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  May 2, 2012

Commission file number 001-15254

 

 

ENBRIDGE INC.

(Exact name of Registrant as specified in its charter)

 

Canada

(State or other jurisdiction

of incorporation or organization)

 

None

(I.R.S. Employer Identification No.)

 

3000, 425 – 1st Street S.W.

Calgary, Alberta, Canada  T2P 3L8

(Address of principal executive offices and postal code)

 

(403) 231-3900

(Registrants telephone number, including area 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

 



 

Indicate by check mark whether the Registrant by furnishing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934.

 

Yes

 

 

No

P

 

If “Yes” is marked, indicate below the file number assigned to the Registrant in connection with Rule 12g3-2(b):

 

N/A

 

THIS REPORT ON FORM 6-K SHALL BE DEEMED TO BE INCORPORATED BY REFERENCE IN THE REGISTRATION STATEMENTS ON FORM S-8 (FILE NO. 333-145236, 333-127265, 333-13456, 333-97305 AND 333-6436), FORM F-3 (FILE NO. 33-77022) AND FORM F-10 (FILE NO. 333-170200) 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 AND TO BE PART THEREOF FROM THE DATE ON WHICH THIS REPORT IS FURNISHED, TO THE EXTENT NOT SUPERSEDED BY DOCUMENTS OR REPORTS SUBSEQUENTLY FILED OR FURNISHED.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:

 

·    U.S. GAAP Consolidated Financial Statements

 

 

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:

May 2, 2012

   By:

/s/ Alison T. Love

 

 

 

Alison T. Love

 

 

 

Vice President and Corporate Secretary

 


 


 

ENBRIDGE INC.

U.S. GAAP CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2011

 



 

GRAPHIC

 

Independent Auditor’s Report

 

To the Directors of Enbridge Inc.

 

We have audited the accompanying consolidated financial statements of Enbridge Inc., which comprise the consolidated statements of financial position as at December 31, 2011 and December 31, 2010 and the consolidated statements of earnings, comprehensive income, changes in equity and cash flows for each of the three years in the period ended December 31, 2011, and the related notes, which comprise a summary of significant accounting policies and other explanatory information.

 

Management’s responsibility for the consolidated financial statements

Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with accounting principles generally accepted in the United States of America and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

 

Auditor’s responsibility

Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement. Canadian generally accepted auditing standards require that we comply with ethical requirements.

 

An audit involves performing procedures to obtain audit evidence, on a test basis, about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. An audit also includes evaluating the appropriateness of accounting principles and policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

 

We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit opinion.

 

Opinion

In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of Enbridge Inc. as at December 31, 2011 and December 31, 2010 and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2011 in accordance with accounting principles generally accepted in the United States of America.

 

 

 

 

 

 


PricewaterhouseCoopers LLP, Chartered Accountants

111 5 Avenue SW, Suite 3100, Calgary, Alberta, Canada T2P 5L3

T: +1 403 509 7500, F: +1 403 781 1825, www.pwc.com/ca

 

“PwC” refers to PricewaterhouseCoopers LLP, an Ontario limited liability partnership.

 



 

GRAPHIC

 

Other matter

Enbridge Inc. has prepared another set of consolidated financial statements for the years ended December 31, 2011 and December 31, 2010 in accordance with Canadian generally accepted accounting principles. We have issued an integrated audit report on those consolidated financial statements and on the internal control over financial reporting as at December 31, 2011 to the shareholders of Enbridge Inc. dated February 21, 2012.

 

“PricewaterhouseCoopers LLP”

 

Chartered Accountants

Calgary, Alberta, Canada

May 2, 2012

 

 

2


 


 

U.S. GAAP CONSOLIDATED STATEMENTS OF EARNINGS

 

Year ended December 31,

 

2011

 

 

2010

 

2009

 

(millions of Canadian dollars, except per share amounts)

 

 

 

 

 

 

 

 

Revenues

 

 

 

 

 

 

 

 

Commodity sales

 

20,611

 

 

15,863

 

12,242

 

Gas distribution sales

 

1,903

 

 

1,812

 

2,186

 

Transportation and other services

 

4,467

 

 

3,775

 

3,274

 

 

 

26,981

 

 

21,450

 

17,702

 

Expenses

 

 

 

 

 

 

 

 

Commodity costs

 

19,864

 

 

15,276

 

11,551

 

Gas distribution costs

 

1,209

 

 

1,179

 

1,586

 

Operating and administrative

 

2,281

 

 

2,032

 

2,058

 

Depreciation and amortization

 

1,112

 

 

1,017

 

897

 

Environmental costs, net of recoveries (Note 28)

 

(116

)

 

619

 

3

 

 

 

24,350

 

 

20,123

 

16,095

 

 

 

2,631

 

 

1,327

 

1,607

 

Income from equity investments (Note 11)

 

210

 

 

228

 

232

 

Other income (Note 25)

 

117

 

 

318

 

681

 

Interest expense (Note 16)

 

(928

)

 

(865

)

(751

)

Gain on sale of investments (Note 6)

 

-

 

 

-

 

365

 

 

 

2,030

 

 

1,008

 

2,134

 

Income taxes (Note 23)

 

(526

)

 

(227

)

(312

)

Earnings from continuing operations

 

1,504

 

 

781

 

1,822

 

Loss from discontinued operations, net of tax (Note 6)

 

-

 

 

-

 

(70

)

Earnings before extraordinary item

 

1,504

 

 

781

 

1,752

 

Extraordinary item, net of tax (Note 30)

 

(262

)

 

-

 

-

 

Earnings

 

1,242

 

 

781

 

1,752

 

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

 

(409

)

 

170

 

(234

)

Earnings attributable to Enbridge Inc.

 

833

 

 

951

 

1,518

 

Preference share dividends

 

(13

)

 

(7

)

(7

)

Earnings attributable to Enbridge Inc. common shareholders

 

820

 

 

944

 

1,511

 

 

 

 

 

 

 

 

 

 

Earnings attributable to Enbridge Inc. common shareholders

 

 

 

 

 

 

 

 

Earnings from continuing operations

 

1,082

 

 

944

 

1,530

 

Loss from discontinued operations, net of tax

 

-

 

 

-

 

(19

)

Extraordinary item, net of tax (Note 30)

 

(262

)

 

-

 

-

 

 

 

820

 

 

944

 

1,511

 

 

 

 

 

 

 

 

 

 

Earnings/(loss) per common share attributable to Enbridge Inc. common shareholders (Note 19)

 

 

 

 

 

 

 

 

Continuing operations

 

1.44

 

 

1.27

 

2.10

 

Discontinued operations

 

-

 

 

-

 

(0.03

)

Extraordinary item

 

(0.35

)

 

-

 

-

 

 

 

1.09

 

 

1.27

 

2.07

 

 

 

 

 

 

 

 

 

 

Diluted earnings/(loss) per common share attributable to Enbridge Inc. common shareholders (Note 19)

 

 

 

 

 

 

 

 

Continuing operations

 

1.42

 

 

1.26

 

2.09

 

Discontinued operations

 

-

 

 

-

 

(0.03

)

Extraordinary item

 

(0.34

)

 

-

 

-

 

 

 

1.08

 

 

1.26

 

2.06

 

 

The accompanying notes are an integral part of these consolidated financial statements.

 

 

4



 

U.S. GAAP CONSOLIDATED STATEMENTS OF
COMPREHENSIVE INCOME

 

Year ended December 31,

 

2011

 

 

2010

 

2009

 

(millions of Canadian dollars)

 

 

 

 

 

 

 

 

Earnings

 

1,242

 

 

781

 

1,752

 

Other comprehensive income/(loss)

 

 

 

 

 

 

 

 

Change in unrealized loss on cash flow hedges, net of tax

 

(582

)

 

(156

)

(143

)

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

 

(19

)

 

51

 

151

 

Other comprehensive income/(loss) from equity investees, net of tax

 

(17

)

 

4

 

(6

)

Reclassification to earnings of realized cash flow hedges, net of tax

 

14

 

 

(15

)

123

 

Reclassification to earnings of unrealized cash flow hedges, net of tax (Notes 6 and 22)

 

12

 

 

(3

)

(20

)

Overfunded/(underfunded) pension adjustment, net of tax

 

(144

)

 

(38

)

13

 

Change in foreign currency translation adjustment

 

151

 

 

(376

)

(1,207

)

Other comprehensive loss

 

(585

)

 

(533

)

(1,089

)

Comprehensive income

 

657

 

 

248

 

663

 

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

 

(329

)

 

331

 

288

 

Comprehensive income attributable to Enbridge Inc.

 

328

 

 

579

 

951

 

Preferred share dividends

 

(13

)

 

(7

)

(7

)

Comprehensive income attributable to Enbridge Inc. common shareholders

 

315

 

 

572

 

944

 

 

The accompanying notes are an integral part of these consolidated financial statements.

