipeline to full service by the winter heating season.

Gas Distribution and Storage Update

The Company announced today that it is proceeding with $0.3 billion of utility growth capital expenditures including regulated rate base system reinforcements and an enhancement of its unregulated storage facilities at Dawn, Ontario. These projects are expected to come into service between 2021 and 2023.

In May, Enbridge Gas Inc. (EGI) received a positive decision on its 2020 rate filing from the Ontario Energy Board which included approval of 2020 rates and the funding of two discrete incremental capital investments through the incremental capital funding (ICM) mechanism with a total capital cost of $0.1 billion. The ICM mechanism is a regulatory tool that allows for recovery of the revenue requirement for certain incremental capital additions, beyond what is funded through previously approved rates. This 2020 filing represents the second year of a five-year incentive rate structure.

The Company continues to advance the capture of synergies from the amalgamation of Enbridge Gas Distribution Inc. and Union Gas Limited.

Renewable Power Update

Enbridge has investments in 24 facilities in North America and now has several investments in offshore wind projects in Europe, both in the development stage as well as operational. In June of 2020, the Company announced that it is moving forward with the 500 MW Fécamp offshore wind farm, which is comprised of 71 wind turbines off the coast of northwest France, providing annual electricity to meet the power needs for 770,000 people.

Enbridge has a 35% interest in the project (17.9% after completion of the CPP Investment transaction discussed below) with partners EDF Renewables and wpd holding the remaining interest. The total project capital cost is estimated to be EUR2 billion, of which the majority will be financed through non-recourse project level debt. The project is underpinned by a 20-year fixed price power purchase agreement with the French State and project commissioning is expected in 2023.

In the first quarter, Enbridge announced the execution of agreements whereby 49% of an entity that holds Enbridge's 50% interest in Éolien Maritime France SAS (EMF) will be sold to CPP Investments. The Company's investment in Fécamp is held through its 50% interest in EMF. Completion of the transaction is subject to customary regulatory approvals and is anticipated to close in the fourth quarter of 2020.

STRONG FINANCIAL POSITION AND SELF FUNDING MODEL INTACT

The Company has exited the second quarter in a strong financial position with over $14 billion of liquidity and having completed its 2020 funding plan. The equity-self funding model remains intact and debt to EBITDA is expected to remain comfortably well-within the target range of 4.5x to 5.0x for the full year.

The Company continued to secure additional debt financing at attractive rates and proceeds from these offerings were primarily used to reduce existing indebtedness and partially fund capital projects.

In May, the Company raised $1.3 billion with a dual tranche offering of 5-year and 7-year notes in the Canadian debt capital markets at a weighted average coupon rate of 2.65%. In addition, subsequent to the second quarter, Enbridge raised an additional US$1.0 billion of 60-year hybrid subordinated notes in the United States debt capital markets. These hybrid notes qualify for 50% equity treatment from most rating agencies which further bolsters the Company's financial strength.

In late July, the Company successfully renegotiated and extended approximately $10 billion of its 364-day extendible credit facilities to July 2021, with the option of a term out date to July 2022.

The above actions have positioned the Company to fund all of our capital projects and any debt maturities through 2021 in the event capital markets are inaccessible.

EXECUTIVE LEADERSHIP CHANGES

The Company is announcing that Executive Vice President & Chief Development Officer, John Whelen, will retire, effective October 31. Over the last 28 years, Mr. Whelen has played a pivotal role in Enbridge's growth and evolution, holding several senior leadership roles in Finance and Corporate Development. From 2014 to 2019, Mr. Whelen held the role of Chief Financial Officer, where he oversaw the financial design and execution of several very significant funding and investment transactions, including Enbridge's $37 Billion acquisition of Spectra.

"Along the way John has played a key role in helping build Enbridge's financial foundation and laying the groundwork for our Company's growth and success", said President and CEO Al Monaco.  "He will leave a lasting legacy at Enbridge, and we wish him and his family the very best in the future."

John's role will be filled by current members of our Executive Leadership Team.  Matthew Akman will continue in his role as Senior Vice President, Strategy and Power, and Allen Capps will expand his corporate development portfolio to include our energy marketing business as Senior Vice President, Corporate Development and Energy Services.  Both Mr. Akman and Mr. Capps will report directly to Al Monaco, President and Chief Executive Officer effective September 15.

