UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C.  20549

 

FORM 6-K

 

Report of Foreign Issuer

Pursuant to Rule 13a-16 or 15d-16 of

the Securities Exchange Act of 1934

 

Dated August 3, 2017

Commission file number 001-15254

 

 

ENBRIDGE INC.

(Exact name of Registrant as specified in its charter)

 

 

200, 425 – 1st Street S.W.

Calgary, Alberta, Canada  T2P 3L8

(Address of principal executive offices and postal code)

 

 

Indicate by check mark whether the Registrant files or will file annual reports under cover of Form 20-F or Form 40-F.

 

Form 20-F

 

 

Form 40-F

P

 

 

Indicate by check mark if the Registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1):

 

Yes

 

 

No

P

 

Indicate by check mark if the Registrant is submitting the Form 6-K in paper as permitted by regulation S-T Rule 101(b)(7):

 

Yes

 

 

No

P

 

 

THIS REPORT ON FORM 6-K SHALL BE DEEMED TO BE INCORPORATED BY REFERENCE IN THE REGISTRATION STATEMENTS ON FORM S-8 (FILE NO. 333-216272, 333-145236, 333-127265, 333-13456, 333-97305 AND 333-6436), FORM F-3 (FILE NO. 333-185591) AND FORM F-10 (FILE NO. 333-213234) OF ENBRIDGE INC. AND TO BE PART THEREOF FROM THE DATE ON WHICH THIS REPORT IS FURNISHED, TO THE EXTENT NOT SUPERSEDED BY DOCUMENTS OR REPORTS SUBSEQUENTLY FILED OR FURNISHED.

 



 

The following documents are being submitted herewith:

 

·                 Interim Report to Shareholders for the six months ended June 30, 2017

 

 

SIGNATURES

 

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 

 

 

 

ENBRIDGE INC.

 

 

(Registrant)

 

 

 

 

 

 

Date:

  August 3, 2017

By:   

/s/”Tyler W. Robinson”

 

 

Tyler W. Robinson

Vice President & Corporate Secretary

 

 

2



 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

ENBRIDGE INC.

 

MANAGEMENT’S DISCUSSION AND ANALYSIS

 

June 30, 2017

 



 

GLOSSARY

 

Algonquin

Algonquin Gas Transmission, L.L.C.

ALJ

Administrative Law Judge

ASU

Accounting Standards Update

Average Exchange Rate

United States to Canadian dollar average exchange rate

bcf/d

Billion cubic feet per day

bpd

Barrels per day

Canadian L3R Program

Canadian portion of the Line 3 Replacement Program

CTS

Competitive Toll Settlement

EBIT

Earnings before interest and income taxes

Eddystone Rail

Eddystone Rail Company, LLC

EEP

Enbridge Energy Partners, L.P.

EGD

Enbridge Gas Distribution Inc.

Enbridge or the Company

Enbridge Inc.

ENF

Enbridge Income Fund Holdings Inc.

EPA

United States Environmental Protection Agency

FCA

Federal Court of Appeal

FERC

Federal Energy Regulatory Commission

Flanagan South

Flanagan South Pipeline

GHG

Greenhouse gas

Gulfstream

Gulfstream Natural Gas System, L.L.C.

IJT

International Joint Tariff

L3R Program

Line 3 Replacement Program

Lakehead System

Lakehead Pipeline System

LNG

Liquefied natural gas

M&N U.S.

Maritimes & Northeast Pipeline, L.L.C.

MD&A

Management’s Discussion and Analysis

MEP

Midcoast Energy Partners, L.P.

mmcf/d

Million cubic feet per day

MNPUC

Minnesota Public Utilities Commission

NEB

National Energy Board

NGL

Natural gas liquids

OEB

Ontario Energy Board

Offshore

Enbridge Offshore Pipelines

Seaway Pipeline

Seaway Crude Pipeline System

SEP

Spectra Energy Partners, LP

Spectra Energy

Spectra Energy Corp

Texas Eastern

Texas Eastern Transmission, L.P.

the Fund

Enbridge Income Fund

the Fund Group

Enbridge Income Fund, Enbridge Commercial Trust, Enbridge Income Partners LP and the subsidiaries and investees of Enbridge Income Partners LP

the Merger Transaction

The stock-for-stock merger transaction between Enbridge and Spectra Energy

 

1



 

the Tupper Plants

Tupper Main and Tupper West gas plants

Union Gas

Union Gas Limited

U.S. GAAP

Generally accepted accounting principles in the United States of America

U.S. L3R Program

United States portion of the Line 3 Replacement Program

Westcoast

Westcoast Energy Inc.

 

2



 

MANAGEMENT’S DISCUSSION AND ANALYSIS

FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2017

 

This Management’s Discussion and Analysis (MD&A) dated August 3, 2017 should be read in conjunction with the unaudited interim consolidated financial statements and notes thereto of Enbridge Inc. (Enbridge or the Company) as at and for the three and six months ended June 30, 2017, prepared in accordance with generally accepted accounting principles in the United States of America (U.S. GAAP). It should also be read in conjunction with the Company’s audited consolidated financial statements and MD&A for the year ended December 31, 2016 filed on February 17, 2017. For information relating to assets and operations acquired through the combination with Spectra Energy Corp (Spectra Energy), additional information is also available in Spectra Energy’s audited consolidated financial statements and MD&A for the year ended December 31, 2016 filed on SEDAR on February 24, 2017. All financial measures presented in this MD&A are expressed in Canadian dollars, unless otherwise indicated. Additional information related to the Company, including its Annual Information Form, is available on SEDAR at www.sedar.com.

 

MERGER WITH SPECTRA ENERGY

 

On February 27, 2017, Enbridge announced the closing of the previously announced combination of Enbridge and Spectra Energy through a stock-for-stock merger transaction (the Merger Transaction).

 

Under the terms of the Merger Transaction, Spectra Energy shareholders received 0.984 shares of Enbridge for each share of Spectra Energy common stock they held. Upon closing of the Merger Transaction, Enbridge shareholders owned approximately 57% of the combined company and Spectra Energy shareholders owned approximately 43%.

 

Spectra Energy, now wholly-owned by Enbridge, is one of North America’s leading natural gas delivery companies owning and operating a large, diversified and complementary portfolio of gas transmission, midstream gathering and processing and distribution assets. It also owns and operates a crude oil pipeline system that connects Canadian and United States producers to refineries in the United States Rocky Mountain and Midwest regions. The combination with Spectra Energy has created the largest energy infrastructure company in North America with an extensive portfolio of energy assets that are well positioned to serve key supply basins and end use markets and multiple business platforms through which to drive future growth. At the time of closing of the Merger Transaction, the Company’s capital program included $27 billion of commercially secured growth projects, which are expected to come into service through 2019, and an additional portfolio of projects in earlier stages of development expected to come into service by 2024. These growth projects, together with Enbridge’s existing businesses, are expected to generate dividend growth of 10% to 12% on average through 2024.

 

A more detailed description of each of the businesses and underlying assets acquired through the Merger Transaction is provided under Financial Results within this MD&A. The results of operations from assets acquired through the Merger Transaction are included in Enbridge’s financial statements and in this MD&A on a prospective basis from the closing date of the Merger Transaction.

 

Post-combination, the Company’s activities continue to be carried out through five business segments: Liquids Pipelines; Gas Pipelines and Processing; Gas Distribution; Green Power and Transmission; and Energy Services. Effective February 27, 2017, as a result of the Merger Transaction, and in addition to Enbridge assets previously held:

·         Liquids Pipelines also includes results from the operation of the Express-Platte System.

·         Gas Pipelines and Processing also includes Spectra Energy’s United States Storage and Transmission Assets, Canadian British Columbia Pipeline & Field Services, Canadian Midstream and Maritimes & Northeast U.S. and Canada businesses, as well as the results of the Company’s 50% interest in DCP Midstream, LLC (DCP Midstream).

·         Gas Distribution also includes results from the operation of Union Gas Limited (Union Gas).

 

3



 

A number of the assets acquired through the Merger Transaction and included in the business segments discussed above are owned through the Company’s investment in Spectra Energy Partners, LP (SEP). As a result of the combination, Enbridge now holds a 75% equity interest in SEP, a natural gas and crude oil infrastructure master limited partnership, which owns 100% of Texas Eastern Transmission, L.P. (Texas Eastern), 91% of Algonquin Gas Transmission, L.L.C. (Algonquin), 100% of East Tennessee Natural Gas, L.L.C. (East Tennessee), 100% of Express-Platte, 100% of Saltville Gas Storage Company L.L.C. (Saltville), 100% of Ozark Gas Gathering, L.L.C. and Ozark Gas Transmission, L.L.C., 100% of Big Sandy Pipeline, L.L.C., 100% of Market Hub Partners Holding, 100% of Bobcat Gas Storage, 78% of Maritimes & Northeast Pipeline, L.L.C. (M&N U.S.), 50% of Southeast Supply Header, L.L.C., 50% of Steckman Ridge, L.P. and 50% of Gulfstream Natural Gas System, L.L.C. (Gulfstream).

 

UNITED STATES SPONSORED VEHICLE STRATEGY

 

On April 28, 2017, Enbridge announced the completion of the strategic review of Enbridge Energy Partners, L.P. (EEP). The following actions, together with the measures announced in January 2017 and disclosed in the Company’s 2016 annual MD&A, were taken to enhance EEP’s value proposition to its unitholders and to Enbridge:

 

Acquisition of Midcoast Assets and Privatization of Midcoast Energy Partners, L.P.

On April 27, 2017, Enbridge completed its previously-announced merger through a wholly-owned subsidiary, through which it privatized Midcoast Energy Partners, L.P. (MEP) by acquiring all of the outstanding publicly-held common units of MEP for total consideration of approximately US$170 million.

 

On June 28, 2017, Enbridge, through a wholly-owned subsidiary, acquired all of EEP’s interest in the Midcoast gas gathering and processing business for cash consideration of US$1.3 billion plus existing indebtedness of MEP of US$953 million.

 

As a result of the above transactions, 100% of the Midcoast gas gathering and processing business is now owned by Enbridge.

 

Finalization of Bakken Pipeline System Joint Funding Agreement

On February 15, 2017, EEP acquired an effective 27.6% interest in the Dakota Access and Energy Transfer Crude Oil Pipelines (collectively, the Bakken Pipeline System). On April 27, 2017, Enbridge entered into a joint funding arrangement with EEP whereby Enbridge owns 75% and EEP owns 25% of the combined 27.6% effective interest in the Bakken Pipeline System. Under this arrangement, EEP has retained a five-year option to acquire an additional 20% interest. On finalization of this joint funding arrangement, EEP repaid the outstanding balance on its US$1.5 billion credit agreement with Enbridge, which it had drawn upon to fund the initial purchase.

 

EEP Strategic Restructuring Actions

On April 27, 2017, EEP redeemed all of its outstanding Series 1 Preferred Units held by Enbridge at face value of US$1.2 billion through the issuance of 64.3 million Class A common units to Enbridge. Further, Enbridge irrevocably waived all of its rights associated with its 66.1 million Class D units and 1,000 Incentive Distribution Units (IDUs), in exchange for the issuance of 1,000 Class F units. The Class F units are entitled to (i) 13% of all distributions in excess of US$0.295 per EEP unit, but equal to or less than US$0.35 per EEP unit, and (ii) 23% of all distributions in excess of US$0.35 per EEP unit. The irrevocable waiver is effective with respect to distributions declared with a record date after April 27, 2017. In connection with these strategic restructuring actions, EEP reduced its quarterly distribution from US$0.583 per unit to US$0.35 per unit.

 

The irrevocable waiver of the Class D units and IDUs, the redemption of the Series 1 Preferred Units and the reduction in the quarterly distributions will result in a lower contribution of earnings from EEP. This lower contribution will be partially offset by an increased contribution of earnings as a result of Enbridge’s increased ownership in the Class A common units post restructuring.

 

4



 

ASSET MONETIZATION

 

In conjunction with the announcement of the Merger Transaction in September 2016, the Company announced its intention to divest $2 billion of assets over the ensuing 12 months in order to further strengthen its post-combination balance sheet and enhance the financial flexibility of the combined entity. With the completion of the secondary offering noted below, the Ozark pipeline system sale, the Olympic refined products pipeline sale and other divestitures completed in 2016, the Company has exceeded the $2 billion monetization target.

 

On April 18, 2017, the Company and Enbridge Income Fund Holdings Inc. (ENF) completed the secondary offering of 17,347,750 ENF common shares to the public at a price of $33.15 per share, for gross proceeds to Enbridge of approximately $0.6 billion (the Secondary Offering). To effect the Secondary Offering, Enbridge exchanged 21,657,617 Enbridge Income Fund (Fund) units it owned for an equivalent amount of ENF common shares. In order to maintain its 19.9% ownership interest in ENF, Enbridge retained 4,309,867 of the common shares it received in the exchange, and sold the balance under the Secondary Offering. Enbridge used the proceeds from the Secondary Offering to pay down short-term debt, pending reinvestment by the Company in its growing portfolio of secured projects. Upon closing of the Secondary Offering, the Company’s total economic interest in ENF decreased from 86.9% to 84.6%.

 

CONSOLIDATED EARNINGS

 

 

 

Three months ended

 

Six months ended

 

 

June 30,

 

June 30,

 

 

2017

2016

 

2017

2016

(millions of Canadian dollars, except per share amounts)

 

 

 

 

 

 

Liquids Pipelines

 

1,272

643

 

2,396

2,255

Gas Pipelines and Processing

 

682

19

 

1,021

80

Gas Distribution

 

153

83

 

428

322

Green Power and Transmission

 

51

41

 

101

90

Energy Services

 

(18)

(7)

 

138

(13)

Eliminations and Other

 

(41)

(48)

 

(356)

173

Earnings before interest and income taxes

 

2,099

731

 

3,728

2,907

Interest expense

 

(565)

(369)

 

(1,051)

(781)

Income tax expense

 

(293)

(10)

 

(491)

(427)

(Earnings)/loss attributable to noncontrolling interests and redeemable noncontrolling interests

 

(241)

20

 

(465)

(41)

Preference share dividends

 

(81)

(71)

 

(164)

(144)

Earnings attributable to common shareholders

 

919

301

 

1,557

1,514

Earnings per common share

 

0.56

0.33

 

1.11

1.69

Diluted earnings per common share

 

0.56

0.33

 

1.10

1.67

 

EARNINGS BEFORE INTEREST AND INCOME TAXES

For the three and six months ended June 30, 2017, earnings before interest and income taxes (EBIT) were $2,099 million and $3,728 million, respectively, compared with $731 million and $2,907 million for the three and six months ended June 30, 2016. Earnings for the three and six months ended June 30, 2017 were positively impacted by contributions from new assets following the completion of the Merger Transaction on February 27, 2017.

 

The positive impact to EBIT resulting from the Merger Transaction’s new assets was partially offset by lower results in Energy Services and the Liquids Pipelines segment as discussed below.

 

5



 

The comparability of the Company’s earnings period-over-period is also impacted by a number of unusual, non-recurring or non-operating factors that are enumerated in the Non-GAAP Reconciliation tables, the most significant of which are changes in unrealized derivative fair value gains and losses. For the three months ended June 30, 2017, the Company’s EBIT reflected $461 million of unrealized derivative fair value gains, compared with losses of $98 million in the corresponding 2016 period. For the six months ended June 30, 2017, the Company’s EBIT reflected $877 million of unrealized derivative fair value gains, compared with gains of $834 million in the corresponding 2016 period. The Company has a comprehensive long-term economic hedging program to mitigate interest rate, foreign exchange and commodity price risks which creates volatility in short-term earnings. Over the long term, Enbridge believes its hedging program supports the reliable cash flows and dividend growth upon which the Company’s investor value proposition is based.

 

In addition, the comparability of period-over-period EBIT was impacted by the recognition of an impairment of $176 million ($103 million after-tax attributable to Enbridge) in the second quarter of 2016 related to Enbridge’s 75% joint venture interest in Eddystone Rail Company, LLC (Eddystone Rail), a rail-to-barge transloading facility located in Greater Philadelphia, Pennsylvania.

 

EBIT for the six months ended June 30, 2017 also reflected charges of $178 million ($130 million after-tax) with respect to costs incurred in conjunction with the Merger Transaction, as well as $208 million ($146 million after-tax) of employee severance costs in relation to the Company’s enterprise-wide reduction of workforce in March 2017 and restructuring costs in connection with the completion of the Merger Transaction.

 

EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS

Earnings attributable to common shareholders for the three months ended June 30, 2017 were $919 million, or $0.56 per common share, compared with $301 million, or $0.33 per common share, for the three months ended June 30, 2016. Earnings attributable to common shareholders for the six months ended June 30, 2017 were $1,557 million, or $1.11 per common share, compared with $1,514 million, or $1.69 per common share, for the six months ended June 30, 2016.

 

In addition to the factors discussed in Earnings Before Interest and Income Taxes above, interest expense for the three and six months ended June 30, 2017 was higher, compared with the corresponding 2016 periods, as a result of debt assumed in the Merger Transaction. Preference share dividends were also higher reflecting additional preference shares issued in the fourth quarter of 2016 to partially fund the Company’s growth capital program.

 

Income tax expense increased for the three and six months ended June 30, 2017, compared with the corresponding 2016 periods, largely due to the increase in earnings.

 

Earnings attributable to noncontrolling interests and redeemable noncontrolling interests increased in the second quarter and the first half of 2017, compared with the corresponding 2016 periods. The increase was driven by additional noncontrolling interests associated with the assets acquired in the Merger Transaction and lower earnings attributable to noncontrolling interests in EEP during 2016.

 

Lower earnings per common share for the six months ended June 30, 2017, compared with the corresponding 2016 period, reflected the issuance of approximately 691 million common shares in February 2017 as part of the consideration for the Merger Transaction, the issuance of approximately 75 million common shares in 2016 through a 56 million follow-on common share offering in the first quarter of 2016, and ongoing issuances under the Company’s Dividend Reinvestment Program.

 

6



 

FORWARD-LOOKING INFORMATION

Forward-looking information, or forward-looking statements, have been included in this MD&A 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 EBIT or expected adjusted EBIT; expected earnings/(loss) or adjusted earnings/(loss); expected earnings/(loss) or adjusted earnings/(loss) per share; expected future cash flows; expected performance of the Liquids Pipelines business; financial strength and flexibility; expectations on sources of liquidity and sufficiency of financial resources; expected costs related to announced projects and projects under construction; expected in-service dates for announced projects and projects under construction; expected capital expenditures; expected equity funding requirements for the Company’s commercially secured growth program; expected future growth and expansion opportunities; expectations about the Company’s joint venture partners’ ability to complete and finance projects under construction; expected closing of acquisitions and dispositions; estimated future dividends; recovery of the costs of the Canadian portion of the Line 3 Replacement Program (Canadian L3R Program); expected expansion of the T-South System; expected capacity of the Hohe See Expansion Offshore Wind Project; expected costs in connection with Line 6A and Line 6B crude oil releases; expected effect of Aux Sable Consent Decree; expected future actions of regulators; expected costs related to leak remediation and potential insurance recoveries; expectations regarding commodity prices; supply forecasts; expectations regarding the impact of the Merger Transaction including the combined Company’s scale, financial flexibility, growth program, future business prospects and performance; impact of the Canadian L3R Program on existing integrity programs; dividend payout policy; dividend growth and dividend payout expectation; and expectations on impact of hedging program.