 

 

5



 

U.S. GAAP CONSOLIDATED STATEMENTS OF
CHANGES IN EQUITY

 

Year ended December 31,

 

2011

 

 

2010

 

2009

 

(millions of Canadian dollars, except per share amounts)

 

 

 

 

 

 

 

 

Preference shares (Note 19)

 

 

 

 

 

 

 

 

Balance at beginning of year

 

125

 

 

125

 

125

 

Preference shares issued

 

931

 

 

-

 

-

 

Balance at end of year

 

1,056

 

 

125

 

125

 

Common shares (Note 19)

 

 

 

 

 

 

 

 

Balance at beginning of year

 

3,683

 

 

3,379

 

3,194

 

Common shares issued

 

-

 

 

-

 

4

 

Dividend reinvestment and share purchase plan

 

229

 

 

224

 

143

 

Shares issued on exercise of stock options

 

57

 

 

80

 

38

 

Balance at end of year

 

3,969

 

 

3,683

 

3,379

 

Additional paid-in capital

 

 

 

 

 

 

 

 

Balance at beginning of year

 

131

 

 

90

 

74

 

Stock-based compensation

 

18

 

 

13

 

19

 

Options exercised

 

(7

)

 

(8

)

(3

)

Dilution gains

 

100

 

 

36

 

-

 

Balance at end of year

 

242

 

 

131

 

90

 

Retained earnings

 

 

 

 

 

 

 

 

Balance at beginning of year

 

3,993

 

 

3,828

 

2,917

 

Earnings attributable to Enbridge Inc. common shareholders

 

820

 

 

944

 

1,511

 

Common share dividends declared

 

(759

)

 

(648

)

(555

)

Dividends paid to reciprocal shareholder

 

25

 

 

19

 

17

 

Redemption value adjustment attributable to redeemable noncontrolling interests (Note 18)

 

(153

)

 

(150

)

(62

)

Balance at end of year

 

3,926

 

 

3,993

 

3,828

 

Accumulated other comprehensive loss (Note 21)

 

 

 

 

 

 

 

 

Balance at beginning of year

 

(1,027

)

 

(654

)

(88

)

Other comprehensive loss attributable to Enbridge Inc. common shareholders

 

(505

)

 

(373

)

(566

)

Balance at end of year

 

(1,532

)

 

(1,027

)

(654

)

Reciprocal shareholding (Note 11)

 

 

 

 

 

 

 

 

Balance at beginning of year

 

(154

)

 

(154

)

(154

)

Acquisition of equity investment

 

(33

)

 

-

 

-

 

Balance at end of year

 

(187

)

 

(154

)

(154

)

Total Enbridge Inc. shareholders’ equity

 

7,474

 

 

6,751

 

6,614

 

Noncontrolling interests

 

 

 

 

 

 

 

 

Balance at beginning of year

 

2,424

 

 

2,740

 

3,334

 

Earnings/(loss) attributable to noncontrolling interests

 

416

 

 

(182

)

218

 

Other comprehensive income/(loss) attributable to noncontrolling interests

 

 

 

 

 

 

 

 

Change in unrealized loss on cash flow hedges, net of tax

 

(84

)

 

(12

)

(95

)

Change in foreign currency translation adjustment

 

66

 

 

(121

)

(453

)

Reclassification to earnings of realized cash flow hedges, net of tax

 

(63

)

 

(13

)

28

 

Reclassification to earnings of unrealized cash flow hedges, net of tax

 

4

 

 

(2

)

-

 

Other comprehensive loss attributable to noncontrolling interests

 

(77

)

 

(148

)

(520

)

Comprehensive income/(loss)

 

339

 

 

(330

)

(302

)

Distributions

 

(355

)

 

(318

)

(296

)

Contributions (Note 18)

 

735

 

 

358

 

-

 

Dilution gain

 

22

 

 

15

 

-

 

Acquisitions (Notes 6 and 18)

 

(27

)

 

(41

)

-

 

Other

 

3

 

 

-

 

4

 

Balance at end of year

 

3,141

 

 

2,424

 

2,740

 

Total equity

 

10,615

 

 

9,175

 

9,354

 

 

 

 

 

 

 

 

 

 

Dividends paid per common share

 

0.98

 

 

0.85

 

0.74

 

 

The accompanying notes are an integral part of these consolidated financial statements.

 

 

6



 

U.S. GAAP CONSOLIDATED STATEMENTS OF CASH FLOWS

 

Year ended December 31,

 

2011

 

 

2010

 

2009

 

 

(millions of Canadian dollars)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating activities

 

 

 

 

 

 

 

 

Earnings

 

1,242

 

 

781

 

1,752

 

Depreciation and amortization

 

1,112

 

 

1,017

 

897

 

Unrealized gains on derivative instruments, net

 

(73

)

 

-

 

(176

)

Allowance for equity funds used during construction

 

(3

)

 

(96

)

(148

)

Cash distributions in excess of equity earnings

 

125

 

 

102

 

86

 

Regulatory asset write-off (Note 30)

 

262

 

 

-

 

-

 

Gain on sale of investments (Note 6)

 

-

 

 

-

 

(365

)

Gain on acquisition (Note 6)

 

-

 

 

(22

)

-

 

Deferred income taxes (Note 23)

 

368

 

 

203

 

229

 

Asset impairment losses (Note 6)

 

11

 

 

11

 

81

 

Other

 

14

 

 

9

 

(79

)

Changes in regulatory assets and liabilities

 

28

 

 

29

 

(22

)

Changes in environmental liabilities, net of recoveries (Note 28)

 

(118

)

 

267

 

2

 

Changes in operating assets and liabilities (Note 26)

 

403

 

 

(424

)

316

 

 

 

3,371

 

 

1,877

 

2,573

 

Investing activities

 

 

 

 

 

 

 

 

Additions to property, plant and equipment

 

(3,452

)

 

(3,030

)

(4,505

)

Government grant

 

145

 

 

-

 

-

 

Additions to intangible assets

 

(154

)

 

(56

)

(87

)

Changes in construction payable

 

(19

)

 

60

 

(120

)

Acquisitions, net of cash acquired (Note 6 and 18)

 

(33

)

 

(850

)

(28

)

Long-term investments

 

(1,571

)

 

(58

)

(50

)

Affiliate loans, net

 

7

 

 

14

 

(12

)

Proceeds on sale of investments and net assets (Note 6)

 

-

 

 

23

 

696

 

Settlement of hedges (Note 6)

 

-

 

 

-

 

6

 

Changes in restricted cash

 

(2

)

 

(5

)

16

 

 

 

(5,079

)

 

(3,902

)

(4,084

)

Financing activities

 

 

 

 

 

 

 

 

Net change in bank indebtedness and short-term borrowings

 

224

 

 

(165

)

(393

)

Net change in commercial paper and credit facility draws

 

(630

)

 

(212

)

1,421

 

Net change in Southern Lights project financing

 

(62

)

 

14

 

343

 

Debenture and term note issues

 

1,604

 

 

3,220

 

1,500

 

Debenture and term note repayments

 

(234

)

 

(631

)

(1,099

)

Contributions from/(distributions to) noncontrolling interests, net

 

518

 

 

121

 

(299

)

Contributions from/(distributions to) redeemable noncontrolling interests, net

 

175

 

 

(23

)

(23

)

Common shares issued

 

46

 

 

66

 

36

 

Preference shares issued

 

926

 

 

-

 

-

 

Preference share dividends

 

(7

)

 

(7

)

(7

)

Common share dividends

 

(530

)

 

(426

)

(414

)

 

 

2,030

 

 

1,957

 

1,065

 

Effect of translation of foreign denominated cash and cash equivalents

 

25

 

 

(12

)

(31

)

Increase/(decrease) in cash and cash equivalents

 

347

 

 

(80

)

(477

)

Cash and cash equivalents at beginning of year

 

376

 

 

456

 

933

 

Cash and cash equivalents at end of year

 

723

 

 

376

 

456

 

 

 

 

 

 

 

 

 

 

Supplementary cash flow information

 

 

 

 

 

 

 

 

Income taxes (received)/paid

 

(28

)

 

115

 

211

 

Interest paid

 

955

 

 

871

 

819

 

 

The accompanying notes are an integral part of these consolidated financial statements.

 

 

7



 

U.S. GAAP CONSOLIDATED STATEMENTS OF
FINANCIAL POSITION

 

December 31,

 

 

2011

 

 

2010

 

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

 

 

 

 

 

 

 

Assets

 

 

 

 

 

 

 

Current assets

 

 

 

 

 

 

 

Cash and cash equivalents

 

 

723

 

 

376

 

Restricted cash

 

 

17

 

 

15

 

Accounts receivable and other (Note 7)

 

 

4,011

 

 

3,623

 

Accounts receivable from affiliates

 

 

55

 

 

38

 

Inventory (Note 8)

 

 

823

 

 

916

 

 

 

 

5,629

 

 

4,968

 

Property, plant and equipment, net (Note 9)

 

 

28,941

 

 

26,355

 

Long-term investments (Note 11)

 

 

3,160

 

 

1,729

 

Deferred amounts and other assets (Note 12)

 

 

2,667

 

 

2,464

 

Intangible assets, net (Note 13)

 

 

711

 

 

585

 

Goodwill (Note 14)

 

 

440

 

 

431

 

Deferred income taxes (Note 23)

 

 

29

 

 

20

 

 

 

 

41,577

 

 

36,552

 

Liabilities and equity

 

 

 

 

 

 

 

Current liabilities

 

 

 

 

 

 

 

Bank indebtedness

 

 

102

 

 

100

 

Short-term borrowings (Note 16)

 

 

548

 

 

326

 

Accounts payable and other (Note 15)

 

 

4,764

 

 

3,703

 

Accounts payable to affiliates

 

 

48

 

 

7

 

Interest payable

 

 

185

 

 

176

 

Environmental liabilities (Note 28)

 

 

175

 

 

226

 

Current maturities of long-term debt (Note 16)

 

 

354

 

 

185

 

 

 

 

6,176

 

 

4,723

 

Long-term debt (Note 16)

 

 

19,251

 

 

18,403

 

Other long-term liabilities (Note 17)

 

 

2,323

 

 

1,642

 

Deferred income taxes (Note 23)

 

 

2,572

 

 

2,247

 

 

 

 

30,322

 

 

27,015

 

Commitments and contingencies (Note 28)

 

 

 

 

 

 

 

Redeemable noncontrolling interests (Note 18)

 

 

640

 

 

362

 

Equity

 

 

 

 

 

 

 

Share capital (Note 19)

 

 

 

 

 

 

 

Preference shares

 

 

1,056

 

 

125

 

Common shares (781 outstanding at December 31, 2011 (2010 - 770))

 

 

3,969

 

 

3,683

 

Additional paid-in capital

 

 

242

 

 

131

 

Retained earnings

 

 

3,926

 

 

3,993

 

Accumulated other comprehensive loss (Note 21)

 

 

(1,532

)

 

(1,027

)

Reciprocal shareholding (Note 11)

 

 

(187

)

 

(154

)

Total Enbridge Inc. shareholders’ equity

 

 

7,474

 

 

6,751

 

Noncontrolling interests (Note 18)

 

 

3,141

 

 

2,424

 

 

 

 

10,615

 

 

9,175

 

 

 

 

41,577

 

 

36,552

 

 

The accompanying notes are an integral part of these consolidated financial statements.