SECOND QUARTER 2020 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 2020.

GAAP SEGMENT EBITDA AND CASH FLOW FROM OPERATIONS

	Three months ended June 30,		Six months ended June 30,
	2020	2019	2020	2019
(unaudited, millions of Canadian dollars)
Liquids Pipelines	2,340	1,992	3,190	4,064
Gas Transmission and Midstream	950	941	(104)	1,961
Gas Distribution and Storage	383	390	987	1,052
Renewable Power Generation	163	94	283	218
Energy Services	(99)	221	22	227
Eliminations and Other	261	107	(705)	355
EBITDA	3,998	3,745	3,673	7,877
Earnings attributable to common shareholders	1,647	1,736	218	3,627
Cash provided by operating activities	2,416	2,494	5,225	4,670

For purposes of evaluating performance, the Company makes adjustments for unusual, infrequent or other 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 underlying business performance. Tables incorporating these adjustments follow below. Schedules reconciling EBITDA, adjusted EBITDA, adjusted EBITDA by segment, adjusted earnings, adjusted earnings per 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,
	2020	2019	2020	2019
(unaudited, millions of Canadian dollars, except per share amounts)
Liquids Pipelines	1,744	1,766	3,663	3,495
Gas Transmission and Midstream	975	936	2,072	1,976
Gas Distribution and Storage	406	390	1,015	1,083
Renewable Power Generation	150	100	268	223
Energy Services	86	88	73	264
Eliminations and Other	(49)	(72)	(16)	(64)
Adjusted EBITDA^1,3	3,312	3,208	7,075	6,977
Maintenance capital	(135)	(269)	(339)	(448)
Interest expense^1	(709)	(662)	(1,420)	(1,346)
Current income tax^1	(134)	(53)	(242)	(211)
Distributions to noncontrolling interests^1	(88)	(54)	(164)	(100)
Cash distributions in excess of equity earnings^1	210	189	282	283
Preference share dividends	(94)	(96)	(190)	(191)
Other receipts of cash not recognized in revenue^2	81	33	132	86
Other non-cash adjustments	(6)	14	9	18
DCF^3	2,437	2,310	5,143	5,068
Weighted average common shares outstanding	2,019	2,018	2,019	2,017

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 2020 DCF increased $127 million compared with the same period of 2019. Key performance drivers of quarter-over-quarter increase included:

• Growth in adjusted EBITDA was driven by strong utilization in our Gas pipelines and utility, incremental earnings from positive rate settlements on Texas Eastern, contributions from new assets that were placed into service throughout 2019 and the first quarter of 2020 and Energy Services profits from favourable storage opportunities. These positive business factors were partially offset by lower earnings from Liquids Pipelines due to lower Mainline throughput related to COVID-19 and the absence of contributions from the federally regulated Canadian natural gas gathering and processing business sold on December 31, 2019. For further detail on business performance refer to Adjusted EBITDA by Segments.
• Lower maintenance capital due to timing of spend in light of COVID-19 mobility restrictions.
• Higher interest expense due to a combination of additional new debt incurred to fund capital expenditures as well as a reduction in capitalized interest associated with the Canadian portion of Line 3 placed into service in December 2019, partially offset by lower rates on short-term and newly issued long-term notes.
• Higher current income tax due to higher minimum US tax and timing of recognition of newly enacted Canadian tax legislation that came into effect in the second half of 2019.
• Higher cash distributions in excess of equity earnings due to both timing of distributions and new assets placed into service, including Gray Oak crude oil pipeline and Hohe See Offshore Wind Project; partially offset by a 50% distribution cut at DCP Midstream, LP (DCP Midstream).

ADJUSTED EARNINGS	Three months ended June 30,		Six months ended June 30,
	2020	2019	2020	2019
(unaudited, millions of Canadian dollars, except per share amounts)
Adjusted EBITDA^2	3,312	3,208	7,075	6,977
Depreciation and amortization	(949)	(842)	(1,831)	(1,682)
Interest expense^1	(695)	(643)	(1,391)	(1,311)
Income taxes^1	(404)	(279)	(855)	(767)
Noncontrolling interests^1	(37)	1	(7)	(37)
Preference share dividends	(94)	(96)	(190)	(191)
Adjusted earnings^2	1,133	1,349	2,801	2,989
Adjusted earnings per common share	0.56	0.67	1.39	1.48