 

Although Enbridge believes these forward-looking statements are reasonable based on the information available on the date such statements are made and processes used to prepare the information, such statements are not guarantees of future performance and readers are cautioned against placing undue reliance on forward-looking statements. By their nature, these statements involve a variety of assumptions, known and unknown risks and uncertainties and other factors, which may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Material assumptions include assumptions about the following: the expected supply of and demand for crude oil, natural gas, natural gas liquids (NGL) and renewable energy; prices of crude oil, natural gas, NGL and renewable energy; exchange rates; inflation; interest rates; availability and price of labour and construction materials; operational reliability; customer and regulatory approvals; maintenance of support and regulatory approvals for the Company’s projects; anticipated in-service dates; weather; the realization of anticipated benefits and synergies of the Merger Transaction; governmental legislation; acquisitions and the timing thereof; the success of integration plans; impact of the dividend policy on the Company’s future cash flows; credit ratings; capital project funding; expected EBIT or expected adjusted EBIT; expected earnings/(loss) or adjusted earnings/(loss); expected earnings/(loss) or adjusted earnings/(loss) per share; expected future cash flows and estimated future dividends. Assumptions regarding the expected supply of and demand for crude oil, natural gas, NGL and renewable energy, and the prices of these commodities, are material to and underlie all forward-looking statements, as they may impact current and future levels of demand for the Company’s services. Similarly, exchange rates, inflation and interest rates impact the economies and business environments in which the Company operates and may impact levels of demand for the Company’s services and cost of inputs, and are therefore inherent in all forward-looking statements. Due to the interdependencies and correlation of these macroeconomic factors, the impact of any one assumption on a forward-looking statement cannot be determined with certainty, particularly with respect to the impact of the Merger Transaction on the Company, expected EBIT, adjusted EBIT, earnings/(loss), adjusted earnings/(loss) and associated per share amounts, or estimated future dividends. The most relevant assumptions associated with forward-looking statements on announced projects and projects under construction, including estimated completion dates and expected capital expenditures, include the following: the availability and price of labour and construction materials; the effects of inflation 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.

 

7



 

Enbridge’s forward-looking statements are subject to risks and uncertainties pertaining to the impact of the Merger Transaction, operating performance, regulatory parameters, dividend policy, project approval and support, renewals of rights of way, weather, economic and competitive conditions, public opinion, changes in tax laws and tax rates, changes in trade agreements, exchange rates, interest rates, commodity prices, political decisions and supply of and demand for commodities, including but not limited to those risks and uncertainties discussed in this MD&A 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 MD&A or otherwise, whether as a result of new information, future events or otherwise. All subsequent forward-looking statements, whether written or oral, attributable to Enbridge or persons acting on the Company’s behalf, are expressly qualified in their entirety by these cautionary statements.

 

NON-GAAP MEASURES

 

This MD&A contains references to adjusted EBIT, adjusted earnings and adjusted earnings per common share. Adjusted EBIT represents EBIT adjusted for unusual, non-recurring or non-operating factors on both a consolidated and segmented basis. Adjusted earnings represent earnings attributable to common shareholders adjusted for unusual, non-recurring or non-operating factors included in adjusted EBIT, as well as adjustments for unusual, non-recurring or non-operating factors in respect of interest expense, income taxes, noncontrolling interests and redeemable noncontrolling interests on a consolidated basis. These factors, referred to as adjusting items, are reconciled and discussed in the financial results sections for the affected business segments.

 

Management believes the presentation of adjusted EBIT, adjusted earnings and adjusted earnings per share gives useful information to investors and shareholders as they provide increased transparency and insight into the performance of the Company. Management uses adjusted EBIT and adjusted earnings to set targets and to assess the performance of the Company. Adjusted EBIT, adjusted EBIT for each segment, adjusted earnings and adjusted earnings per common share 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 GAAP and non-GAAP measures.

 

8



 

NON-GAAP RECONCILIATION – EBIT TO ADJUSTED EARNINGS

 

 

 

Three months ended

 

Six months ended

 

 

June 30,

 

June 30,

 

 

2017

2016

 

2017

2016

(millions of Canadian dollars)

 

 

 

 

 

 

Earnings before interest and income taxes

 

2,099

731

 

3,728

2,907

Adjusting items1:

 

 

 

 

 

 

Change in unrealized derivative fair value (gain)/loss2

 

(461)

98

 

(877)

(834)

Assets and investment impairment loss

 

-

187

 

-

187

Unrealized intercompany foreign exchange (gain)/loss

 

7

(5)

 

14

55

Hydrostatic testing

 

-

-

 

-

(12)

Make-up rights adjustments3

 

-

48

 

-

115

Northeastern Alberta wildfires pipelines and facilities restart costs

 

-

21

 

-

21

Leak remediation costs, net of leak insurance recoveries

 

4

1

 

8

16

Warmer/(colder) than normal weather4

 

-

(9)

 

-

8

Project development and transaction costs

 

50

3

 

203

3

Employee severance and restructuring costs

 

79

8

 

208

8

Other

 

(65)

6

 

(56)

(11)

Adjusted earnings before interest and income taxes

 

1,713

1,089

 

3,228

2,463

Interest expense

 

(565)

(369)

 

(1,051)

(781)

Income taxes

 

(293)

(10)

 

(491)

(427)

(Earnings)/loss attributable to noncontrolling interests and redeemable noncontrolling interests

 

(241)

20

 

(465)

(41)

Preference share dividends

 

(81)

(71)

 

(164)

(144)

Adjusting items in respect of:

 

 

 

 

 

 

Interest expense

 

(23)

6

 

(2)

24

Income taxes

 

99

(121)

 

153

120

Noncontrolling interests and redeemable noncontrolling interests

 

53

(88)

 

129

(95)

Adjusted earnings

 

662

456

 

1,337

1,119

 

1

The above table summarizes adjusting items by nature. For a detailed listing of adjusting items by segment, refer to individual segment discussions.

2

Changes in unrealized derivative fair value gains and losses are presented net of amounts realized on the settlement of derivative contracts during the applicable period.

3

Effective January 1, 2017, the Company no longer makes such an adjustment to its EBIT. For further details refer to Financial Results - Liquids Pipelines.

4

Effective January 1, 2017, the Company no longer makes such an adjustment to its EBIT. For further details refer to Financial Results - Gas Distribution.

 

9



 

NON-GAAP RECONCILIATION – ADJUSTED EBIT TO ADJUSTED EARNINGS

 

 

 

Three months ended

 

Six months ended

 

 

June 30,

 

June 30,

 

 

2017

2016

 

2017

2016

(millions of Canadian dollars, except per share amounts)

 

 

 

 

 

 

Liquids Pipelines

 

938

922

 

1,908

2,006

Gas Pipelines and Processing

 

667

90

 

1,003

177

Gas Distribution

 

153

73

 

422

313

Green Power and Transmission

 

51

40

 

101

88

Energy Services

 

(3)

47

 

(8)

48

Eliminations and Other

 

(93)

(83)

 

(198)

(169)

Adjusted earnings before interest and income taxes

 

1,713

1,089

 

3,228

2,463

Interest expense1

 

(588)

(363)

 

(1,053)

(757)

Income taxes1

 

(194)

(131)

 

(338)

(307)

Noncontrolling interests and redeemable noncontrolling interests1

 

(188)

(68)

 

(336)

(136)

Preference share dividends

 

(81)

(71)

 

(164)

(144)

Adjusted earnings

 

662

456

 

1,337

1,119

Adjusted earnings per common share

 

0.41

0.50

 

0.95

1.25

 

1

These balances are presented net of adjusting items.

 

Adjusted EBIT

For the three and six months ended June 30, 2017, adjusted EBIT was $1,713 million and $3,228 million, respectively, an increase of $624 million and $765 million over the corresponding three and six-month periods in 2016. The largest driver of adjusted EBIT growth over the prior year periods was the contributions of new assets acquired in the Merger Transaction which closed on February 27, 2017. Also contributing to the period-over-period growth in adjusted EBIT were increased contributions from the Green Power and Transmission segment. These positive contributions were partially offset by warmer weather in the franchise areas served by the Company’s gas distribution utilities and lower results in the Energy Services and Liquids Pipelines segments.

 

Growth in adjusted EBIT was most pronounced in the Gas Pipelines and Processing segment, where a majority of the new assets acquired through the Merger Transaction are reported. Growth for this segment also reflected contributions from the Tupper Main and Tupper West gas plants (the Tupper Plants) acquired in April 2016.

 

Excluding contributions from Express-Platte as part of the Merger Transaction, Liquids Pipelines adjusted EBIT decreased in the three and six months ended June 30, 2017, compared with the corresponding 2016 periods. The second quarter of 2017 was impacted by several transitory items including a significant unexpected outage and accelerated maintenance at a customer’s upstream facility, additional related and unrelated production disruptions, and a hydrostatic testing program on Line 5 during the month of June 2017. The combined impact on the mainline system of these factors was approximately $50 million in the second quarter of 2017. Up until the month of June, the mainline system had been delivering near record volumes and operating under apportionment in heavy crude oil service. Apportionment on the mainline system also impacted the adjusted EBIT contribution of certain downstream pipelines during the first and second quarters of 2017. Liquids Pipelines reported performance was further impacted by a change in practice whereby the Company no longer includes cash received under certain take-or-pay contracts with make-up rights in its determination of adjusted EBIT. In addition, the divestiture of certain assets and lower surcharge revenues decreased adjusted EBIT. Adjusted EBIT generated by Liquids Pipelines is expected to grow over the second half of 2017 as throughput on the mainline system is expected to return to record levels achieved earlier in the year and capacity optimization projects, undertaken in the first half of the year to alleviate apportionment on the mainline system, are operationalized.

 

Within the Gas Distribution segment, Enbridge Gas Distribution Inc. (EGD) generated lower adjusted EBIT for the six months ended June 30, 2017, compared with the corresponding 2016 period, primarily due to lower distribution revenues attributable to warmer than normal weather in the first half of 2017. Effective January 1, 2017, EGD ceased to exclude the effect of warmer/colder weather from its adjusted EBIT. In the first half of 2017 warmer than normal weather impacted EGD’s adjusted EBIT by approximately $23 million. The period-over-period decrease in EGD’s adjusted EBIT was more than offset by contributions from Union Gas since the completion of the Merger Transaction.

 

10



 

Energy Services adjusted EBIT for the three and six months ended June 30, 2017 reflected compressed location and quality differentials in certain markets, lower refinery demand for certain products and fewer opportunities to achieve profitable margins on facilities where the Company holds capacity obligations. Adjusted EBIT from Energy Services is dependent on market conditions and results achieved in one period may not be indicative of results to be achieved in future periods.

 

The increase in adjusted loss before interest and income taxes reported within Eliminations and Other reflects higher unallocated corporate costs which primarily resulted from the Merger Transaction, partially offset by synergies achieved thus far on integration of corporate functions.

 

Adjusted Earnings

Adjusted earnings were $662 million, or $0.41 per common share, for the three months ended June 30, 2017, compared with $456 million, or $0.50 per common share, for the three months ended June 30, 2016. Adjusted earnings were $1,337 million, or $0.95 per common share, for the six months ended June 30, 2017, compared with $1,119 million, or $1.25 per common share, for the six months ended June 30, 2016.

 

In addition to the factors discussed in Adjusted EBIT above, the comparability of adjusted earnings is consistent with the discussion in Earnings Attributable to Common Shareholders above.

 

11



 

GROWTH PROJECTS – COMMERCIALLY SECURED PROJECTS

 

The following table summarizes the status of the Company’s commercially secured projects, organized by business segment. Expenditures to date reflect total cumulative expenditures incurred from inception of the project to June 30, 2017.

 

 

 

 

 

 

 

 

Expected

 

 

 

 

 

Estimated

 

Expenditures

 

In-Service

 

 

 

 

 

Capital Cost1

 

to Date

 

Date

 

Status

(Canadian dollars, unless stated otherwise)

 

 

 

 

 

 

 

 

LIQUIDS PIPELINES

 

 

 

 

 

 

 

 

1.

 

Norlite Pipeline System (the Fund Group)

 

$1.3 billion

 

$1.1 billion

 

2017

 

Complete

2.

 

Bakken Pipeline System (EEP)

 

US$1.5 billion

 

US$1.5 billion

 

2017

 

Complete

3.

Regional Oil Sands Optimization Project (the Fund Group)

 

$2.6 billion

 

$2.3 billion

 

2017
(in phases)

 

Substantially
complete

4.

Lakehead System Mainline Expansion - Line 61 (EEP)

 

US$0.4 billion

 

US$0.4 billion

 

2019

 

Substantially
complete

5.

Canadian Line 3 Replacement2 Program (the Fund Group)

 

$5.3 billion

 

$1.7 billion

 

2019

 

Pre-
construction

6.

U.S. Line 3 Replacement Program2 (EEP)

 

US$2.9 billion

 

US$0.5 billion

 

2019

 

Under
construction

7.

Other - Canada

 

$0.3 billion

 

$0.1 billion

 

2017-2018

 

Various
stages

 

GAS PIPELINES AND PROCESSING

 

 

 

 

 

 

 

 

8.

 

Sabal Trail (SEP)3

 

US$1.6 billion

 

US$1.4 billion

 

2017

 

Complete

9.

Access South, Adair Southwest and Lebanon Extension (SEP)3

 

US$0.5 billion

 

US$0.2 billion

 

2017

 

Under
construction

10.

Atlantic Bridge (SEP)3

 

US$0.5 billion

 

US$0.2 billion

 

2017-2018

 

Under
construction

11.

NEXUS (SEP)3

 

US$1.1 billion

 

US$0.5 billion

 

2018

 

Pre-
construction

12.

High Pine3

 

$0.4 billion

 

$0.2 billion

 

2017

 

Under
construction

13.

Reliability and Maintainability Project3

 

$0.5 billion

 

$0.3 billion

 

2017-2018

 

Under
construction

14.

Valley Crossing Pipeline3

 

US$1.5 billion

 

US$0.5 billion

 

2018

 

Under
construction

15.

Spruce Ridge Program3

 

$0.5 billion

 

No significant
expenditures to date

 

2019

 

Pre-
construction

16.

British Columbia Pipeline3 T-South System

 

$1.0 billion

 

No significant
expenditures to date

 

2020

 

Pre-
construction

17.

Other - United States3

 

US$1.6 billion

 

US$0.9 billion

 

2017-2019

 

Various
stages

18.

Other - Canada3

 

$0.4 billion

 

$0.2 billion

 

2017-2018

 

Various
stages

 

12



 

 

 

 

 

 

 

 

Expected

 

 

 

 

 

Estimated

 

Expenditures

 

In-Service

 

 

 

 

 

Capital Cost1

 

to Date

 

Date

 

Status

(Canadian dollars, unless stated otherwise)

 

 

 

 

 

 

 

 

GAS DISTRIBUTION

 

 

 

 

 

 

 

 

19.

2017 Dawn-Parkway Expansion3

 

$0.6 billion

 

$0.5 billion

 

2017

 

Under
construction

20.

Other - Canada3

 

$0.3 billion

 

$0.1 billion

 

2017

 

Under
construction

 

GREEN POWER AND TRANSMISSION

 

 

 

 

 

 

 

 

21.

Chapman Ranch Wind Project

 

US$0.4 billion

 

US$0.3 billion

 

2017

 

Under
 construction

22.

Rampion Offshore Wind Project

 

$0.8 billion
(£0.37 billion)

 

$0.5 billion
(£0.3 billion)

 

2018

 

Under
 construction

23.

Hohe See Offshore Wind Project4

 

$1.7 billion
(€1.07 billion)

 

$0.5 billion
(€0.3 billion)

 

2019

 

Pre-
 construction

24.

Hohe See Expansion Project

 

$0.4 billion
(€0.27 billion)

 

No significant
expenditures to date

 

2019

 

Pre- construction

 

1

These amounts are estimates and are subject to upward or downward adjustment based on various factors. Where appropriate, the amounts reflect Enbridge’s share of joint venture projects.

2

Based on the updated execution plan, the updated project capital costs are $5.3 billion in Canada and US$2.9 billion in the United States.

3

Includes projects acquired as part of the Merger Transaction. For additional information, refer to Merger with Spectra Energy.

4

In February 2017, Enbridge acquired an effective 50% interest in the Hohe See Offshore Wind Project.

 

The description of each of the Enbridge projects, including those being undertaken by EEP and the Fund Group, which is comprised of the Fund, Enbridge Commercial Trust, Enbridge Income Partners LP (EIPLP) and the subsidiaries and investees of EIPLP, is provided in the Company’s 2016 annual MD&A. Projects where significant developments have occurred since February 17, 2017, the date of the filing of the Company’s MD&A for the year ended December 31, 2016, including the commercially secured growth projects acquired upon close of the Merger Transaction, are discussed below.

 

LIQUIDS PIPELINES

Norlite Pipeline System (the Fund Group)

Norlite Pipeline System, a new industry diluent pipeline originating from the Company’s Stonefell Terminal, was placed into commercial service on May 1, 2017. To meet the needs of multiple producers in the Athabasca oil sands region, the 24-inch diameter pipeline provides an initial capacity of approximately 218,000 Barrels per day (bpd) of diluent, with the potential to be further expanded to approximately 465,000 bpd of capacity with the addition of pump stations. Keyera Corp. has elected to participate in the Norlite Pipeline System as a 30% non-operating owner.

 

Bakken Pipeline System (EEP)

On February 15, 2017, EEP acquired an effective 27.6% interest in the Bakken Pipeline System for a purchase price of $2.0 billion (US$1.5 billion). The Bakken Pipeline System was placed into service on June 1, 2017. It connects the Bakken formation in North Dakota to markets in the eastern Petroleum Administration for Defense Districts and the United States Gulf Coast, providing customers with access to premium markets at a competitive cost.

 

On April 27, 2017, Enbridge entered into a joint funding arrangement with EEP whereby Enbridge owns 75% and EEP owns 25% of the combined 27.6% effective interest in the Bakken Pipeline System.

 

Lakehead System Mainline Expansion (EEP)

The Lakehead System Mainline Expansion includes several projects to expand capacity of the Lakehead Pipeline System (Lakehead System) mainline between its origin at the United States/Canada border, near Neche, North Dakota, and Flanagan, Illinois. These projects include the expansion of Alberta Clipper (Line 67) and Southern Access (Line 61) and the construction of the Spearhead North Twin pipeline (Line 78). The expansion of Line 67 and construction of Line 78 were completed in 2015.