 

 

8



 

NOTES TO THE U.S. GAAP

CONSOLIDATED FINANCIAL STATEMENTS

 

1.          GENERAL BUSINESS DESCRIPTION

 

Enbridge Inc. (Enbridge or the Company) is a publicly traded energy transportation and distribution company. Enbridge conducts its business through five operating segments: Liquids Pipelines; Gas Distribution; Gas Pipelines, Processing and Energy Services; Sponsored Investments and Corporate. These operating segments are strategic business units established by senior management to facilitate the achievement of the Company’s long-term objectives, to aid in resource allocation decisions and to assess operational performance.

 

LIQUIDS PIPELINES

Liquids Pipelines consists of common carrier and contract crude oil, natural gas liquids (NGL) and refined products pipelines and terminals in Canada and the United States, including the Canadian Mainline, Regional Oil Sands System, Southern Lights Pipeline, Spearhead Pipeline, Seaway Crude Pipeline (Seaway Pipeline) interest and other feeder pipelines.

 

GAS DISTRIBUTION

Gas Distribution consists of the Company’s natural gas utility operations, the core of which is Enbridge Gas Distribution Inc. (EGD) which serves residential, commercial and industrial customers, primarily in central and eastern Ontario as well as northern New York State. This business segment also includes natural gas distribution activities in Quebec and New Brunswick.

 

GAS PIPELINES, PROCESSING AND ENERGY SERVICES

Gas Pipelines, Processing and Energy Services consists of investments in natural gas pipelines and processing facilities, green energy projects, Canadian midstream businesses, the Company’s energy services businesses and international activities.

 

Investments in natural gas pipelines include the Company’s interests in the United States portion of Alliance Pipeline (Alliance Pipeline US), the Vector Pipeline and transmission and gathering pipelines in the Gulf of Mexico. Investments in natural gas processing include the Company’s interest in Aux Sable, a natural gas fractionation and extraction business, an interest in the development of Cabin Gas Plant in northeastern British Columbia, and processing facilities connected to the Gulf of Mexico System. The energy services businesses manage the Company’s volume commitments on Alliance and Vector Pipelines, as well as perform natural gas, NGL and crude oil storage, transport and supply management services, as principal and agent.

 

SPONSORED INVESTMENTS

Sponsored Investments includes the Company’s 23.0% ownership interest in Enbridge Energy Partners, L.P. (EEP), Enbridge’s 66.7% investment in the United States segment of the Alberta Clipper Project through EEP and Enbridge Energy, Limited Partnership (EELP) and an overall 69.2% economic interest in Enbridge Income Fund (the Fund), held both directly, and indirectly through Enbridge Income Fund Holdings Inc. (ENF). Enbridge manages the day-to-day operations of, and develops and assesses opportunities for each of these investments, including both organic growth and acquisition opportunities.

 

EEP transports crude oil and other liquid hydrocarbons through common carrier and feeder pipelines and transports, gathers, processes and markets natural gas and NGLs. The primary operations of the Fund include a crude oil and liquids pipeline and gathering system, a 50% interest in the Canadian portion of Alliance Pipeline (Alliance Pipeline Canada) and interests in renewable power generation projects.

 

CORPORATE

Corporate consists of the Company’s investment in Noverco Inc. (Noverco), new business development activities, corporate investments and financing costs not allocated to the business segments.

 

 

9



 

2.          SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

 

These consolidated financial statements of the Company are prepared in accordance with United States generally accepted accounting principles (U.S. GAAP). Amounts are stated in Canadian dollars unless otherwise noted.

 

Enbridge prepared and filed consolidated financial statements for the year ended December 31, 2011 in accordance with Part V – Pre-changeover Accounting Standards of the Canadian Institute of Chartered Accountants Handbook with a reconciliation to U.S. GAAP in conformity with Item 18 of Form 20-F under United States securities regulations. These U.S. GAAP consolidated financial statements for the year ended December 31, 2011 have been prepared on a voluntary basis. As a United States Security and Exchange Commission registrant, Enbridge is permitted by Canadian Securities regulation to prepare its financial statements in accordance with U.S. GAAP and will commence reporting using U.S. GAAP as its primary basis of accounting in 2012.

 

BASIS OF PRESENTATION AND USE OF ESTIMATES

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities in the consolidated financial statements. Significant estimates and assumptions used in preparation of the consolidated financial statements include, but are not limited to: carrying values of regulatory assets and liabilities (Note 5); unbilled revenues (Note 7); allowance for doubtful accounts (Note 7); depreciation rates and carrying value of property, plant and equipment (Note 9); amortization rates of intangible assets (Note 13); measurement of goodwill (Note 14); valuation of share based compensation (Note 20); fair value of financial instruments (Note 22); income taxes (Note 23); retirement and postretirement benefits (Note 24); commitments and contingencies (Note 28); and fair value of asset retirement obligations (AROs). Actual results could differ from these estimates.

 

PRINCIPLES OF CONSOLIDATION

The consolidated financial statements include the accounts of Enbridge, its subsidiaries and a variable interest entity (VIE) for which the Company is the primary beneficiary. The consolidated financial statements also include the accounts of any limited partnerships where the Company represents the general partner and, based on all facts and circumstances, controls such limited partnerships.

 

All significant intercompany accounts and transactions are eliminated upon consolidation. Ownership interests in subsidiaries represented by other parties that do not control the entity are presented in the consolidated financial statements as activities and balances attributable to noncontrolling interests and redeemable noncontrolling interests. Investments and entities over which the Company exercises significant influence are accounted for using the equity method.

 

REGULATION

Certain of the Company’s businesses are subject to regulation by various authorities including, but not limited to, the National Energy Board (NEB), the Federal Energy Regulatory Commission (FERC), the Energy Resources Conservation Board in Alberta, the New Brunswick Energy and Utilities Board (EUB), and the Ontario Energy Board (OEB). Regulatory bodies exercise statutory authority over matters such as construction, rates and ratemaking and agreements with customers. To recognize the economic effects of the actions of the regulator, the timing of recognition of certain revenues and expenses in these operations may differ from that otherwise expected under U.S. GAAP for non rate-regulated entities.

 

Regulatory assets represent amounts that are expected to be recovered from customers in future periods through rates. Regulatory liabilities represent amounts that are expected to be refunded to customers in future periods through rates. Long-term regulatory assets are recorded in Deferred amounts and other assets and current regulatory assets are recorded in Accounts receivable and other. Long-term regulatory liabilities are included in Other long-term liabilities and current regulatory liabilities are recorded in Accounts payable and other. Regulatory assets are assessed for impairment if the Company identifies an event indicative of possible impairment. The recognition of regulatory assets and liabilities is based on the actions, or expected future actions of the regulator. To the extent that the regulator’s actions differ from the Company’s expectations, the timing and amount of recovery or settlement of regulatory balances could

 

 

10



 

differ significantly from those recorded. In the absence of rate regulation, the Company would generally not recognize regulatory assets or liabilities and the earnings impact would be recorded in the period the expenses are incurred or revenues are earned.

 

Allowance for funds used during construction (AFUDC) is included in the cost of property, plant and equipment and is depreciated over future periods as part of the total cost of the related asset. AFUDC includes both an interest component and, if approved by the regulator, a cost of equity component which are both capitalized based on rates set out in a regulatory agreement.  In the absence of rate regulation, the Company would capitalize interest using a capitalization rate based on its cost of borrowing and the capitalized equity component, the corresponding earnings during the construction phase and the subsequent depreciation would not be recognized.

 

Certain regulators prescribe the pool method of accounting for property, plant and equipment where similar assets with comparable useful lives are grouped and depreciated as a pool. When those assets are retired or otherwise disposed of, gains and losses are not reflected in earnings but are booked as an adjustment to accumulated depreciation. Entities not subject to rate regulation write off the net book value of the retired asset and include any resulting gain or loss in earnings.

 

With the approval of the regulator, EGD and certain distribution operations capitalize a percentage of certain operating costs. These operations are authorized to charge depreciation and earn a return on the net book value of such capitalized costs in future years.  To the extent that the regulator’s actions differ from the Company’s expectations, the timing and amount of recovery or settlement of capitalized costs could differ significantly from those recorded. In the absence of rate regulation, a portion of such costs may be charged to current period earnings.

