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Enbridge Reports Strong Third Quarter 2022 Financial Results and Secures B.C. Pipeline Expansion

Press Release

CALGARY, AB – Enbridge Inc. (Enbridge or the Company) (TSX: ENB) (NYSE: ENB) today reported third quarter 2022 financial results, announced $3.8 billion of newly secured growth projects, including an expansion of the T-South segment of the B.C. Pipeline, and reaffirmed its 2022 financial outlook.

Highlights
(All financial figures are unaudited and in Canadian dollars unless otherwise noted. * identifies non-GAAP financial measures. Please refer to Non-GAAP Reconciliations Appendices.)

  • Third quarter GAAP earnings of $1.3 billion or $0.63 per common share, compared with GAAP earnings of $0.7 billion or $0.34 per common share in 2021
  • Adjusted earnings* of $1.4 billion or $0.67 per common share*, compared with $1.2 billion or $0.59 per common share in 2021
  • Adjusted earnings before interest, income taxes and depreciation and amortization (EBITDA)* of $3.8 billion, compared with $3.3 billion in 2021
  • Cash provided by operating activities of $2.1 billion, compared with $2.3 billion in 2021
  • Distributable cash flow (DCF)* of $2.5 billion or $1.24 per common share*, compared with $2.3 billion or $1.13 per common share in 2021
  • Reaffirmed 2022 full year guidance range for EBITDA of $15.0 billion to $15.6 billion and DCF per share of $5.20 to $5.50
  • Secured an expansion of B.C. Pipeline’s T-South section adding 300 million cubic feet per day (MMcf/d) of capacity with an estimated capital cost of up to $3.6 billion
  • Launched a binding open season for a second expansion of B.C. Pipeline’s T-North section adding approximately 500MMcf/d of capacity
  • Formed strategic partnership with 23 First Nation and Métis communities selling a 11.57% non-operating interest in seven Regional Oil Sands pipelines for $1.12 billion
  • Advanced U.S. Gulf Coast oil strategy through increased interest in Gray Oak Pipeline while lowering commodity exposure with reduced interest in DCP Midstream LP; received US$400 million cash
  • Enhanced North American renewable development portfolio with US$270 million acquisition of Tri Global Energy (TGE)
  • Acquired additional 10% ownership interest in Cactus II Pipeline in the Permian bringing Enbridge’s ownership to 30%
  • Sanctioned investment for four additional oil storage tanks at the Enbridge Ingleside Energy Center (EIEC)
  • Secured two new RNG projects in Ontario where Enbridge will invest in gas upgrading and pipeline connections
  • Released Enbridge’s Indigenous Reconciliation Action Plan building on the Company’s growing track record of engagement with Indigenous communities and employees

CEO COMMENT

Al Monaco, President and CEO commented on the following:

“While global economies and energy markets are experiencing significant volatility, Enbridge’s premium North America franchises, resilient commercial underpinnings, and our increasing inventory of organic opportunities put us in a great position to continue to grow into the future. The fundamentals of our business continue to be positive; it’s clear that the world needs all forms of energy to meet future demand, especially in the context of the energy security, reliability, and affordability challenges that everyone is faced with in today’s environment.

“We are pleased with our strong third quarter results and year-to-date performance, a testament to the Enbridge team across our four core businesses. We’re tracking to plan and expect to achieve our 2022 EBITDA and DCF per share guidance. Looking forward, our low-risk business model provides us with excellent visibility to growing cash flows and our assets are underpinned by long-term contracts or cost-of-service frameworks that provide built-in inflation protections.

“The current environment and strong global energy fundamentals validate our dual-pronged strategy of expanding and modernizing our conventional business and increasing investment in low-carbon growth. We’ve made excellent progress on the priorities that we laid out at Enbridge Day last December, particularly related to our natural gas strategy on both sides of the border.

“On the conventional infrastructure side, last quarter we sanctioned a major expansion of our T-North gas transmission system in British Columbia and agreed to acquire a 30% interest in Woodfibre LNG near Squamish. The 535 MMcf/d T-North expansion is progressing and we expect to close the Woodfibre transaction shortly.

“Today we’re announcing an expansion of our T-South system that will provide much needed capacity for customers, supported by binding long-term take-or-pay commitments. The expansion is critical to meet natural gas demand and ensuring energy reliability in the region. The project illustrates well the criticality of existing pipe in the ground in minimizing the environmental footprint of much needed energy infrastructure. The project will be developed in consultation and close collaboration with communities.

“We also announced today an open season for a further expansion of our T-North system of approximately 500 MMcf/d. This expansion is needed to support regional production growth, LNG exports, and increased demand.

“South of the border, we’re also excited about our growing opportunity set in the U.S. Gulf Coast where we already feed five LNG export facilities and we have line of sight to additional LNG related and regional gas pipeline expansion projects.

“Continuing with natural gas, we’re executing our $3.5 billion secured growth program at our Ontario gas distribution utility with $1.1 billion of projects on track to enter service this year. Last week, we filed a regulatory application that will establish the next incentive framework, through 2028. This rate-making model has worked well for customers and Enbridge, and we expect continued rate base and earnings growth from this franchise.

“In our Liquids business, we’ve seen strong recovery of Western Canadian supply and throughput across our systems, including the Mainline. We’ve sanctioned construction of four new oil storage tanks at our Ingleside export facility and acquired an additional 10% interest in the Cactus II Pipeline, both of which bolster our U.S. Gulf Coast oil export strategies.

“We announced a landmark partnership with Athabasca Indigenous Investments on seven pipelines in the Athabasca region. We’re excited to work together with our Indigenous partners on operating these assets, as well as stewarding the surrounding environment. This transaction demonstrates our commitment to recycling capital at attractive valuations and provides a framework for potential future Indigenous partnerships which we believe will be a critical component of future energy infrastructure development and ownership.

