Enbridge Inc. Reports Strong Fourth Quarter & Full Year 2019 Results

CALGARY, Feb. 14, 2020 /CNW/ - Enbridge Inc. (Enbridge or the Company) (TSX:ENB) (NYSE:ENB) today reported fourth quarter and full year 2019 financial results and provided a quarterly business update.

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

• Full year GAAP earnings of $5,322 million or $2.64 per common share compared with $2,515 million or $1.46 per common share for 2018
  
  
• Adjusted earnings of $5,341 million or $2.65 per common share in 2019 compared with $4,568 million or $2.65 per common share for 2018
  
  
• Adjusted earnings before interest, income tax and depreciation and amortization (EBITDA) of $13,271 million in 2019 compared with $12,849 million for 2018
  
  
• Cash Provided by Operating Activities of $9,398 million in 2019 compared with $10,502 million for 2018
  
  
• Distributable Cash Flow (DCF) of $9,224 million in 2019 compared with $7,618 million for 2018
  
  
• Achieved the top-end of full-year DCF per share guidance range of $4.30 to $4.60
  
  
• Reaffirmed 2020 DCF per share guidance range of $4.50 to $4.80, and longer term 5 to 7% DCF per share growth outlook, within an equity self-funding model
  
  
• Increased the quarterly dividend by 9.8% for 2020 to 81 cents per share, reflecting strong operating and financial performance and the Company's outlook
  
  
• Delivered 100 thousand barrels per day (kbpd) of planned Mainline optimizations, providing much needed egress capacity for Western Canadian producers
  
  
• Placed $7 billion of new projects into service in the fourth quarter, including the US$0.7 billion investment in the Gray Oak pipeline, the $1.1 billion German Hohe See offshore wind project, and the Canadian segment of the Line 3 Replacement project, under an interim surcharge agreement
  
  
• Filed regulatory application in support of contracting the Liquids Mainline System on December 19, with support from shippers representing over 70% of current throughput
  
  
• Minnesota Public Utilities Commission (MPUC) re-certified the Line 3 Replacement project Final Environmental Impact Statement (FEIS), the Certificate of Need and the Route Permit on February 3, 2020
  
  
• Advanced LNG supply strategy with the announcement of agreement to expand our system to supply the Annova LNG facility in the Port of Brownsville, Texas, and agreements to acquire the Rio Bravo pipeline development project and supply the Rio Grande LNG facility
  
  
• Closed second phase of the Canadian midstream sale, successfully concluding previously announced $8 billion asset sale program; achieved 4.5x Debt/EBITDA at year end
  
  
• Announced the $0.2 billion sale of the Montana-Alberta Tie Line (MATL); further increasing financial flexibility

CEO COMMENT

"2019 was a successful year for Enbridge", commented Al Monaco, President and Chief Executive Officer of Enbridge. "Our low risk pipeline-utility model continued to deliver strong financial results and we advanced our strategic priorities on many fronts.

"Each of our core businesses delivered solid results in 2019 that translated into full-year DCF per share at the top-end of our guidance range. The Liquids Mainline System achieved record annual throughput, our gas pipelines were highly utilized, and we're capturing synergies through the amalgamation of our Ontario Utility businesses. In addition to strong business performance, we placed a further $9 billion of new projects into service, including the Canadian segment of the Line 3 Replacement. Our focus on optimizing our base business and executing on our secured growth program continues to drive highly predictable and growing cash flows, which resulted in exceptional annual dividend growth for our shareholders of 10% in 2019 and 9.8% in 2020.

"Despite strong utilization and financial performance across our businesses, we experienced a major incident on our natural gas system in Kentucky. The safety of our systems is always our number one priority and we're re-doubling our efforts to ensure our pipelines continue to be the safest in the industry.

"In the Liquids Pipeline segment, we delivered on our plan for 100 kbpd of throughput optimizations on the Mainline system by the end of 2019. We're planning for a further 50 kbpd of Mainline optimizations and we're moving forward with a 50 kbpd expansion of the Express Pipeline in 2020. These actions will provide WCSB producers with at least 200 kbpd of much needed additional pipeline capacity.

"On the U.S. portion of our Line 3 Replacement Project, on February 3 the MPUC approved the FEIS and reinstated the Certificate of Need and Route Permit. This important decision by the MPUC reflects the most comprehensive review of a pipeline project in Minnesota history and reaffirms the need for the pipeline to be replaced. We'll continue to work closely with State and Federal permitting agencies to secure all necessary permits prior to commencing construction.

"In addition, following almost two years of extensive negotiation with our shippers, we filed the Mainline Contract Offering with the Canada Energy Regulator (CER). The priority access offering is in direct response to what our shippers have asked us for and balances their diverse needs. Ultimately, contracting the Mainline will provide all shippers with priority access at competitive tolls, and supports further improvement in netbacks for WCSB producers. Most notably, it secures long-term demand for Canadian crude oil, while ensuring that all interested shippers can participate in a fair and transparent open season process. For example, we've made this offering accessible to smaller producers by reducing the minimum volume required to contract on the system and introducing a Requirements Contract with very attractive terms. We expect the CER will conduct a thorough review of our application which will include input from Enbridge and the industry. Importantly, we included in our application 13 letters from the shippers representing well over 70 percent of the Mainline volumes to demonstrate the support we have for the offering.

"We've also been advancing our liquids strategy to extend our integrated value chain from Western Canada down to the U.S. Gulf Coast. We're moving ahead with developing a terminal at Jones Creek, Texas, which will be fully integrated with our Seaway pipeline system and will provide connectivity and services to local refineries as well as export facilities. We've also secured an option to purchase an ownership interest in an offshore VLCC-capable oil export terminal, further advancing our energy export strategy in the U.S. Gulf Coast.