 

13



 

The Line 67 pipeline capacity expansion remains subject to the receipt of an amendment to the current Presidential Permit to allow for operation of the Line 67 pipeline at the United States/Canada border at its currently planned operating capacity of 800,000 bpd. On February 10, 2017, the United States Department of State (DOS), the agency that is responsible for issuing permits for cross-border pipelines pursuant to a delegation of authority by the President under an Executive Order, issued a draft Supplemental Environmental Impact Statement (SEIS), which determined that there were no significant adverse environmental impacts from the planned capacity increase. The public comment period on the draft SEIS closed on March 27, 2017. The DOS is reviewing all received comments and preparing a final SEIS. As required by the Executive Order, the DOS initiated a 90-day inter-agency consultation period to solicit comments from certain other federal agencies on whether the Line 67 expansion will serve the national interest. The inter-agency consultation period commenced on March 28, 2017. Following the issuance of the final SEIS and completion of the inter-agency consultation process, the Administration will make a decision and issue a Presidential Permit if it finds that doing so is in the national interest. The Administration’s decision is expected later in the year.

 

The remaining scope of the Lakehead System Mainline Expansion included the Southern Access expansion between Superior, Wisconsin and Flanagan, Illinois. The expansion to increase the pipeline capacity to 1,200,000 bpd at an expected cost of approximately US$0.4 billion was substantially completed in June of 2017. In conjunction with shippers, a decision was made to delay the in-service date of this phase of the Southern Access expansion to 2019 to align more closely with the anticipated in-service date for the United States portion of the Line 3 Replacement Program (U.S. L3R Program).

 

EEP will operate this project on a cost-of-service basis. The Lakehead System Mainline Expansion is funded 75% by Enbridge and 25% by EEP under a joint funding agreement. Under that agreement, EEP has the option to increase its economic interest held by up to an additional 15% at cost.

 

Line 3 Replacement Program

The Line 3 Replacement Program (L3R Program) will support the safety and operational reliability of the mainline system, enhance system flexibility, allow the Company and EEP to optimize throughput on the mainline system and restore approximately 370,000 bpd of capacity from western Canada into Superior, Wisconsin.

 

Canadian Line 3 Replacement Program (the Fund Group)

The Canadian L3R Program will complement existing integrity programs by replacing approximately 1,084 kilometres (673 miles) of the remaining line segments of the existing Line 3 pipeline between Hardisty, Alberta and Gretna, Manitoba.

 

In April 2016, the National Energy Board (NEB) found that the Canadian L3R Program is in the Canadian public interest and issued final conditions and a recommendation to the Federal Cabinet to approve the issuance of the Certificate of Public Convenience and Necessity (the Certificate) for the construction and operation of the pipeline and related facilities. Approval was received from the Government of Canada on November 29, 2016, with no material changes to permit conditions and on December 1, 2016, the NEB issued the Certificate. Once the Certificate was issued, Natural Resources Canada (NRCan) released the final assessment of the upstream greenhouse gas (GHG) emissions, as well as reports summarizing the additional Crown Consultation with Indigenous groups and the public online survey conducted by NRCan.

 

In December 2016, the Manitoba Metis Federation (MMF) and the Association of Manitoba Chiefs (AMC) applied to the Federal Court of Appeal (FCA) for leave, which was subsequently granted, to judicially review the Government of Canada’s decision to approve the Canadian L3R Program. On July 4, 2017, the MMF discontinued its judicial review application. It is expected that the FCA’s hearing of the AMC judicial review application will take place during 2018, although a hearing date has not yet been set. The potential outcome of this matter cannot be predicted at this time.

 

14



 

On July 7, 2017, the NEB approved the Plan, Profile and Book of Reference for the Canadian L3R Program, meaning that the detailed route for the Canadian L3R Program has been approved. All required pre-construction filings have been submitted to the NEB. Enbridge is awaiting the approval of the two remaining conditions by the NEB before construction can proceed.

 

Based on the updated execution plan, the revised cost of the project is $5.3 billion in Canada. This modest increase is roughly 8% above prior estimates and reflects the ongoing delays in the regulatory process, as well as some additional scope, route modifications and other changes as a result of the extensive consultation efforts and obligation to meet permit conditions. The impact of these additional costs are fully offset by lower estimated operating costs and a stronger United States dollar relative to the original project assumptions.

 

United States Line 3 Replacement Program (EEP)

The U.S. L3R Program will complement existing integrity programs by replacing approximately 576 kilometres (358 miles) of the remaining line segments of the existing Line 3 pipeline between Neche, North Dakota and Superior, Wisconsin. EEP has the authorization to replace Line 3 in North Dakota and Wisconsin.

 

EEP is in the process of obtaining the appropriate permits for constructing the U.S. L3R Program in Minnesota. The project requires both a Certificate of Need and an approval of the pipeline’s route (Route Permit) from the Minnesota Public Utilities Commission (MNPUC). The MNPUC found both the Certificate of Need and Route Permit applications for the U.S. L3R Program through Minnesota to be complete. On February 1, 2016, the MNPUC issued a written order requiring the Minnesota Department of Commerce (DOC) to prepare an Environmental Impact Statement (EIS) before Certificate of Need and Route Permit processes commence. The DOC’s draft EIS was issued on May 15, 2017 and public comments regarding the draft EIS were accepted by the DOC until July 10, 2017. The DOC has stated that it anticipates issuing the final EIS in August 2017. Construction of the Wisconsin portion of U.S. L3R Program commenced in late June 2017.

 

Based on the updated execution plan, the revised cost of the project is US$2.9 billion in the United States. This modest increase is roughly 12% above prior estimates and reflects the ongoing delays in the regulatory process, as well as some additional scope, route modifications and other changes as a result of the extensive consultation efforts and obligation to meet permit conditions. EEP will recover the costs plus a return on capital based on its existing Facilities Surcharge Mechanism with the initial term of the agreement being 15 years. For the purpose of the toll surcharge, the agreement specifies a 30-year recovery of the capital based on a cost-of-service methodology.

 

On January 26, 2017, Enbridge and EEP entered into an agreement for the joint funding of the U.S. L3R Program, whereby Enbridge and EEP will fund 99% and 1%, respectively, of the project cost. Enbridge has reimbursed EEP approximately US$450 million for expenditures incurred to date on the project and it will fund 99% of the capital costs through construction. EEP has the option to increase its economic interest by up to 40% at Enbridge’s cost until four years after the project is placed into service.

 

GAS PIPELINES AND PROCESSING

Sabal Trail (SEP)

The Sabal Trail project, a joint venture with NextEra Energy and Duke Energy, was placed into service in early July 2017. The project will provide firm natural gas transportation to Florida Power & Light Company for its power generation needs and to Duke Energy Florida for its proposed natural gas plant in Florida. Facilities include a new 748 kilometre (465 mile) pipeline, laterals and various compressor stations. This new pipeline infrastructure is located in Alabama, Georgia and Florida, and will add approximately 1,100 million cubic feet per day (mmcf/d) of new capacity to access onshore shale gas supplies once approved future expansions are completed.

 

Access South, Adair Southwest and Lebanon Extension (SEP)

SEP’s Access South, Adair Southwest and Lebanon Extension projects will provide shippers with the opportunity to deliver new natural gas supplies from the Appalachian region of the United States to markets in the Midwest and Southeast regions of the United States where demand for natural gas is high. The facilities for these projects include pipeline looping, as well as modifications and expansions of existing compressor stations on SEP’s Texas Eastern pipeline system. The combined projects are designed to deliver 622 mmcf/d of gas to customers in Ohio, Kentucky and Mississippi. These projects are expected to be placed into service in the second half of 2017.

 

15



 

Atlantic Bridge (SEP)

The Atlantic Bridge project is an expansion designed to provide additional capacity of 133 mmcf/d to SEP’s Algonquin Gas Transmission and Maritimes & Northeast pipeline systems into New England and to specific end use markets in the Canadian Maritime provinces. The expansion primarily consists of the replacement of 10 kilometres (6 miles) of 26-inch pipeline with 42-inch pipeline, compression additions in Connecticut and a new compressor station in Massachusetts. The Connecticut portion of the project is expected to be placed into service in the fourth quarter of 2017. The Massachusetts portion of the project is expected to be placed into service in late 2018.

 

NEXUS (SEP)

Under a 50% joint venture with DTE Energy Company, SEP has begun pre-construction work on the NEXUS project, which is a new pipeline system designed to transport up to 1.5 billion cubic feet per day (bcf/d) from SEP’s Texas Eastern pipeline system in Ohio to the Union Gas Dawn hub in Ontario. The facilities will consist of approximately 410 kilometres (255 miles) of 36-inch pipeline across northern Ohio to the Detroit, Michigan area, addition of four new compressor stations totalling 130,000 horsepower and six meter stations. Approval of the NEXUS project remains pending before the Federal Energy Regulatory Commission (FERC) due to a lack of quorum. While the NEXUS certificate application remains pending, the record supporting the Final EIS and Applications are complete and ready for prompt FERC approval once a quorum is restored. Once the expected approval is received, a revised 2018 in-service date will be identified.

 

High Pine

Westcoast’s High Pine project on the British Columbia Pipeline includes a 240 mmcf/d expansion of the T-North pipeline system consisting of two 42-inch pipeline loops totalling approximately 37 kilometres (23 miles) in length in the Fort St. John region of British Columbia. The expansion consists of an additional compressor unit with associated infrastructure at the Sunset Creek compressor site in northeastern British Columbia. The project is expected to be placed into service by the end of 2017.

 

Reliability and Maintainability Project

Westcoast’s Reliability and Maintainability (RAM) project was designed to enhance the performance of the southern segment of the British Columbia Pipeline system to accommodate the increased base load on the system, which is driven by a combination of increased gas production in the northeastern region of British Columbia and demand driven by end users, such as incremental industrial projects, electric power generation and small-scale liquefied natural gas (LNG). The RAM project involves upgrading the southern segment of the British Columbia Pipeline system with three compressor station replacements. It will prepare the British Columbia Pipeline system to operate at a higher load factor as higher utilization rates are expected from new incremental year-round loads. The first two compressor stations are expected to be placed into service in the fourth quarter of 2017, with the final station expected to be placed into service in the first half of 2018.

 

Valley Crossing Pipeline

The Valley Crossing Pipeline project will provide new market opportunities for Texas gas producers and help Mexico meet its growing electric generation needs as generators shift away from fuel oil and imported LNG. The project will include a new 269 kilometre (167 mile) mainline pipeline that will consist of approximately 221 kilometres (138 miles) of 48-inch pipe and 48 kilometres (30 miles) of 42-inch pipe. The pipeline is designed to carry 2.6 bcf/d of gas from the Agua Dulce hub in Texas to an offshore tie-in with the Sur de Texas-Tuxpan project, which is being constructed by a third party. The Valley Crossing Pipeline is expected to be placed into service in the second half of 2018.

 

16



 

Spruce Ridge Program

Under the Spruce Ridge Program, Westcoast is pursuing an expansion of the British Columbia Pipeline in northern British Columbia. The expansion service agreements were executed in late 2016 and the final scoping of the project is underway, with a targeted in-service date in 2019.

 

British Columbia Pipeline T-South System

In the second quarter of 2017, Enbridge completed a successful binding open season on its British Columbia Pipeline T-South system for delivery of an incremental 190 mmcf/d of natural gas into the Huntington/Sumas market at the United States/Canada border. All customer contracts associated with the open season have been executed. The T-South system is currently fully contracted and an expansion is necessary to meet increasing customer demand as a result of rapidly growing production in the Montney region. The project will include looping of the T-South system and upgrades at compressor stations along the pipeline system at a cost of approximately $1 billion and is expected to be in-service by late 2020.

 

GAS DISTRIBUTION

2017 Dawn-Parkway Expansion

The Union Gas 2017 Dawn-Parkway expansion project in Ontario involves a 419 mmcf/d expansion of the Dawn to Parkway transmission system consisting of the addition of a new 44,500 horsepower compressor at each of the Dawn, Lobo and Bright compressor stations in Ontario. The Dawn-Parkway expansion project is expected to be placed into service in the fourth quarter of 2017.

 

GREEN POWER AND TRANSMISSION

Hohe See Expansion Project

In June 2017, the Company announced it had moved forward on its option to partner with German utility EnBW on an expansion of the previously announced Hohe See Offshore Wind Project (Hohe See Project). The Hohe See expansion project, to be located in the vicinity of the 497 megawatt Hohe See Project, will have a capacity of 112 megawatts. Similar to the Hohe See Project, the Hohe See expansion project will be constructed under fixed-price engineering, procurement, construction and installation contracts which have been secured with key suppliers. The Hohe See expansion project is backed by a government legislated 20-year revenue support mechanism and is expected to be placed into service alongside the Hohe See Project in 2019.

 

OTHER ANNOUNCED PROJECTS UNDER DEVELOPMENT

 

The following projects have been announced by the Company, but have not yet met the Company’s criteria to be classified as commercially secured. The Company also has a large portfolio of additional projects under development that have not yet progressed to the point of public announcement.

 

GAS PIPELINES AND PROCESSING

Gulf Coast Express Pipeline Project

In April 2017, DCP Midstream announced the signing of a letter of intent with Kinder Morgan Texas Pipeline LLC to participate in the development of the proposed Gulf Coast Express Pipeline Project. The project will provide an outlet for increased natural gas production from the Permian Basin to growing markets along the Texas Gulf Coast. The project is designed to transport up to 1.7 bcf/d of natural gas through approximately 692 kilometres (430 miles) of 42-inch pipeline from the Waha, Texas area to Agua Dulce, Texas. The project is expected to be placed into service during the second half of 2019, subject to obtaining sufficient shipper commitments.

 

GREEN POWER AND TRANSMISSION

Éolien Maritime France SAS

Enbridge has a 50% interest in Éolien Maritime France SAS (EMF), a French offshore wind development company. EMF is co-owned by Enbridge and EDF Energies Nouvelles, a subsidiary of Électricité de France S.A. EMF, through subsidiary companies, which holds licenses for three large-scale offshore wind farms off the coast of France. Combined, the three projects will have a capacity of 1,428 megawatts of power. The development of these projects is subject to a final investment decision and regulatory approvals, the timing of which is not yet certain. Enbridge’s portion of the costs incurred to date is approximately $226 million (148 million).

 

17



 

FINANCIAL RESULTS

 

For assets owned by Enbridge as at December 31, 2016, a description of the asset and associated risks can be found under the relevant segment discussion in the Company’s MD&A for the year ended December 31, 2016. For assets acquired through the Merger Transaction, the description of the asset and any additional risks specifically associated with these assets have been included with the discussion of the operating results of individual assets that follows. The performance summaries below reflect the financial results of the assets acquired in the Merger Transaction from the closing date of the merger.

 

18



 

LIQUIDS PIPELINES

Earnings Before Interest and Income Taxes

 

 

 

Three months ended

 

Six months ended

 

 

June 30,

 

June 30,

 

 

2017

2016

 

2017

2016

(millions of Canadian dollars)

 

 

 

 

 

 

Canadian Mainline

 

234

177

 

471

486

Lakehead System

 

300

359

 

689

712

Regional Oil Sands System

 

91

88

 

184

181

Mid-Continent and Gulf Coast

 

128

160

 

246

341

Southern Lights Pipeline

 

43

39

 

85

80

Express-Platte System1

 

56

-

 

83

-

Bakken System

 

50

54

 

82

108

Feeder Pipelines and Other

 

36

45

 

68

98

Adjusted earnings before interest and income taxes

 

938

922

 

1,908

2,006

Canadian Mainline - changes in unrealized derivative fair value gains/(loss)

 

266

(12)

 

421

556

Canadian Mainline - leak remediation costs

 

(5)

-

 

(12)

-

Lakehead system - changes in unrealized derivative fair value gains/(loss)

 

1

(4)

 

2

(5)

Lakehead System - hydrostatic testing

 

-

-

 

-

12

Lakehead System - leak remediation costs

 

-

(1)

 

-

(21)

Regional Oil Sands System - northeastern Alberta wildfire pipelines and facilities restart cost

 

-

(21)

 

-

(21)

Regional Oil Sands System - make-up rights adjustment2

 

-

(20)

 

-

(34)

Regional Oil Sands System - leak insurance recoveries

 

-

-

 

3

5

Mid-Continent and Gulf Coast - changes in unrealized derivative fair value loss

 

-

(1)

 

-

(1)

Mid-Continent and Gulf Coast - make-up rights adjustment2

 

-

(28)

 

-

(78)

Southern Lights Pipeline - changes in unrealized derivative fair value gains/(loss)

 

9

(6)

 

16

26

Bakken System - changes in unrealized derivative fair value loss

 

(1)

(2)

 

-

(3)

Bakken System - make-up rights adjustment2

 

-

3

 

-

-

Bakken System - gain on sale of pipe and project wind-down costs

 

67

-

 

62

-

Feeder Pipelines and Other - investment impairment loss

 

-

(176)

 

-

(176)

Feeder Pipelines and Other - derecognition of regulatory balances

 

-

(6)

 

-

(6)

Feeder Pipelines and Other - make-up rights adjustment2

 

-

(2)

 

-

(2)

Feeder Pipelines and Other - project development and transaction costs

 

(3)

(3)

 

(4)

(3)

Earnings before interest and income taxes

 

1,272

643

 

2,396

2,255

 

1         Includes adjusted EBIT from Express-Platte System since the completion of the Merger Transaction on February 27, 2017. For additional information, refer to Merger with Spectra Energy.

2         Effective January 1, 2017, the Company no longer makes such an adjustment to its EBIT.

 

Additional details on items impacting Liquids Pipelines EBIT include:

 

·                  Canadian Mainline EBIT for each period reflects changes in unrealized fair value gains and losses on derivative financial instruments used to manage foreign exchange and commodity price risk inherent within the Competitive Toll Settlement (CTS).

·                  Southern Lights Pipeline EBIT for each period reflects changes in unrealized fair value gains and losses on derivative financial instruments used to manage foreign exchange risk on United States dollar cash flows from the Southern Lights Class A units.

 

19



 

·                  Bakken System EBIT for 2017 includes the gain on sale of pipe offset by project wind-down costs related to EEP’s Sandpiper Project.

·                  Feeder Pipelines and Other loss before interest and income taxes for 2016 included impairment charges related to Enbridge’s 75% joint venture interest in Eddystone Rail attributable to market conditions that impacted volumes at the rail facility.

 

Canadian Mainline

Canadian Mainline adjusted EBIT increased in the second quarter of 2017, compared with the corresponding 2016 period, primarily due to a higher Canadian Mainline International Joint Tariff (IJT) Residual Benchmark Toll and higher average throughput. The Canadian Mainline also benefitted from a higher foreign exchange hedge rate used to record Canadian Mainline revenues. For the second quarter of 2017, the effective hedged rate for the translation of Canadian Mainline United States dollar transactional revenues was $1.04, compared with $1.03 for the corresponding 2016 period.