“Discussions with shippers on a new Mainline commercial agreement continue. We are pursuing two commercial paths – the potential for another incentive-type tolling arrangement, or a cost-of-service model. While we anticipated a decision to determine the optimal path for Enbridge and our customers in the third quarter, discussions are ongoing, and we expect to continue negotiations through the end of the year.

“This quarter, we made great progress on our low-carbon priorities. In renewables, our acquisition of Tri Global Energy meaningfully accelerates our North American strategy and opportunity set. The Tri Global team strongly complements our existing capabilities and the deal immediately adds an attractive backlog of 3 GW of development projects that could be in service between 2024 and 2028, with more opportunities in the works. In Europe, execution of our four offshore wind projects off the coast of France is progressing, with Saint Nazaire wrapping up and expected to generate first power later this month.

“We’ve also made good strides in our RNG business with two newly secured projects in Ontario totaling approximately $100 million, which will supply zero emissions natural gas, delivered under long term take-or-pay contracts.

“With today’s announcements, we’ve secured $8 billion of new capital projects this year and our secured capital backlog is now $17 billion, which will be fully funded within our equity self-funding model. Our secured program is diversified and underpinned by commercial models that align with our low-risk value proposition. We will continue to be disciplined allocators of capital by focusing on a strong balance sheet, investing wisely in the business, and returning capital to shareholders.

“Finally, as I reflect on my 27 years at Enbridge, the last 11 as CEO, I’m proud of what the Enbridge team has accomplished. We’ve consistently grown cash flows and the dividend, delivered on our strategic priorities, and materially enhanced and diversified our asset mix by substantially increasing our natural gas footprint and low-carbon platform and capabilities. I’m particularly pleased with how we have positioned our business and implemented strategies to lead the energy transition. Looking forward, we’ll continue to deliver on our purpose to fuel people’s quality of life, safely, reliably, and sustainably.

“I’ve been honored to lead Enbridge and I’m confident that under Greg Ebel’s leadership, the management team will continue to grow Enbridge – North America’s leading energy infrastructure company. I wish to sincerely thank our immensely skilled and dedicated staff, shareholders and other stakeholders, and our Board of Directors for their support of Enbridge. Since the announcement, Greg and I have implemented a transition plan to ensure a smooth changeover and maintain momentum and consistency – and that’s well underway.”

FINANCIAL RESULTS SUMMARY

Financial results for the three months ended September 30, 2022 and 2021 are summarized in the table below:

Three months ended
September 30,

Nine months ended
September 30,

2022

2021

2022

2021

(unaudited; millions of Canadian dollars, except per share amounts; number of shares in millions)

GAAP Earnings attributable to common shareholders

1,279

682

3,656

3,976

GAAP Earnings per common share

0.63

0.34

1.80

1.97

Cash provided by operating activities

2,144

2,313

7,617

7,366

Adjusted EBITDA1

3,758

3,269

11,620

10,314

Adjusted Earnings1

1,366

1,184

4,421

4,175

Adjusted Earnings per common share1

0.67

0.59

2.18

2.06

Distributable Cash Flow1

2,501

2,290

8,320

7,554

Weighted average common shares outstanding

2,025

2,024

2,026

2,023

1  Non-GAAP financial measures. Please refer to Non-GAAP Reconciliations Appendices.

GAAP earnings attributable to common shareholders for the third quarter of 2022 increased by $597 million or $0.29 per share compared with the same period in 2021, primarily due to operating performance factors discussed in detail below and a $1,076 million gain ($732 million after-tax) recorded on the closing of the joint venture merger transaction with Phillips 66 (P66). This has been partially offset by the impact of the mark-to-market value of derivative financial instruments used to manage foreign exchange risk. In the third quarter of 2022, GAAP earnings attributable to common shareholders were negatively impacted by non-cash, net unrealized derivative fair value losses of $1,334 million ($1,021 million after-tax) compared with unrealized losses of $436 million ($332 million after-tax) in the third quarter of 2021.

The period-over-period comparability of GAAP earnings attributable to common shareholders is 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. Refer to the Management’s Discussion & Analysis for the third quarter of 2022 filed in conjunction with the third quarter financial statements for a detailed discussion of GAAP financial results.

Adjusted EBITDA in the third quarter of 2022 increased by $489 million compared with the same period in 2021. This was primarily driven by contributions from new assets placed into service including the U.S. portion of the Line 3 Replacement Project and the acquisition of EIEC, as well as the recognition of higher revenues from updated rates on Texas Eastern as a result of its recent rate case.

Adjusted earnings in the third quarter of 2022 increased by $182 million, or $0.08 per share, primarily due to higher Adjusted EBITDA contributions, offset by higher financing costs due to lower capitalized interest with the completion of the U.S. portion of the Line 3 Replacement Project along with the impacts of rising interest rates on floating-rate debt, and increased depreciation expense on new assets placed into service in the fourth quarter of 2021.

DCF for the third quarter of 2022 increased by $211 million, or $0.11 per share, primarily due to higher Adjusted EBITDA contributions partially offset by the timing of maintenance capital spend, higher cash taxes on higher taxable earnings, and higher financing costs noted above.

Detailed financial information and analysis can be found below under Third Quarter 2022 Financial Results.

FINANCIAL OUTLOOK

The Company reaffirms its 2022 financial guidance, which includes adjusted EBITDA between $15.0 and $15.6 billion and DCF per share between $5.20 to $5.50. Results for the nine months of 2022 are in line with expectations and the Company anticipates that its businesses will continue to experience strong capacity utilization and throughput, and good operating performance through the balance of the year with normal course seasonality. Forward financial guidance reflects a provision in recognition of the uncertainty of future Mainline tolls associated with the ongoing commercial framework discussions with shippers.