"Our Gas Transmission and Midstream business is awaiting a decision from the FERC on a settlement agreement on the Texas Eastern rate case and are entering rate proceedings on several other pipelines this year. These are important milestones as they will allow us to rebase our rates and set us up for recovery of future modernization costs.

"Also, in Gas Transmission and Midstream, we've again advanced our LNG supply strategy by leveraging our incumbent position in the U.S. Gulf Coast, with the announcement of the agreements to supply both the Annova LNG facility and the Rio Grande LNG facility, along with acquiring the Rio Bravo pipeline development project.

Finally, in the fourth quarter, we closed the second phase of the divestiture of our Canadian midstream assets, which completes our $8 billion asset sale program. These non-core asset sales have further strengthened our balance sheet and focused our business on our low risk pipeline-utility model.

"In summary, we're pleased with the Company's performance in 2019 and the successful completion of the 3-year plan we announced in early 2017 following the Spectra merger. As we look ahead to our new 3-year plan through 2022, our strategic priorities for the business remain focused on optimizing our base business, executing our secured growth program and growing the business through in-franchise, capital efficient investment. The combination of our strong financial position, disciplined capital allocation, and low-risk business model, positions us well to sustain attractive shareholder returns well into the future," concluded Mr. Monaco.

FINANCIAL RESULTS SUMMARY

Financial results for the three and twelve months ended December 31, 2019, are summarized in the table below:

	Three months ended December 31,			Twelve months ended December 31,
	2019	2018		2019	2018
(unaudited, millions of Canadian dollars, except per share amounts;
number of shares in millions)
GAAP Earnings attributable to common shareholders	746	1,089		5,322	2,515
GAAP Earnings per common share	0.37	0.60		2.64	1.46
Cash provided by operating activities	1,993	2,503		9,398	10,502
Adjusted EBITDA^1	3,186	3,320		13,271	12,849
Adjusted Earnings^1	1,228	1,166		5,341	4,568
Adjusted Earnings per common share^1	0.61	0.65		2.65	2.65
Distributable Cash Flow^1	2,051	1,863		9,224	7,618
Weighted average common shares outstanding	2,018	1,806		2,017	1,724

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 fourth quarter of 2019 decreased by $343 million or $0.23 per share compared with the same period in 2018. 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 earnings in the fourth quarter 2019 increased by $62 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 2019, partially offset by weaker performance in Energy Services due to the narrowing of certain location and quality differentials. On a per share basis, adjusted earnings decreased by $0.04 per share compared with the same period in 2018, reflecting the same operating factors noted above, partially offset by a higher share count which reflected common shares issued by the Company to buy-in the public interests in its sponsored vehicles during the fourth quarter of 2018.

Adjusted earnings for the year ended 2019 increased by $773 million compared with the year ended 2018. The increase is primarily due to strong operating results across many of the Company's business units, as well as new projects placed into service in 2019 and in late 2018. These factors were partially offset by the disposition of certain Gas Transmission and Midstream assets, which included the provincially regulated portion of the Canadian natural gas gathering and processing assets sold on October 1, 2018, as well as the disposition of Midcoast Operating, L.P., sold on August 1, 2018.

DCF for the fourth quarter was $2,051 million, an increase of $188 million over the comparable prior period in 2018, while DCF for the year ended 2019 was $9,224 million, which is an increase of $1,606 million over 2018. The increased DCF in 2019 for both the fourth quarter and full year over the comparable periods in 2018 was driven largely by the operating factors noted above, as well as lower distributions to noncontrolling interests following the completion of the Company's buy-in of the publicly held interest in its sponsored vehicles.

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

PROJECT EXECUTION UPDATE

Over the course of 2019, the Company placed $9 billion of secured growth projects into service, including $7 billion in the fourth quarter. These projects further strengthen Enbridge's footprint in all business lines, including enhancing the safety of the Liquids Mainline, advancing the Company's U.S. Gulf Coast Liquids competitive position, expanding and extending its gas pipelines, completing its largest offshore wind project in Europe, and investing in its Utilities business to reinforce the distribution system and connect new customers. The successful execution of the Company's secured growth program in 2019 contributes reliable earnings and cash flow growth and advances the Company's strategic priorities.

In the fourth quarter, several projects were placed into service, including:

• A US$0.7 billion investment in the Gray Oak Pipeline, which provides incremental crude pipeline capacity out of the Eagle Ford and Permian basins and is underpinned by long-term take-or-pay transportation contracts.
• The $1.1 billion HoHe See Offshore Wind Project and adjacent expansion, which are both fully operational with a combined capacity of 609MW, and are fully back stopped by a government legislated 20-year revenue support mechanism.
• The $5.0 billion Canadian segment of the Line 3 Replacement project (discussed in the Line 3 Replacement section).

Enbridge continues to make progress on its $11 billion secured growth capital program, which includes projects at various stages of execution across all businesses. These projects are supported by long-term take-or-pay contracts, cost-of-service frameworks or similar low-risk commercial arrangements and are diversified across a wide range of regulatory jurisdictions.

U.S. Gulf Coast LNG Strategy
Enbridge announced yesterday that it had executed a Purchase and Sale Agreement with NextDecade to acquire the Rio Bravo Pipeline development project. In addition, Enbridge and NextDecade have negotiated a precedent agreement, to be executed at closing, under which Enbridge will provide firm transportation capacity on the Rio Bravo Pipeline to NextDecade's Rio Grande LNG export facility for a term of at least twenty years. The capital cost of the pipeline is approximately US$1.2 billion with opportunities for further expansion, subject to FID and the final design specifications for the LNG facility.