 

REVENUE RECOGNITION

For businesses which are not rate-regulated, revenues are recorded when products have been delivered or services have been performed and the amount of revenue can be reliably measured. Customer credit worthiness is assessed prior to agreement signing as well as throughout the contract duration. Certain Liquids Pipelines revenues are recognized under the terms of committed delivery contracts rather than the cash tolls received.

 

For the rate-regulated portion of the Company’s main Canadian crude oil pipeline system, revenue was recognized in a manner that is consistent with the underlying agreements as approved by the regulator. Effective July 1, 2011, Canadian Mainline (excluding Lines 8 and 9) earnings are governed by the Competitive Toll Settlement (CTS), under which revenues are recorded when services are performed.  Effective July 1, 2011, the Company discontinued the application of rate-regulated accounting for its Canadian Mainline (excluding Lines 8 and 9) on a prospective basis, with the exception of flow-through income taxes covered by a specific rate order.

 

For natural gas utility rate-regulated operations in Gas Distribution, revenue is recognized in a manner consistent with the underlying rate-setting mechanism as mandated by the regulator. Natural gas utilities revenues are recorded on the basis of regular meter readings and estimates of customer usage from the last meter reading to the end of the reporting period.

 

For the natural gas and marketing businesses within Sponsored Investments, there is one month of estimated revenue and cost of gas included in the Consolidated Statements of Earnings based on the best available volume and price data for natural gas delivered and received.

 

 

11



 

DERIVATIVE INSTRUMENTS AND HEDGING

Non-qualifying Derivatives

Non-qualifying derivative instruments are used primarily to economically hedge foreign exchange and commodity price earnings exposure. Non-qualifying derivatives are measured at fair value with changes in fair value recognized in earnings in Transportation and other services revenue, Commodity costs, Operating and administrative expense, Other income and Interest expense.

 

Derivatives in Qualifying Hedging Relationships

The Company uses derivative financial instruments to manage changes in commodity prices, foreign exchange rates, interest rates and certain compensation tied to its share price. Hedge accounting is optional and requires the Company to document the hedging relationship and test the hedging item’s effectiveness in offsetting changes in fair values or cash flows of the underlying hedged item on an ongoing basis. The Company presents the earnings and cash flow effects of hedging items with the hedged transaction. Derivatives in qualifying hedging relationships are categorized as cash flow hedges, fair value hedges and net investment hedges.

 

Cash Flow Hedges

The Company uses cash flow hedges to manage changes in commodity prices, foreign exchange rates, interest rates and certain compensation tied to its share price. The effective portion of the change in the fair value of a cash flow hedging instrument is recorded in Other comprehensive income (OCI) and is reclassified to earnings when the hedged item impacts earnings. Any hedge ineffectiveness is recorded in current period earnings.

 

If a derivative instrument designated as a cash flow hedge ceases to be effective or is terminated, hedge accounting is discontinued and the gain or loss at that date is deferred in OCI and recognized concurrently with the related transaction. If a hedged anticipated transaction is no longer probable, the gain or loss is recognized immediately in earnings. Subsequent gains and losses from derivative instruments for which hedge accounting has been discontinued are recognized in earnings in the period in which they occur.

 

Fair Value Hedges

The Company may use fair value hedges to hedge the fair value of debt instruments or commodity positions. The change in the fair value of the hedging instrument is recorded in earnings with changes in the fair value of the hedged asset or liability that is designated as part of the hedging relationship. If a fair value hedge is discontinued or ceases to be effective, the hedged asset or liability, otherwise required to be carried at cost or amortized cost, ceases to be remeasured at fair value and the cumulative fair value adjustment to the carrying value of the hedged item is recognized in earnings over the remaining life of the hedged item. The Company did not have any fair value hedges at December 31, 2011 or 2010.

 

Net Investment Hedges

The Company uses net investment hedges to manage the carrying values of United States dollar denominated foreign operations. The effective portion of the change in the fair value of the hedging instrument is recorded in OCI. Any ineffectiveness is recorded in current period earnings. Amounts recorded in Accumulated other comprehensive income/loss (AOCI) are recognized in earnings when there is a reduction of the hedged net investment resulting from a disposal of the foreign operation.

 

Classification of Derivatives

The Company recognizes the fair market value of derivative instruments on the statement of financial position as current and long-term assets or liabilities depending on the timing of the settlements and the resulting cash flows associated with the instruments.  Fair value amounts related to cash flows occurring beyond one year are classified as non-current.

 

Balance Sheet Offset

Assets and liabilities arising from derivative instruments are offset in the Consolidated Statements of Financial Position when the Company has the legal right and intention to settle them on a net basis.

 

 

12



 

Transaction Costs

Transaction costs are incremental costs directly related to the acquisition of a financial asset or the issuance of a financial liability. The Company incurs transaction costs primarily through the issuance of debt and classifies these costs with Deferred amounts and other assets. These costs are amortized using the effective interest rate method over the life of the related debt instrument.

 

EQUITY INVESTMENTS

Equity investments over which the Company exercises significant influence, but does not have controlling financial interests, are accounted for using the equity method. Equity investments are initially measured at cost and are adjusted for the Company’s proportionate share of undistributed equity earnings or loss. Equity investments are increased for contributions made to and decreased for distributions received from the investees.

 

OTHER INVESTMENTS

Generally, the Company classifies equity investments in entities over which it does not exercise significant influence and that do not trade on an actively quoted market as other investments carried at cost. Financial assets in this category are initially recorded at fair value with no subsequent re-measurement. Dividends received from these financial assets are recognized in earnings when the right to receive payment is established.

 

NONCONTROLLING INTERESTS

Noncontrolling interests represent the outstanding ownership interests attributable to third parties in certain consolidated subsidiaries, limited partnerships and VIEs. The portion of the entities not owned by the Company is reflected as noncontrolling interests within the equity section of the Consolidated Statements of Financial Position and, in the case of redeemable noncontrolling interests, within the mezzanine section of the Consolidated Statements of Financial Position between long-term liabilities and equity.

 

The Fund’s noncontrolling interest holders have the option to redeem Fund trust units for cash, subject to certain limitations. Redeemable noncontrolling interest is recognized at the maximum redemption value of the trust units held by third parties, which references the market price of ENF common shares. On a quarterly basis, changes in estimated redemption values are reflected as a charge or credit to retained earnings.

 

INCOME TAXES

The liability method of accounting for income taxes is followed. Deferred income tax assets and liabilities are recorded based on temporary differences between the tax bases of assets and liabilities and their carrying values for accounting purposes. Deferred income tax assets and liabilities are measured using the tax rate that is expected to apply when the temporary differences reverse. For the Company’s regulated operations, a deferred income tax liability is recognized with a corresponding regulatory asset. Any interest and/or penalty incurred related to tax is reflected in Income taxes.

 

FOREIGN CURRENCY TRANSACTIONS AND TRANSLATION

Foreign currency transactions are those transactions whose terms are denominated in a currency other than the currency of the primary economic environment in which the Company or a reporting subsidiary operates, referred to as the functional currency. Transactions denominated in foreign currencies are translated into the functional currency using the exchange rate prevailing at the date of transaction. Monetary assets and liabilities denominated in foreign currencies are translated to the functional currency using the rate of exchange in effect at the balance sheet date whereas non-monetary assets and liabilities are translated at the historical rate of exchange in effect on the date of the transaction. Exchange gains and losses resulting from translation of monetary assets and liabilities are included in the Consolidated Statements of Earnings in the period that they arise.

 

Gains and losses arising from translation of foreign operations’ functional currencies to the Company’s Canadian dollar presentation currency are included in the cumulative translation adjustment component

 

 

13



 

of AOCI and are recognized in earnings when there is a disposal of all of the foreign operation. Asset and liability accounts are translated at the exchange rates in effect on the balance sheet date, while revenues and expenses are translated using monthly average exchange rates.

 

CASH AND CASH EQUIVALENTS

Cash and cash equivalents include short-term investments with a term to maturity of three months or less when purchased.

 

RESTRICTED CASH

Cash and cash equivalents that are restricted, in accordance with specific customer agreements, as to withdrawal or usage are presented as Restricted cash on the Consolidated Statements of Financial Position.

 

LOANS AND RECEIVABLES

Affiliate long-term notes receivable are measured at amortized cost using the effective interest rate method, net of any impairment losses recognized. Accounts receivable and other are measured at cost.

 

ALLOWANCE FOR DOUBTFUL ACCOUNTS

The allowance for doubtful accounts is determined based on collection history. When the Company has determined that further collection efforts are unlikely to be successful, amounts charged to the allowance for doubtful accounts are applied against the impaired accounts receivable.

 

INVENTORY

Inventory is primarily comprised of natural gas in storage held in EGD. Natural gas in storage is recorded at the quarterly prices approved by the OEB in the determination of distribution rates. The actual price of gas purchased may differ from the OEB approved price. The difference between the approved price and the actual cost of the gas purchased is deferred as a liability for future refund or as an asset for collection as approved by the OEB. Other commodities inventory is recorded at the lower of cost, as determined on a weighted average basis, or market value. Upon disposition, inventory is recorded to Commodity costs in the Consolidated Statement of Earnings at the weighted average cost of inventory, including any adjustments recorded to reduce inventory to market value.

 

PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment is recorded at historical cost. Expenditures for construction, expansion, major renewals and betterments are capitalized. Maintenance and repair costs are expensed as incurred. Expenditures for project development are capitalized if they are expected to have future benefit. The Company capitalizes interest incurred during construction for non rate-regulated assets. For rate regulated assets, AFUDC is included in the cost of property, plant and equipment and is depreciated over future periods as part of the total cost of the related asset. AFUDC includes both an interest component and, if approved by the regulator, a cost of equity component.