Strong operational performance is expected to be offset by challenging market conditions which continue to impact Energy Services, along with higher financing costs, due to increased interest rates on unhedged floating rate debt, relative to 2022 financial guidance.

FINANCING UPDATE

During the third quarter of 2022, Enbridge Gas Inc. a wholly-owned subsidiary of Enbridge, issued $325 million of 10-year senior notes and $325 million of 30-year senior notes. Additionally, Enbridge issued US$1.1 billion of 60-year hybrid subordinated notes which will receive partial equity treatment from rating agencies. These debt offerings were completed at attractive rates with proceeds used to pay down existing indebtedness, fund capital projects, and for other general corporate purposes.

In August of 2022, the Company closed a transaction with P66 which provided Enbridge with approximately US$400 million of net proceeds. In October of 2022, Enbridge completed the sale of a minority non-operating interest in certain Enbridge-operated pipelines in the Athabasca region of northern Alberta to Athabasca Indigenous Investments (Aii) for $1.12 billion of cash proceeds. Both transactions are discussed below. Proceeds from these transactions create financial flexibility and provide Enbridge with additional investable capacity to be deployed within the Company’s disciplined capital allocation framework.

The Company expects to continue to fund its secured capital growth program within its equity self-funding model utilizing internally generated cash flows, proceeds from recently completed transactions and future debt financings.

SECURED GROWTH PROJECT EXECUTION UPDATE

During the third quarter, the Company added approximately $3.8 billion of growth capital to its secured capital program, including an expansion of the T-South section of the B.C. Pipeline System (T-South Expansion) with an estimated capital cost of up to $3.6 billion, a US$60 million expansion of storage facilities at EIEC, and an approximately $100 million investment in two RNG projects in Ontario.

The Company’s current secured growth program is now approximately $17 billion with the Company expecting to place $4.0 billion into service in 2022 with the East-West Tie-Line and Gulfstream Phase VI projects already in service.

B.C. Pipeline Expansions

Enbridge continues to advance engineering and design work on the previously announced 535 MMcf/d expansion of the T-North segment (Aspen Point) of the B.C. Pipeline System with an estimated capital cost of $1.2 billion. The Company expects to file its application with the CER in 2024 with an anticipated in-service date in 2026.

During the third quarter, Enbridge successfully completed an oversubscribed binding open season and is proceeding with the 300 MMcf/d T-South Expansion project with a capital cost of up to $3.6 billion.

The T-South Expansion will consist of compressor unit additions, pipeline looping and other ancillary station modifications. Enbridge has now begun the regulatory and permitting process and plans to file its application with the Canada Energy Regulator (CER) in 2024. The project is expected to be placed in service in 2028 and will be underpinned by a cost-of-service commercial model.

Today, Enbridge announced that it is proceeding with a binding open season for a further expansion of approximately 500 MMcf/d on the T-North segment of the B.C. Pipeline with an estimated capital cost of up $1.9 billion to meet demand for further egress from growing Montney production, LNG exports, and to accommodate downstream demand. The open season is expected to close in early 2023.

BUSINESS UPDATES

Advancing U.S. Gulf Coast Oil Strategy

On August 17, 2022, Enbridge completed a joint venture merger transaction with P66 resulting in a single joint venture holding both Enbridge’s and P66’s indirect ownership interests in Gray Oak Pipeline, LLC (Gray Oak) and DCP Midstream LP (DCP) and an agreement to realign their respective economic and governance interests in the underlying business operations.

Enbridge’s indirect economic interest in Gray Oak has increased to 58.5% from 22.8% and Enbridge will assume operatorship of Gray Oak in the second quarter of 2023. The Company’s indirect economic interest in DCP has been reduced to 13.2% from 28.3%. Additionally, Enbridge received approximately US$400 million of cash proceeds from the merged entity.

Gray Oak is a long-haul, contracted pipeline providing critical, low-cost connectivity from the Permian basin to Corpus Christi and Houston regions.

On November 2, 2022, the Company announced that it acquired an additional 10% ownership interest in the 670 thousand barrel per day (kbpd) Cactus II Pipeline (Cactus II) for US$177 million in cash from Western Midstream. Enbridge’s non-operating ownership in Cactus II is now 30%.

Cactus II is a highly contracted take-or-pay system that benefits from flexible delivery options across key locations in Corpus Christi and is integrated with EIEC. The pipeline has the lowest operating cost of all major Permian oil pipelines and can offer competitive tariffs to utilize available capacity to transport intermittent volumes.

Also today, Enbridge has sanctioned a US$60 million oil storage expansion at EIEC which will add four additional oil storage tanks for approximately two million barrels of additional storage capacity in 2024.

In combination with EIEC and Enbridge’s increased economic interest in Gray Oak and Cactus II, the Company is well-positioned to provide transportation solutions for growing Permian Basin supply to local U.S. Gulf Coast and global export markets.

Acquisition of Tri Global Energy

On September 29, 2022, Enbridge announced the acquisition of TGE, a leading US renewable power project developer, for US$270 million in cash and assumed debt. TGE has a large development portfolio, including 3.9 GW of renewable generation projects that TGE has already sold to operators, which will generate development fees and DCF per share accretion for Enbridge beginning in 2023. In addition, 3 GW of wholly-owned, late-stage development projects are expected to be placed into service between 2024 and 2028, providing visible cash flow growth, along with a large slate of early-stage development projects.