The Company also announced that it has signed a Precedent Agreement to supply the Annova LNG facilities in the Port of Brownsville, Texas for a term of at least twenty years, by expanding Enbridge's existing Valley Crossing system. The expansion will be subject to the Annova facility reaching FID. The capital cost of the expansion is expected to be approximately US$0.5 billion subject to the final design specifications of the LNG facility.

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 Company placed the Canadian segment of the Line 3 Replacement into service on December 1, 2019, with an interim surcharge of US$0.20 per barrel. This safety-driven maintenance project reflects the importance of protecting the environment and ensuring the continued safe and reliable operations of our Canadian Mainline System well into the future. The capital cost for the Canadian portion of Line 3 Replacement Project came in slightly below budget.

In Minnesota, the Department of Commerce issued a FEIS on December 9 and the MPUC gathered public comment through January 16, 2020. On February 3, 2020, the MPUC approved the adequacy of the FEIS and reinstated the Certificate of Need and Route Permit, clearing the way for construction of the pipeline to commence following the issuance of required permits. The State and Federal environmental permitting agencies have continued to advance their work, including the initiation of public consultation processes, in parallel with the ongoing 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.

OTHER BUSINESS UPDATES

Mainline Contracting
On December 19, 2019, the Company submitted an application to the CER to implement term contracts on the Liquids Canadian Mainline System. The application for contracted and uncommitted service included the associated terms, conditions and tolls of each service, which would be offered in an open season following approval by the CER. The tolls and services will replace the current Competitive Toll Settlement (CTS) that is in place until June 30, 2021. If a replacement agreement is not in place by that time, the CTS tolls will continue on an interim basis.

The application that the Company filed is the result of two years of extensive negotiations with a diverse group of shippers and has been designed to align the interests of its shippers and Enbridge. Shippers representing well over 70% of the current Mainline system throughput have filed letters supporting the application with the CER demonstrating the strong shipper backing for the offering.

The application highlights benefits of the Mainline contract offering for both shippers and the public, including the following:

• Secures long-term demand for WCSB heavy and light barrels in premium markets;
• Supports the best netbacks for WCSB producers;
• Competitive and stable tolls for customers; and
• Flexibility for shippers of all types and sizes to participate by offering both a traditional take-or-pay and producer and refiner requirements contracts.

On January 16, 2020, the CER issued a letter inviting comments from interested persons to identify issues to be considered during the regulatory proceeding and on procedural matters, such as processes the CER may establish to consider the application efficiently. On February 7, 2020, Enbridge replied to the letters solicited by the CER and we expect a thorough regulatory process to continue through substantially all of 2020.

Line 5 Tunnel
On October 31, 2019, the Michigan Court of Claims ruled in favor of Enbridge, recognizing the constitutionality of the legislation underpinning the tunnel agreement with the State of Michigan. 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 an underground tunnel, deep under the Straits, making a safe pipeline even safer. This state-of-the-art tunnel, with enhanced safety features, demonstrates Enbridge's commitment to protecting Michigan's natural resources. Enbridge plans to begin filing permit applications with the State to proceed with constructing the tunnel across the Line 5 Straits in the first quarter of 2020.

Gas Transmission and Midstream Rate Cases
One of the Company's strategic priorities is to ensure timely and fair returns on the Company's U.S. natural gas transmission systems. Following extensive negotiations with shippers on the Texas Eastern rate case, Enbridge filed a settlement agreement on October 28, 2019, with the FERC. On January 13, 2020, the Administrative Law Judge certified this uncontested settlement agreement to the FERC and the Company expects a decision from the FERC in the second quarter of 2020. The Company has also commenced rate discussions with Algonquin and East Tennessee Natural Gas customers.  If a pre-packaged settlement on these pipelines is not reached, Algonquin will file a Section 4 rate case by March 31, 2020, and East Tennessee will file in the second quarter of this year. Additionally, rate proceedings are planned on the Alliance U.S. pipeline and on Maritimes and Northeast U.S. pipeline in the second quarter of 2020.

NON-CORE ASSET SALES & FINANCING UPDATE

In December 2019, Enbridge closed the sale of its federally regulated Canadian midstream assets, completing the second phase of the $4.3 billion transaction. In aggregate, the Company has now received total proceeds of approximately $8 billion from previously announced non-core asset sales. In addition to that, in January 2020, Enbridge entered into an agreement for the sale of the MATL transmission assets for $0.2 billion subject to certain regulatory approvals and customary closing conditions. The transaction is expected to close in the first quarter of 2020. These sales provide the Company with further financial flexibility to self-fund its secured growth program.

On the financing front, the Company continued to execute on its funding plan with term debt issuances in the fourth quarter exceeding $3.5 billion. These included a $1 billion single tranche offering of 10-year notes by Enbridge Inc. in the Canadian debt capital markets and a US$2 billion three-tranche offering of 5-year, 10-year and 30-year fixed rate notes in the U.S. debt capital markets. Proceeds were used to re-finance maturing debt and fund new growth projects within the Company's financial capacity.

As of December 31, 2019, the Company's consolidated Debt-to-EBITDA ratio was 4.5x on a trailing twelve month basis. This is at the low end of the Company's long-term target credit metric range of 4.5x to below 5.0x Debt-to-EBITDA.

