Enbridge Annual Report 2012

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Our investors
have come to
expect superior
returns,and
that’s what
we’re delivering.

ENBRIDGE INC. FINANCIAL REPORT 2012

Enbridge Inc., a Canadian company,
is a North American leader in delivering
energy and one of the Global 100 Most
Sustainable Corporations in the World.
As a transporter of energy, Enbridge
operates, in Canada and the U.S., the
world’s longest crude oil and liquids
transportation system. The Company also
has a significant and growing involvement
in natural gas gathering, transmission and
midstream businesses, and an increasing
involvement in power transmission. As a
distributor of energy, Enbridge owns and
operates Canada’s largest natural gas
distribution company, and provides
distribution services in Ontario, Quebec,
New Brunswick and New York State. As a
generator of energy, Enbridge has interests
in close to 1,300 megawatts of renewable
and alternative energy generating capacity
and is expanding its interests in wind and
solar energy, geothermal and hybrid fuel
cells. Enbridge employs approximately
10,000 people, primarily in Canada and the
U.S. and is ranked as one of Canada’s
Greenest Employers and one of the Top
100 Companies to Work for in Canada.
Enbridge’s common shares trade on the
Toronto and New York stock exchanges
under the symbol ENB. For more
information, visit enbridge.com

INVESTOR INFORMATION

COMMON AND PREFERENCE SHARES

The Common Shares of Enbridge Inc. trade in Canada

DIVIDEND REINVESTMENT AND
SHARE PURCHASE PLAN

on the Toronto Stock Exchange and in the United States

Enbridge Inc. offers a Dividend Reinvestment and Share

on the New York Stock Exchange under the trading symbol

Purchase Plan that enables shareholders to reinvest their

‘‘ENB’’. The Preference Shares of Enbridge Inc. trade in

cash dividends in Common Shares and to make additional

Canada on the Toronto Stock Exchange under the following

cash payments for purchases at the market price. Effective

trading symbols:

Series A – ENB.PR.A

Series J – ENB.PR.U

Series B – ENB.PR.B

Series L – ENB.PF.U

Series D – ENB.PR.D

Series N – ENB.PR.N

Series F – ENB.PR.F

Series P – ENB.PR.P

Series H – ENB.PR.H

Series R – ENB.PR.T

with dividends payable on March 1, 2008, participants in

the Plan will receive a two per cent discount on the purchase

of common shares with reinvested dividends. Details may

be obtained from the Investor Information section of the

Enbridge website at or by contacting CIBC Mellon Trust

Company at any of the locations listed above.

REGISTRAR AND TRANSFER AGENT
IN CANADA

NEW YORK STOCK EXCHANGE
DISCLOSURE DIFFERENCES

For information relating to shareholdings, shareholder

investment plan, dividends, direct dividend deposit, dividend

re-investment accounts and lost certificates please contact:

CIBC Mellon Trust Company 1
P.O. Box 700
Station B
Montreal, Québec H3B 3K3
Toll free: 800.387.0825
Internet: www.canstockta.com/investorinquiry

CIBC Mellon Trust Company also has offices in Halifax,

Montreal, Calgary and Vancouver.

Canadian Stock Transfer Company Inc. acts as the Administrative Agent for CIBC
Mellon Trust Company

CO-REGISTRAR AND CO-TRANSFER
AGENT IN THE UNITED STATES

Computershare
480 Washington Blvd.
Jersey City, New Jersey

U.S.A. 07310

AUDITORS

PricewaterhouseCoopers LLP

Enbridge is committed to reducing its impact on the
environment in every way, including the production of this
publication. This report was printed entirely on FSC® Certified
paper containing 100% post-consumer recycled fibre and is
manufactured using biogas and wind energy.

As a foreign private issuer, Enbridge Inc. is required

to disclose any significant ways in which its corporate

governance practices differ from those followed by

United States companies under NYSE listing standards.

This disclosure can be obtained from the U.S. Compliance

subsection of the Corporate Governance section of the

Enbridge website at enbridge.com.

FORM 40-F

The Company files annually with the United States Securities

and Exchange Commission a report known as the Annual

Report on Form 40-F. Copies of the Form 40-F are available,

free of charge, upon written request to the Corporate

Secretary of the Company. In addition a link to it is available

on the ‘‘Reports and Filings’’ subsection of the ‘‘Financial

Reports’’ section of our website.

CORPORATE SOCIAL
RESPONSIBILITY REPORT

Enbridge publishes an annual Corporate Social Responsibility

report. The report is available on the Company’s website at

csr.enbridge.com.

REGISTERED OFFICE

Enbridge Inc.
3000, 425 – 1st Street S.W.
Calgary, Alberta, Canada T2P 3L8
Telephone: 403.231.3900
Facsimile: 403.231.3920
Internet: enbridge.com

Investor Information > 159

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Forward-Looking Information: This Financial Report
includes references to forward-looking information.
By its nature this information applies certain
assumptions and expectations about future
outcomes, so we remind you it is subject to risks
and uncertainties that affect every business,
including ours. The more significant factors and
risks that might affect future outcomes for
Enbridge are listed and discussed in the “Forward-
Looking Information” section on page 8 of this
Financial Report and also in the risk sections of our
public disclosure filings, including Management’s
Discussion and Analysis, available on both the
SEDAR and EDGAR systems at www.sedar.com
and www.sec.gov/edgar.shtml.