Rising targets for State renewable portfolio standards and growing private sector demand for zero-carbon electricity are set to drive investment in wind and solar power generation significantly higher over the next decade. The acquisition of TGE enhances Enbridge’s renewable power platform and further builds on the Company’s inventory of North American growth opportunities.

Athabasca Indigenous Investments Partnership

On October 5th, 2022, Enbridge closed the previously announced partnership with Aii, a newly created entity representing 23 First Nation and Métis communities, whereby Aii acquired an 11.57% non-operating interest in seven Enbridge-operated Regional Oil Sands pipelines in northern Alberta for $1.12 billion. The transaction included the following pipelines: Athabasca; Wood Buffalo/Athabasca Twin and associated tanks; Norlite Diluent; Waupisoo; Wood Buffalo; Woodland; and the Woodland extension.

The partnership with Aii strengthens the Company’s record of engagement with Indigenous communities and developing financial partnerships. It also provides Enbridge an opportunity to realize value from its existing asset base and supplements the Company’s investable capacity into new value enhancing growth opportunities.

Texas Eastern Transmission, LP (Texas Eastern) Rate Case

On September 8, 2022, Texas Eastern filed an uncontested Stipulation and Agreement with the Federal Energy Regulatory Commission (FERC) to resolve all issues from the rate proceeding. The comment and reply period ended October 11, 2022 and it is now with the FERC awaiting approval.

Mainline Commercial Framework

The Company is currently advancing two potential commercial frameworks for the Canadian Mainline in parallel: i) a new incentive rate-making agreement that may be similar to the Competitive Toll Settlement (CTS) agreement that expired on June 30, 2021, and ii) a Canadian Mainline cost-of-service application.  Either framework is anticipated to provide attractive risk-adjusted returns and the range of financial outcomes is not expected to materially impact Enbridge’s financial outlook.

Enbridge has consulted with industry participants regarding the Canadian Mainline and shared incentive rate making proposals, supported by detailed cost information, with an industry representative group comprised of a cross-section of participants, including producers, integrated producers and refiners.

The Company had previously anticipated deciding whether to file either a negotiated incentive tolling settlement or a Canadian Mainline cost-of-service application with the CER in the third quarter of 2022. However, we expect negotiations with stakeholders to continue through the end of the year.

Enbridge has already filed and is currently negotiating with shippers a cost-of-service application with the FERC in the U.S for the Lakehead System (U.S. portion of the Mainline).

Enbridge is collecting interim tolls, which are subject to refund, related to its July 1, 2021 Lakehead cost of service filing. On the Canadian Mainline, Enbridge is also collecting, per the terms of the CTS, interim tolls consistent with the tolls in effect on June 30, 2021 when the CTS agreement expired and which are also subject to refund. The Company’s financial results and forward 2022 financial guidance reflects a provision in recognition of the uncertainty of future mainline tolls.

THIRD QUARTER 2022 FINANCIAL RESULTS

GAAP Segment EBITDA and Cash Flow from Operations

Three months ended
September 30,

Nine months ended
September 30,

2022

2021

2022

2021

(unaudited; millions of Canadian dollars)

Liquids Pipelines

1,946

1,673

6,093

5,756

Gas Transmission and Midstream

2,251

884

4,384

2,725

Gas Distribution and Storage

286

282

1,368

1,374

Renewable Power Generation

105

91

389

362

Energy Services

(70)

(204)

(348)

(379)

Eliminations and Other

(935)

(121)

(1,284)

191

EBITDA1 

3,583

2,605

10,602

10,029

Earnings attributable to common shareholders

1,279

682

3,656

3,976

Cash provided by operating activities

2,144

2,313

7,617

7,366

1   Non-GAAP financial measure. Please refer to Non-GAAP Reconciliations Appendices.

For purposes of evaluating performance, the Company makes adjustments to GAAP reported earnings, segment EBITDA and cash flow provided by operating activities for unusual, infrequent or other non-operating factors, 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.

Adjusted EBITDA By Segment

Adjusted EBITDA generated from U.S. dollar denominated businesses was translated to Canadian dollars at a higher average exchange rate (C$1.31/US$) in the third quarter of 2022 when compared with the third quarter in 2021 (C$1.26/US$). A portion of 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
September 30,

Nine months ended
September 30,

2022

2021

2022

2021

(unaudited; millions of Canadian dollars)

Mainline System

1,271

1,083

3,778

3,264

Regional Oil Sands System

236

225

694

693

Gulf Coast and Mid-Continent System

375

252

1,006

702

Other Systems1

387

338

1,103

964

Adjusted EBITDA2

2,269

1,898

6,581

5,623

Operating Data (average deliveries – thousands of bpd)

Mainline System – ex-Gretna volume3

2,966

2,673

2,917

2,680

International Joint Tariff (IJT)4

$4.27

$4.27

$4.27

$4.27

Competitive Tolling Settlement (CTS) Surcharges4

$0.26

$0.26

$0.26

$0.26

Line 3 Replacement Surcharge4,5,6

$0.85

$0.20

$0.91

$0.20

1

Other consists of Southern Lights Pipeline, Express-Platte System, Bakken System, and Feeder Pipelines and Other.

2

Non-GAAP financial measure. Please refer to Non-GAAP Reconciliations Appendices.

3

Mainline System throughput volume represents Mainline System deliveries ex-Gretna, Manitoba which is made up of U.S. and Eastern Canada deliveries originating from Western Canada.

4

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 55% of total Mainline System revenue and the average effective FX rate realized for the Canadian portion of the Mainline during the third quarter of 2022 was C$1.23/US$ (Q3 2021: 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 with offsetting hedge settlements reported within Eliminations and Other. The Company is currently recording a provision against the IJT in recognition of the uncertainty of the final Mainline tolls upon the completion of the Mainline commercial framework negotiations.