2020 GUIDANCE AND LONGER TERM GROWTH OUTLOOK
At its December 2019 investor conference the Company highlighted that its key strategic priorities are focused on optimizing existing operations while preserving financial flexibility and prudently growing its three world-class core franchises: Liquids Pipelines, Gas Transmission and Midstream, and Gas Distribution and Storage. Specific priorities include:

• Ensuring safe and reliable operations and providing effective and cost-efficient transportation solutions for customers;
• Enhancing the business through asset optimization, cost efficiencies and low-risk growth;
• Executing on an $11 billion secured growth capital program, including the U.S. segment of the Line 3 Replacement project; and
• Growing core businesses through capital efficient organic growth and disciplined capital allocation.

Enbridge provided its financial guidance for 2020 including EBITDA of approximately $13.7 billion and a projected range of 2020 DCF of $4.50 to $4.80 per share. The Company also announced a 9.8% dividend increase for 2020 to a quarterly dividend of $0.81 per share, commencing with the dividend payable on March 1, 2020, to shareholders of record on February 14, 2020. Post 2020, the Company re-affirmed expected annual DCF per share growth rate in the range of 5-7%, driven by a operating efficiencies and a significant opportunity to invest in new low risk growth projects within its core franchises.

FOURTH QUARTER AND YEAR-END 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 fourth quarter and full year of 2019.

GAAP SEGMENT EBITDA AND CASH FLOW FROM OPERATIONS

	Three months ended December 31,		Twelve months ended December 31,
	2019	2018	2019	2018
(unaudited, millions of Canadian dollars)
Liquids Pipelines	1,971	978	7,681	5,331
Gas Transmission and Midstream	638	1,254	3,371	2,334
Gas Distribution and Storage	443	449	1,747	1,711
Renewable Power Generation	(189)	83	111	369
Energy Services	(68)	374	250	482
Eliminations and Other	114	(340)	429	(708)
EBITDA	2,909	2,798	13,589	9,519
Earnings attributable to common shareholders	746	1,089	5,322	2,515
Cash provided by operating activities	1,993	2,503	9,398	10,502

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 the 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 December 31,		Twelve months ended December 31,
	2019	2018	2019	2018
(unaudited, millions of Canadian dollars, except per share amounts)
Liquids Pipelines	1,720	1,728	7,041	6,617
Gas Transmission and Midstream	948	952	3,868	4,068
Gas Distribution and Storage	481	452	1,819	1,726
Renewable Power Generation	119	98	424	435
Energy Services	(22)	73	269	167
Eliminations and Other	(60)	17	(150)	(164)
Adjusted EBITDA^1,3	3,186	3,320	13,271	12,849
Maintenance capital	(342)	(361)	(1,083)	(1,144)
Interest expense^1	(704)	(675)	(2,716)	(2,735)
Current income tax^1	(81)	(156)	(386)	(384)
Distributions to noncontrolling interests and redeemable
noncontrolling interests^1	(54)	(281)	(204)	(1,182)
Cash distributions in excess of equity earnings^1	107	51	534	318
Preference share dividends	(96)	(96)	(383)	(364)
Other receipts of cash not recognized in revenue^2	30	51	169	208
Other non-cash adjustments	5	10	22	52
DCF^3	2,051	1,863	9,224	7,618
Weighted average common shares outstanding	2,018	1,806	2,017	1,724

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.

Fourth quarter 2019 DCF increased $188 million compared with the same period of 2018. Key performance drivers of quarter-over-quarter growth included:

• Adjusted EBITDA reflected strong operating performance, increased asset utilization and contributions from assets placed into service in late 2018 and through 2019, offset by the absence of contributions from the sale of assets in the Gas Transmission and Midstream segment during 2018, as well as lower EBITDA from Energy Services crude operations due to narrowing of certain location and quality differentials during the fourth quarter.
• Lower distributions to noncontrolling and redeemable noncontrolling interests following the completion of Enbridge's buy-in of the publicly held interests in its sponsored vehicles, which were completed in the fourth quarter of 2018.
• Higher cash distributions in excess of equity earnings from equity investments primarily due to higher distributions as a result of strong performance, as well as new equity investments placed into service, including the Valley Crossing Pipeline, the NEXUS Gas Transmission Pipeline, and the Big Foot Pipeline.

DCF increased $1,606 million for the year ended December 31, 2019, compared to the year ended December 31, 2018, due to the same factors discussed above as well as:

• Increased adjusted EBITDA contributions from Energy Services for the year 2019 when compared to 2018 due to the widening of certain location and quality differentials benefiting the first half of 2019. 
   

ADJUSTED EARNINGS	Three months ended December 31,		Twelve months ended December 31,
	2019	2018	2019	2018
(unaudited, millions of Canadian dollars, except per share amounts)
Adjusted EBITDA^2	3,186	3,320	13,271	12,849
Depreciation and amortization	(865)	(794)	(3,391)	(3,246)
Interest expense^1	(687)	(656)	(2,649)	(2,637)
Income taxes^1	(237)	(421)	(1,381)	(1,122)
Noncontrolling interests and redeemable
noncontrolling interests^1	(73)	(188)	(126)	(909)
Preference share dividends	(96)	(95)	(383)	(367)
Adjusted earnings^2	1,228	1,166	5,341	4,568
Adjusted earnings per common share	0.61	0.65	2.65	2.65

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 $62 million for the fourth quarter of 2019 compared with 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, partially offset by the following factors:

• Higher depreciation and amortization expense as a result of new assets placed into service, net of depreciation expense no longer recorded for assets which were classified as assets held for sale or sold during second half of 2018.
• Higher interest expense due to the absence of capitalized interest related to assets that were placed into service in late 2018 and 2019.
• Lower income taxes due to lower adjusted earnings before tax for the fourth quarter of 2019 when compared with the fourth quarter of 2018.