 

Throughput on the mainline system was affected by unusual events in the second quarter of both 2016 and 2017. In 2016, wildfires in Alberta resulted in a curtailment of production from oil sands facilities and the temporary shutdown of certain of the Company’s upstream pipelines and terminal facilities, decreasing second quarter 2016 adjusted EBIT by approximately $30 million. While higher than the second quarter of 2016, throughput in the second quarter of 2017 was affected by a significant unexpected outage and accelerated maintenance at a customer’s upstream facility, and additional related and unrelated production disruptions.

 

The outages experienced in June were temporary and adjusted EBIT on the Canadian Mainline is expected to be positively impacted in the second half of 2017 as throughput returns to levels experienced earlier in the year and apportionment on the system is relieved through capacity optimizations that were implemented in the first half of the year.

 

Canadian Mainline adjusted EBIT decreased in the first half of 2017, compared with the corresponding 2016 period. Higher adjusted EBIT in the second quarter of 2017, as discussed above, was offset by the lower first quarter results. First quarter results in 2017 decreased, compared with the corresponding 2016 period, due to the absence of hydrostatic test surcharge revenue recognized in 2017, a lower average Canadian Mainline IJT Residual Benchmark Toll and a lower foreign exchange hedge rate used to record United States dollar denominated Canadian Mainline revenues. For the first quarter of 2017, the effective hedged rate for the translation of Canadian Mainline United States dollar transactional revenues was $1.04, compared with $1.11 for the corresponding 2016 period.

 

Supplemental information related to the Canadian Mainline for the three and six months ended June 30, 2017 and 2016, is provided below:

 

June 30,

2017

2016

(United States dollars per barrel)

 

 

IJT Benchmark Toll1

$4.05

$4.07

Lakehead System Local Toll2

$2.43

$2.61

Canadian Mainline IJT Residual Benchmark Toll3

$1.62

$1.46

 

1

The IJT Benchmark Toll is per barrel of heavy crude oil transported from Hardisty, Alberta to Chicago, Illinois. A separate distance adjusted toll applies to shipments originating at receipt points other than Hardisty and lighter hydrocarbon liquids pay a lower toll than heavy crude oil. Effective July 1, 2016, this toll decreased to US$4.05. Effective July 1, 2017, this toll increased to US$4.07.

2

The Lakehead System Local Toll is per barrel of heavy crude oil transported from Neche, North Dakota to Chicago, Illinois. Effective April 1, 2016, this toll increased to US$2.61 and effective July 1, 2016, this toll decreased to US$2.58. Effective April 1, 2017, this toll decreased to US$2.43.

3

The Canadian Mainline IJT Residual Benchmark Toll is per barrel of heavy crude oil transported from Hardisty, Alberta to Gretna, Manitoba. For any shipment, this toll is the difference between the IJT Benchmark Toll and the Lakehead System Local Toll. Effective April 1, 2016, this toll decreased to US$1.46, coinciding with the revised Lakehead System Local Toll. Effective July 1, 2016, this toll increased to US$1.47. Effective April 1, 2017, this toll increased to US$1.62, coinciding with the revised Lakehead System Local Toll. Effective July 1, 2017, this toll increased to US$1.64.

 

20



 

Throughput Volume

 

 

 

Three months ended

 

Six months ended

 

 

June 30,

 

June 30,

 

 

2017

2016

 

2017

2016

(thousands of bpd)

 

 

 

 

 

 

Average throughput volume1

 

2,449

2,242

 

2,521

2,392

 

1

Throughput volume represents mainline deliveries ex-Gretna, Manitoba which is made up of United States and eastern Canada deliveries originating from western Canada.

 

Lakehead System

Lakehead System adjusted EBIT decreased in the second quarter of 2017, compared with the corresponding 2016 period. The second quarter decrease was primarily due to a lower Lakehead System Local Toll, and increased property taxes and depreciation expense resulting from an increased asset base and hydrostatic testing costs in the second quarter of 2017. These negative impacts were partially offset by a higher average United States to Canadian dollar exchange rate (Average Exchange Rate) in the second quarter of 2017, compared with the corresponding 2016 period, and higher average throughput reflecting system optimization.

 

In addition, the higher average throughput in the second quarter of 2017 compared to 2016 was partially driven by the negative impact of the northeastern Alberta wildfires experienced in 2016. The wildfires resulted in a curtailment of production from oil sands facilities and the temporary shutdown of certain of the Company’s upstream pipelines and terminal facilities, decreasing adjusted EBIT by approximately $38 million for the three months ended June 30, 2016. While higher than the second quarter of 2016, throughput in the second quarter of 2017 was affected by a significant unexpected outage and accelerated maintenance at a customer’s upstream facility, additional related and unrelated production disruptions, and a hydrostatic testing program on Line 5 during the month of June 2017.

 

The outages experienced in June were temporary and adjusted EBIT on the Lakehead System is expected to be positively impacted in the second half of 2017 as throughput returns to levels experienced earlier in the year and apportionment on the system is relieved through capacity optimizations that were implemented in the first half of the year.

 

Lakehead System adjusted EBIT decreased in the first half of 2017, compared with the corresponding 2016 period. The decrease in the second quarter of 2017, as discussed above, was partially offset by higher first quarter results in 2017. Strong operating performance in the first quarter of 2017 was driven by higher long-haul throughput and a higher Lakehead System Local Toll compared to 2016. As discussed under Canadian Mainline above, higher throughput on the Lakehead System in the first quarter of 2017 reflected system optimization. It is expected that volumes will increase for the remainder of 2017 as a result of continued optimization efforts.

 

Excluding the impact of foreign exchange translation to Canadian dollars, Lakehead System adjusted EBIT was US$222 million and US$516 million for the three and six months ended June 30, 2017, respectively, compared with US$279 million and US$535 million for corresponding 2016 periods.

 

As noted above, partially offsetting the three and six months ended June 30, 2017 decrease in Lakehead System adjusted EBIT was the favourable effect of translating United States dollar earnings at a higher Average Exchange Rate in the second quarter of 2017, compared with the corresponding 2016 period. A portion of Lakehead System United States dollar EBIT is hedged as part of the Company’s enterprise-wide financial risk management program. The Company uses foreign exchange derivative instruments to manage the foreign exchange risk arising from its United States businesses including the Lakehead System. Realized gains and losses from these derivative instruments are reported within Eliminations and Other. For further details refer to Eliminations and Other.

 

21



 

Throughput Volume

 

 

 

Three months ended

 

Six months ended

 

 

June 30,

 

June 30,

 

 

2017

2016

 

2017

2016

(thousands of bpd)

 

 

 

 

 

 

Average throughput volume1

 

2,604

2,440

 

2,675

2,588

 

1   Throughput volume represents mainline system deliveries to the United States midwest and eastern Canada.

 

Average Exchange Rate

 

 

 

Three months ended

 

Six months ended

 

 

June 30,

 

June 30,

 

 

2017

2016

 

2017

2016

 

 

 

 

 

 

 

Average Exchange Rate (U.S. dollar to Canadian dollar)

 

1.34

1.29

 

1.33

1.33

 

Mid-Continent and Gulf Coast

Mid-Continent and Gulf Coast adjusted EBIT decreased for the three and six months ended June 30, 2017, compared with the corresponding 2016 period, primarily due to lower contributions from Flanagan South Pipeline (Flanagan South) and the absence of adjusted EBIT from the Ozark Pipeline that was sold in the first quarter of 2017. The decrease in adjusted EBIT was partially offset by a higher Average Exchange Rate in the second quarter of 2017, compared with the corresponding 2016 period.

 

Adjusted EBIT reported by Flanagan South in the first half of 2017 was impacted by apportionments on the mainline system and by a change in treatment of deferred revenue created by take-or-pay contracts with make-up rights in the determination of adjusted EBIT. When committed shippers on Flanagan South are unable to fulfill their volume commitments due to apportionment, they are provided with temporary relief to make up those volumes during the course of their contracts or the apportioned volumes are added on to the end of the contract term. Due to upstream mainline apportionment, committed shippers on Flanagan South were provided higher apportionment relief in the first half of 2017, compared with the first half of 2016, which resulted in lower contractual cash payments from these shippers. For the purposes of adjusted EBIT, prior to January 1, 2017, the Company reflected contributions from these contracts rateably over the life of the contract, consistent with contractual cash payments under the contract. Effective January 1, 2017, for the purposes of determining adjusted EBIT, the Company discontinued this treatment.

 

Excluding the impact of foreign exchange translation to Canadian dollars, Mid-Continent and Gulf Coast adjusted EBIT was US$95 million and US$185 million for the three and six months ended June 30, 2017, respectively, compared with US$125 million and US$257 million for the three and six months ended June 30, 2016.

 

As noted above, partially offsetting the three and six months ended June 30, 2017 decrease in adjusted EBIT was the favourable effect of translating United States dollar earnings at a higher Average Exchange Rate in the second quarter of 2017, compared with the corresponding 2016 period. Similar to Lakehead System, a portion of Mid-Continent and Gulf Coast United States dollar EBIT is hedged as part of the Company’s enterprise-wide financial risk management program, and realized gains and losses from the derivative instruments used to hedge foreign exchange risk arising from the Company’s investment in United States businesses are reported within Eliminations and Other. For further details refer to Eliminations and Other.

 

Express-Platte System

The Express-Platte pipeline system, an approximate 2,736 kilometre (1,700 mile) crude oil transportation system, which begins in Hardisty, Alberta, and terminates in Wood River, Illinois, is comprised of both the Express and Platte crude oil pipelines and crude oil storage of approximately 5.6 million barrels. The Express pipeline carries crude oil to United States refining markets in the Rockies area, including Montana, Wyoming, Colorado and Utah. The Platte pipeline, which interconnects with the Express pipeline in Casper, Wyoming, transports crude oil predominantly from the Bakken shale and western Canada to refineries in the Midwest. The Company has a 75% indirect ownership interest in Express-Platte, through its investment in SEP.

 

22



 

Express capacity is typically committed under long-term take-or-pay contracts with shippers. A small portion of Express capacity and all of the Platte capacity is used by uncommitted shippers who pay only for the pipeline capacity they actually use in a given month.

 

Express-Platte is exposed to the same business risks as the Company’s other Liquids Pipelines assets as discussed in Enbridge’s MD&A for the year ended December 31, 2016.

 

Results of Operations

Express-Platte adjusted EBIT for the three and six months ended June 30, 2017, reflects results of operations since the completion of the Merger Transaction on February 27, 2017.

 

When compared to pre-Merger results from the prior year, Express-Platte results include higher crude oil transportation revenues due to higher uncommitted volumes on the Express pipeline, higher tariff rates on the Express pipeline due to annual escalations, and higher volumes from the Express Enhancement expansion project placed into service in October 2016. These higher revenues were partially offset by higher power costs due to higher throughput.

 

Bakken System

Bakken System adjusted EBIT decreased for the three months ended June 30, 2017, compared with the corresponding 2016 period. The decrease in adjusted EBIT reflected lower rates and lower rail revenues on the United States portion of the Bakken System owned by EEP, partially offset by the positive impact of translating United States dollar earnings to Canadian dollars at a higher Average Exchange Rate in the second quarter of 2017, compared with the corresponding 2016 period.

 

Bakken System adjusted EBIT decreased for the six months ended June 30, 2017, compared with the corresponding 2016 period, primarily due the three month reasons discussed above.

 

Excluding the impact of foreign exchange translation to Canadian dollars, Bakken System adjusted EBIT was US$31 million and US$51 million for the three and six months ended June 30, 2017, respectively, compared with US$36 million and US$73 million for the corresponding 2016 periods. The decrease in adjusted EBIT for the three and six months ended June 30, 2017, for the United States portion of the Bakken System was attributable to lower surcharge revenues as certain surcharge rates expired effective December 31, 2016.

 

As noted above, partially offsetting the three and six months ended June 30, 2017 decrease in adjusted EBIT was the favourable effect of translating United States dollar earnings at a higher Average Exchange Rate in the second quarter of 2017, compared with the corresponding 2016 period. Similar to Lakehead System, a part of the United States portion of the Bakken System United States dollar EBIT is hedged under the Company’s enterprise-wide financial risk management program, and realized gains and losses from the derivative instruments used to hedge foreign exchange risk arising from the Company’s investment in United States businesses are reported within Eliminations and Other. For further details refer to Eliminations and Other.

 

Feeder Pipelines and Other

Feeder Pipelines and Other adjusted EBIT decreased for the three and six months ended June 30, 2017, compared with the corresponding 2016 periods, reflecting the absence of EBIT from the South Prairie Region assets that were sold in December 2016.

 

23



 

GAS PIPELINES AND PROCESSING

Earnings Before Interest and Income Taxes

 

 

 

 

Three months ended

 

Six months ended

 

 

June 30,

 

June 30,

 

 

2017

2016

 

2017

2016

(millions of Canadian dollars)

 

 

 

 

 

 

US Gas Transmission1

 

567

-

 

774

-

Canadian Midstream2

 

52

28

 

103

49

Alliance Pipeline

 

43

47

 

100

96

US Midstream3,4

 

(17)

5

 

(24)

4

Other5

 

22

10

 

50

28

Adjusted earnings before interest and income taxes

 

667

90

 

1,003

177

US Gas Transmission - inspection, repair and other costs

 

(14)

-

 

(16)

-

US Gas Transmission - project development and transaction costs

 

(1)

-

 

(3)

-

Canadian Midstream - project development and transaction costs

 

-

-

 

(1)

-

Canadian Midstream - Grizzly Valley flood

 

7

-

 

7

-

Alliance Pipeline - changes in unrealized derivative fair value gains

 

3

-

 

5

12

US Midstream - changes in unrealized derivative fair value gains/(loss)

 

14

(59)

 

22

(97)

US Midstream - assets impairment loss

 

-

(11)

 

-

(11)

US Midstream - make-up rights adjustment

 

-

(1)

 

-

(1)

Other - DCP Midstream mark-to-market adjustment

 

6

-

 

4

-

Earnings before interest and income taxes

 

682

19

 

1,021

80

 

1       Includes adjusted EBIT from US Gas Transmission since the completion of the Merger Transaction on February 27, 2017. For additional information, refer to Merger with Spectra Energy.

2       Includes adjusted EBIT from British Columbia Pipeline & Field Services, Spectra Canadian Midstream, Maritimes & Northeast Canada (M&N Canada) and certain other gas pipeline, gathering and storage assets since the completion of the Merger Transaction on February 27, 2017.

3       Includes adjusted EBIT from DCP Midstream since the completion of the Merger Transaction on February 27, 2017.

4       Effective January 1, 2017, adjusted EBIT from Aux Sable, which is comprised of Enbridge’s equity interest in Aux Sable US, Aux Sable Midstream US and Aux Sable Canada, has been grouped with US Midstream. Comparative amounts have been reclassified to facilitate comparison.

5       Effective January 1, 2017, adjusted EBIT from Vector Pipeline and Enbridge Offshore Pipelines (Offshore) have been grouped with Other. Comparative amounts have been reclassified to facilitate comparison.

 

Additional details on items impacting Gas Pipelines and Processing EBIT include:

 

·                  US Midstream EBIT for each period reflects changes in unrealized fair value gains and losses on derivative financial instruments used to risk manage commodity price exposures.

 

US Gas Transmission

The assets that comprise US Gas Transmission were acquired through the Merger Transaction and consist of natural gas transmission and storage assets that are held through SEP. The following indirect ownership interests are reported in this business segment: 75% of Texas Eastern, 68% of Algonquin, 75% of East Tennessee Natural Gas, 59% of M&N U.S., 38% of Gulfstream, and certain other gas pipeline, gathering and storage assets. The US Gas Transmission business primarily provides transmission, storage and gathering of natural gas through interstate pipeline systems for customers in various regions of the midwestern, northeastern and southern United States and in Canada. Demand on the natural gas pipeline and storage systems is seasonal, with the highest throughput occurring during colder periods in the first and fourth quarters, and storage injections occurring primarily during the summer periods.

 

24



 

The Texas Eastern natural gas transmission system extends approximately 2,735 kilometres (1,700 miles) from producing fields in the Gulf Coast region of Texas and Louisiana to Ohio, Pennsylvania, New Jersey and New York and includes both onshore and offshore pipelines, compressor stations and three storage facilities. Texas Eastern is also connected to four affiliated storage facilities that are partially or wholly-owned by other entities within the US Gas Transmission business.

 

The Algonquin natural gas transmission system connects with Texas Eastern’s facilities in New Jersey and extends approximately 402 kilometres (250 miles) through New Jersey, New York, Connecticut, Rhode Island and Massachusetts where it connects to M&N U.S. The system consists of approximately 1,819 kilometres (1,130 miles) of pipeline with associated compressor stations.

 

East Tennessee’s natural gas transmission system crosses Texas Eastern’s system at two locations in Tennessee and consists of two mainline systems totalling approximately 2,414 kilometres (1,500 miles) of pipeline in Tennessee, Georgia, North Carolina and Virginia, with associated compressor stations. East Tennessee has a LNG storage facility in Tennessee and also connects to the Saltville storage facilities in Virginia.

 

M&N U.S., which is owned 78% by Enbridge, is an approximately 563 kilometre (350 mile) mainline interstate natural gas transmission system, including associated compressor stations, which extends from the border of Canada near Baileyville, Maine to northeastern Massachusetts. M&N U.S. is connected to the Canadian portion of the Maritimes & Northeast Pipeline system, M&N Canada (see Gas Pipelines and Processing – Canadian Midstream).

 

Gulfstream is an approximately 1,199 kilometre (745 mile) interstate natural gas transmission system, with associated compressor stations, operated jointly by SEP and The Williams Companies, Inc. (Williams). Gulfstream transports natural gas from Mississippi, Alabama, Louisiana and Texas, crossing the Gulf of Mexico to markets in central and southern Florida. Gulfstream is owned 50% directly by SEP and 50% by affiliates of Williams and is accounted for under the equity method of accounting.

 

Transmission and storage services are generally provided under firm agreements where customers reserve capacity in pipelines and storage facilities. The vast majority of these agreements provide for fixed reservation charges that are paid monthly regardless of the actual volumes transported on the pipelines or injected or withdrawn from the Company’s storage facilities, plus a small variable component that is based on volumes transported, injected or withdrawn, which is intended to recover variable costs.

 

Interruptible transmission and storage services are also provided where customers can use capacity if it is available at the time of the request. Interruptible revenues depend on the amount of volumes transported or stored and the associated rates for this interruptible service. Storage operations also provide a variety of other value-added services including natural gas parking, loaning and balancing services to meet customers’ needs.

 

Business Risks

The risks identified below are specific to US Gas Transmission. General risks that affect the entire Company are described under Risk Management and Financial Instruments – General Business Risks in Enbridge’s MD&A for the year ended December 31, 2016.

 

25



 

Asset Utilization

Gas supply and demand dynamics continue to change as a result of the development of non-conventional shale gas supplies. The increase in natural gas supply has resulted in declines in the price of natural gas in North America. As a result, a shift occurred to extraction of gas in richer, “wet” gas areas with higher NGL content which depressed activity in “dry” fields. This, in turn, has contributed to a resulting oversupply of pipeline takeaway capacity in some areas.