5

The interim surcharge of US$0.20 for the Canadian portion of the Line 3 Replacement Project, which was placed into service on December 1, 2019, was collected until October 1, 2021. With the completion of the U.S. portion of the Line 3 Replacement Project on October 1, 2021, the interim surcharge was replaced by the full Line 3 Replacement surcharge.

6

Effective July 1, 2022, the Line 3 Replacement Surcharge, exclusive of the receipt terminalling surcharge, will be determined on a monthly basis by a volume ratchet based on the 9-month rolling average of ex-Gretna volumes. Each 50kbpd volume ratchet above 2,835 kbpd (up to 3,085 kbpd) applies a US$0.035/bbl discount whereas each 50kbpd volume ratchet below 2,350 kbpd (down to 2,050 kbpd) adds a US$0.04/bbl charge. Refer to Enbridge’s Application for a Toll Order respecting the implementation of the Line 3 Replacement Surcharges and CER Order TO-003-2021 for further details.

Liquids Pipelines adjusted EBITDA increased $371 million compared with the third quarter of 2021, primarily related to:

  • higher Mainline System throughput enabled by incremental Line 3 capacity placed into service October 1, 2021, higher tolls due to the implementation of the full Line 3 Replacement surcharge compared with the smaller surcharge on the Canadian portion of the project in effect prior to October 2021, partially offset by the recognition of a provision against the interim Mainline IJT for barrels shipped in 2022 and higher power costs as a result of increased volumes and increased power prices;
  • higher contributions from the Gulf Coast and Mid-Continent System due primarily to the acquisition of EIEC and related assets in the fourth quarter of 2021, higher volumes on the Flanagan South Pipeline, and an increased economic interest in the Gray Oak Pipeline as a result of the joint venture merger transaction with P66; partially offset by lower contributions from the Seaway Crude Pipeline System and Cushing storage assets as a result of lower demand; receipts of cash not recognized in revenue related to unshipped contracted volumes at EIEC that have a contractual right to ship at a later date are recognized in DCF;
  • higher contributions from the Bakken System due to higher volumes; and
  • the positive effect of translating U.S. dollar denominated EBITDA at a higher Canadian to U.S. dollar average exchange rate, which is partially offset in the Eliminations and Other segment as part of the Company’s enterprise-wide financial risk management program.

Gas Transmission And Midstream

Three months ended

September 30,

Nine months ended
September 30,

2022

2021

2022

2021

(unaudited; millions of Canadian dollars)

U.S. Gas Transmission

853

732

2,372

2,235

Canadian Gas Transmission

157

130

485

412

U.S. Midstream

114

85

334

169

Other

34

39

109

112

Adjusted EBITDA1

1,158

986

3,300

2,928

1  Non-GAAP financial measure. Please refer to Non-GAAP Reconciliations Appendices.

  • Gas Transmission and Midstream adjusted EBITDA increased $172 million compared with the third quarter of 2021, primarily related to:
  • higher U.S. Gas Transmission contributions from the Cameron Extension, Middlesex Extension and the Appalachia to Market projects placed into service in the fourth quarter of 2021 and the recognition of revenues attributable to the Texas Eastern rate case resulting from an uncontested Stipulation & Agreement;
  • higher Canadian Gas Transmission contributions from the T-South Expansion and Spruce Ridge projects placed fully into service in the fourth quarter of 2021 and higher contributions from Enbridge’s investment in the Alliance Pipeline due to higher AECO-Chicago basis differential;
  • higher U.S. midstream contributions resulting from higher commodity prices at Enbridge’s DCP and Aux Sable joint ventures, partially offset by reduced economic interest in DCP as a result of the joint venture merger transaction with P66; and
  • the positive effect of translating U.S. dollar denominated EBITDA at a higher Canadian to U.S. dollar average exchange rate within U.S. Gas Transmission and U.S. Midstream, which is partially offset in the Eliminations and Other segment as part of the Company’s enterprise-wide financial risk management program.

Gas Distribution And Storage

Three months ended

September 30,

Nine months ended
September 30,

2022

2021

2022

2021

(unaudited; millions of Canadian dollars)

Enbridge Gas Inc. (EGI)

285

294

1,358

1,317

Other

8

2

31

86

Adjusted EBITDA1

293

296

1,389

1,403

Operating Data

EGI

Volumes (billions of cubic feet)

349

302

1,556

1,383

Number of active customers2 (millions)

3.8

3.8

Heating degree days3

Actual

79

61

2,602

2,350

Forecast based on normal weather4

91

94

2,535

2,538

1

Non-GAAP financial measure. Please refer to Non-GAAP Reconciliations Appendices.

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 & Storage adjusted EBITDA remained consistent compared with the third quarter of 2021, resulting from higher distribution charges at EGI from increases in rates and customer base that were offset by higher maintenance and integrity costs.

When compared with the normal weather forecast embedded in rates, the weather in the third quarter of 2022 and 2021 had no impact on EBITDA.

Renewable Power Generation

Three months ended

September 30,

Nine months ended
September 30,

2022

2021

2022

2021

(unaudited; millions of Canadian dollars)

Adjusted EBITDA1

113

89

400

356

1  Non-GAAP financial measure. Please refer to Non-GAAP Reconciliations Appendices.

Renewable Power Generation adjusted EBITDA increased $24 million compared with the third quarter of 2021 primarily related to higher energy pricing at European offshore wind facilities.