Adjusted earnings per share for the fourth quarter of 2019 decreased $0.04 compared with the fourth quarter of 2018. The increase in adjusted earnings noted above was more than offset on a per share basis by the issuance during the fourth quarter of 2018 of approximately 297 million common shares to acquire, in separate transactions, all of the outstanding equity securities of the Company's sponsored vehicles not beneficially owned by Enbridge.

For the year ended December 31, 2019, adjusted earnings increased $773 million over the same period in 2018. The increase is primarily driven by the increased adjusted EBITDA from strong asset performance, as well as lower distributions to noncontrolling and redeemable noncontrolling interests following the completion of Enbridge's buy-in of the publicly held interests in its sponsored vehicles as discussed under Distributable Cash Flow above. The increase to adjusted earnings was offset by increased 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 U.S. Master Limited Partnerships (MLP), Enbridge Energy Partners, L.P. and Spectra Energy Partners, LP, which resulted in the Company being taxed on 100% of the MLP earnings rather than the Company's proportionate share of their earnings.

Adjusted earnings per share for the year of 2019 are the same as in 2018 as a result of the increased adjusted earnings discussed above being offset on a per share basis by the increase in common shares issued to acquire the outstanding equity securities of the Company's sponsored vehicles, also discussed above.

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 the same average Canadian dollar exchange rates in the fourth quarter of 2019 (C$1.32/US$) when compared with the corresponding 2018 period (C$1.32/US$).

On a full year basis, adjusted EBITDA generated from U.S. dollar denominated businesses for the year ended December 31, 2019, was translated at a weaker Canadian exchange rate of C$1.33/US$ compared with C$1.30/US$ for the year ended December 31, 2018.

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 December 31,		Twelve months ended December 31,
	2019	2018	2019	2018
(unaudited, millions of Canadian dollars)
Mainline System^1	960	997	3,900	3,847
Regional Oil Sands System	208	209	856	851
Gulf Coast and Mid-Continent System	214	201	922	709
Other^2	338	321	1,363	1,210
Adjusted EBITDA^3	1,720	1,728	7,041	6,617
Operating Data (average deliveries – thousands of bpd)
Mainline System - ex-Gretna volume^4	2,728	2,685	2,705	2,631
Regional Oil Sands System^5	1,864	1,856	1,817	1,830
International Joint Tariff (IJT)^6	$4.21	$4.15	$4.18	$4.11

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 fourth quarter of 2019 as well as full year, was C$1.19/US$ (Q4 and full year 2018: C$1.26/US$). 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 $8 million for the fourth quarter of 2019 compared with the same period of 2018. Key quarter-over-quarter performance drivers included:

• Mainline System adjusted EBITDA reflected higher throughput, driven by strong supply and continued optimizations of the system, as well as a higher period-over-period International Joint Toll (IJT). In addition, the Canadian portion of the Line 3 Replacement project was placed into service on December 1, 2019, with an interim surcharge on all mainline volumes of US$0.20 per barrel. 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 (2019: C$1.19/US; 2018: C$1.26/US), as well as higher operating costs due to timing of expenditures.
• Gulf Coast and Mid-Continent System growth was driven by strong Gulf Coast demand resulting from favourable price differentials, as well as modest contributions from the Gray Oak Pipeline project that commenced service late in the fourth quarter of 2019, with volume expected to ramp up in the first half of 2020.

Liquids Pipelines adjusted EBITDA increased $424 million for the year ended 2019 compared with 2018. In addition to factors discussed above, key year-over-year performance drivers included:

• Gulf Coast and Mid-Continent System growth was a result of higher volumes on the Flanagan South and Seaway pipelines due to strong Gulf Coast demand resulting from favourable price differentials.
• Other EBITDA increased primarily due to increased volume throughput on the Bakken Pipeline System driven by strong production in the region.

GAS TRANSMISSION AND MIDSTREAM

	Three months ended December 31,		Twelve months ended December 31,
	2019	2018	2019	2018
(unaudited, millions of Canadian dollars)
US Gas Transmission	678	646	2,730	2,625
Canadian Gas Transmission^1	191	208	760	983
US Midstream	48	54	194	319
Other	31	44	184	141
Adjusted EBITDA^2	948	952	3,868	4,068

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 $4 million for the fourth quarter of 2019 compared with the same period of 2018. Key quarter-over-quarter performance drivers included:

• US Gas Transmission adjusted EBITDA reflected a full quarter of contributions from new assets placed into service in late 2018, including Valley Crossing Pipeline and the NEXUS Gas Transmission Pipeline. The increase in EBITDA was partially offset by higher planned integrity expenditures, lower AFUDC on decreased capital spend, as well as both lower revenues and higher operating costs associated with the Texas Eastern pipeline incident in Lincoln County, Kentucky that occurred in the third quarter of 2019.
• Canadian Gas Transmission adjusted EBITDA decreased period-over-period due to a decrease in interruptible service revenue in 2019 as a result of a weaker AECO-Chicago basis.
• US Midstream adjusted EBITDA primarily reflects the impact of lower commodity prices on fractionation margins at Aux Sable partially offset by higher volumes and more favourable margins at DCP Midstream.

Gas Transmission and Midstream adjusted EBITDA decreased $200 million for the year ended 2019 compared with 2018. In addition to factors discussed above, key year-over-year performance included:

• Canadian Gas Transmission adjusted 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 October 1, 2018. The sale of the remaining federally regulated Canadian natural gas gathering and processing assets closed on December 31, 2019.
• US Midstream adjusted EBITDA primarily reflects the absence of EBITDA from Midcoast Operating, L.P. which was sold on August 1, 2018.
• Other EBITDA has increased in 2019 primarily due to contributions from the Big Foot Pipeline which was placed into service in the fourth quarter of 2018.