 

Seasonal Price Spreads

The supply increase has also had a negative impact on the seasonal price spreads historically seen between the summer and winter months. The value of storage assets and contracts has declined in recent years, negatively affecting the results from the Company’s storage facilities.

 

Economic Regulation

US Gas Transmission is subject to laws and regulations at the federal and state levels. Regulations applicable to the natural gas transmission and storage industries have a significant effect on the nature of the businesses and the manner in which they operate. Changes to regulations are ongoing and the Company cannot predict the future course of changes in the regulatory environment or the ultimate effect that any future changes will have on its businesses.

 

Competition

The US Gas Transmission business competes with similar facilities that serve the same supply and market areas in the transmission and storage of natural gas. The principal elements of competition are location, rates, terms of service, flexibility and reliability of service. The natural gas transported in the US Gas Transmission business also competes with other forms of energy available to the Company’s customers and end-users, including electricity, coal, propane and fuel oils.

 

Results of Operations

US Gas Transmission adjusted EBIT for the three and six months ended June 30, 2017, reflected results of operations since the completion of the Merger Transaction on February 27, 2017. When compared to pre-Merger results from the prior year, US Gas Transmission’s operating results include higher earnings primarily from business expansion projects on Algonquin Gas Transmission, Sabal Trail Transmission and Texas Eastern Transmission.

 

Canadian Midstream

Upon completion of the Merger Transaction on February 27, 2017, Canadian Midstream now also includes the Western Canada Transmission & Processing businesses, which comprise British Columbia Pipeline & Field Services, Canadian Midstream, M&N Canada and certain other gas pipeline, gathering and storage assets. British Columbia Pipeline and British Columbia Field Services provide fee-based natural gas transmission and gas gathering and processing services. British Columbia Pipeline has approximately 2,816 kilometres (1,750 miles) of transmission pipeline in British Columbia and Alberta, as well as associated mainline compressor stations. The British Columbia Field Services business includes eight gas processing plants located in British Columbia associated field compressor stations and approximately 2,253 kilometres (1,400 miles) of gathering pipelines. Canadian Midstream provides similar gas gathering and processing services in British Columbia and Alberta and consists of nine natural gas processing plants and approximately 966 kilometres (600 miles) of gathering pipelines. M&N Canada is an approximately 885 kilometre (550 mile) interprovincial natural gas transmission mainline system which extends from Goldboro, Nova Scotia to the United States border near Baileyville, Maine. M&N Canada is connected to M&N U.S. – refer to US Gas Transmission. Enbridge has an approximate 78% interest in M&N Canada.

 

The majority of transportation services are provided by British Columbia Pipeline under firm agreements, which provide for fixed reservation charges that are paid monthly regardless of actual volumes transported on the pipeline, plus a small variable component that is based on volumes transported to recover variable costs. British Columbia Pipeline also provides interruptible transmission services where customers can use capacity if it is available at the time of request. Payments under these services are based on volumes transported. Natural gas gathering and processing services are provided under fee-for-service contracts.

 

26



 

Business Risks

The risks identified below are specific to the Western Canada Transmission & Processing businesses. General risks that affect the entire Company are described under Risk Management and Financial Instruments – General Business Risks in Enbridge’s MD&A for the year ended December 31, 2016.

 

Competition

Western Canada Transmission & Processing businesses compete with third-party midstream companies, producers and pipelines in the gathering, processing and transmission of natural gas. The principal elements of competition are location, rates, terms of service, and flexibility and reliability of service.

 

Asset Utilization

Western Canada Transmission & Processing businesses provide services under fee-for-service contracts and its revenues are not directly exposed to commodity price risk. However, the sustained decline in natural gas prices has reduced producer demand for both expansions of the British Columbia gas processing plants as well as renewals of existing gas processing contracts, and this trend could continue if prices remain below historical norms.

 

Results of Operations

Canadian Midstream adjusted EBIT for the three and six months ended June 30, 2017, reflected the results of operations from the new assets acquired through the Merger Transaction as described above. The three and six months ended June 30, 2017 increase in Canadian Midstream adjusted EBIT also reflected contributions from the Tupper Plants acquired in April 2016.

 

When compared to pre-Merger results from the corresponding periods in 2016, Canadian Midstream results include a decrease in firm revenue primarily as a result of shipper contract renewals at lower volumes as well as an increase in operating and maintenance costs, partially offset by higher interruptible revenues and incremental revenues from volumes that exceeded take-or-pay levels due to robust producer activity within Canadian Midstream’s footprint.

 

Alliance Pipeline

Alliance Pipeline adjusted EBIT for the three and six months ended June 30, 2017, which comprises equity earnings from the Company’s 50% equity investment in Alliance Pipeline, was comparable with the corresponding 2016 periods.

 

US Midstream

Upon completion of the Merger Transaction on February 27, 2017, US Midstream now also includes a 50% investment in DCP Midstream, which is accounted for as an equity investment. DCP Midstream gathers, compresses, treats, processes, transports, stores and sells natural gas. It also produces, fractionates, transports, stores and sells NGLs, recovers and sells condensate, and trades and markets natural gas and NGLs. Phillips 66 owns the other 50% interest in DCP Midstream.

 

DCP Midstream owns or operates assets in 17 states in the United States including approximately 102,998 kilometres (64,000 miles) of gathering and transmission pipeline, 61 natural gas processing plants and 12 fractionation facilities. In addition, DCP Midstream operates a propane wholesale marketing business and an eight-million barrel propane and butane storage facility in the northeastern United States. DCP Midstream also holds a 33.3% interest in the Sand Hills and Southern Hills NGL pipelines.

 

DCP Midstream is exposed to similar business risks as the Company’s existing US Midstream assets as disclosed in Enbridge’s MD&A for the year ended December 31, 2016.

 

Purchase, Service and Sales Agreements

DCP Midstream sells a portion of its NGLs to Phillips 66 and Chevron Phillips Chemical Company LLC (CPChem). In addition, DCP Midstream purchases NGLs from CPChem. Approximately 26% of DCP Midstream’s NGL production was committed to Phillips 66 and CPChem as at June 30, 2017, under contracts expiring in January 2019. DCP Midstream anticipates continuing to purchase and sell commodities with Phillips 66 and CPChem, in the ordinary course of business.

 

27



 

The residual natural gas, primarily methane, that results from processing raw natural gas is sold at market-based prices to marketers and end-users, including large industrial companies, natural gas distribution companies and electric utilities. DCP Midstream purchases or takes custody of substantially all of its raw natural gas from producers, principally under percentage-of-proceeds/index arrangements, keep-whole and wellhead purchase agreements and fee-based arrangements. More than 75% of the volumes of gas that are gathered and processed are under percentage-of-proceeds contracts. Percentage-of-proceeds arrangements typically result in DCP Midstream gathering, processing and selling natural gas that has been purchased from producers. The residue natural gas and NGLs are sold based on index prices from published index market prices. DCP Midstream remits to the producers either an agreed-upon percentage of the actual proceeds received by DCP Midstream or an agreed-upon percentage of the proceeds based on index-related prices or contractual recoveries, regardless of the actual amount of sales proceeds. DCP Midstream’s revenues from percentage-of-proceeds/index arrangements are directly related to the prices of natural gas, NGLs or condensate.

 

Results of Operations

US Midstream incurred a higher adjusted loss before interest and income taxes for the three and six months ended June 30, 2017, compared with the corresponding 2016 periods. The increase in adjusted loss before interest and income taxes for the three and six months ended June 30, 2017, was primarily attributable to lower volumes on the Company’s US Midstream assets that are held by MEP, as a result of the continued low commodity price environment which resulted in reduced drilling by producers. Partially offsetting this negative effect was higher contributions from Aux Sable US due to increased fractionation margins, as well as a contribution from the Company’s investment in DCP Midstream that was acquired through the Merger Transaction. Post completion of the Merger Transaction, DCP Midstream contributed $23 million and $28 million to US Midstream adjusted EBIT for the three and six months ended June 30, 2017, respectively.

 

Other

Other adjusted EBIT increased for the three and six months ended June 30, 2017, compared with the corresponding 2016 periods, primarily reflecting positive contributions from Offshore as a result of an increase in transportation rates on Heidelberg Oil Pipeline and an increase in variable rate revenues on Walker Ridge Gas Gathering System.

 

GAS DISTRIBUTION

Earnings Before Interest and Income Taxes

 

 

 

 

Three months ended

 

Six months ended

 

 

June 30,

 

June 30,

 

 

2017

2016

 

2017

2016

(millions of Canadian dollars)

 

 

 

 

 

 

Enbridge Gas Distribution Inc. (EGD)

 

81

72

 

219

247

Union Gas Limited (Union Gas)1

 

79

-

 

142

-

Noverco Inc. (Noverco)

 

(13)

(5)

 

24

33

Other Gas Distribution and Storage

 

6

6

 

37

33

Adjusted earnings before interest and income taxes

 

153

73

 

422

313

EGD - (warmer)/colder than normal weather2

 

-

9

 

-

(8)

Noverco - changes in unrealized derivative fair value gains

 

-

1

 

10

-

Noverco - recognition of regulatory balances

 

-

-

 

-

17

Union Gas - employee severance and restructuring costs

 

-

-

 

(4)

-

Earnings before interest and income taxes

 

153

83

 

428

322

 

1       Includes adjusted EBIT from Union Gas since the completion of the Merger Transaction on February 27, 2017. For additional information, refer to Merger with Spectra Energy.

2       Effective January 1, 2017, the Company no longer adjusts for the impact of weather in the determination of its adjusted EBIT.

 

28



 

EGD

As EGD’s operations are rate-regulated and its revenues are directly impacted by items such as depreciation, financing charges and current income taxes, the adjusted EBIT measure for EGD is less indicative of business performance. In light of the nature of the regulated model for EGD’s business, the following supplemental adjusted earnings information is provided to facilitate an understanding of EGD’s results from operations:

 

EGD Earnings

 

 

 

Three months ended

 

Six months ended

 

 

June 30,

 

June 30,

 

 

2017

2016

 

2017

2016

(millions of Canadian dollars)

 

 

 

 

 

 

Adjusted earnings before interest and income taxes

 

81

72

 

219

247

Interest expense

 

(44)

(44)

 

(90)

(81)

Income taxes

 

4

-

 

(6)

(20)

Adjusting items in respect of:

 

 

 

 

 

 

Interest expense

 

-

-

 

1

-

Income taxes

 

-

2

 

-

(2)

Adjusted earnings

 

41

30

 

124

144

EGD - (warmer)/colder than normal weather

 

-

7

 

-

(6)

Earnings attributable to common shareholders

 

41

37

 

124

138

 

EGD adjusted earnings increased in the second quarter of 2017, compared with the corresponding 2016 period, primarily due to lower employee and pension related costs, and higher distribution charges, partially offset by warmer weather.

 

EGD adjusted earnings decreased in the first half of 2017, compared with the corresponding 2016 period. The increase in the second quarter of 2017, as discussed above, was more than offset by weaker first quarter results. First quarter results in 2017 decreased, compared with the corresponding 2016 period, primarily due to higher earnings sharing in 2017, higher depreciation expense resulting from a higher overall asset base and lower capitalized interest due to the completion of the Greater Toronto Area project in March 2016.

 

Adjusted earnings for EGD was also lower for the six months ended June 30, 2017, relative to the comparable period in 2016, as a result of a change in practice with respect to weather normalization. Prior to January 1, 2017, the impacts of warmer/colder than normal weather were removed for the purposes of EGD adjusted earnings. Effective January 1, 2017, the Company discontinued this practice, and as such, EGD adjusted earnings reflected lower distribution revenues due to the impacts of warmer than normal weather during the three and six months ended June 30, 2017. If the Company had continued with the above noted weather normalization treatment, EGD adjusted earnings would have increased by $2 million and $23 million, for the three and six months ended June 30, 2017, respectively.

 

Union Gas

Union Gas is a major Canadian natural gas storage, transmission and distribution company based in Ontario with over 100 years of operations and service to customers. The distribution business serves approximately 1.5 million residential, commercial and industrial customers in more than 400 communities across northern, southwestern and eastern Ontario. Union Gas’ storage and transmission business offers storage and transmission services to customers at the Dawn Hub, the largest integrated underground storage facility in Canada and one of the largest in North America. It offers customers an important link in the movement of natural gas from western Canada and United States supply basins to markets in central Canada and the northeast United States.

 

Union Gas’ distribution system consists of approximately 64,374 kilometres (40,000 miles) of main and service pipelines. Union Gas’ underground natural gas storage facilities have a working capacity of approximately 165 billion cubic feet in 25 underground facilities located in depleted gas fields. Its transmission system consists of approximately 4,828 kilometres (3,000 miles) of high pressure pipeline and associated mainline compressor stations.

 

29



 

As with EGD, Union Gas’ distribution system is regulated by the Ontario Energy Board (OEB) and is subject to regulation in a number of areas, including rates. Union Gas provides its infranchise customers with regulated distribution, transmission and storage services and also provides unregulated natural gas storage and regulated transmission services for other utilities and energy market participants, including large natural gas transmission and distribution companies. A substantial amount of Union Gas’ annual transportation and storage revenue is generated by fixed demand charges.

 

Incentive Regulation Framework

Union Gas’ distribution rates are set under a five-year incentive regulation framework. The incentive regulation framework establishes new rates at the beginning of each year through the use of a pricing formula rather than through the examination of revenue and cost forecasts. The framework allows for:

·                  annual inflationary rate increases, offset by a productivity factor of 60% of inflation, such that the annual net rate escalator in each year is 40% of inflation;

·                  rate increases or decreases in the small volume customer classes where average use declines or increases;

·                  certain adjustments to rates;

·                  the continued pass-through of gas commodity, upstream transportation and demand side management costs;

·                  the additional pass-through of costs associated with major capital investments and certain fuel variances;

·                  an allowance for unexpected cost changes that are outside of management’s control;

·                  equal sharing of tax changes between Union Gas and customers; and

·                  an earnings sharing mechanism that permits Union Gas to fully retain the return on equity from utility operations up to 9.93%, share 50% of any earnings between 9.93% and 10.93% with customers, and share 90% of any earnings above 10.93% with customers. In October 2016, Union Gas filed an application with the OEB for new rates effective January 1, 2017, pursuant to the incentive regulation framework. In December 2016, the OEB approved the application on an interim basis with an implementation date of January 1, 2017, to be included in the Quarterly Rate Adjustment Mechanism. A final rate order is expected after the OEB completes its review of Union Gas’ Cap and Trade Compliance Plan.

 

Cap and Trade

Similar to EGD, Union Gas is subject to the requirements of the Government of Ontario’s Cap and Trade program, which became effective January 1, 2017. Refer to Gas Distribution – Enbridge Gas Distribution Inc. – Cap and Trade in Enbridge’s MD&A for the year ended December 31, 2016, for more information on this program. In November 2016, Union Gas filed its 2017 Compliance Plan and the OEB issued an interim rate order approving the associated Cap and Trade costs for recovery from customers effective January 1, 2017. The OEB will complete its review of Union Gas’ 2017 Compliance Plan and approve the final rates in 2017.

 

Business Risks

Union Gas is subject to substantially the same business risks as Enbridge’s other gas distribution assets as disclosed in Enbridge’s MD&A for the year ended December 31, 2016.

 

Results of Operations

Union Gas’ adjusted EBIT for the three and six months ended June 30, 2017, reflects its results of operations since the completion of the Merger Transaction on February 27, 2017.

 

Union Gas’ results benefitted mainly from higher transportation revenue from the Dawn-Parkway expansion project, partially offset by lower usage due to warmer weather in the first half of 2017.

 

30



 

As Union Gas’ operations are rate-regulated and its revenues are directly impacted by items such as depreciation, financing charges and current income taxes, the adjusted EBIT measure for Union Gas is less indicative of business performance. In light of the nature of the regulated model for Union Gas’ business, the following supplemental adjusted earnings information is provided to facilitate an understanding of Union Gas’ results from operations:

 

Union Gas Earnings1

 

 

 

Three months ended

 

Six months ended

 

 

June 30, 2017

 

June 30, 2017

(millions of Canadian dollars)

 

 

 

 

Adjusted earnings before interest and income taxes

 

79

 

142

Interest expense

 

(41)

 

(56)

Income taxes

 

(4)

 

11

Adjusting items in respect of:

 

 

 

 

Income taxes

 

-

 

(1)

Earnings attributable to noncontrolling interests

 

-

 

(1)

Adjusted earnings

 

34

 

95

Union Gas - Employee severance and restructuring costs

 

-

 

(3)

Earnings attributable to common shareholders

 

34

 

92

 

1       Includes adjusted earnings generated by Union Gas since the completion of the Merger Transaction on February 27, 2017.

 

Similar to EGD, Union Gas’ adjusted earnings for each period include the impact of warmer/colder than normal weather in their franchise area. If Union Gas made an adjustment for warmer than normal weather, adjusted earnings would have increased by $7 million and $9 million, for the three and six months ended June 30, 2017, respectively.

 

GREEN POWER AND TRANSMISSION

Earnings Before Interest and Income Taxes

 

 

 

 

Three months ended

 

Six months ended

 

 

June 30,

 

June 30,

 

 

2017

2016

 

2017

2016

(millions of Canadian dollars)

 

 

 

 

 

 

Green Power and Transmission

 

51

40

 

101

88

Adjusted earnings before interest and income taxes

 

51

40

 

101

88

Green Power and Transmission - changes in unrealized derivative fair value gains

 

-

1

 

-

2

Earnings before interest and income taxes

 

51

41

 

101

90

 

Green Power and Transmission adjusted EBIT increased for the three and six months ended June 30, 2017, compared with the corresponding 2016 periods. The increase in adjusted EBIT reflected stronger Canadian wind resources in the first half of 2017 and stronger United States wind resources in the second quarter of 2017.

 

31



 

ENERGY SERVICES

Earnings Before Interest and Income Taxes

 

 

 

 

Three months ended

 

Six months ended

 

 

June 30,

 

June 30,

 

 

2017

2016

 

2017

2016

(millions of Canadian dollars)

 

 

 

 

 

 

Energy Services

 

(3)

47

 

(8)

48

Adjusted earnings/(loss) before interest and income taxes

 

(3)

47

 

(8)

48

Energy Services - changes in unrealized derivative fair value gains/(loss)

 

(15)

(54)

 

146

(61)

Earnings/(loss) before interest and income taxes

 

(18)

(7)

 

138

(13)

 

Following are additional details on items impacting Energy Services EBIT:

 

·                 Energy Services EBIT for each period reflects changes in unrealized fair value gains and losses related to the revaluation of financial derivatives used to manage the profitability of transportation and storage transactions and exposure to movements in commodity prices on the value of inventory.

 

Energy Services adjusted EBIT for the three and six months ended June 30, 2017, reflected compressed location and quality differentials in certain markets, lower refinery demand for certain products and fewer opportunities to achieve profitable margins on facilities where the Company holds capacity obligations. Adjusted EBIT from Energy Services is dependent on market conditions and results achieved in one period may not be indicative of results to be achieved in future periods.