 

The Company uses the group method of depreciation for all property, plant and equipment, except for the non rate-regulated assets in Canada and the United States, which are depreciated on a single asset basis. Depreciation is provided on a straight-line basis over the estimated useful lives of the assets commencing when the asset is placed in service. Under the group method, upon the disposition of property, plant and equipment, the net book value less net proceeds is typically charged to accumulated depreciation and no gain or loss on disposal is recognized. However, when a separately identifiable group of assets, such as a stand-alone pipeline system, is sold, a gain or loss is recognized in the Consolidated Statements of Earnings for the difference between the cash received and the net book value of the assets sold.

 

DEFERRED AMOUNTS AND OTHER ASSETS

Deferred amounts and other assets primarily include: costs which regulatory authorities have permitted, or are expected to permit, to be recovered through future rates including deferred income taxes; contractual receivables under the terms of long-term delivery contracts; derivative financial instruments; direct financing lease receivable; as well as deferred financing costs. Deferred financing costs are amortized using the effective interest method over the term of the related debt.

 

 

14



 

INTANGIBLE ASSETS

Intangible assets consist primarily of acquired long-term transportation or power purchase agreements, natural gas supply opportunities, and certain software costs. Natural gas supply opportunities are growth opportunities, identified upon acquisition, present in gas producing zones where certain of EEP’s gas systems are located. The Company capitalizes costs incurred during the application development stage of internal use software projects. Intangible assets are amortized on a straight-line basis over their expected lives, commencing when the asset is available for use.

 

GOODWILL

Goodwill represents the excess of the purchase price over the fair value of net identifiable assets on acquisition of a business. The carrying value of goodwill, which is not amortized, is assessed for impairment annually, or more frequently if events or changes in circumstances arise that suggest the carrying value of goodwill may be impaired. For the purposes of impairment testing, reporting units are identified as business operations within an operating segment. Potential impairment is identified when the carrying value of a reporting unit, including allocated goodwill, exceeds its fair value. Goodwill impairment is measured as the excess of the carrying amount of the reporting unit’s allocated goodwill over the implied fair value of the goodwill based on the fair value of the assets and liabilities of the reporting unit.

 

IMPAIRMENT

The Company reviews the carrying values of its long-lived assets as events or changes in circumstances warrant. If it is determined that the carrying value of an asset exceeds the undiscounted cash flows expected from the asset, the asset is written down to fair value.

 

With respect to investments in debt and equity securities, the Company assesses at each balance sheet date whether there is objective evidence that a financial asset is impaired by completing a quantitative or qualitative analysis of factors impacting the investment. If there is determined to be objective evidence of impairment, the Company internally values the expected discounted cash flows using observable market inputs and determines whether the decline below carrying value is other than temporary. If the decline is determined to be other than temporary, an impairment charge is recorded in earnings with an offsetting reduction to the carrying value of the asset.

 

With respect to other financial assets, the Company assesses the assets for impairment when it no longer has reasonable assurance of timely collection. If evidence of impairment is noted, the Company reduces the value of the financial asset to its estimated realizable amount, determined using discounted expected future cash flows.

 

ASSET RETIREMENT OBLIGATIONS

AROs associated with the retirement of long-lived assets are measured at fair value and recognized as Other long-term liabilities in the period in which they can be reasonably determined. The fair value approximates the cost a third party would charge to perform the tasks necessary to retire such assets and is recognized at the present value of expected future cash flows. AROs are added to the carrying value of the associated asset and depreciated over the asset’s useful life. The corresponding liability is accreted over time through charges to earnings and is reduced by actual costs of decommissioning and reclamation. The Company’s estimates of retirement costs could change as a result of changes in cost estimates and regulatory requirements.

 

For the majority of the Company’s assets it is not possible to make a reasonable estimate of AROs due to the indeterminate timing and scope of the asset retirements.

 

RETIREMENT AND POSTRETIREMENT BENEFITS

The Company maintains pension plans which provide defined benefit and defined contribution pension benefits.

 

Defined benefit pension plan costs are determined using actuarial methods and are funded through contributions determined using the projected benefit method, which incorporates management’s best

 

 

15



 

estimate of future salary levels, other cost escalations, retirement ages of employees and other actuarial factors including discount rates which are determined using either the Citigroup Pension Discount Curve (United States Plan) or the discount rate curve developed by the Canadian Institute of Actuaries (Canadian Plans). Pension cost is charged to earnings and includes:

 

·                  Cost of pension plan benefits provided in exchange for employee services rendered during the year;

·                  Amortization of the prior service costs and amendments on a straight-line basis over the expected average remaining service period of the active employee group covered by the plans;

·                  Interest cost of pension plan obligations;

·                  Expected return on pension fund assets; and

·                  Amortization of cumulative unrecognized net actuarial gains and losses in excess of 10% of the greater of the accrued benefit obligation or the fair value of plan assets, over the expected average remaining service life of the active employee group covered by the plans.

 

Actuarial gains and losses arise from the difference between the actual and expected rate of return on plan assets for that period or from changes in actuarial assumptions used to determine the accrued benefit obligation, including discount rate or salary inflation experience.

 

Pension plan assets are measured at fair value. The expected return on pension plan assets is determined using market related values and assumptions on the specific invested asset mix within the pension plans. The market related values reflect estimated return on investments consistent with long-term historical averages for similar assets.

 

For defined contribution plans, contributions made by the Company are expensed in the period in which the contribution occurs.

 

The Company also provides other postretirement benefits (OPEB) other than pensions, including group health care and life insurance benefits for eligible retirees, their spouses and qualified dependents. The cost of such benefits is accrued during the years in which employees render service.

 

The overfunded or underfunded status of defined benefit pension and OPEB are recognized as Deferred amounts and other assets or Other long-term liabilities on the Consolidated Statements of Financial Position. A plan’s funded status is measured as the difference between the fair value of plan assets and the plan’s accrued benefit obligation. Any unrecognized actuarial gains and losses and prior service costs and credits that arise during the period are recognized as a component of OCI, net of tax.

 

Certain regulated operations of the Company recover pension and OPEB expense based on amounts paid in accordance with the methodology accepted by the regulators for rate-making purposes. As a result, rates typically only include the recovery of required contributions. A corresponding pension regulatory asset has been recorded reflecting the Company’s ability to incorporate this amount in future rates.  In the absence of rate regulation, these balances would not be recorded and pension costs would be charged to earnings based on the accrual basis of accounting. No regulatory asset has been recorded for the difference between net periodic OPEB expense and the amount considered for rate-making purposes.

 

STOCK-BASED COMPENSATION

Incentive Stock Options (ISOs) granted are recorded using the fair value method. Under this method, compensation expense is measured at the grant date based on the fair value as calculated by the Black-Scholes-Merton model and is recognized on a straight-line basis over the shorter of the vesting period or the period to early retirement eligibility, with a corresponding credit to Additional paid-in capital. Balances in Additional paid-in capital are transferred to Share capital when the options are exercised.

 

Performance based stock options (PBSOs) granted are recorded using the fair value method. Under this method, compensation expense is measured at the grant date based on the fair value as calculated by the Bloomberg barrier option valuation model and is recognized on a straight-line basis with a corresponding credit to Additional paid-in capital. The options become exercisable when both

 

 

16



 

performance targets and time vesting requirements have been met. Balances in Additional paid-in capital are transferred to Share capital when the options are exercised.

 

Performance Stock Units (PSUs) and Restricted Stock Units (RSUs) are cash settled awards for which the related liability is remeasured each reporting period. PSUs vest at the completion of a three-year term and RSUs vest at the completion of a 35-month term. During the vesting term, an expense is recorded based on the number of units outstanding and the current market price of the Company’s shares with an offset to Accounts payable and other or Other long-term liabilities. The value of the PSUs is also dependent on the Company’s performance relative to performance targets set out under the plan.

 

COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES

The Company expenses or capitalizes, as appropriate, expenditures for ongoing compliance with environmental regulations that relate to past or current operations. The Company expenses costs incurred for remediation of existing environmental contamination caused by past operations that do not benefit future periods. The Company records liabilities for environmental matters when assessments indicate that remediation efforts are probable and the costs can be reasonably estimated. Estimates of environmental liabilities are based on currently available facts, existing technology and presently enacted laws and regulations taking into consideration the likely effects of inflation and other factors. These amounts also consider prior experience in remediating contaminated sites, other companies’ clean-up experience and data released by government organizations. The Company’s estimates are subject to revision in future periods based on actual costs or new information and are included in Environmental liabilities and Other long-term liabilities in the Consolidated Statements of Financial Position at their undiscounted amounts. The Company evaluates recoveries from insurance coverage separately from the liability and, when recovery is probable, the Company records and reports an asset separately from the associated liability in the Consolidated Statements of Financial Position.

 

Liabilities for other commitments and contingencies are recognized when it is either probable that an asset has been impaired, or that a liability has been incurred, and the amount of impairment or loss can be reasonably estimated. When a range of probable loss can be estimated, the Company recognizes the most likely amount, or if no amount is more likely than another, the minimum of the range of probable loss is accrued. The Company expenses legal costs associated with loss contingencies as such costs are incurred.

 

3.          CHANGES IN ACCOUNTING POLICIES

 

FUTURE ACCOUNTING POLICY CHANGES

Fair Value Measurement

In May 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2011-04, which revises the existing guidance on the disclosure of fair value measurements under U.S. GAAP as part of the FASB’s joint project with the International Accounting Standards Board. Under the revised standard, the Company will be required to provide additional disclosures about fair value measurements, including information about the unobservable inputs and assumptions used in Level 3 fair value measurements, a description of the valuation methodologies used in Level 3 fair value measurements, and the level in the fair value hierarchy of items that are not measured at fair value but whose fair value disclosure is required. This accounting update is effective for the first reporting period beginning after December 15, 2011.