GAS DISTRIBUTION AND STORAGE

	Three months ended December 31,		Twelve months ended December 31,
	2019	2018	2019	2018
(unaudited, millions of Canadian dollars)
Enbridge Gas Inc. (EGI)	444	407	1,714	1,598
Other	37	45	105	128
Adjusted EBITDA^1	481	452	1,819	1,726
Operating Data
EGI
Volumes (billions of cubic feet)	532	531	1,860	1,821
Number of active customers (thousands)^2			3,755	3,713
Heating degree days^3
Actual	1,383	1,406	4,082	3,932
Forecast based on normal weather^4	1,314	1,310	3,849	3,843

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

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 and lowest in the third quarter as there is generally less volumetric demand 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.

Gas Distribution and Storage adjusted EBITDA increased $29 million for the fourth quarter 2019 compared with the same period of 2018. Key quarter-over-quarter performance drivers included:

• EGI adjusted EBITDA increased due to higher distribution charges primarily resulting from increases in distribution rates and customer base, synergies realized from the amalgamation of EGD and Union Gas, as well as the absence of earnings sharing in 2019 which was recognized in 2018 under EGD's previous incentive rate structure.
• These contributions were partially offset due to warmer weather in EGI's franchise areas in the fourth quarter which led to lower utilization, as well as the effects of the accelerated capital cost allowance deductions reflected as a pass through to customers, consistent with the Ontario Energy Board's prescribed deferral account treatment.
• Other Gas Distribution and Storage adjusted EBITDA decreased due to closing of the sale of Enbridge Gas New Brunswick on October 1, 2019, and St. Lawrence Gas Company, Inc. on November 1, 2019.

Gas Distribution and Storage adjusted EBITDA increased $93 million for the year ended 2019 compared with 2018. The key year-over-year performance drivers reflected the same factors discussed above in the fourth quarter analysis as well as the impact of colder weather in EGI's franchise areas in 2019 when compared to 2018, which drove higher demand.

For the year ended December 31, 2019, Adjusted EBITDA at EGI was positively impacted by $67 million due to colder weather experienced in the franchise area relative to the assumptions for normal weather embedded in customer rates.

RENEWABLE POWER GENERATION

	Three months ended December 31,		Twelve months ended December 31,
	2019	2018	2019	2018
(unaudited, millions of Canadian dollars)
Adjusted EBITDA^1	119	98	424	435

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

Renewable Power Generation adjusted EBITDA increased $21 million for the fourth quarter of 2019 compared with the same period of 2018. Key quarter-over-quarter performance drivers included:

• Higher adjusted EBITDA as a result of contributions from the Hohe See Offshore Wind Project, which reached full operating capacity in October 2019. The adjacent expansion project, Albatros, came into service in January 2020.
• Stronger wind resources across the Company's Canadian wind facilities.

Renewable Power Generation adjusted EBITDA decreased $11 million for the year ended 2019 compared with 2018. In addition to factors discussed above, key year-over-year performance drivers included:

• Absence of a positive arbitration settlement of $11 million from a warranty claim that occurred in the first quarter of 2018.
• Weaker wind resources, availability, and higher mechanical repair costs primarily at US wind facilities in the first half of 2019, net of insurance recoveries.

ENERGY SERVICES

	Three months ended December 31,		Twelve months ended December 31,
	2019	2018	2019	2018
(unaudited, millions of Canadian dollars)
Adjusted earnings/(loss) before interest, income
taxes, and depreciation and amortization^1	(22)	73	269	167

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

Energy Services adjusted EBITDA decreased $95 million for the fourth quarter of 2019 compared with the same period of 2018. Key quarter-over-quarter performance drivers included:

• Lower EBITDA contributions from Energy Services crude operations as a result of narrowing of certain location and quality differentials during the fourth quarter.

Full year 2019 Adjusted EBITDA results for Energy Services increased $102 million compared with full year results of 2018 primarily due to higher EBITDA contributions from Energy Services crude operations as a result of widening of certain location and quality differentials during the second half of 2018 and the first half of 2019, which increased opportunities to generate profitable margins that were realized during 2019.

ELIMINATIONS AND OTHER

	Three months ended December 31,		Twelve months ended December 31,
	2019	2018	2019	2018
(unaudited, millions of Canadian dollars)
Operating and administrative (expenses)/recoveries	(10)	82	66	55
Realized foreign exchange hedge settlements	(50)	(65)	(216)	(219)
Adjusted earnings/(loss) before interest, income
taxes, and depreciation and amortization^1	(60)	17	(150)	(164)

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) 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 decreased $77 million for the fourth quarter of 2019, compared with the same period of 2018. Key quarter-over-quarter performance drivers included:

• The timing of the recovery of certain operating and administrative costs allocated to the business segments, partially offset by lower operating and administrative costs.
• Lower realized foreign exchange settlement losses in the fourth quarter of 2019 primarily due to a narrower spread between the average exchange rate of $1.32 for the fourth quarter of 2019 (Q4 2018:$1.32) and the fourth quarter 2019 hedge rate of $1.24 (Q4 2018:$1.20).

Eliminations and Other adjusted EBITDA increased $14 million for the year ended 2019 compared with the same period of 2018. This increase was a result of:

• Lower operating and administrative expenses.
• Lower realized foreign exchange settlement losses in 2019 primarily due to a narrower spread between the average exchange rate of $1.33 for 2019 (2018:$1.30) and the 2019 hedge rate of $1.24 (2018:$1.16).