 

ELIMINATIONS AND OTHER

Earnings Before Interest and Income Taxes

 

 

 

Three months ended

 

Six months ended

 

 

June 30,

 

June 30,

 

 

2017

2016

 

2017

2016

(millions of Canadian dollars)

 

 

 

 

 

 

Operating and administrative

 

(38)

(19)

 

(78)

(34)

Realized foreign exchange derivative loss

 

(70)

(64)

 

(142)

(151)

Other

 

15

-

 

22

16

Adjusted loss before interest and income taxes

 

(93)

(83)

 

(198)

(169)

Changes in unrealized derivative fair value gains

 

184

38

 

255

405

Unrealized intercompany foreign exchange gains/(loss)

 

(7)

5

 

(14)

(55)

Project development and transaction costs

 

(46)

-

 

(195)

-

Employee severance and restructuring costs

 

(79)

(8)

 

(204)

(8)

Earnings/(loss) before interest and income taxes

 

(41)

(48)

 

(356)

173

 

Items impacting Eliminations and Other EBIT include:

 

·                  Project development and transaction costs incurred in 2017 in relation to the Merger Transaction. For additional information, refer to Merger with Spectra Energy.

 

Included in Eliminations and Other adjusted loss before interest and income taxes for the three and six months ended June 30, 2017, was a realized loss of $70 million and $142 million, respectively, compared with $64 million and $151 million for the corresponding 2016 periods. The realized loss related to settlements under the Company’s foreign exchange risk management program. The Company targets to hedge 80% or more of anticipated consolidated United States dollar denominated earnings from its United States operations utilizing foreign exchange derivative contracts with the objective of enhancing the predictability of its Canadian dollar earnings.

 

32



 

Supplemental information related to the foreign exchange risk management program for the three and six months ended June 30, 2017 and 2016 is provided below:

 

 

 

Three months ended

 

Six months ended

 

 

June 30,

 

June 30,

 

 

2017

2016

 

2017

2016

(millions of U.S. dollars, except exchange rates)

 

 

 

 

 

 

Foreign currency derivatives realized - notional amount

 

320

261

 

584

522

Average hedge rate

 

1.12

1.04

 

1.09

1.04

Average Exchange Rate (U.S. dollar to Canadian dollar)

 

1.34

1.29

 

1.33

1.33

 

As the hedged rate was lower than the Average Exchange Rate in each of the three and six-month periods in 2017 and 2016, the Company recognized a realized hedge loss in each of these periods. The realized hedge loss for the three months ended June 30, 2017, was greater than the comparative 2016 period due to a higher notional amount of derivatives, partially offset by a lower unfavourable spread between the Average Exchange Rate and hedged rate. The realized hedge loss for the six months ended June 30, 2017, was less than the comparative 2016 period due to lower unfavourable spread between the Average Exchange Rate and hedged rate. The realized loss in Eliminations and Other partially offsets the positive effect of translating the earnings performance of United States dollar denominated businesses at the Average Exchange Rate which is reflected in the reported EBIT of the applicable business segments.

 

Realized gains and losses on this hedging program are reported in their entirety within Eliminations and Other as the Company manages the foreign exchange risk of its United States businesses at an enterprise-wide level. Gains and losses arising on settlements of foreign exchange derivatives hedging transactional exposure arising from foreign denominated revenues or expenses within the Company’s Canadian businesses are captured at the business level and reported as part of the EBIT of the applicable segment. For example, gains and losses on hedges of the Canadian Mainline’s United States denominated revenue are reported as part of the EBIT from Canadian Mainline.

 

The increase in adjusted loss before interest and income taxes reported within Eliminations and Other reflects higher unallocated corporate costs which primarily results from the Merger Transaction, partially offset by synergies achieved thus far on integration of corporate functions.

 

LIQUIDITY AND CAPITAL RESOURCES

 

The maintenance of financial strength and flexibility is fundamental to Enbridge’s growth strategy, particularly in light of the significant level of capital projects currently secured or under development. Access to timely funding from capital markets could be limited by factors outside Enbridge’s control, including but not limited to financial market volatility resulting from economic and political events both inside and outside North America. To mitigate such risks, the Company actively manages financial plans and funding strategies to ensure it maintains sufficient liquidity to meet routine operating and future capital requirements. In the near term, the Company generally expects to utilize cash from operations and capital markets issuances, commercial paper and/or credit facility draws to fund liabilities as they become due, finance capital expenditures, fund debt retirements and pay common and preference share dividends. The Company targets to maintain liquidity through securement of committed credit facilities with a diversified group of banks and financial institutions sufficient to enable it to fund all anticipated requirements for approximately one year without accessing the capital markets.

 

The Company’s financing plan is regularly updated to reflect evolving capital requirements and financial market conditions and incorporates a variety of potential sources of debt and equity funding alternatives, including utilization of its sponsored vehicles, EEP, the Fund Group and SEP.

 

CAPITAL MARKET ACCESS

The Company and its self-funding subsidiaries ensure ready access to capital markets, subject to market conditions, through maintenance of shelf prospectuses that allow for issuance of long-term debt, equity and other forms of long-term capital when market conditions are attractive.

 

33



 

SEP has US$1.8 billion of capital expansion spending planned in 2017, which is expected to be funded through a combination of debt, equity issued primarily through its “at the market” program and return of capital at the project level.

 

Bank Credit and Liquidity

To ensure ongoing liquidity and to mitigate the risk of capital market disruption, Enbridge maintains ready access to funds through securement of committed bank credit facilities and it actively manages its bank funding sources to optimize pricing and ensure flexibility. The following table provides details of the Company’s committed credit facilities as at June 30, 2017 and December 31, 2016.

 

 

 

June 30, 2017

 

Maturity

Total

 

 

 

Dates

Facilities

Draws1

Available

(millions of Canadian dollars)

 

 

 

 

Enbridge

2018-2022

6,826

5,686

1,140

Enbridge (U.S.) Inc.

2018-2019

3,805

2,216

1,589

EEP

2019-2020

3,409

1,994

1,415

EGD

2018

1,017

684

333

Enbridge Income Fund

2019

1,500

771

729

Enbridge Pipelines (Southern Lights) L.L.C.

2018

26

-

26

Enbridge Pipelines Inc.

2018

3,000

1,105

1,895

Enbridge Southern Lights LP

2018

5

-

5

Spectra Energy Capital, LLC2

2021

1,299

-

1,299

Spectra Energy Partners2

2021

3,247

1,721

1,526

Westcoast2

2021

400

-

400

Union Gas2

2021

700

300

400

Total committed credit facilities

 

25,234

14,477

10,757

 

1       Includes facility draws, letters of credit and commercial paper issuances that are back-stopped by the credit facility.

2       Committed credit facility acquired as part of the merger with Spectra Energy. For additional information, refer to Merger with Spectra Energy.

 

During the second quarter of 2017, the Company completed the following term debt offerings:

 

·                  $1.2 billion of unsecured medium-term notes with maturity dates ranging from 2022 to 2044 and fixed interest rates ranging from 3.2% to 4.6%.

·                  $750 million of unsecured floating rate notes which mature in 2019 and carry an interest rate equal to the three-month banker’s acceptance rate plus 59 basis points.

·                  US$500 million of unsecured floating rate notes which mature in 2020 and carry an interest rate equal to the three-month London Interbank Offered Rate (LIBOR) rate plus 70 basis points.

 

During the second quarter of 2017, SEP issued US$400 million of unsecured floating rate notes which mature in 2020 and carry an interest rate equal to the three-month LIBOR rate plus 70 basis points.

 

On July 7, 2017, Enbridge completed an offering of aggregated US$1.4 billion of senior unsecured notes (the Notes). The Notes consisted of two US$700 million tranches with fixed interest rates of 2.9% and 3.7%, and mature in five and 10 years, respectively. Approximately US$1.2 billion of the net proceeds from the Notes were used to pay for the redemption of the tendered notes described below.

 

On July 14, 2017, Enbridge also completed an offering of US$1.0 billion of fixed-to-floating rate subordinated notes. These notes carry a fixed interest rate of 5.5% for the initial 10 years with a floating rate thereafter. These notes have a maturity of 60 years and are callable after 10 years.

 

34



 

The company also completed the following tender offers. On July 7, 2017, Enbridge and Spectra Energy Capital, LLC (Spectra Capital) completed a cash tender offer to purchase the principal amount of Spectra Capital’s outstanding 8.0% senior unsecured notes due 2019. The principal amount tendered and accepted was US$267 million. Spectra Capital paid the consenting note holders an aggregate cash consideration of US$310 million. On July 13, 2017, pursuant to a cash tender offer, Spectra Capital purchased the principal amount of its outstanding senior unsecured notes carrying interest rates ranging from 3.3% to 7.5%, with maturities ranging from one to 21 years. The principal amount tendered and accepted was US$761 million. Spectra Capital paid the consenting note holders an aggregate cash consideration of US$857 million.

 

During the first quarter of 2017, the Company continued to diversify its access to funding through the establishment of a term credit facility with a syndicate of Asian banks for a total commitment of $239 million. As at June 30, 2017, the Company maintained three term credit facilities with syndicates of Asian banks, which were fully drawn upon and provided a cost-effective source of term debt financing when compared with the cost of term debt financing in the North American public markets available at the time.

 

In addition to the committed credit facilities noted above, the Company also has $556 million (December 31, 2016 - $335 million) of uncommitted demand credit facilities, of which $148 million (December 31, 2016 - $177 million) were unutilized as at June 30, 2017.

 

The Company’s net available liquidity of $11,783 million as at June 30, 2017, was inclusive of $2,028 million of unrestricted cash and cash equivalents and net of bank indebtedness of $1,002 million as reported on the Consolidated Statements of Financial Position.

 

The Company’s credit facility agreements and term debt indentures include standard events of default and covenant provisions whereby accelerated repayment and/or termination of the agreements may result if the Company were to default on payment or violate certain covenants. As at June 30, 2017, the Company was in compliance with all debt covenants and expects to continue to comply with such covenants.

 

Strong growth in internal cash flow, ready access to liquidity from diversified sources and a stable business model have enabled Enbridge to manage its credit profile. The Company actively monitors and manages key financial metrics with the objective of sustaining investment grade credit ratings from the major credit rating agencies and ongoing access to bank funding and term debt capital on attractive terms. Key measures of financial strength that are closely managed include the ability to service debt obligations from operating cash flow and the ratio of debt to total capital. As at June 30, 2017, the Company’s debt capitalization ratio was 47.9%, compared with 62.1% as at December 31, 2016. The improvement in the ratio reflected an increase in equity as a result of the Merger Transaction.

 

Following the close of the Merger Transaction, the Company’s credit ratings were affirmed as follows:

 

·                  DBRS Limited confirmed the Company’s issuer rating and medium-term notes and unsecured debentures rating of BBB (high), fixed-to-floating subordinated notes rating of BBB (low), preference share rating of Pfd-3 (high) and commercial paper rating of R-2 (high), and changed their rating outlook from under review with developing implications to stable.

·                  Moody’s Investor Services, Inc. affirmed the Company’s issuer rating and senior unsecured debt rating of Baa2, subordinated rating of Ba1, preference share rating of Ba1 and commercial paper rating of P-2, and retained a negative outlook.

·                  Standard & Poor’s Rating Services (S&P) affirmed the Company’s corporate credit rating and senior unsecured debt rating of BBB+, preference share rating of P-2 (low) and commercial paper rating of A-1 (low), and reaffirmed a stable outlook. S&P also affirmed the Company’s global overall short-term rating of A-2.

·                  In June 2017, the Company obtained Fitch long-term issuer default rating and senior unsecured debt rating of BBB+, preference share rating of BBB-, junior subordinated note rating of BBB-, and short-term and commercial paper rating of F2 with a stable rating outlook.

 

35



 

Enbridge’s solid investment grade credit ratings are a reflection of the low risk nature of its underlying assets; limited exposure to commodity prices and volume risk; its project execution track record; strong dividend coverage; and substantial standby liquidity. The Company believes that it continues to have ample access to capital markets in both Canada and the United States to adequately fund the execution of its growth capital program.

 

There are no material restrictions on the Company’s cash with the exception of the restricted cash of $100 million, which includes EGD’s and Union Gas’ receipt of cash from the Government of Ontario to fund its Green Investment Fund program. In addition, the Company’s restricted cash includes cash collateral and amounts for specific shipper commitments. Cash and cash equivalents held by EEP, the Fund Group and SEP are generally not readily accessible by Enbridge until distributions are declared and paid by these entities, which occurs quarterly for EEP and SEP, and monthly for the Fund Group. Further, cash and cash equivalents held by certain foreign subsidiaries may not be readily accessible for alternative uses by Enbridge.

 

Excluding current maturities of long-term debt, the Company had a negative working capital position as at June 30, 2017. The major contributing factor to the negative working capital position was the ongoing funding of the Company’s growth capital program.

 

To address this negative working capital position, the Company maintains significant liquidity in the form of committed credit facilities and other sources as previously discussed, which enable the funding of liabilities as they become due. As previously noted, as at June 30, 2017, the Company’s net available liquidity totalled $11,783 million (December 31, 2016 - $14,274 million). It is anticipated that any current maturities of long-term debt will be refinanced upon maturity.

 

SOURCES AND USES OF CASH

 

 

 

Three months ended

 

Six months ended

 

 

June 30,

 

June 30,

 

 

2017

2016

 

2017

2016

(millions of Canadian dollars)

 

 

 

 

 

 

Operating activities

 

2,033

1,370

 

3,710

3,231

Investing activities

 

(2,368)

(2,080)

 

(5,891)

(3,932)

Financing activities

 

531

230

 

2,124

981

Effect of translation of foreign denominated cash and cash equivalents

 

(23)

2

 

(32)

(38)

Increase/(decrease) in cash and cash equivalents

 

173

(478)

 

(89)

242

 

Significant sources and uses of cash for the three and six months ended June 30, 2017 and June 30, 2016 are summarized below:

 

Operating Activities

 

·                  The Company’s cash flows from operating activities increased by $663 million and $479 million for the three and six months ended June 30, 2017, respectively, relative to the corresponding periods of 2016. The cash growth delivered by operations reflect operating factors discussed under Non-GAAP Measures – Adjusted EBIT and Non-GAAP Measures – Adjusted Earnings.

·                  For the three and six months ended June 30, 2017, partially offsetting the increase in cash flows from operating activities are transaction and transition costs in connection with the Merger Transaction, as well as employee severance costs in relation to the Company’s enterprise-wide reduction of workforce.

·                  Changes in operating assets and liabilities included within operating activities were $318 million (2016 - $64 million) for the three months ended June 30, 2017 and $555 million (2016 - $195 million) for the six months ended June 30, 2017. Enbridge’s operating assets and liabilities fluctuate in the normal course due to various factors, including fluctuations in commodity prices and activity levels within the Energy Services and Gas Distribution segments, the timing of tax payments, as well as timing of cash receipts and payments. In addition, cap and trade regulation in the Province of Ontario went into effect on January 1, 2017, which resulted in recognition of a cap and trade compliance liability within the Gas Distribution segment in the first half of 2017.

 

36



 

Investing Activities

 

·                  Cash used in investing activities increased by $288 million and $1,959 million for the three and six months ended June 30, 2017, respectively, relative to the corresponding periods of 2016. The increase was primarily attributable to increased investment in equity investments. During the first half of 2017, the Company paid cash consideration of $2.0 billion (US $1.5 billion) for the acquisition of an interest in the Bakken Pipeline System. In addition, the Company also made an equity investment of $0.5 billion in connection with its 50% interest in the Hohe See Project.

·                  This increase was also attributable to the Company’s continued execution of its growth capital program which is further described in Growth Projects – Commercially Secured Projects. The timing of project approval, construction and in-service dates impacts the timing of cash requirements.

·                  Also, during the first half of 2017, the Company’s investment in intangible assets in relation to the cap and trade regulation was higher compared with the corresponding 2016 period.

·                  The above increase in cash usage was partially offset by cash acquired in the Merger Transaction in the first quarter of 2017, as well as proceeds from the disposition of the Ozark Pipeline and Sandpiper assets in the first half of 2017. In the first quarter of 2016, the Company paid a deposit of $54 million in connection with the acquisition of the Tupper Plants. In addition, in the second quarter of 2017, the Company also received a cash reimbursement of capital expenditure from a natural gas producer relating to a suspended pipeline project.

 

Financing Activities

 

·                  Net cash generated from financing activities increased by $301 million and $1,143 million for the three and six months ended June 30, 2017, respectively, relative to the corresponding periods of 2016. During the first half of 2017, the Company issued a series of medium term fixed and floating rate notes, the proceeds of which were primarily used to repay maturing term notes and to finance growth capital programs.

·                  The increase in cash generated from financing activities also reflected overall higher cash contributions from noncontrolling interests, which now include noncontrolling interests in the assets acquired through the Merger Transaction. The distribution to noncontrolling interests also increased due to the acquired assets; which were offset by the decrease in distributions resulting from the EEP strategic restructuring discussed under United States Sponsored Vehicle Strategy.

·                  The above increases in cash were partially offset by the $227 million paid to acquire all of the outstanding publicly-held common units of MEP during the second quarter of 2017, as well as higher cash received from the issuance of common shares in the first quarter of 2016, as a result of the issuance of 56 million common shares in March 2016.

·                  Finally, the Company’s common share dividend payments increased in the first half of 2017, primarily due to the increase in the common share dividend rate effective March 2017, as well as higher number of common shares outstanding as a result of the issuance of approximately 75 million common shares in 2016 and 691 million common shares issued in connection with the Merger Transaction.

 

Dividend Reinvestment and Share Purchase Plan

Participants in the Company’s Dividend Reinvestment and Share Purchase Plan receive a 2% discount on the purchase of common shares with reinvested dividends. For the three months ended June 30, 2017, dividends declared were $1,003 million (2016 - $492 million), of which $659 million (2016 - $281 million) were paid in cash and reflected in financing activities. The remaining $344 million (2016 - $211 million) of dividends declared were reinvested pursuant to the plan and resulted in the issuance of common shares rather than a cash payment. For the six months ended June 30, 2017, dividends declared were $1,551 million (2016 - $952 million), of which $1,013 million (2016 - $557 million) were paid in cash and reflected in financing activities. The remaining $538 million (2016 - $395 million) of dividends declared were reinvested pursuant to the plan and resulted in the issuance of common shares rather than a cash payment. For the three and six months ended June 30, 2017, 34.3% (2016 – 42.9%) and 34.7% (2016 – 41.5%), respectively, of total dividends declared were reinvested.

 

37



 

On August 2, 2017, the Enbridge Board of Directors declared the following quarterly dividends. All dividends are payable on September 1, 2017, to shareholders of record on August 15, 2017.