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

Adjusted earnings decreased $216 million and adjusted earnings per share decreased $0.11 compared with the first quarter in 2019. Growth in adjusted EBITDA was driven by the same factors impacting business performance and adjusted EBITDA as discussed under Distributable Cash Flow above, partially offset by the following factors:

• Higher depreciation and amortization expense as a result of new assets placed into service throughout 2019, primarily on Line 3 Canada which entered service in December 2019.
• Higher interest expense due to debt issued to fund new growth capital as well as a reduction in capitalized interest associated with the Canadian portion of Line 3, partially offset by lower rates on short-term debt and newly issued long-term notes.
• Higher income taxes primarily due to higher minimum US tax and timing of recognition of newly enacted Canadian tax legislation that came into effect in the second half of 2019.

ADJUSTED EBITDA BY SEGMENTS

Adjusted EBITDA by segment is reported on a Canadian dollar basis. Adjusted EBITDA generated from U.S. dollar denominated businesses was translated at a higher average Canadian dollar exchange rate in the second quarter of 2020 (C$1.39/US$) when compared with the corresponding 2019 period (C$1.34/US$).

A portion of the U.S. dollar earnings is 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,
	2020	2019	2020	2019
(unaudited, millions of Canadian dollars)
Mainline System^1	969	950	2,076	1,914
Regional Oil Sands System	199	203	410	430
Gulf Coast and Mid-Continent System	257	265	501	481
Other^2	319	348	676	670
Adjusted EBITDA^3	1,744	1,766	3,663	3,495
Operating Data (average deliveries – thousands of bpd)
Mainline System - ex-Gretna volume^4	2,439	2,661	2,641	2,689
Regional Oil Sands System^5	1,399	1,818	1,632	1,785
International Joint Tariff (IJT)^6	$4.21	$4.15	$4.21	$4.15

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 2020 was C$1.17/US$ (Q2 2019: C$1.19/US$).
	The U.S. portion of the Mainline System is subject to FX translation similar to the Company's other U.S. based businesses, which are translated at the average spot rate for a given period. A portion of this U.S. 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 decreased $22 million compared to the second quarter of 2019 primarily as a result of the following factors:

• Mainline System contributions was negatively impacted by reduced utilization rates, with ex-Gretna throughput down on average 222 kbpd, driven by the impact of COVID-19 on supply and demand for oil and related products; this was more than offset by a higher IJT Benchmark Toll and contributions from the Canadian Line 3 Replacement (L3R) Program that was placed into service on December 1, 2019 with an interim surcharge on Mainline System volumes of US$0.20 per barrel.
• Regional Oil Sands contributions were consistent despite the decrease in delivery volumes which is largely due to the majority of the assets being contracted under take-or-pay arrangements.
• Gulf Coast and Mid-Continent System was slightly down due to lower period-over-period throughput on the Seaway Crude Pipeline driven by the impact of COVID-19 on the Gulf Coast demand and lower Flanagan South Pipeline throughput.
• Other decreased due to lower throughput on our Bakken Pipeline System driven by the impact of lower prices and COVID-19 on supply and demand for oil and products.

GAS TRANSMISSION AND MIDSTREAM

	Three months ended June 30,		Six months ended June 30,
	2020	2019	2020	2019
(unaudited, millions of Canadian dollars)
US Gas Transmission^1	791	672	1,655	1,417
Canadian Gas Transmission^1	105	164	243	352
US Midstream	35	51	80	103
Other	44	49	94	104
Adjusted EBITDA^2	975	936	2,072	1,976

1	US Gas Transmission includes the Canadian portion of the Maritimes & Northeast Pipeline which was previously included in Canadian Gas Transmission. The comparable 2019 adjusted EBITDA has been restated to reflect this change.
2	Schedules reconciling adjusted EBITDA are available as Appendices to this news release.

Gas Transmission and Midstream adjusted EBITDA increased $39 million compared to the second quarter of 2019 primarily due to the following factors:

• US Gas Transmission adjusted EBITDA increased primarily due to higher revenues from Texas Eastern resulting from the recent rate settlement and contributions from the Stratton Ridge project and the second phase of the Atlantic Bridge project that were placed into service in the third and fourth quarters of 2019, respectively; partly offset by higher operating costs.
• Canadian Gas Transmission adjusted EBITDA decreased primarily due to the absence of contributions from federally regulated Canadian gas gathering and processing assets that were sold on December 31, 2019. Further, contributions from the Alliance Pipeline and Aux Sable are also lower driven by narrowed AECO-Chicago basis and lower commodity prices impacting fractionation margins, respectively.