CONFERENCE CALL

Enbridge will host a conference call and webcast on February 14, 2020 at 9:00 a.m. Eastern Time (7:00 a.m. Mountain Time) to provide an enterprise wide business update and review 2019 fourth quarter and full-year 2019 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 7174457#. The call will be audio webcast live at https://edge.media-server.com/mmc/p/nkzon3c7. 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 7174457#).

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

On December 9, 2019, the Company's Board of Directors declared the following quarterly dividends. All dividends are payable on March 1, 2020 to shareholders of record on February 14, 2020.

Common Shares^1	$0.81000
Preference Shares, Series A	$0.34375
Preference Shares, Series B	$0.21340
Preference Shares, Series C^2	$0.25305
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^3	$0.27369
Preference Shares, Series R^4	$0.25456
Preference Shares, Series 1	US$0.37182
Preference Shares, Series 3^5	$0.23356
Preference Shares, Series 5^6	US$0.33596
Preference Shares, Series 7^7	$0.27806
Preference Shares, Series 9^8	$0.25606
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 common share was increased 9.8% to $0.81000 from $0.73800, effective March 1, 2020.
2	The quarterly dividend per share paid on Series C was decreased to $0.25395 from $0.25459 on March 1, 2019, increased to $0.25647 from $0.25395 on June 1, 2019, decreased to $0.25243 from $0.25647 on September 1, 2019, and increased to $0.25305 from $0.25243 on December 1, 2019, 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 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.
4	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 year thereafter.
5	The quarterly dividend per share paid on Series 3 was decreased to $0.23356 from $0.25000 on September 1, 2019, due to the reset of the annual dividend on September 1, 2019, and every five year thereafter.
6	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.
7	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.
8	The quarterly dividend per share paid on Series 9 was decreased to $0.25606 from $0.27500 on December 1, 2019, due to the reset of the annual dividend on December 1, 2019, 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 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 the Company's commercially secured growth program; expected future growth and expansion opportunities, including optimization plans; 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 future  actions of regulators and courts; expectations regarding commodity prices; supply forecasts; expectations regarding the impact of transactions; plans to launch binding open seasons, including the terms and timing thereof; toll and rate case discussions and filings, including Mainline Contracting and the anticipated benefits thereof; 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 the Company's dividend policy on its 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, the Company's dividend policy, regulatory parameters, changes in regulations applicable to the Company's 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.; 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, 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, 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 December 31,		Twelve months ended December 31,
	2019	2018	2019	2018
(unaudited, millions of Canadian dollars)
Liquids Pipelines	1,971	978	7,681	5,331
Gas Transmission and Midstream	638	1,254	3,371	2,334
Gas Distribution and Storage	443	449	1,747	1,711
Renewable Power Generation	(189)	83	111	369
Energy Services	(68)	374	250	482
Eliminations and Other	114	(340)	429	(708)
EBITDA	2,909	2,798	13,589	9,519
Depreciation and amortization	(865)	(794)	(3,391)	(3,246)
Interest expense	(697)	(661)	(2,663)	(2,703)
Income tax expense	(433)	(60)	(1,708)	(237)
Earnings attributable to noncontrolling interests and
redeemable noncontrolling interests	(72)	(99)	(122)	(451)
Preference share dividends	(96)	(95)	(383)	(367)
Earnings attributable to common shareholders	746	1,089	5,322	2,515

ADJUSTED EBITDA TO ADJUSTED EARNINGS

	Three months ended December 31,		Twelve months ended December 31,
	2019	2018	2019	2018
(unaudited, millions of Canadian dollars, except per share amounts)
Liquids Pipelines	1,720	1,728	7,041	6,617
Gas Transmission and Midstream	948	952	3,868	4,068
Gas Distribution and Storage	481	452	1,819	1,726
Renewable Power Generation	119	98	424	435
Energy Services	(22)	73	269	167
Eliminations and Other	(60)	17	(150)	(164)
Adjusted EBITDA	3,186	3,320	13,271	12,849
Depreciation and amortization	(865)	(794)	(3,391)	(3,246)
Interest expense	(687)	(656)	(2,649)	(2,637)
Income taxes	(237)	(421)	(1,381)	(1,122)
Earnings attributable to noncontrolling interests and
redeemable noncontrolling interests	(73)	(188)	(126)	(909)
Preference share dividends	(96)	(95)	(383)	(367)
Adjusted earnings	1,228	1,166	5,341	4,568
Adjusted earnings per common share	0.61	0.65	2.65	2.65

EBITDA TO ADJUSTED EARNINGS

	Three months ended December 31,		Twelve months ended December 31,
	2019	2018	2019	2018
(unaudited, millions of Canadian dollars, except per share amounts)
EBITDA	2,909	2,798	13,589	9,519
Adjusting items:
Change in unrealized derivative fair value (gain)/loss	(754)	378	(1,806)	660
Hedging program pre-settlement payment	310	—	310	—
Asset write-down loss	318	32	423	2,118
(Gain)/loss on sale of assets	278	(72)	278	22
Employee severance, transition and transformation
costs	52	60	140	203
Asset monetization transaction costs	—	23	—	88
Equity investment asset impairment	34	14	96	47
Write-down of inventory to the lower of cost or market	17	291	188	327
Regulatory liability adjustment	—	(223)	—	(223)
Other	22	19	53	88
Total adjusting items	277	522	(318)	3,330
Adjusted EBITDA	3,186	3,320	13,271	12,849
Depreciation and amortization	(865)	(794)	(3,391)	(3,246)
Interest expense	(697)	(661)	(2,663)	(2,703)
Income tax expense	(433)	(60)	(1,708)	(237)
Earnings attributable to noncontrolling interests and
redeemable noncontrolling interests	(72)	(99)	(122)	(451)
Preference share dividends	(96)	(95)	(383)	(367)
Adjusting items in respect of:
Interest expense	10	5	14	66
Income taxes	196	(361)	327	(885)
Earnings attributable to noncontrolling interests and
redeemable noncontrolling interests	(1)	(89)	(4)	(458)
Adjusted earnings	1,228	1,166	5,341	4,568
Adjusted earnings per common share	0.61	0.65	2.65	2.65