 

Statement of Comprehensive Income

In June 2011, the FASB issued ASU 2011-05, which updates the existing guidance on comprehensive income under U.S. GAAP, requiring presentation of earnings and OCI either in one continuous statement, referred to as the statement of comprehensive income, or in two separate, but consecutive, statements of earnings and OCI. The adoption of this pronouncement does not affect the Company’s presentation of comprehensive income, and will not have an impact on the Company’s consolidated financial statements. This accounting update is effective for the first reporting period beginning after December 15, 2011.

 

 

17



 

Goodwill Impairment

In September 2011, the FASB issued ASU 2011-08, which is intended to reduce the overall costs and complexity of goodwill impairment testing. The standard allows an entity to first assess qualitative factors to determine whether it is necessary to perform the current two-step goodwill impairment test. An entity will not be required to calculate the fair value of a reporting unit unless the entity determines, based on a qualitative assessment, that it is more likely than not that its fair value is less than its carrying amount. The standard does not change the current two-step test and applies to all entities that have goodwill reported in their financial statements. This accounting update will be effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011.

 

Balance Sheet Offsetting

In December 2011, the FASB issued ASU 2011-11, which provides enhanced disclosures on the effect or potential effect of netting arrangements on an entity’s financial position. The adoption of the pronouncement affects financial statement disclosures only and is not anticipated to have a material impact on the Company’s consolidated financial statements. This accounting update is effective for annual and interim periods beginning on or after January 1, 2013.

 

4.          SEGMENTED INFORMATION

 

Year ended December 31, 2011

 

Liquids
Pipelines

 

Gas
Distribution

 

Gas Pipelines,
Processing
and Energy
Services

 

Sponsored
Investments

 

Corporate

 

Consolidated

 

(millions of Canadian dollars)

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues

 

1,942

 

2,444

 

13,599

 

8,996

 

-

 

26,981

 

Commodity and gas distribution costs

 

-

 

(1,210)

 

(13,051)

 

(6,812)

 

-

 

(21,073)

 

Operating and administrative

 

(752)

 

(508)

 

(138)

 

(847)

 

(36)

 

(2,281)

 

Depreciation and amortization

 

(322)

 

(320)

 

(75)

 

(383)

 

(12)

 

(1,112)

 

Environmental costs, net of recoveries

 

-

 

-

 

-

 

116

 

-

 

116

 

 

 

868

 

406

 

335

 

1,070

 

(48)

 

2,631

 

Income/(loss) from equity investments

 

5

 

-

 

153

 

57

 

(5)

 

210

 

Other income/(expense)

 

31

 

(12)

 

40

 

68

 

(10)

 

117

 

Interest expense

 

(256)

 

(166)

 

(56)

 

(350)

 

(100)

 

(928)

 

Income taxes recovery/(expense)

 

(140)

 

(54)

 

(166)

 

(171)

 

5

 

(526)

 

Earnings/(loss) from continuing operations

 

508

 

174

 

306

 

674

 

(158)

 

1,504

 

Extraordinary item, net of tax

 

-

 

(262)

 

-

 

-

 

-

 

(262)

 

Earnings

 

508

 

(88)

 

306

 

674

 

(158)

 

1,242

 

Earnings attributable to noncontrolling interests and redeemable noncontrolling interests

 

(3)

 

-

 

(1)

 

(405)

 

-

 

(409)

 

Preference share dividends

 

-

 

-

 

-

 

-

 

(13)

 

(13)

 

Earnings/(loss) attributable to Enbridge Inc. common shareholders

 

505

 

(88)

 

305

 

269

 

(171)

 

820

 

Additions to property, plant and equipment1

 

902

 

483

 

850

 

1,187

 

33

 

3,455

 

Total assets

 

12,470

 

7,189

 

4,468

 

13,453

 

3,997

 

41,577

 

 

 

18



 

Year ended December 31, 2010

 

Liquids
Pipelines

 

Gas
Distribution

 

Gas Pipelines,
Processing
and Energy
Services

 

Sponsored
Investments

 

Corporate

 

Consolidated

 

(millions of Canadian dollars)

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues

 

1,627

 

2,414

 

9,604

 

7,805

 

-

 

21,450

 

Commodity and gas distribution costs

 

-

 

(1,179)

 

(9,386)

 

(5,890)

 

-

 

(16,455)

 

Operating and administrative

 

(579)

 

(508)

 

(100)

 

(807)

 

(38)

 

(2,032)

 

Depreciation and amortization

 

(303)

 

(310)

 

(55)

 

(339)

 

(10)

 

(1,017)

 

Environmental costs

 

-

 

-

 

-

 

(619)

 

-

 

(619)

 

 

 

745

 

417

 

63

 

150

 

(48)

 

1,327

 

Income from equity investments

 

9

 

-

 

151

 

59

 

9

 

228

 

Other income/(expense)

 

139

 

(17)

 

28

 

51

 

117

 

318

 

Interest expense

 

(224)

 

(179)

 

(51)

 

(295)

 

(116)

 

(865)

 

Income taxes recovery/(expense)

 

(136)

 

(66)

 

(61)

 

(44)

 

80

 

(227)

 

Earnings/(loss)

 

533

 

155

 

130

 

(79)

 

42

 

781

 

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

 

(2)

 

(5)

 

-

 

177

 

-

 

170

 

Preference share dividends

 

-

 

-

 

-

 

-

 

(7)

 

(7)

 

Earnings attributable to Enbridge Inc. common shareholders

 

531

 

150

 

130

 

98

 

35

 

944

 

Additions to property, plant and equipment1

 

741

 

387

 

1,114

 

884

 

-

 

3,126

 

Total assets

 

11,593

 

7,377

 

4,966

 

11,033

 

1,583

 

36,552

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year ended December 31, 2009

 

Liquids
Pipelines

 

Gas
Distribution

 

Gas Pipelines,
Processing
and Energy
Services

 

Sponsored
Investments

 

Corporate

 

Consolidated

 

(millions of Canadian dollars)

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues

 

1,257

 

2,828

 

7,024

 

6,588

 

5

 

17,702

 

Commodity and gas distribution costs

 

-

 

(1,586)

 

(6,900)

 

(4,651)

 

-

 

(13,137)

 

Operating and administrative

 

(526)

 

(511)

 

(97)

 

(893)

 

(31)

 

(2,058)

 

Depreciation and amortization

 

(223)

 

(298)

 

(45)

 

(323)

 

(8)

 

(897)

 

Environmental costs

 

-

 

-

 

-

 

(3)

 

-

 

(3)

 

 

 

508

 

433

 

(18)

 

718

 

(34)

 

1,607

 

Income from equity investments

 

20

 

-

 

140

 

61

 

11

 

232

 

Other income/(expense) and gain on sale of investments

 

165

 

(12)

 

353

 

25

 

515

 

1,046

 

Interest expense

 

(145)

 

(187)

 

(35)

 

(262)

 

(122)

 

(751)

 

Income taxes expense

 

(102)

 

(59)

 

(44)

 

(104)

 

(3)

 

(312)

 

Earnings from continuing operations

 

446

 

175

 

396

 

438

 

367

 

1,822

 

Loss from discontinued operations, net of tax

 

-

 

-

 

-

 

(70)

 

-

 

(70)

 

Earnings

 

446

 

175

 

396

 

368

 

367

 

1,752

 

Earnings attributable to noncontrolling interests and redeemable noncontrolling interests

 

(2)

 

(6)

 

-

 

(225)

 

(1)

 

(234)

 

Preference share dividends

 

-

 

-

 

-

 

-

 

(7)

 

(7)

 

Earnings attributable to Enbridge Inc. common shareholders

 

444

 

169

 

396

 

143

 

359

 

1,511

 

Additions to property, plant and equipment1

 

2,678

 

326

 

230

 

1,409

 

10

 

4,653

 

 

1    Includes allowance for equity funds used during construction (AEDC).

 

The measurement basis for preparation of segmented information is consistent with the significant accounting policies described in Note 2.

 

 

19



 

GEOGRAPHIC INFORMATION

Revenues1

 

Year ended December 31, 

 

2011

 

2010

 

2009

 

(millions of Canadian dollars)

 

 

 

 

 

 

 

Canada

 

12,025

 

9,315

 

7,410

 

United States

 

14,956

 

12,135

 

10,292

 

 

 

26,981

 

21,450

 

17,702

 

 

1   Revenues are based on the country of origin of the product or service sold.

 

Property, Plant and Equipment

 

December 31, 

 

2011

 

2010

 

(millions of Canadian dollars)

 

 

 

 

 

Canada

 

16,557

 

15,015

 

United States

 

12,384

 

11,340

 

 

 

28,941

 

26,355

 

 

5.          FINANCIAL STATEMENT EFFECTS OF RATE REGULATION

 

GENERAL INFORMATION ON RATE REGULATION AND ITS ECONOMIC EFFECTS

A number of businesses within the Company are subject to regulation. The Company’s significant regulated businesses and related accounting impacts are described below.

 

Canadian Mainline

The Canadian Mainline includes the Canadian portion of the mainline system. The primary business activities of the Canadian Mainline are subject to regulation by the NEB. Prior to July 1, 2011, the incentive tolling settlement (ITS) defined the methodology for calculation of tolls and the revenue requirement on the core component of the Canadian Mainline. Toll adjustments, for variances from requirements defined in the ITS, were filed annually with the regulator for approval. Surcharges were also determined for a number of system expansion components and were added to the base toll determined for the core system.