Energy Services

Three months ended

September 30,

Nine months ended
September 30,

2022

2021

2022

2021

(unaudited; millions of Canadian dollars)

Adjusted EBITDA1

(132)

(116)

(302)

(277)

1  Non-GAAP financial measure. Please refer to Non-GAAP Reconciliations Appendices.

Energy Services adjusted EBITDA decreased $16 million compared with the third quarter of 2021. The decrease is the result of a more pronounced market structure backwardation than in the same period of 2021 limiting storage opportunities and significant compression of location and quality differentials in certain markets.

Eliminations and Other

Three months ended

September 30,

Nine months ended
September 30,

2022

2021

2022

2021

(unaudited; millions of Canadian dollars)

Operating and administrative recoveries

22

66

107

153

Realized foreign exchange hedge settlement gains

35

50

145

128

Adjusted EBITDA1

57

116

252

281

1  Non-GAAP financial measure. Please refer to Non-GAAP Reconciliations Appendices.

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. U.S. dollar denominated earnings within operating segment results are translated at average foreign exchange rates during the quarter, and the offsetting impact of settlements made under the Company’s enterprise foreign exchange hedging program are captured in this corporate segment.

Eliminations and Other adjusted EBITDA decreased $59 million compared with the third quarter of 2021 due to:

  • the timing of recovery of operating and administrative costs from the business segments; and
  • lower realized foreign exchange gains on hedge settlements.

Distributable Cash Flow

Three months ended

September 30,

Nine months ended
September 30,

2022

2021

2022

2021

(unaudited; millions of Canadian dollars; number of shares in millions)

Liquids Pipelines

2,269

1,898

6,581

5,623

Gas Transmission and Midstream

1,158

986

3,300

2,928

Gas Distribution and Storage

293

296

1,389

1,403

Renewable Power Generation

113

89

400

356

Energy Services

(132)

(116)

(302)

(277)

Eliminations and Other

57

116

252

281

Adjusted EBITDA1,3

3,758

3,269

11,620

10,314

Maintenance capital

(215)

(142)

(466)

(412)

Interest expense1

(837)

(665)

(2,357)

(1,977)

Current income tax1

(129)

(89)

(391)

(210)

Distributions to noncontrolling interests1

(60)

(66)

(184)

(207)

Cash distributions in excess of equity earnings1

9

52

153

248

Preference share dividends

(81)

(92)

(254)

(274)

Other receipts of cash not recognized in revenue2

48

23

173

74

Other non-cash adjustments

8

26

(2)

DCF3

2,501

2,290

8,320

7,554

Weighted average common shares outstanding

2,025

2,024

2,026

2,023

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  Non-GAAP financial measures. Please refer to Non-GAAP Reconciliations Appendices.

Third quarter 2022 DCF increased $211 million compared with the same period of 2021 primarily due to operational factors discussed above contributing to higher Adjusted EBITDA, as well as:

  • higher receipts of cash not recognized in revenue related to unshipped contracted volumes at EIEC that have a contractual right to ship at a later date; offset by
  • the timing of maintenance capital spend;
  • higher interest expense due to higher interest rates impacting floating-rate debt, lower capitalized interest associated with the U.S. portion of the Line 3 Replacement Project placed into service in the fourth quarter of 2021, and higher debt balances associated with advancing the Company’s secured growth program in 2021;
  • higher current income tax due to higher taxable earnings and an increase in U.S. minimum taxes; and
  • lower cash distributions in excess of equity earnings as a result of the joint venture merger transaction with P66 which lowered Enbridge’s economic interest in DCP.

Adjusted Earnings

Three months ended

September 30,

Nine months ended
September 30,

2022

2021

2022

2021

(unaudited; millions of Canadian dollars, except per share amounts)

Adjusted EBITDA1,2

3,758

3,269

11,620

10,314

Depreciation and amortization

(1,104)

(944)

(3,272)

(2,805)

Interest expense2

(826)

(654)

(2,324)

(1,941)

Income taxes2

(360)

(355)

(1,274)

(1,023)

Noncontrolling interests2

(20)

(34)

(58)

(90)

Preference share dividends

(82)

(98)

(271)

(280)

Adjusted earnings1

1,366

1,184

4,421

4,175

Adjusted earnings per common share1

0.67

0.59

2.18

2.06

1   Non-GAAP financial measures. Please refer to Non-GAAP Reconciliations Appendices.

2  Presented net of adjusting items.

Adjusted earnings increased $182 million and adjusted earnings per share was consistent when compared with the third quarter in 2021 primarily due to operational factors discussed above contributing to higher Adjusted EBITDA, offset by:

  • higher depreciation expense on new assets placed into service throughout 2021, including the U.S. portion of the Line 3 Replacement Project, which was placed into service in the fourth quarter and EIEC acquired in October, 2021; and
  • higher interest expense due to higher interest rates impacting floating-rate debt, lower capitalized interest associated with the U.S. portion of the Line 3 Replacement Project placed into service in the fourth quarter of 2021, and higher debt balances associated with advancing the Company’s secured growth program in 2021.

CONFERENCE CALL

Enbridge will host a conference call and webcast on November 4, 2022 at 9:00 a.m. Eastern Time (7:00 a.m. Mountain Time) to provide an enterprise wide business update and review 2022 third quarter results. Analysts, members of the media and other interested parties can access the call toll free at 1-800-606-3040. The call will be audio webcast live at https://events.q4inc.com/attendee/326327152. It is recommended that participants dial in or join the audio webcast fifteen minutes prior to the scheduled start time. A webcast replay will be available soon after the conclusion of the event and a transcript will be posted to the website. The replay will be available for seven days after the call toll-free1-(800)-770-2030 (conference ID: 9581867).

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 November 2, 2022, our Board of Directors declared the following quarterly dividends. All dividends are payable on December 1, 2022 to shareholders of record on November 15, 2022.