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

	Three months ended December 31,		Twelve months ended December 31,
	2019	2018	2019	2018
(unaudited, millions of Canadian dollars)
Adjusted EBITDA	1,720	1,728	7,041	6,617
Change in unrealized derivative fair value gain/(loss)	586	(715)	976	(1,077)
Hedging program pre-settlement payment	(310)	—	(310)	—
Asset write-down loss	(21)	(32)	(21)	(186)
Employee severance, transition and transformation
costs	—	(1)	—	(26)
Other	(4)	(2)	(5)	3
Total adjustments	251	(750)	640	(1,286)
EBITDA	1,971	978	7,681	5,331

GAS TRANSMISSION AND MIDSTREAM

	Three months ended December 31,		Twelve months ended December 31,
	2019	2018	2019	2018
(unaudited, millions of Canadian dollars)
Adjusted EBITDA	948	952	3,868	4,068
Change in unrealized derivative fair value gain/(loss)	—	(1)	—	24
Asset write-down loss - US Midstream	—	—	—	(1,932)
Asset write-down loss - US Gas Transmission	—	—	(105)	—
Equity investment asset impairment	(24)	—	(86)	—
Gain/(loss) on sale of assets	(268)	72	(268)	(2)
Asset monetization transaction costs	—	—	—	(20)
Employee severance, transition and transformation
costs	(5)	(3)	(5)	(13)
Regulatory liability adjustment	—	223	—	223
Other	(13)	11	(33)	(14)
Total adjustments	(310)	302	(497)	(1,734)
EBITDA	638	1,254	3,371	2,334

GAS DISTRIBUTION AND STORAGE

	Three months ended December 31,		Twelve months ended December 31,
	2019	2018	2019	2018
(unaudited; millions of Canadian dollars)
Adjusted EBITDA	481	452	1,819	1,726
Change in unrealized derivative fair value gain/(loss)	(21)	3	(12)	6
Loss on sale of assets	(10)	—	(10)	—
Noverco Inc. equity earnings adjustment	—	—	—	(9)
Employee severance, transition and transformation
costs	(8)	(6)	(51)	(12)
Other	1	—	1	—
Total adjustments	(38)	(3)	(72)	(15)
EBITDA	443	449	1,747	1,711

RENEWABLE POWER GENERATION

	Three months ended December 31,		Twelve months ended December 31,
	2019	2018	2019	2018
(unaudited, millions of Canadian dollars)
Adjusted EBITDA	119	98	424	435
Change in unrealized derivative fair value gain/(loss)	—	(1)	2	1
Asset write-down loss	(297)	—	(297)	—
Equity investment asset impairment	(10)	(14)	(10)	(47)
Loss on sale of assets	—	—	—	(20)
Other	(1)	—	(8)	—
Total adjustments	(308)	(15)	(313)	(66)
EBITDA	(189)	83	111	369

ENERGY SERVICES

	Three months ended December 31,		Twelve months ended December 31,
	2019	2018	2019	2018
(unaudited, millions of Canadian dollars)
Adjusted EBITDA	(22)	73	269	167
Change in unrealized derivative fair value gain/(loss)	(29)	592	169	642
Write-down of inventory to the lower of cost or market	(17)	(291)	(188)	(327)
Total adjustments	(46)	301	(19)	315
EBITDA	(68)	374	250	482

ELIMINATIONS AND OTHER

	Three months ended December 31,		Twelve months ended December 31,
	2019	2018	2019	2018
(unaudited, millions of Canadian dollars)
Adjusted EBITDA	(60)	17	(150)	(164)
Change in unrealized derivative fair value gain/(loss)	218	(256)	671	(256)
Asset monetization transaction costs	—	(23)	—	(68)
Employee severance, transition and transformation
costs	(39)	(50)	(84)	(152)
Other	(5)	(28)	(8)	(68)
Total adjustments	174	(357)	579	(544)
EBITDA	114	(340)	429	(708)

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

	Three months ended December 31,		Twelve months ended December 31,
	2019	2018	2019	2018
(unaudited, millions of Canadian dollars)
Cash provided by operating activities	1,993	2,503	9,398	10,502
Adjusted for changes in operating assets and liabilities^1	(192)	28	259	(915)
	1,801	2,531	9,657	9,587
Distributions to noncontrolling interests and redeemable
noncontrolling interests^4	(54)	(281)	(204)	(1,182)
Preference share dividends	(96)	(96)	(383)	(364)
Maintenance capital expenditures^2	(342)	(361)	(1,083)	(1,144)
Significant adjusting items:
Other receipts of cash not recognized in revenue^3	30	51	169	208
Employee severance, transition and transformation
costs	52	59	143	248
Asset monetization costs	—	23	—	107
Distributions from equity investments in excess of
cumulative earnings^4	154	35	361	326
Regulatory liability adjustment	—	(223)	—	(223)
Hedging program pre-settlement payment	310	—	310	—
Other items	196	125	254	55
DCF	2,051	1,863	9,224	7,618

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