GAS DISTRIBUTION AND STORAGE

	Three months ended June 30,		Six months ended June 30,
	2020	2019	2020	2019
(unaudited, millions of Canadian dollars)
Enbridge Gas Inc. (EGI)	385	373	959	1,015
Other	21	17	56	68
Adjusted EBITDA^1	406	390	1,015	1,083
Operating Data
EGI
Volumes (billions of cubic feet)	351	340	989	1,059
Number of active customers (thousands)^2			3,750	3,723
Heating degree days^3
Actual	606	593	2,333	2,639
Forecast based on normal weather^4	516	516	2,439	2,438

1	Schedules reconciling adjusted EBITDA are available as Appendices to this news release.
2	Number of active customers is the number of natural gas consuming 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	Normal weather is the weather forecast by EGI in its legacy rate zones, using the forecasting methodologies approved by the Ontario Energy Board.

Gas Distribution and Storage adjusted EBITDA will typically follow a seasonal profile. It is generally highest in the first and fourth quarters of the year reflecting greater volumetric demand during the heating season. 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.

Gas Distribution and Storage adjusted EBITDA increased $16 million compared to the second quarter of 2019 primarily due to:

• Colder weather experienced in our franchise service areas which led to higher utilization. When compared with the normal weather forecast embedded in rates, the colder weather in the second quarter of 2020 positively impacted EBITDA by approximately $22 million (Q2 2019: ~$19 million); and
• Higher distribution revenues resulting from increases in rates and customer base growth, as well as synergy capture realized from the amalgamation of Enbridge Gas Distribution Inc. and Union Gas Limited.

The positive business factors above were partially offset by the absence of earnings in 2020 from Enbridge Gas New Brunswick and St. Lawrence Gas Company, Inc. which were sold on October 1, 2019, and November 1, 2019, respectively.

RENEWABLE POWER GENERATION

	Three months ended June 30,		Six months ended June 30,
	2020	2019	2020	2019
(unaudited, millions of Canadian dollars)
Adjusted EBITDA^1	150	100	268	223

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

Renewable Power Generation adjusted EBITDA increased $50 million compared to second quarter of 2019 primarily due to:

• Stronger wind resources at United States wind facilities;
• Contributions from the Hohe See Offshore Wind Project, which reached full operating capacity in October 2019, and the Albatros expansion, which was placed into service in January 2020; and
• Reimbursements received at certain Canadian wind facilities resulting from a change in operator.

These factors were partially offset by higher mechanical repair costs at certain United States wind facilities.

ENERGY SERVICES

	Three months ended June 30,		Six months ended June 30,
	2020	2019	2020	2019
(unaudited, millions of Canadian dollars)
Adjusted EBITDA^1	86	88	73	264

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

Energy Services adjusted EBITDA decreased $2 million compared to the second quarter of 2019 as a result of compression of location and quality differentials in certain markets which lead to fewer opportunities to achieve profitable margins on capacity obligations, partially offset by favorable storage opportunities.

ELIMINATIONS AND OTHER

	Three months ended June 30,		Six months ended June 30,
	2020	2019	2020	2019
(unaudited, millions of Canadian dollars)
Operating and administrative recoveries	29	(11)	108	52
Realized foreign exchange hedge settlements	(78)	(61)	(124)	(116)
Adjusted EBITDA^1	(49)	(72)	(16)	(64)

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

Operating and administrative recoveries captured in this segment reflect the cost of centrally delivered services (including depreciation of corporate assets) inclusive 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 are captured in this segment.

Eliminations and Other adjusted EBITDA increased $23 million compared with the second quarter of 2019. Key quarter-over-quarter performance drivers included:

• Lower operating and administrative costs as a result of cost containment actions, as well as timing related to the recovery of certain operating and administrative costs allocated to the business segments offset by
• Higher realized foreign exchange settlement losses primarily due to a wider spread between the average exchange rate of $1.39 for the second quarter of 2020 (Q2 2019:$1.34) and the second quarter 2020 hedge rate of $1.29 (Q2 2019:$1.24).