Dividend per share

Common Shares1

$0.86000

Preference Shares, Series A

$0.34375

Preference Shares, Series B2

$0.32513

Preference Shares, Series D

$0.27875

Preference Shares, Series F

$0.29306

Preference Shares, Series H

$0.27350

Preference Shares, Series L3

                US$0.36612 

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

$0.24613

Preference Shares, Series 13

$0.19019

Preference Shares, Series 15

$0.18644

Preference Shares, Series 19

$0.30625

1

The quarterly dividend per common share was increased 3% to $0.86 from $0.835, effective March 1, 2022.

2

The quarterly dividend per share paid on Preference Shares, Series B was increased to $0.32513 from $0.21340 on June 1, 2022 due to reset of the annual dividend on June 1, 2022. On June 1, 2022, all outstanding Preference Shares, Series C were converted to Preference Shares, Series B.

3

The quarterly dividend per share paid on Preference Shares, Series L was increased to US$0.36612 from US$0.30993 on September 1, 2022 due to reset of the annual dividend on September 1, 2022.

ABOUT ENBRIDGE INC.

At Enbridge, we safely connect millions of people to the energy they rely on every day, fueling quality of life through our North American natural gas, oil or renewable power networks and our growing European offshore wind portfolio. We’re investing in modern energy delivery infrastructure to sustain access to secure, affordable energy and building on two decades of experience in renewable energy to advance new technologies including wind and solar power, hydrogen, renewable natural gas and carbon capture and storage. We’re committed to reducing the carbon footprint of the energy we deliver, and to achieving net zero greenhouse gas emissions by 2050. Headquartered in Calgary, Alberta, Enbridge’s common shares trade under the symbol ENB on the Toronto (TSX) and New York (NYSE) stock exchanges. To learn more, visit us at enbridge.com

None of the information contained in, or connected to, Enbridge’s website is incorporated in or otherwise forms part of this news release.

FOR FURTHER INFORMATION PLEASE CONTACT:

Enbridge Inc. – Media

Enbridge Inc. – Investment Community

Jesse Semko

Rebecca Morley

Toll Free: (888) 992-0997

Toll Free: (800) 481-2804

Email: [email protected]

Email: [email protected]

NON-GAAP RECONCILIATIONS APPENDICES

This news release contains references to EBITDA, 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.

EBITDA represents earnings before interest, tax, depreciation and amortization.

Adjusted EBITDA represents EBITDA adjusted for unusual, infrequent or other non-operating factors on both a consolidated and segmented basis. Management uses EBITDA and 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 and non-GAAP ratios to comparable GAAP measures are not available due to the challenges and impracticability of estimating certain items, particularly certain contingent liabilities and non-cash unrealized derivative fair value losses and gains subject to market variability. Because of those challenges, a reconciliation of forward-looking non-GAAP financial measures and non-GAAP ratios is not available without unreasonable effort.

Our non-GAAP financial measures and non-GAAP ratios described above are not measures that have standardized meaning prescribed by 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

September 30,

Nine months ended
September 30,

2022

2021

2022

2021

(unaudited; millions of Canadian dollars)

Liquids Pipelines

1,946

1,673

6,093

5,756

Gas Transmission and Midstream

2,251

884

4,384

2,725

Gas Distribution and Storage

286

282

1,368

1,374

Renewable Power Generation

105

91

389

362

Energy Services

(70)

(204)

(348)

(379)

Eliminations and Other

(935)

(121)

(1,284)

191

EBITDA

3,583

2,605

10,602

10,029

Depreciation and amortization

(1,076)

(944)

(3,195)

(2,805)

Interest expense

(806)

(648)

(2,316)

(1,923)

Income tax expense

(318)

(199)

(1,044)

(952)

Earnings attributable to noncontrolling interests

(21)

(34)

(61)

(93)

Preference share dividends

(83)

(98)

(330)

(280)

Earnings attributable to common shareholders

1,279

682

3,656

3,976

ADJUSTED EBITDA TO ADJUSTED EARNINGS

Three months ended

September 30,

Nine months ended
September 30,

2022

2021

2022

2021

(unaudited; millions of Canadian dollars, except per share amounts)

Liquids Pipelines

2,269

1,898

6,581

5,623

Gas Transmission and Midstream

1,158

986

3,300

2,928

Gas Distribution and Storage

293

296

1,389

1,403

Renewable Power Generation

113

89

400

356

Energy Services

(132)

(116)

(302)

(277)

Eliminations and Other

57

116

252

281

Adjusted EBITDA

3,758

3,269

11,620

10,314

Depreciation and amortization

(1,104)

(944)

(3,272)

(2,805)

Interest expense

(826)

(654)

(2,324)

(1,941)

Income tax expense

(360)

(355)

(1,274)

(1,023)

Earnings attributable to noncontrolling interests

(20)

(34)

(58)

(90)

Preference share dividends

(82)

(98)

(271)

(280)

Adjusted earnings

1,366

1,184

4,421

4,175

Adjusted earnings per common share

0.67

0.59

2.18

2.06

EBITDA TO ADJUSTED EARNINGS

Three months ended

September 30,

Nine months ended
September 30,

2022

2021

2022

2021

(unaudited; millions of Canadian dollars, except per share amounts)

EBITDA

3,583

2,605

10,602

10,029

Adjusting items:

Change in unrealized derivative fair value (gain)/loss – Foreign exchange

1,334

436

1,751

(91)

Change in unrealized derivative fair value (gain)/loss – Commodity prices

(58)

88

(22)

102

Gain on joint venture merger transaction

(1,076)

(1,076)