 

Common Shares

 

$0.61000

Preference Shares, Series A

 

$0.34375

Preference Shares, Series B1

 

$0.21340

Preference Shares, Series C2

 

$0.18600

Preference Shares, Series D

 

$0.25000

Preference Shares, Series F

 

$0.25000

Preference Shares, Series H

 

$0.25000

Preference Shares, Series J3

 

US$0.30540

Preference Shares, Series L

 

US$0.25000

Preference Shares, Series N

 

$0.25000

Preference Shares, Series P

 

$0.25000

Preference Shares, Series R

 

$0.25000

Preference Shares, Series 1

 

US$0.25000

Preference Shares, Series 3

 

$0.25000

Preference Shares, Series 5

 

US$0.27500

Preference Shares, Series 7

 

$0.27500

Preference Shares, Series 9

 

$0.27500

Preference Shares, Series 11

 

$0.27500

Preference Shares, Series 13

 

$0.27500

Preference Shares, Series 15

 

$0.27500

Preference Shares, Series 17

 

$0.32188

 

 

 

 

1       The quarterly dividend amount of Series B was reset to $0.21340 from $0.25000 on June 1, 2017, due to reset on every fifth anniversary thereafter.

2       The quarterly dividend amount of Series C was set at $0.18600 on June 1, 2017, due to reset on a quarterly basis thereafter.

3       The quarterly dividend amount of Series J was reset to US$0.30540 from US$0.25000 on June 1, 2017, due to reset on every fifth anniversary thereafter.

 

38



 

LEGAL AND OTHER UPDATES

 

LIQUIDS PIPELINES

Disposition of Ozark Pipeline Asset

As noted previously under Asset Monetization, on March 1, 2017, the Company sold the Ozark Pipeline to a subsidiary of MPLX LP for cash proceeds of approximately $0.3 billion (US$0.2 billion) including reimbursement of certain costs. The Ozark Pipeline, a non-core asset owned by EEP, transports crude oil from Cushing, Oklahoma to Wood River, Illinois, where it delivers to a third-party refinery and interconnects with other third-party pipelines. Results of operations from the Ozark Pipeline for the period prior to its sales are reported within Liquids Pipelines – Mid-Continent and Gulf Coast.

 

Renewal of Line 5 Easement

On January 4, 2017, the Tribal Council of the Bad River Band of Lake Superior Tribe of Chippewa Indians (the Band) issued a press release indicating that the Band had passed a resolution not to renew its interest in certain Line 5 easements through the Bad River Reservation. Line 5 is included within the Company’s mainline system. The Band’s resolution calls for decommissioning and removal of the pipeline from all Bad River tribal lands and watershed and could impact the Company’s ability to operate the pipeline on the Reservation. Since the Band passed the resolution, the parties have agreed to ongoing discussions with the objective of understanding and resolving the Band’s concerns on a long-term basis.

 

Eddystone Rail Legal Matter

In February 2017, Enbridge subsidiary Eddystone Rail filed an action against several defendants in the United States District Court for the Eastern District of Pennsylvania. Eddystone Rail alleges that the defendants transferred valuable assets from Eddystone Rail’s counterparty in a maritime contract, so as to avoid outstanding obligations to Eddystone Rail. Eddystone Rail is seeking payment of compensatory and punitive damages in excess of US$140 million. Eddystone Rail’s chances of success in connection with the above noted action cannot be predicted and it is possible that Eddystone Rail may not recover any of the amounts sought. In March 2017, the defendants filed motions to dismiss on all counts. On July 19, 2017, the defendants’ motions to dismiss were denied and Eddystone Rail’s action will therefore be allowed to proceed. Results of operations from Eddystone Rail are reported within Liquids Pipelines – Feeder Pipelines and Other.

 

Dakota Access Pipeline

As noted previously under United States Sponsored Vehicle Strategy — Finalization of Bakken Pipeline System Joint Funding Agreement, the Company’s investment in the Bakken Pipeline System is inclusive of the Dakota Access Pipeline. On February 9, 2017, the Standing Rock Sioux nation filed a lawsuit with the US District Court of Appeals (Court) contesting the validity of the process used by the United States Army Corps of Engineers (Army Corps) to permit the Dakota Access Pipeline. The Standing Rock Sioux nation is requesting the Court to order the operator to shut down the pipeline until the appropriate regulatory process is completed.

 

On June 14, 2017, the Court ruled that the Army Corps failed to adequately consider the impact of an oil spill on the hunting and fishing rights of the Standing Rock Sioux nation and ordered the Army Corps to reconsider those components of its environmental analysis. The Court did not rule on whether or not the Dakota Access Pipeline should cease operations, but on June 21, 2017, the Court established a briefing schedule pursuant to which the parties to the litigation will be provided with an opportunity to submit written arguments on this issue. Final briefs must be filed by the parties in late August 2017, but it is not known when the Court will issue its ruling. However, the Dakota Access Pipeline continues to operate pending the Court’s decision on this issue.

 

Lakehead System Lines 6A and Line 6B Crude Oil Release

Line 6B Crude Oil Release

On July 26, 2010, a release of crude oil on Line 6B of EEP’s Lakehead System was reported near Marshall, Michigan.

 

As at June 30, 2017, EEP’s cumulative cost estimate for the Line 6B crude oil release remains at US$1.2 billion ($195 million after-tax attributable to Enbridge) including those costs that were considered probable and that could be reasonably estimated at June 30, 2017. Despite the efforts EEP has made to ensure the reasonableness of its estimate, there continues to be the potential for EEP to incur additional costs in connection with this crude oil release due to variations in any or all of the cost categories, including modified or revised requirements from regulatory agencies.

 

Insurance Recoveries

EEP is included in the comprehensive insurance program that is maintained by Enbridge for its subsidiaries and affiliates. As at June 30, 2017, EEP has recorded total insurance recoveries of US$547 million ($80 million after-tax attributable to Enbridge) for the Line 6B crude oil release out of the US$650 million applicable limit. Of the remaining US$103 million coverage limit, US$85 million was the subject matter of a lawsuit against one particular insurer. In March 2015, Enbridge reached an agreement with that insurer to submit the US$85 million claim to binding arbitration. On May 2, 2017, the arbitration panel issued a decision that was not favourable to Enbridge. As a result, EEP is unlikely to receive any additional insurance recoveries in connection with the Line 6B crude oil release.

 

39



 

Legal and Regulatory Proceedings

A number of United States governmental agencies and regulators have initiated investigations into the Line 6B crude oil release. One action or claim is pending against Enbridge, EEP or their affiliates in United States state courts in connection with the Line 6B crude oil release. Based on the current status of this case, the Company does not expect the outcome of this action to be material to its results of operations or financial condition.

 

Line 6B Fines and Penalties

As at June 30, 2017, EEP’s total estimated costs related to the Line 6B crude oil release include US$69 million in fines and penalties, which includes fines and penalties from the Department of Justice as discussed below.

 

Consent Decree

On May 23, 2017, the United States District Court for the Western District of Michigan, Southern Division, approved the Consent Decree. The Consent Decree is EEP’s signed settlement agreement with the United States Environmental Protection Agency (EPA) and the United States Department of Justice regarding Lines 6A and 6B crude oil releases. On June 15, 2017, Enbridge made a total payment of US$68 million as required by the Consent Decree, which reflects US$61 million for the civil penalty for the Line 6B release, US$1 million for the Line 6A release, and US$6 million for past removal costs and interest.

 

Seaway Pipeline Regulatory Matters

Seaway Crude Pipeline System (Seaway Pipeline) filed an application for market-based rates in December 2011 and refiled in December 2014. Several parties filed comments in opposition alleging that the application should be denied because Seaway Pipeline has market power in both its receipt and destination markets. On December 1, 2016, the Administrative Law Judge (ALJ) issued its decision which concluded that the Commission should grant the application of Seaway Pipeline for authority to charge market-based rates. The parties filed briefs during the first quarter of 2017 to defend the ALJ’s decision and to respond to criticisms of that decision. The Commissioners will now review the entire record and issue a decision. There is no timeline for the FERC to act and issue a decision.

 

GAS PIPELINES AND PROCESSING

Aux Sable Environmental Protection Agency Matter

In September 2014, Aux Sable received a Notice and Finding of Violation (NFOV) from the EPA for alleged violations of the Clean Air Act related to the Leak Detection and Repair program, and related provisions of the Clean Air Act permit for Aux Sable’s Channahon, Illinois facility. As part of the ongoing process of responding to the September 2014 NFOV, Aux Sable discovered what it believed to be an exceedance of currently permitted limits for Volatile Organic Material. In April 2015, a second NFOV from the EPA was received in connection with this potential exceedance. Aux Sable engaged in discussions with the EPA to evaluate the impacts and ultimate resolution of these issues, including with respect to a draft Consent Decree. Those discussions are continuing and the Consent Decree, when finalized, is not expected to have a material impact on the Company’s consolidated financial position or results of operations.

 

On October 14, 2016, an amended claim was filed against Aux Sable by a counterparty to an NGL supply agreement. On January 5, 2017, Aux Sable filed a Statement of Defence with respect to this claim. While the final outcome of this action cannot be predicted with certainty, at this time management believes that the ultimate resolution of this action will not have a material impact on the Company’s consolidated financial position or results of operations.

 

CAPITAL EXPENDITURE COMMITMENTS

The Company has signed contracts for the purchase of services, pipe and other materials totalling $4,588 million which are expected to be paid over the next five years.

 

40



 

TAX MATTERS

Enbridge and its subsidiaries maintain tax liabilities related to uncertain tax positions. While fully supportable in the Company’s view, these tax positions, if challenged by tax authorities, may not be fully sustained on review.

 

OTHER LITIGATION

The Company and its subsidiaries are subject to various other legal and regulatory actions and proceedings which arise in the normal course of business, including interventions in regulatory proceedings and challenges to regulatory approvals and permits by special interest groups. While the final outcome of such actions and proceedings cannot be predicted with certainty, management believes that the resolution of such actions and proceedings will not have a material impact on the Company’s consolidated financial position or results of operations.

 

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

 

The Company’s earnings, cash flows and other comprehensive income (OCI) are subject to movements in foreign exchange rates, interest rates, commodity prices and the Company’s share price. The Company uses a combination of qualifying and non-qualifying derivative instruments to manage these risks.

 

The following summarizes the types of market risks to which the Company is exposed and the risk management instruments used to mitigate them. The Company uses a combination of qualifying and non-qualifying derivative instruments to manage the risks noted below.

 

Foreign Exchange Risk

The Company generates certain revenues, incurs expenses and holds a number of investments and subsidiaries that are denominated in currencies other than Canadian dollars. As a result, the Company’s earnings, cash flows and OCI are exposed to fluctuations resulting from foreign exchange rate variability.

 

The Company has implemented a policy whereby, at a minimum, it hedges a level of foreign currency denominated earnings exposures over a five-year forecast horizon. A combination of qualifying and non-qualifying derivative instruments are used to hedge anticipated foreign currency denominated revenues and expenses, and to manage variability in cash flows. The Company hedges certain net investments in United States dollar denominated investments and subsidiaries using foreign currency derivatives and United States dollar denominated debt.

 

Interest Rate Risk

The Company’s earnings and cash flows are exposed to short-term interest rate variability due to the regular repricing of its variable rate debt, primarily commercial paper. Pay fixed-receive floating interest rate swaps and options are used to hedge against the effect of future interest rate movements. The Company has implemented a program to significantly mitigate the impact of short-term interest rate volatility on interest expense via execution of floating to fixed interest rate swaps with an average swap rate of 2.5%.

 

As a result of the Merger Transaction, the Company is exposed to changes in the fair value of the fixed rate debt that arise as a result of the changes in market interest rates. Pay floating-receive fixed interest rate swaps are used to hedge against the future changes to the fair value of the fixed rate debt. The Company has implemented a program to significantly mitigate the impact of fluctuations in the fair value of the fixed rate debt via execution of fixed to floating interest rate swaps with an average swap rate of 2.1%.

 

The Company’s earnings and cash flows are also exposed to variability in longer term interest rates ahead of anticipated fixed rate term debt issuances. Forward starting interest rate swaps are used to hedge against the effect of future interest rate movements. The Company has implemented a program to significantly mitigate its exposure to long-term interest rate variability on select forecast term debt issuances via execution of floating to fixed interest rate swaps with an average swap rate of 3.8%.

 

41



 

The Company also monitors its debt portfolio mix of fixed and variable rate debt instruments to maintain a consolidated portfolio of debt within its Board of Directors approved policy limit of a maximum of 25% floating rate debt as a percentage of total debt outstanding. The Company primarily uses qualifying derivative instruments to manage interest rate risk.

 

Commodity Price Risk

The Company’s earnings and cash flows are exposed to changes in commodity prices as a result of its ownership interests in certain assets and investments, as well as through the activities of its energy services subsidiaries. These commodities include natural gas, crude oil, power and NGL. The Company employs financial derivative instruments to fix a portion of the variable price exposures that arise from physical transactions involving these commodities. The Company uses primarily non-qualifying derivative instruments to manage commodity price risk.

 

Emission Allowance Price Risk

Emission allowance price risk is the risk of gain or loss due to changes in the market price of emission allowances that the gas distribution business of the Company is required to purchase for itself and most of its customers to meet GHG compliance obligations. Similar to the gas supply procurement framework, the OEB framework for emission allowance procurement allows recovery of fluctuations in emission allowance prices in customer rates, subject to OEB approval.

 

Equity Price Risk

Equity price risk is the risk of earnings fluctuations due to changes in the Company’s share price. The Company has exposure to its own common share price through the issuance of various forms of stock-based compensation, which affect earnings through revaluation of the outstanding units every period. The Company uses equity derivatives to manage the earnings volatility derived from one form of stock-based compensation, restricted share units. The Company uses a combination of qualifying and non-qualifying derivative instruments to manage equity price risk.

 

42



 

THE EFFECT OF DERIVATIVE INSTRUMENTS ON THE STATEMENTS OF EARNINGS AND COMPREHENSIVE INCOME

The following table presents the effect of cash flow hedges and net investment hedges on the Company’s consolidated earnings and consolidated comprehensive income, before the effect of income taxes.

 

 

 

Three months ended

 

Six months ended

 

 

June 30,

 

June 30,

 

 

2017

2016

 

2017

2016

(millions of Canadian dollars)

 

 

 

 

 

 

Amount of unrealized gain/(loss) recognized in OCI

 

 

 

 

 

 

Cash flow hedges

 

 

 

 

 

 

Foreign exchange contracts

 

3

2

 

1

(33)

Interest rate contracts

 

(41)

(428)

 

(55)

(1,004)

Commodity contracts

 

(9)

(18)

 

12

(2)

Other contracts

 

(6)

6

 

(15)

37

Net investment hedges

 

 

 

 

 

 

Foreign exchange contracts

 

65

(12)

 

73

72

 

 

12

(450)

 

16

(930)

Amount of (gain)/loss reclassified from Accumulated other comprehensive income (AOCI) to earnings (effective portion)

 

 

 

 

 

 

Foreign exchange contracts1

 

(102)

(1)

 

(101)

2

Interest rate contracts2

 

36

72

 

84

51

Commodity contracts3

 

(2)

2

 

(4)

(6)

Other contracts4

 

4

(4)

 

13

(30)

 

 

(64)

69

 

(8)

17

Amount of (gain)/loss reclassified from AOCI to earnings (ineffective portion and amount excluded from effectiveness testing)

 

 

 

 

 

 

Interest rate contracts2

 

4

5

 

6

31

 

 

4

5

 

6

31

Amount of gain/(loss) from non-qualifying derivatives included in earnings

 

 

 

 

 

 

Foreign exchange contracts1

 

434

28

 

707

1,044

Interest rate contracts2

 

32

4

 

14

8

Commodity contracts3

 

19

(114)

 

182

(298)

Other contracts4

 

(5)

5

 

(5)

11

 

 

480

(77)

 

898

765

 

1       Reported within Transportation and other services revenues and Other income/(expense) in the Consolidated Statements of Earnings.

2       Reported within Interest expense in the Consolidated Statements of Earnings.

3       Reported within Transportation and other services revenues, Commodity sales revenues, Commodity costs and Operating and administrative expense in the Consolidated Statements of Earnings.

4       Reported within Operating and administrative expense in the Consolidated Statements of Earnings.

 

Fair Value Derivatives

For interest rate derivative instruments that are designated and qualify as fair value hedges, the gain or loss on the derivative as well as the offsetting loss or gain on the hedged item attributable to the hedged risk is included in Interest expense on the Consolidated Statements of Earnings. During the three and six months ended June 30, 2017, the Company recognized an unrealized gain of $3 million and $1 million (2016 - nil) on the derivative and an unrealized loss of $3 million and $1 million (2016 - nil) on the hedged item in earnings. The difference in the amounts, if any, represents hedge ineffectiveness.

 

LIQUIDITY RISK

Liquidity risk is the risk that the Company will not be able to meet its financial obligations, including commitments and guarantees, as they become due. In order to mitigate this risk, the Company forecasts cash requirements over a 12-month rolling time period to determine whether sufficient funds will be available and maintains substantial capacity under its committed bank lines of credit, as discussed under Liquidity and Capital Resources. The Company also maintains current shelf prospectuses with securities regulators, which enables, subject to market conditions, ready access to either the Canadian or United States public capital markets. The Company was deemed to be in compliance with all the terms and conditions of its committed credit facilities as at June 30, 2017.

 

43



 

CREDIT RISK

Entering into derivative financial instruments may result in exposure to credit risk from the possibility that a counterparty will default on its contractual obligations. In order to mitigate this risk, the Company enters into risk management transactions primarily with institutions that possess investment grade credit ratings. Credit risk relating to derivative counterparties is mitigated by credit exposure limits and contractual requirements, netting arrangements, and ongoing monitoring of counterparty credit exposure using external credit rating services and other analytical tools.

 

The Company generally has a policy of entering into individual International Swaps and Derivatives Association, Inc. agreements or other similar derivative agreements with the majority of its derivative counterparties. These agreements provide for the net settlement of derivative instruments outstanding with specific counterparties in the event of bankruptcy or other significant credit event, and would reduce the Company’s credit risk exposure on derivative asset positions outstanding with the counterparties in these particular circumstances.

 

Credit risk also arises from trade and other long-term receivables and is mitigated through credit exposure limits and contractual requirements, assessment of credit ratings and netting arrangements. Within EGD and Union Gas, credit risk is mitigated by the utilities’ large and diversified customer base and the ability to recover an estimate for doubtful accounts through the ratemaking process. The Company actively monitors the financial strength of large industrial customers and, in select cases, has obtained additional security to minimize the risk of default on receivables. Generally, the Company classifies and provides for receivables older than 30 days as past due. The maximum exposure to credit risk related to non-derivative financial assets is their carrying value.

 

CHANGES IN ACCOUNTING POLICIES

 

ADOPTION OF NEW STANDARDS

Simplifying the Measurement of Goodwill Impairment

Effective January 1, 2017, the Company early adopted Accounting Standards Update (ASU) 2017-04 and applied the standard on a prospective basis. Under the new guidance, goodwill impairment will now be measured by the amount by which a reporting unit’s carrying value exceeds its fair value; this amount should not exceed the carrying amount of goodwill. The adoption of the pronouncement did not have a material impact on the Company’s consolidated financial statements.