CONFERENCE CALL

Enbridge will host a conference call and webcast on July 29, 2020 at 9:00 a.m. Eastern Time (7:00 a.m. Mountain Time) to provide an enterprise wide business update and review 2020 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 5290259#. The call will be audio webcast live at https://edge.media-server.com/mmc/p/ih678xin. It is recommended that participants dial in or join the audio webcast fifteen minutes prior to the scheduled start time. 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 5290259#).

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.

DIVIDEND DECLARATION

The Company's Board of Directors declared the following quarterly dividends, payable on September 1, 2020, to shareholders of record on August 14, 2020.

	Dividend per share
Common Shares^1	$0.81000
Preference Shares, Series A	$0.34375
Preference Shares, Series B	$0.21340
Preference Shares, Series C^2	$0.16779
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	$0.27369
Preference Shares, Series R	$0.25456
Preference Shares, Series 1	US$0.37182
Preference Shares, Series 3	$0.23356
Preference Shares, Series 5	US$0.33596
Preference Shares, Series 7	$0.27806
Preference Shares, Series 9	$0.25606
Preference Shares, Series 11^3	$0.24613
Preference Shares, Series 13^4	$0.19019
Preference Shares, Series 15	$0.27500
Preference Shares, Series 17	$0.32188
Preference Shares, Series 19	$0.30625

1	The quarterly dividend per common share was increased 9.8% to $0.81 from $0.738, effective March 1, 2020.
2	The quarterly dividend per share paid on Series C was decreased to $0.16779 from $0.25458 on June 1, 2020 and was increased to $0.25458 from $0.25305 on March 1, 2020, due to reset on a quarterly basis following the date of issuance of the Series C Preference Shares.
3	The quarterly dividend per share paid on Series 11 was decreased to $0.24613 from $0.275 on March 1, 2020, due to the reset of the annual dividend on March 1, 2020, and every five years thereafter.
4	The quarterly dividend per share paid on Series 13 was decreased to $0.19019 from $0.275 on June 1, 2020, due to the reset of the annual dividend on June 1, 2020, and every five years thereafter.

FORWARD-LOOKING INFORMATION

Forward-looking information, or forward-looking statements, have been included in this news release to provide information about Enbridge 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: Enbridge's corporate vision and strategy, including strategic priorities and enablers; 2020 financial guidance; the COVID-19 pandemic and the duration and impact thereof; anticipated reductions in operating costs and deferrals of secured growth capital spend; the expected supply of, demand for and prices of crude oil, natural gas, natural gas liquids, liquified natural gas and renewable energy; anticipated utilization of our existing assets, including throughput on the Mainline; 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; expected debt-to-EBITDA ratio; financial strength and flexibility; expectations on sources of liquidity and sufficiency of financial resources; expected costs related to announced projects and projects under construction and for maintenance; expected in-service dates for announced projects and projects under construction; expected capital expenditures; expected future growth and expansion opportunities; expectations about the Company's joint ventures and our partners' ability to complete and finance announced projects and projects under construction; expected closing of acquisitions and dispositions and the timing thereof; expected benefits of transactions, including the realization of efficiencies and synergies; expected future actions of regulators and courts; toll and rate case discussions and filings, including Mainline Contracting and the anticipated benefits thereof; United States Line 3 Replacement Program; Line 5 dual pipelines and related matters; Line 10 of the Texas Eastern system; interest rates; and exchange rates.

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 COVID-19 pandemic and the duration and impact thereof; anticipated reductions in operating costs and deferrals of secured growth; 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, including the current weakness and volatility of such prices; anticipated utilization of our existing assets; 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; impact of the Company's dividend policy on its future cash flows; credit ratings; capital project funding; hedging program; 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, interest rates and the COVID-19 pandemic 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 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; and the COVID-19 pandemic and the duration and impact thereof.

Enbridge's forward-looking statements are subject to risks and uncertainties pertaining to the realization of anticipated benefits and synergies of projects and transactions; successful execution of our strategic priorities, operating performance, the Company's dividend policy, regulatory parameters, changes in regulations applicable to the Company's business, litigation, acquisitions and dispositions and other transactions, 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, political decisions, exchange rates, interest rates, commodity prices, supply of and demand for commodities and the COVID-19 pandemic, including but not limited to those risks and uncertainties discussed in this 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.; Gas Distribution and Storage, which serves approximately 3.8 million retail customers in Ontario and Quebec; and Renewable Power Generation, which generates approximately 1,750 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.