Equity investment impairment

111

111

Equity earnings adjustment – DCP Midstream, LLC

38

26

104

Net inventory adjustment

(4)

68

Enterprise insurance strategy restructuring

(85)

15

Assets impairment

15

106

Other

49

(9)

150

59

Total adjusting items

175

664

1,018

285

Adjusted EBITDA

3,758

3,269

11,620

10,314

Depreciation and amortization

(1,076)

(944)

(3,195)

(2,805)

Interest expense

(806)

(648)

(2,316)

(1,923)

Income tax expense

(318)

(199)

(1,044)

(952)

Earnings attributable to noncontrolling interests

(21)

(34)

(61)

(93)

Preference share dividends

(83)

(98)

(330)

(280)

Adjusting items in respect of:

Depreciation and amortization

(28)

(77)

Interest expense

(20)

(6)

(8)

(18)

Income tax expense

(42)

(156)

(230)

(71)

Earnings attributable to noncontrolling interests

1

3

3

Preference share dividends

1

59

Adjusted earnings

1,366

1,184

4,421

4,175

Adjusted earnings per common share

0.67

0.59

2.18

2.06

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

LIQUIDS PIPELINES

Three months ended

September 30,

Nine months ended
September 30,

2022

2021

2022

2021

(unaudited; millions of Canadian dollars)

Adjusted EBITDA

2,269

1,898

6,581

5,623

Change in unrealized derivative fair value gain/(loss) – Foreign exchange

(290)

(222)

(364)

84

Assets impairment

(8)

(55)

Property tax settlement

57

Other

(25)

(3)

(69)

(8)

Total adjustments

(323)

(225)

(488)

133

EBITDA

1,946

1,673

6,093

5,756

GAS TRANSMISSION AND MIDSTREAM

Three months ended

September 30,

Nine months ended
September 30,

2022

2021

2022

2021

(unaudited; millions of Canadian dollars)

Adjusted EBITDA

1,158

986

3,300

2,928

Equity investment impairment

(111)

(111)

Gain from joint venture merger transaction

1,076

1,076

Equity earnings adjustment – DCP Midstream, LLC

(38)

(26)

(104)

Other

17

47

34

12

Total adjustments

1,093

(102)

1,084

(203)

EBITDA

2,251

884

4,384

2,725

GAS DISTRIBUTION AND STORAGE

Three months ended

September 30,

Nine months ended
September 30,

2022

2021

2022

2021

(unaudited; millions of Canadian dollars)

Adjusted EBITDA

293

296

1,389

1,403

Change in unrealized derivative fair value gain/(loss) – Foreign exchange

(2)

12

Other

(7)

(12)

(21)

(41)

Total adjustments

(7)

(14)

(21)

(29)

EBITDA

286

282

1,368

1,374

RENEWABLE POWER GENERATION

Three months ended

September 30,

Nine months ended
September 30,

2022

2021

2022

2021

(unaudited; millions of Canadian dollars)

Adjusted EBITDA

113

89

400

356

Change in unrealized derivative fair value gain/(loss) – Foreign exchange

2

2

6

12

Other

(10)

(17)

(6)

Total adjustments

(8)

2

(11)

6

EBITDA

105

91

389

362

ENERGY SERVICES

Three months ended

September 30,

Nine months ended
September 30,

2022

2021

2022

2021

(unaudited; millions of Canadian dollars)

Adjusted EBITDA

(132)

(116)

(302)

(277)

Change in unrealized derivative fair value gain/(loss) – Commodity prices

58

(88)

22

(102)

Net inventory adjustment

4

(68)

Total adjustments

62

(88)

(46)

(102)

EBITDA

(70)

(204)

(348)

(379)

ELIMINATIONS AND OTHER

Three months ended

September 30,

Nine months ended
September 30,

2022

2021

2022

2021

(unaudited; millions of Canadian dollars)

Adjusted EBITDA

57

116

252

281

Change in unrealized derivative fair value gain/(loss) – Foreign exchange

(1,046)

(214)

(1,393)

(17)

Enterprise insurance strategy restructuring

85

(15)

Impairment of lease assets

(7)

(51)

Other

(24)

(23)

(77)

(73)

Total adjustments

(992)

(237)

(1,536)

(90)

EBITDA

(935)

(121)

(1,284)

191

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

Three months ended

September 30,

Nine months ended
September 30,

2022

2021

2022

2021

(unaudited; millions of Canadian dollars)

Cash provided by operating activities

2,144

2,313

7,617

7,366

Adjusted for changes in operating assets and liabilities1

464

293

602

656

2,608

2,606

8,219

8,022

Distributions to noncontrolling interests2

(60)

(66)

(184)

(207)

Preference share dividends

(81)

(92)

(254)

(274)

Maintenance capital expenditures3

(215)

(142)

(466)

(412)

Significant adjusting items:

Other receipts of cash not recognized in revenue4

48

23

173

74

Distributions from equity investments in excess of cumulative earnings2

148

52

474

297

Enterprise insurance strategy restructuring expenses

100

Other items

53

(91)

258

54

DCF

2,501

2,290

8,320

7,554

1

Changes in operating assets and liabilities, net of recoveries.

2

Presented net of adjusting items.

3

Maintenance capital expenditures are expenditures that are required for the ongoing support and maintenance of the existing pipeline system or that are necessary to maintain the service capability of the existing assets (including the replacement of components that are worn, obsolete or completing their useful lives). For the purpose of DCF, maintenance capital excludes expenditures that extend asset useful lives, increase capacities from existing levels or reduce costs to enhance revenues or provide enhancements to the service capability of the existing assets.

4

Consists of cash received, net of revenue recognized, for contracts under make-up rights and similar deferred revenue arrangements.

IBF4

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