 

Effective July 1, 2011, Canadian Mainline earnings (excluding Lines 8 and 9) were governed by the CTS. The CTS covers local tolls to be charged for service on the Canadian Mainline and supersedes all existing toll agreements on the Canadian Mainline during the ten year term of the CTS.  While the CTS is based on previous tolling settlements and cost of service principles, the Company retains some risk associated with volume throughput and capital and operating costs, subject to various protection mechanisms. As a result, the Canadian Mainline operations (excluding Lines 8 and 9) no longer meet all of the criteria required for the continued application of rate-regulated accounting treatment and the Company discontinued the application of rate-regulated accounting on a prospective basis commencing July 1, 2011.

 

The regulatory asset of approximately $470 million related to deferred income taxes recorded at the date of discontinuance will continue to be recognized as the Company retains the ability to recover deferred income taxes under an NEB order governing flow-through income tax treatment. In the same manner, the rate order provides for the recovery of deferred income taxes incurred subsequent to the discontinuance of rate-regulated accounting, and, as such, regulatory assets related to deferred income taxes will continue to be recognized as incurred. The regulatory asset of approximately $70 million related to tolling deferrals recorded at the date of discontinuance is being recovered through a toll surcharge over a period of two years.

 

Southern Lights

The United States portion of the Southern Lights Pipeline is regulated by the FERC and the Canadian portion of the pipeline is regulated by the NEB. Shippers on the Southern Lights Pipeline are subject to 15-year transportation contracts under a cost of service toll methodology. Toll adjustments are filed

 

 

20



 

annually with the regulators. Tariffs provide for recovery of all operating and debt financing costs, plus a pre-determined after-tax rate of return on equity (ROE) of 10%. Southern Lights Pipeline tolls are based on a deemed 70% debt and 30% equity structure.

 

Enbridge Gas Distribution

EGD’s gas distribution operations are regulated by the OEB. EGD’s rates are based on a revenue per customer cap incentive regulation methodology that expires in December 2012, which adjusts revenues, and consequently rates, annually and relies on an annual process to forecast volume and customer additions.

 

EGD’s after-tax rate of return on common equity embedded in rates was 8.39% for the years ended December 31, 2011,  2010 and 2009 based on a 36% deemed common equity component of capital for regulatory purposes for each of those years.

 

Enbridge Gas New Brunswick

Enbridge Gas New Brunswick (EGNB) is regulated by the EUB and an application for rate adjustments is filed annually for EUB approval. EGNB’s after-tax ROE for the year ended December 31, 2011 was 10.90% (2010 - 13.00%; 2009 - 13.00%) based on equity which is capped at 45%.

 

Due to amendments in the rate setting methodology enacted by the Government of New Brunswick in a final rates and tariffs regulation published in April 2012, EGNB no longer meets the criteria for the continuation of rate regulated accounting. As a result, the EGNB regulatory deferral has been written off as at December 31, 2011 as described in Note 30, Subsequent event.

 

FINANCIAL STATEMENT EFFECTS

Accounting for rate-regulated activities has resulted in the recognition of the following significant regulatory assets and liabilities:

 

December 31, 

 

2011 

 

2010

 

Estimated Settlement
Period (years)

 

(millions of Canadian dollars)

 

 

 

 

 

 

 

Regulatory assets/(liabilities)

 

 

 

 

 

 

 

Liquids Pipelines

 

 

 

 

 

 

 

Deferred income taxes

 

527

 

479

 

-

 

Tolling deferrals2

 

14

 

132

 

1

 

Deferred transportation revenue3

 

84

 

32

 

29

 

Gas Distribution

 

 

 

 

 

 

 

Deferred income taxes

 

170

 

211

 

-

 

EGNB regulatory deferral

 

-

 

171

 

-

 

Future removal and site restoration reserves

 

(836)

 

(773)

 

-

 

Purchased gas variance

 

-

 

(144)

 

1

 

Pension plans7

 

108

 

(58)

 

-

 

Sponsored Investments

 

 

 

 

 

 

 

Deferred income taxes

 

83

 

94

 

-

 

 

1           The asset represents the regulatory offset to deferred income tax liabilities to the extent that deferred income taxes are expected to be included in regulator-approved future rates and recovered from or refunded to future customers. The recovery period depends on future temporary differences.

 

2           Tolls for regulated pipelines under a cost of service methodology are established each year based on capacity and the allowed revenue requirement. Where actual volumes shipped on the pipeline result in an under or over collection of the annual revenue requirement, a regulatory asset or liability is recognized and incorporated into tolls in the subsequent year or in accordance with the related agreement.

 

3           Deferred transportation revenue is related to the cumulative difference between U.S. GAAP depreciation expense for Southern Lights and the negotiated depreciation rates included in the regulated transportation tolls. The Company expects to recover this difference after 2020 when depreciation rates in the transportation agreements are expected to exceed U.S. GAAP depreciation rates.

 

4           At December 31, 2010, a regulatory deferral account captures the cumulative difference between EGNB’s distribution revenues and its cost of service revenue requirement. Due to a change in regulation enacted by the Government of New Brunswick in April 2012, the EGNB regulatory deferral has been written off at December 31, 2011 as EGNB no longer meets the criteria for rate regulated accounting. See Note 30, Subsequent event.

 

 

21



 

5           The future removal and site restoration reserves balance results from amounts collected from customers by certain of the Company’s businesses, with the approval of the regulator, to fund future costs for removal and site restoration relating to property, plant and equipment. These costs are collected as part of depreciation charged on property, plant and equipment. The balance represents the amount that has been collected from customers, net of actual costs expended on removal and site restoration. The settlement of this balance will occur as future removal and site restoration costs are incurred.

 

6           Purchased gas variance is the difference between the actual cost and the approved cost of natural gas reflected in rates. EGD has been granted OEB approval to refund this balance to customers in the following year.

 

7           The pension plan balance represents the regulatory offset to the pension plan liability to the extent that the amounts are to be collected from customers in future rates. The settlement period for this balance is not determinable. EGD continues to record and recover pension expenditures through rates on a cash basis.

 

OTHER ITEMS AFFECTED BY RATE REGULATION

Allowance for Funds Used During Construction and Other Capitalized Costs

Under the pool method prescribed by certain regulators, it is not possible to identify the carrying value of the equity component of AFUDC or its effect on depreciation. Similarly, gains or losses on the retirement of certain specific fixed assets in any given year cannot be identified or quantified.

 

Operating Cost Capitalization

With the approval of regulators, certain operations capitalize a percentage of certain operating costs. These operations are authorized to charge depreciation and earn a return on the net book value of such capitalized costs in future years. In the absence of rate regulation, a portion of such operating costs would be charged to earnings in the year incurred.

 

EGD entered into a consulting contract relating to asset management initiatives. The majority of the costs, primarily consulting fees, are being capitalized to gas mains in accordance with regulatory approval. At December 31, 2011, cumulative costs relating to this consulting contract of $133 million (2010 - $124 million) were included in property plant and equipment and are being depreciated over the average service life of 25 years. In the absence of rate regulation, some of these costs would be charged to earnings in the year incurred.

 

6.          ACQUISITIONS, DISPOSITIONS AND DISCONTINUED OPERATIONS

 

ACQUISITIONS

Seaway Crude Pipeline Company

On December 20, 2011, Enbridge acquired 50% of the outstanding common units in Seaway Pipeline, a partnership engaged in the crude oil pipeline business in Texas, for cash consideration of $1.2 billion (US$1.2 billion). The Company’s investment in Seaway Pipeline is accounted for as a joint venture using the equity method (Note 11) within the Liquids Pipeline segment.

 

December 20,

 

2011

 

(millions of Canadian dollars)

 

 

 

Fair value of net assets acquired:

 

 

 

Current assets

 

5

 

Property, plant and equipment

 

536

 

Goodwill

 

638

 

Current liabilities

 

(4

)

 

 

1,175

 

 

 

 

 

Purchase Price:

 

 

 

Cash (net of $9 million cash acquired)

 

1,175

 

 

A net loss of $1 million related to transaction costs was recognized in Earnings for the year ended December 31, 2011. Had the acquisition occurred on January 1, 2011, an unaudited proforma net loss of $2 million, including $1 million of transaction costs, would have been recognized as earnings.  The entire amount of acquired goodwill is expected to be tax deductible for United States income tax purposes.

 

 

22



 

Tonbridge Power Inc.

On October 13, 2011, Enbridge acquired 100% of the 36 million outstanding common shares of Tonbridge Power Inc. (Tonbridge), an independent company engaged in constructing an electric transmission line between Montana and Alberta, for $20 million in cash at a price of $0.54 per share.

 

October 13,

 

2011

 

(millions of Canadian dollars)

 

 

 

Fair value of net assets acquired:

 

 

 

Working capital deficiency

 

(5

)

Property, plant and equipment

 

196

 

Intangible assets

 

17

 

Long-term debt

 

(182

)

Other long-term liabilities

 

(21

)

 

 

5

 

 

 

 

 

Purchase Price:

 

 

 

Cash (net of $15 million cash acquired)

 

5

 

 

No revenue from Tonbridge was recognized in 2011 as the transmission line is not yet in service. A net loss of $1 million was recognized in income for the period from October 13, 2011 to December 31, 2011 related to operating and administrative expenses. An unaudited proforma net loss of $38 million, including $6 million of transaction costs, would have been recognized in income in 2011 had the acquisition occurred on January 1, 2011.