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, infrequent or other 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, infrequent or other non-operating factors included in adjusted EBITDA, as well as adjustments for unusual, infrequent or other non-operating factors in respect of depreciation and amortization expense, interest expense, income taxes, and 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, preference share dividends and maintenance capital expenditures, and further adjusted for unusual, infrequent or other 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,
	2020	2019	2020	2019
(unaudited, millions of Canadian dollars)
Liquids Pipelines	2,340	1,992	3,190	4,064
Gas Transmission and Midstream	950	941	(104)	1,961
Gas Distribution and Storage	383	390	987	1,052
Renewable Power Generation	163	94	283	218
Energy Services	(99)	221	22	227
Eliminations and Other	261	107	(705)	355
EBITDA	3,998	3,745	3,673	7,877
Depreciation and amortization	(949)	(842)	(1,831)	(1,682)
Interest expense	(681)	(637)	(1,387)	(1,322)
Income tax expense	(591)	(436)	(42)	(1,020)
(Earnings)/loss attributable to noncontrolling interests	(36)	2	(5)	(35)
Preference share dividends	(94)	(96)	(190)	(191)
Earnings attributable to common shareholders	1,647	1,736	218	3,627

ADJUSTED EBITDA TO ADJUSTED EARNINGS

	Three months ended June 30,		Six months ended June 30,
	2020	2019	2020	2019
(unaudited, millions of Canadian dollars, except per share amounts)
Liquids Pipelines	1,744	1,766	3,663	3,495
Gas Transmission and Midstream	975	936	2,072	1,976
Gas Distribution and Storage	406	390	1,015	1,083
Renewable Power Generation	150	100	268	223
Energy Services	86	88	73	264
Eliminations and Other	(49)	(72)	(16)	(64)
Adjusted EBITDA	3,312	3,208	7,075	6,977
Depreciation and amortization	(949)	(842)	(1,831)	(1,682)
Interest expense	(695)	(643)	(1,391)	(1,311)
Income tax expense	(404)	(279)	(855)	(767)
(Earnings)/loss attributable to noncontrolling interests	(37)	1	(7)	(37)
Preference share dividends	(94)	(96)	(190)	(191)
Adjusted earnings	1,133	1,349	2,801	2,989
Adjusted earnings per common share	0.56	0.67	1.39	1.48

EBITDA TO ADJUSTED EARNINGS

	Three months ended June 30,		Six months ended June 30,
	2020	2019	2020	2019
(unaudited, millions of Canadian dollars, except per share amounts)
EBITDA	3,998	3,745	3,673	7,877
Adjusting items:
Change in unrealized derivative fair value (gain)/loss - Foreign exchange	(1,186)	(424)	770	(1,024)
Change in unrealized derivative fair value (gain)/loss - Commodity prices	525	(139)	49	122
Equity investment impairment - DCP Midstream	—	—	1,736	—
Equity investment asset and goodwill impairment - DCP Midstream	—	—	324	—
Net inventory adjustment - Energy Services	(340)	6	2	(85)
Employee severance, transition and transformation costs	268	21	279	65
Texas Eastern re-establishment of EDIT regulated liability	—	—	159	—
Other	47	(1)	83	22
Total adjusting items	(686)	(537)	3,402	(900)
Adjusted EBITDA	3,312	3,208	7,075	6,977
Depreciation and amortization	(949)	(842)	(1,831)	(1,682)
Interest expense	(681)	(637)	(1,387)	(1,322)
Income tax expense	(591)	(436)	(42)	(1,020)
(Earnings)/loss attributable to noncontrolling interests	(36)	2	(5)	(35)
Preference share dividends	(94)	(96)	(190)	(191)
Adjusting items in respect of:
Interest expense	(14)	(6)	(4)	11
Income tax expense	187	157	(813)	253
(Earnings)/loss attributable to noncontrolling interests	(1)	(1)	(2)	(2)
Adjusted earnings	1,133	1,349	2,801	2,989
Adjusted earnings per common share	0.56	0.67	1.39	1.48