 

Clarifying the Definition of a Business in an Acquisition

Effective January 1, 2017, the Company early adopted ASU 2017-01 on a prospective basis. The new standard was issued with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (disposals) of assets or businesses. The adoption of the pronouncement did not have a material impact on the Company’s consolidated financial statements.

 

Accounting for Intra-Entity Asset Transfers

Effective January 1, 2017, the Company early adopted ASU 2016-16 on a modified retrospective basis. The new standard was issued with the intent of improving the accounting for the income tax consequences of intra-entity asset transfers other than inventory. Under the new guidance, an entity should recognize the income tax consequences of an intra-entity transfer of an asset, other than inventory, when the transfer occurs. The adoption of the pronouncement did not have a material impact on the Company’s consolidated financial statements.

 

44



 

Improvements to Employee Share-Based Payment Accounting

Effective January 1, 2017, the Company adopted ASU 2016-09 and applied certain amendments on a modified retrospective basis with the remaining amendments applied on a prospective basis. The new standard was issued with the intent of simplifying and improving several aspects of accounting for share-based payment transactions including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The adoption of the pronouncement did not have a material impact on the Company’s consolidated financial statements.

 

Simplifying the Embedded Derivatives Analysis for Debt Instruments

Effective January 1, 2017, the Company adopted ASU 2016-06 on a modified retrospective basis. The new guidance simplifies the embedded derivative analysis for debt instruments containing contingent call or put options. The adoption of the pronouncement did not have a material impact on the Company’s consolidated financial statements.

 

FUTURE ACCOUNTING POLICY CHANGES

Clarifying Guidance on the Application of Modification Accounting on Stock Compensation

ASU 2017-09 was issued in May 2017 with the intent to clarify the scope of modification accounting and when it should be applied to a change to the terms or conditions of a share based payment award. Under the new guidance, modification accounting is required for all changes to share based payment awards, unless all of the following are met: 1) there is no change to the fair value of the award, 2) the vesting conditions have not changed, and 3) the classification of the award as an equity instrument or a debt instrument has not changed. The accounting update is effective for annual periods beginning after December 15, 2017 and is to be applied on a prospective basis. The adoption of ASU 2017-09 is not expected to have a material impact on the Company’s consolidated financial statements.

 

Amending the Amortization Period for Certain Callable Debt Securities Purchased at a Premium

ASU 2017-08 was issued in March 2017 with the intent of shortening the amortization period to the earliest call date for certain callable debt securities held at a premium. The Company is currently assessing the impact of the new standard on the consolidated financial statements. The accounting update is effective for annual and interim periods beginning after December 15, 2018 and is to be applied on a modified retrospective basis.

 

Improving the Presentation of Net Periodic Benefit Cost Related to Defined Benefit Plans

ASU 2017-07 was issued in March 2017 primarily to improve the income statement presentation of the components of net periodic pension cost and net periodic postretirement benefit cost for an entity’s sponsored defined benefit pension and other postretirement plans. In addition, only the service-cost component of net benefit cost is eligible for capitalization. The Company is currently assessing the impact of the new standard on the consolidated financial statements. The accounting update is effective for annual and interim periods beginning after December 15, 2017 and is to be applied on a retrospective basis for the statement of earnings presentation component and a prospective basis for the capitalization component. Other than the revised statement of earnings presentation, the adoption of ASU 2017-07 is not expected to have a material impact on the Company’s consolidated financial statements.

 

Clarifying Guidance on Derecognition and Partial Sales of Nonfinancial Assets

ASU 2017-05 was issued in February 2017 with the intent of clarifying the scope of asset derecognition guidance and accounting for partial sales of nonfinancial assets. The ASU clarifies the scope provisions of nonfinancial assets and how to allocate consideration to each distinct asset, and amends the guidance for derecognition of a distinct nonfinancial asset in partial sale transactions. The Company is currently assessing the impact of the new standard on the consolidated financial statements. The accounting update is effective for annual and interim periods beginning after December 15, 2017, and is to be applied on a retrospective or modified retrospective basis.

 

45



 

Accounting for Credit Losses

ASU 2016-13 was issued in June 2016 with the intent of providing financial statement users with more useful information about the expected credit losses on financial instruments and other commitments to extend credit held by a reporting entity at each reporting date. Current treatment uses the incurred loss methodology for recognizing credit losses that delays the recognition until it is probable a loss has been incurred. The amendment adds a new impairment model, known as the current expected credit loss model, that is based on expected losses rather than incurred losses. Under the new guidance, an entity recognizes as an allowance its estimate of expected credit losses, which the Financial Accounting Standards Board believes will result in more timely recognition of such losses. The Company is currently assessing the impact of the new standard on its consolidated financial statements. The accounting update is effective for annual and interim periods beginning on or after December 15, 2019 and is to be applied using a modified retrospective approach.

 

Recognition of Leases

ASU 2016-02 was issued in February 2016 with the intent to increase transparency and comparability among organizations. It requires lessees of operating lease arrangements to recognize lease assets and lease liabilities on the statement of financial position and disclose additional key information about lease agreements. The accounting update also replaces the current definition of a lease and requires that an arrangement be recognized as a lease when a customer has the right to obtain substantially all of the economic benefits from the use of an asset, as well as the right to direct the use of the asset. The Company is currently assessing the impact of the new standard on its consolidated financial statements. The accounting update is effective for fiscal years beginning after December 15, 2018 and is to be applied using a modified retrospective approach.

 

Revenue from Contracts with Customers

ASU 2014-09 was issued in 2014 with the intent of significantly enhancing consistency and comparability of revenue recognition practices across entities and industries. The new standard establishes a single, principles-based five-step model to be applied to all contracts with customers and introduces new and enhanced disclosure requirements. The standard is effective January 1, 2018. The new revenue standard permits either a full retrospective method of adoption with restatement of all prior periods presented, or a modified retrospective method with the cumulative effect of applying the new standard recognized as an adjustment to opening retained earnings in the period of adoption. The Company has tentatively decided to adopt the new revenue standard using the modified retrospective method.

 

The Company has reviewed a sample of its revenue contracts in order to evaluate the effect of the new standard on its revenue recognition practices. Based on the Company’s initial assessment, the application of the standard may result in a change in presentation in the Gas Distribution business related to payments to customers under the earnings sharing mechanism which, are currently shown as an expense in the Consolidated Statements of Earnings. Under the new standard, these payments would be reflected as a reduction of revenue. Additionally, estimates of variable consideration which will be required under the new standard for certain Liquids Pipelines, Gas Pipelines and Processing and Green Power and Transmission revenue contracts as well as the allocation of the transaction price for certain Liquids Pipelines revenue contracts, may result in changes to the pattern or timing of revenue recognition for those contracts. While the Company has not yet completed the assessment, the Company’s preliminary view is that it does not expect these changes will have a material impact on revenue or earnings/(loss). The Company is currently developing processes to generate the disclosures required under the new standard.

 

46



 

QUARTERLY FINANCIAL INFORMATION

 

 

 

2017

 

2016

 

2015

 

 

Q22

Q12

 

Q4

Q3

Q2

Q1

 

Q4

Q3

(millions of Canadian dollars,

 

 

 

 

 

 

 

 

 

 

 

except per share amounts)

 

 

 

 

 

 

 

 

 

 

 

Revenues

 

11,116

11,146

 

9,338

8,488

7,939

8,795

 

8,914

8,320

Earnings/(loss) attributable to common shareholders

 

919

638

 

365

(103)

301

1,213

 

378

(609)

Earnings/(loss) per common share

 

0.56

0.54

 

0.39

(0.11)

0.33

1.38

 

0.44

(0.72)

Diluted earnings/(loss) per common share

 

0.56

0.54

 

0.39

(0.11)

0.33

1.38

 

0.44

(0.72)

Dividends per common share

 

0.610

0.583

 

0.530

0.530

0.530

0.530

 

0.465

0.465

Changes in unrealized derivative fair value (gains)/loss1

 

(537)

(245)

 

189

32

1

(652)

 

45

654

 

1       Included in earnings/(loss) attributable to common shareholders.

2       Included in the first and second quarters of 2017 were the results of operations from the assets acquired through the Merger Transaction effective February 27, 2017. For additional information, refer to Merger with Spectra Energy, Liquids Pipelines, Gas Pipelines and Processing, Gas Distribution, as well as Eliminations and Other.

 

Several factors impact comparability of the Company’s financial results on a quarterly basis, including, but not limited to, the Merger Transaction in the first quarter of 2017, seasonality in the Company’s gas distribution businesses, fluctuations in market prices such as foreign exchange rates and commodity prices, disposals of investments or assets and the timing of in-service dates of new projects.

 

A significant part of the Company’s revenues is generated from its energy services operations. Revenues from these operations depend on activity levels, which vary from year to year depending on market conditions and commodity prices. Commodity prices do not directly impact earnings since these earnings reflect a margin or percentage of revenues that depends more on differences in commodity prices between locations and points in time than on the absolute level of prices.

 

The Company actively manages its exposure to market risks including, but not limited to, commodity prices, interest rates and foreign exchange rates. To the extent derivative instruments used to manage these risks are non-qualifying for the purposes of applying hedge accounting, changes in unrealized fair value gains and losses on these instruments will impact earnings.

 

In addition to the impacts of the Merger Transaction, as well as the changes in unrealized gains and losses outlined above, significant items impacting the consolidated quarterly earnings are noted below:

·                  Included in the first quarter of 2017 were charges to earnings of $152 million ($111 million after-tax) with respect to costs incurred in relation to the Merger Transaction, as well as $129 million ($92 million after-tax) of employee severance costs in relation to the Company’s enterprise-wide reduction of workforce in March 2017 and restructuring costs in connection with the completion of the Merger Transaction.

·                  Included in the fourth quarter of 2016 were employee severance and restructuring costs incurred in relation to the Company’s Building Our Energy Future initiative, with a net charge to earnings of $37 million. For additional information on this initiative, refer to the Company’s 2016 annual MD&A.

·                  Included in the fourth quarter of 2016 was a gain of $520 million (after-tax attributable to Enbridge) on the disposal of South Prairie Region assets within the Liquids Pipelines segment.

·                  Included in the fourth quarter of 2016 was an asset impairment charge of $272 million (after-tax attributable to Enbridge) related to the Northern Gateway Project within the Liquids Pipelines segment.

·                  Included in the fourth quarter of 2016 and second quarter of 2015 were the tax impacts of asset transfers between entities under common control of Enbridge. The intercompany gains realized by the selling entities have been eliminated from the Company’s consolidated financial statements. However, as the transaction involved the sale of partnership units, the tax consequences remained in consolidated earnings and resulted in charges of $11 million and $39 million, respectively.

 

47



 

·                  In the third quarter of 2016, impairment charges of $1,000 million ($81 million after-tax attributable to Enbridge), including related project costs of $8 million, were recognized in relation to EEP’s Sandpiper Project. In the fourth quarter of 2016, additional project costs of $4 million (nil after-tax attributable to Enbridge) were recognized.

·                  Included in the second and third quarters of 2016 were after-tax costs attributable to Enbridge of $12 million and $10 million, respectively, incurred in relation to the restart of certain of Enbridge’s pipelines and facilities following the northeastern Alberta wildfires.

·                  Included in the second quarter of 2016 were impairment charges of $103 million (after-tax attributable to Enbridge) related to Enbridge’s 75% joint venture interest in Eddystone Rail, attributable to market conditions that impacted volumes at the rail facility.

·                  Included in the fourth quarter of 2015 were employee severance costs in relation to the Company’s enterprise-wide reduction of workforce, with a net charge of $25 million to earnings.

·                  Included in the fourth quarter of 2015 was an asset impairment charge of US$63 million ($11 million after-tax attributable to Enbridge) related to EEP’s Berthold rail facility due to the inability to renew committed shipper agreements beyond 2016 or secure sufficient spot volume.

·                  Included in the third quarter of 2015 were impacts from the transfer of assets between entities under common control of Enbridge in connection with the transfer of Enbridge’s Canadian Liquids Pipelines business and certain Canadian renewable energy assets to EIPLP in which the Fund has an indirect interest, resulting in a $247 million loss on the de-designation of interest rate hedges, an $88 million write-off of a regulatory asset in respect of taxes and $16 million of transaction costs.

·                  Included in the third quarter of 2015 was an after-tax gain of $44 million on the disposal of non-core assets within the Liquids Pipelines segment.

 

Finally, the Company is in the midst of a substantial growth capital program and the timing of construction and completion of growth projects may impact the comparability of quarterly results. The Company’s capital expansion initiatives, including construction commencement and expected in-service dates, are listed under Growth Projects – Commercially Secured Projects.

 

48



 

OUTSTANDING SHARE DATA1

 

PREFERENCE SHARES

 

 

 

 

Redemption and

Right to

 

 

 

Conversion

Convert

 

 

Number

Option Date2,3

Into3,4

Preference Shares, Series A

 

5,000,000

-

-

Preference Shares, Series B

 

18,269,812

June 1, 2022

Series C

Preference Shares, Series C

 

1,730,188

June 1, 2022

Series B

Preference Shares, Series D

 

18,000,000

March 1, 2018

Series E

Preference Shares, Series F

 

20,000,000

June 1, 2018

Series G

Preference Shares, Series H

 

14,000,000

September 1, 2018

Series I

Preference Shares, Series J

 

8,000,000

June 1, 2022

Series K

Preference Shares, Series L

 

16,000,000

September 1, 2017

Series M

Preference Shares, Series N

 

18,000,000

December 1, 2018

Series O

Preference Shares, Series P

 

16,000,000

March 1, 2019

Series Q

Preference Shares, Series R

 

16,000,000

June 1, 2019

Series S

Preference Shares, Series 1

 

16,000,000

June 1, 2018

Series 2

Preference Shares, Series 3

 

24,000,000

September 1, 2019

Series 4

Preference Shares, Series 5

 

8,000,000

March 1, 2019

Series 6

Preference Shares, Series 7

 

10,000,000

March 1, 2019

Series 8

Preference Shares, Series 9

 

11,000,000

December 1, 2019

Series 10

Preference Shares, Series 11

 

20,000,000

March 1, 2020

Series 12

Preference Shares, Series 13

 

14,000,000

June 1, 2020

Series 14

Preference Shares, Series 15

 

11,000,000

September 1, 2020

Series 16

Preference Shares, Series 17

 

30,000,000

March 1, 2022

Series 18

 

 

 

 

 

COMMON SHARES

 

 

 

 

 

 

 

 

Number

Common Shares - issued and outstanding (voting equity shares)

 

 

 

1,645,812,740

Stock Options - issued and outstanding (24,755,721 vested)

 

 

 

39,771,613

 

1         Outstanding share data information is provided as at July 21, 2017.

2         All preference shares are non-voting equity shares. Preference Shares, Series A may be redeemed any time at the Company’s option. For other series of Preference Shares, the Company may, at its option, redeem all or a portion of outstanding Preference Shares for the Base Redemption Value per share plus all accrued and unpaid dividends on the Redemption Option Date and on every fifth anniversary thereafter.

3         The holder will have the right, subject to certain conditions, to convert their shares into Cumulative Redeemable Preference Shares of a specified series on a one-for-one basis on the Conversion Option Date and every fifth anniversary thereafter at an ascribed issue price equal to the Base Redemption Value.

4         On June 1, 2017, 1,730,188 of Series B fixed rate Preference Shares were converted to Series C floating rate Preference Shares based upon preference share holder elections under the terms of the Series B Preference Shares. No series J Preference Shares were converted on the June 1, 2017 conversion option date.

 

49



 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

ENBRIDGE INC.

 

 

CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

 

June 30, 2017

 



 

CONSOLIDATED STATEMENTS OF EARNINGS

 

 

 

Three months ended

 

Six months ended

 

 

June 30,

 

June 30,

 

 

2017

2016

 

2017

2016

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

 

 

 

 

 

 

Revenues

 

 

 

 

 

 

Commodity sales

 

6,620

5,470

 

13,486

10,274

Gas distribution sales

 

847

504

 

2,210

1,511

Transportation and other services

 

3,649

1,965

 

6,566

4,949

 

 

11,116

7,939

 

22,262

16,734

Expenses

 

 

 

 

 

 

Commodity costs

 

6,489

5,303

 

13,039

10,014

Gas distribution costs

 

429

284

 

1,444

1,038

Operating and administrative

 

1,646

1,003

 

3,197

2,100

Depreciation and amortization

 

868

555

 

1,540

1,114

 

 

9,432

7,145

 

19,220

14,266

 

 

1,684

794

 

3,042

2,468

Income/(loss) from equity investments

 

236

(37)

 

472

189

Other income/(expense)

 

179

(26)

 

214

250

Interest expense

 

(565)

(369)

 

(1,051)

(781)

 

 

1,534

362

 

2,677

2,126

Income tax expense (Note 12)

 

(293)

(10)

 

(491)

(427)

Earnings

 

1,241

352

 

2,186

1,699

(Earnings)/loss attributable to noncontrolling interests and redeemable noncontrolling interests

 

(241)

20

 

(465)

(41)

Earnings attributable to Enbridge Inc.

 

1,000

372

 

1,721

1,658

Preference share dividends

 

(81)

(71)

 

(164)

(144)

Earnings attributable to Enbridge Inc. common shareholders

 

919

301

 

1,557

1,514

 

 

 

 

 

 

 

Earnings per common share attributable to Enbridge Inc. common shareholders (Note 4)

 

0.56

0.33

 

1.11

1.69

 

 

 

 

 

 

 

Diluted earnings per common share attributable to

 

 

 

 

 

 

Enbridge Inc. common shareholders (Note 4)

 

0.56

0.33

 

1.10

1.67

 

See accompanying notes to the interim consolidated financial statements.

 

1



 

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

 

 

 

Three months ended

 

Six months ended

 

 

June 30,

 

June 30,

 

 

2017

2016

 

2017

2016

(unaudited; millions of Canadian dollars)

 

 

 

 

 

 

Earnings

 

1,241

352

 

2,186

1,699

Other comprehensive income/(loss), net of tax

 

 

 

 

 

 

Change in unrealized loss on cash flow hedges

 

(85)

(234)

 

(87)

(677)

Change in unrealized gain/(loss) on net investment hedges

 

171

(23)

 

220

371

Other comprehensive income/(loss) from equity investees

 

2

1

 

8

(1)

Reclassification to earnings of loss on cash flow hedges

 

66

26

 

107

25

Reclassification to earnings of pension and other postretirement benefits (OPEB) amounts

 

3

7

 

7

9

Foreign currency translation adjustments

 

(1,443)

61

 

(1,011)

(1,316)

Other comprehensive loss, net of tax

 

(1,286)

(162)

 

(756)

(1,589)

Comprehensive income/(loss)

 

(45)

190

 

1,430

110

Comprehensive (income)/loss attributable to noncontrolling interests and redeemable noncontrolling interests

 

15

70

 

(359)

170

Comprehensive income/(loss) attributable to Enbridge Inc.