 

Elk City Natural Gas Gathering and Processing System

On September 16, 2010, the Company acquired a 100% ownership interest in entities that comprise the Elk City Natural Gas Gathering and Processing System (Elk City System) for $705 million (US$686 million). The results of operations of Elk City System have been included within the Sponsored Investments segment from the date of acquisition.

 

September 16,

 

2010

 

(millions of Canadian dollars)

 

 

 

Fair value of net assets acquired:

 

 

 

Current assets

 

4

 

Property, plant and equipment, net

 

503

 

Intangible assets1

 

194

 

Other assets

 

5

 

Other long-term liabilities

 

(1

)

 

 

705

 

 

 

 

 

Purchase price:

 

 

 

Cash

 

705

 

 

1           Intangible assets acquired are natural gas supply opportunities, which are being amortized on a straight line basis over the weighted average estimated useful life of the underlying reserves at the time of acquisition, which approximate 25 to 30 years.

 

Other Acquisitions

In August 2010, the Company acquired an additional 20% interest in Olympic Pipe Line Company (Olympic), a refined products pipeline, for $12 million, increasing its ownership interest to 85%. As the Company now controls the entity, it has consolidated its interest in Olympic. Prior to August 9, 2010, the entity was accounted for as a joint venture using the equity method.

 

In June 2010, the Company acquired the remaining 50% interest in Hardisty Caverns Limited Partnership (Hardisty Caverns), an oil storage facility, for $52 million, increasing its ownership interest to 100%. The original equity interest and noncontrolling interest were re-measured to fair value on the date control was obtained and a $22 million gain was recorded in Other income (Note 25) for the year ended December 31,

 

 

23



 

2010. As the Company now controls the entity, it has consolidated its interest in Hardisty Caverns. Prior to June 16, 2010, the entity was accounted for as a joint venture using the equity method.

 

During the year ended December 31, 2010, the Company acquired the remaining 27.5% of EGNB limited partnership units held by third parties for $52 million, increasing its partnership interest to 100%.

 

Other acquisitions during 2010 totaled $29 million (US$27 million) and are included within the Sponsored Investments segment.

 

During the year ended December 31, 2009, the Company purchased the additional 50% interest in Starfish Pipeline Company, LLC (Starfish Pipeline) for $28 million (US$27 million), increasing its ownership percentage to 100%. As the Company established control over the entity effective December 31, 2009, it has consolidated its interest in Starfish Pipeline from that date forward. Prior to December 31, 2009, the entity was accounted for as a joint venture using the equity method.

 

Proforma consolidated revenues and earnings that give effect to all other Company’s acquisitions as if they had occurred as of January 1 in the year of acquisition are not presented as the information would not be materially different from the information presented in the accompanying Consolidated Statements of Earnings.

 

DISPOSITIONS
Gain on Sale of Investments

December 31,

 

2011

 

2010

 

2009

 

(millions of Canadian dollars)

 

 

 

 

 

 

NetThruPut (NTP)

 

-

 

-

 

29

Oleoducto Central S.A. (OCENSA)

 

-

 

-

 

336

 

 

-

 

-

 

365

 

NTP

On May 1, 2009, the Company sold its investment in NTP, an internet-based exchange facility for physical crude oil products, for proceeds of $32 million. Earnings generated by the NTP investment for the year ended December 31, 2009 were $1 million and are included in the Corporate operating segment.

 

OCENSA

On March 17, 2009, the Company sold its investment in OCENSA, a crude oil pipeline in Colombia, for proceeds of $512 million (US$402 million). Earnings and cash flows from operating activities generated by this investment for the year ended December 31, 2009 were $7 million. Earnings from the OCENSA investment were included in the Gas Pipelines, Processing and Energy Services operating segment. As a result of the sale of OCENSA, the Company reclassified $20 million of after-tax gains on unrealized cash flow hedges from OCI to earnings in the year ended December 31, 2009.

 

DISCONTINUED OPERATIONS

On November 1, 2009, EEP sold non-core natural gas pipeline assets for cash proceeds of $161 million (US$151 million), excluding any subsequent settlement for working capital as provided in the sale agreement. The loss from discontinued operations, net of tax, of $70 million for the year ended December 31, 2009, resulted from an impairment charge of $70 million. The areas in which the natural gas pipeline assets operated were not strategic to the ongoing operations of EEP’s core natural gas pipeline assets.

 

 

24



 

7.          ACCOUNTS RECEIVABLE AND OTHER

 

December 31,

 

2011

 

2010

 

 

(millions of Canadian dollars)

 

 

 

 

 

Unbilled revenues

 

2,210

 

2,092

 

Trade receivables

 

802

 

849

 

Taxes receivable

 

157

 

205

 

Regulatory assets

 

42

 

170

 

Short-term portion of derivative assets (Note 22)

 

486

 

207

 

Prepaid expenses and deposits

 

54

 

44

 

Current deferred income taxes (Note 23)

 

108

 

2

 

Dividends receivable

 

30

 

11

 

Other

 

180

 

108

 

Allowance for doubtful accounts

 

(58

)

(65

)

 

 

4,011

 

3,623

 

 

8.          INVENTORY

 

December 31,

 

2011

 

2010

 

 

(millions of Canadian dollars)

 

 

 

 

 

Natural gas

 

566

 

655

 

Other commodities

 

257

 

261

 

 

 

823

 

916

 

 

Commodity costs on the Consolidated Statements of Earnings included non-cash charges of $9 million, $9 million and $4 million for the years ended December 31, 2011, 2010 and 2009, respectively, to reduce the cost basis of inventory to market value.

 

 

25



 

9.          PROPERTY, PLANT AND EQUIPMENT

 

 

 

Weighted Average

 

 

 

 

 

December 31,

 

Depreciation Rate

 

2011

 

2010

 

 

(millions of Canadian dollars)

 

 

 

 

 

 

 

Liquids Pipelines

 

 

 

 

 

 

 

Pipeline

 

2.8

%

7,455

 

7,275

 

Pumping equipment, buildings, tanks and other

 

3.5

%

4,982

 

4,603

 

Land and right-of-way

 

3.0

%

230

 

232

 

Under construction

 

 

-

1,089

 

712

 

 

 

 

 

13,756

 

12,822

 

Accumulated depreciation

 

 

 

(3,161

)

(2,817

)

 

 

 

 

10,595

 

10,005

 

Gas Distribution

 

 

 

 

 

 

 

Gas mains, services and other

 

4.0

%

6,846

 

6,605

 

Land and right-of-way

 

2.5

%

79

 

68

 

Under construction

 

 

-

137

 

103

 

 

 

 

 

7,062

 

6,776

 

Accumulated depreciation

 

 

 

(1,419

)

(1,287

)

 

 

 

 

5,643

 

5,489

 

Gas Pipelines, Processing and Energy Services

 

 

 

 

 

 

 

Pipeline

 

3.6

%

568

 

513

 

Wind turbines, solar panels and other1

 

4.9

%

781

 

1,207

 

Land and right-of-way

 

3.6

%

7

 

19

 

Under construction

 

 

-

512

 

620

 

 

 

 

 

1,868

 

2,359

 

Accumulated depreciation

 

 

 

(213

)

(223

)

 

 

 

 

1,655

 

2,136

 

Sponsored Investments

 

 

 

 

 

 

 

Pipeline

 

2.5

%

6,600

 

6,116

 

Pumping equipment, buildings, tanks and other

 

3.3

%

3,792

 

3,406

 

Wind turbines, solar panels and other1

 

3.4

%

1,074

 

-

 

Land and right-of-way

 

2.5

%

611

 

544

 

Under construction

 

 

-

913

 

417

 

 

 

 

 

12,990

 

10,483

 

Accumulated depreciation

 

 

 

(2,213

)

(1,805

)

 

 

 

 

10,777

 

8,678

 

Corporate

 

 

 

 

 

 

 

Other

 

2.9

%

270

 

67

 

Under construction

 

 

-

31

 

-

 

 

 

 

 

301

 

67

 

Accumulated depreciation

 

 

 

(30

)

(20

)

 

 

 

 

271

 

47

 

 

 

 

 

28,941

 

26,355

 

 

1    In October 2011, Enbridge Pipelines Inc. (EPI) sold three renewable energy assets to the Fund. As a result, at December 31, 2011, $1,074 million of property, plant and equipment was reclassified from Gas Pipelines, Processing and Energy Services to Sponsored Investments. The December 31, 2010 balance of $1,103 million has not been reclassified for presentation purposes.

 

Depreciation expense for the year ended December 31, 2011 was $1,089 million (2010 - $987 million; 2009 - $853 million).

 

 

26



 

10. VARIABLE INTEREST ENTITY

 

The Fund is an unincorporated open-ended trust established by a trust indenture under the laws of the Province of Alberta and is considered a VIE by virtue of its capital structure. The Company is the primary beneficiary of the Fund through its combined 69% (2010 - 72%) economic interest, held indirectly through a common investment in ENF, a direct common trust unit investment in the Fund and a preferred unit investment in a wholly-owned subsidiary of the Fund. Enbridge also serves in the capacity of Manager of ENF, the Fund and its subsidiaries.

 

The summarized impact of the Company’s interest in the Fund on earnings, cash flows and financial position is presented below. Earnings include the results of operations of the renewable energy assets transferred from Enbridge subsequent to transfer in October 2011. Earnings, cash flows and financial position information exclude the effect of intercompany transactions.

 

 

Year ended December 31,