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

LIQUIDS PIPELINES

	Three months ended June 30,		Six months ended June 30,
	2020	2019	2020	2019
(unaudited, millions of Canadian dollars)
Adjusted EBITDA	1,744	1,766	3,663	3,495
Change in unrealized derivative fair value gain/(loss)	616	227	(450)	570
Asset write-down loss	(13)	(1)	(13)	(1)
Employee severance, transition and transformation costs	(7)	—	(7)	—
Other	—	—	(3)	—
Total adjustments	596	226	(473)	569
EBITDA	2,340	1,992	3,190	4,064

GAS TRANSMISSION AND MIDSTREAM

	Three months ended June 30,		Six months ended June 30,
	2020	2019	2020	2019
(unaudited, millions of Canadian dollars)
Adjusted EBITDA	975	936	2,072	1,976
Equity investment impairment - DCP Midstream	—	—	(1,736)	—
Equity investment asset and goodwill impairment - DCP Midstream	—	—	(324)	—
Equity earnings adjustment - DCP Midstream	(22)	9	31	(4)
Texas Eastern re-establishment of EDIT regulated liability	—	—	(159)	—
Other	(3)	(4)	12	(11)
Total adjustments	(25)	5	(2,176)	(15)
Earnings/(loss) before interest, income taxes and depreciation and amortization	950	941	(104)	1,961

GAS DISTRIBUTION AND STORAGE

	Three months ended June 30,		Six months ended June 30,
	2020	2019	2020	2019
(unaudited; millions of Canadian dollars)
Adjusted EBITDA	406	390	1,015	1,083
Change in unrealized derivative fair value gain/(loss)	(15)	4	(9)	8
Employee severance, transition and transformation costs	(8)	(4)	(15)	(39)
Other	—	—	(4)	—
Total adjustments	(23)	—	(28)	(31)
EBITDA	383	390	987	1,052

RENEWABLE POWER GENERATION

	Three months ended June 30,		Six months ended June 30,
	2020	2019	2020	2019
(unaudited, millions of Canadian dollars)
Adjusted EBITDA	150	100	268	223
Change in unrealized derivative fair value gain	—	1	2	2
Disposition - MATL transmission assets	13	—	13	—
Other	—	(7)	—	(7)
Total adjustments	13	(6)	15	(5)
EBITDA	163	94	283	218

ENERGY SERVICES

	Three months ended June 30,		Six months ended June 30,
	2020	2019	2020	2019
(unaudited, millions of Canadian dollars)
Adjusted EBITDA	86	88	73	264
Change in unrealized derivative fair value gain/(loss)	(525)	139	(49)	(122)
Net inventory adjustment	340	(6)	(2)	85
Total adjustments	(185)	133	(51)	(37)
Earnings/(loss) before interest, income taxes and depreciation and amortization	(99)	221	22	227

ELIMINATIONS AND OTHER

	Three months ended June 30,		Six months ended June 30,
	2020	2019	2020	2019
(unaudited, millions of Canadian dollars)
Adjusted loss before interest, income taxes, and depreciation and amortization	(49)	(72)	(16)	(64)
Change in unrealized derivative fair value gain/(loss)	585	192	(313)	444
Change in corporate guarantee obligation	—	—	(74)	—
Investment write-down loss	—	—	(43)	—
Employee severance, transition and transformation costs	(253)	(17)	(257)	(26)
Other	(22)	4	(2)	1
Total adjustments	310	179	(689)	419
Earnings/(loss) before interest, income taxes and depreciation and amortization	261	107	(705)	355

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

	Three months ended June 30,		Six months ended June 30,
	2020	2019	2020	2019
(unaudited, millions of Canadian dollars)
Cash provided by operating activities	2,416	2,494	5,225	4,670
Adjusted for changes in operating assets and liabilities^1	91	12	(103)	679
	2,507	2,506	5,122	5,349
Distributions to noncontrolling interests^4	(88)	(54)	(164)	(100)
Preference share dividends	(94)	(96)	(190)	(191)
Maintenance capital expenditures^2	(135)	(269)	(339)	(448)
Significant adjusting items:
Other receipts of cash not recognized in revenue^3	81	33	132	86
Employee severance, transition and transformation costs	268	27	279	71
Distributions from equity investments in excess of cumulative earnings^4	176	129	253	190
Other items	(278)	34	50	111
DCF	2,437	2,310	5,143	5,068

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