2012 FINANCIAL REPORT

MANAGEMENT’S DISCUSSION AND ANALYSIS

2 Overview

4 Performance Overview

9 Corporate Vision, Strategy and Values

13 Industry Fundamentals

50 Gas Pipelines, Processing and Energy Services

59 Sponsored Investments

70 Corporate

72 Liquidity and Capital Resources

16 Growth Projects – Commercially Secured Projects

77 Commitments and Contingencies

Liquids Pipelines

23 Gas Distribution

79 Quarterly Financial Information

80 Related Party Transactions

24 Gas Pipelines, Processing and Energy Services

80 Risk Management and Financial Instruments

27 Sponsored Investments

32 Corporate

87 Critical Accounting Estimates

89 Changes in Accounting Policies

32 Growth Projects – Other Projects Under Development

91 Controls and Procedures

35 Liquids Pipelines

45 Gas Distribution

92 Non-GAAP Reconciliations

CONSOLIDATED FINANCIAL STATEMENTS

93 Management’s Report

94 Independent Auditor’s Report

96 Consolidated Statements of Earnings

97 Consolidated Statements of Comprehensive Income

98 Consolidated Statements of Changes in Equity

99 Consolidated Statements of Cash Flows

100 Consolidated Statements of Financial Position

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
124

1. General Business Description

101

102

2. Summary of Significant Accounting Policies

110

111

113

115

117

118

119

120

122

123

3. Changes in Accounting Policies

4. Segmented Information

5. Financial Statement Effects of Rate Regulation

6. Acquisitions

7. Accounts Receivable and Other

Inventory

9. Property, Plant and Equipment

10. Variable Interest Entity

11. Long-Term Investments

12. Deferred Amounts and Other Assets

13.

Intangible Assets

14. Goodwill

15. Accounts Payable and Other

125

126

127

129

132

133

143

146

151

152

155

16. Debt

17. Other Long-Term Liabilities

18. Noncontrolling Interests

19. Share Capital

20. Stock Option and Stock Unit Plans

21. Components of Accumulated Other Comprehensive Loss

22. Derivative Financial Instruments and Hedging Activities

23.

Income Taxes

24.

Retirement and Postretirement Benefits

25. Other Income

26. Changes in Operating Assets and Liabilities

27. Related Party Transactions

28. Commitments and Contingencies

29. Guarantees

156 Five-Year Consolidated Highlights

159 Investor Information

158 Glossary

> 1

MANAGEMENT’S DISCUSSION AND ANALYSIS

This Management’s Discussion and Analysis (MD&A) dated February 14, 2013 should be read in conjunction with

the audited consolidated financial statements and notes thereto of Enbridge Inc. (Enbridge or the Company) for the

year ended December 31, 2012, prepared in accordance with accounting principles generally accepted in the United

States of America (U.S. GAAP). Where applicable, comparative figures presented within this MD&A have been restated

to correspond to the Company’s consolidated financial statements prepared in accordance with U.S. GAAP for the years

ended December 31, 2011 and 2010. 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.

TOTAL ASSETS
(millions of Canadian dollars)

1
2
7
1

7
4

1
4
9
4
,
1
4

1
2
5
5
,
6
3

2
1
0
7
,
4
2

2
7
0
9
,
9
1

Liquids Pipelines
Gas Distribution
Gas Pipelines, Processing
and Energy Services
Sponsored Investments
Corporate

Overview

Enbridge is a North American leader in delivering energy. As a transporter

of energy, Enbridge operates, in Canada and the United States, the world’s

longest crude oil and liquids transportation system. The Company also has

significant and growing involvement in natural gas gathering, transmission

and midstream businesses and an increasing involvement in power

transmission. As a distributor of energy, Enbridge owns and operates

Canada’s largest natural gas distribution company and provides distribution

services in Ontario, Quebec, New Brunswick and New York State. As a

generator of energy, Enbridge has interests in close to 1,300 megawatts

(MW) of renewable and alternative energy generating capacity and is

expanding its interests in wind, solar and geothermal. Enbridge has

approximately 10,000 employees and contractors, primarily in Canada

and the United States.

The Company’s activities are carried out through five business segments:

Liquids Pipelines; Gas Distribution; Gas Pipelines, Processing and Energy

Services; Sponsored Investments; and Corporate, as discussed below.

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 Canadian Mainline, Regional Oil Sands

System, Southern Lights Pipeline, Seaway Pipeline, Spearhead Pipeline and
Feeder Pipelines and Other.

2 < EN BR IDGE I NC. 2012 FINANCIAL REPO RT

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

and gathering facilities and the Company’s energy services businesses, along with renewable energy projects.

Investments in natural gas pipelines include the Company’s interests in the United States portion of the Alliance

System (Alliance Pipeline US), the Vector Pipeline (Vector) 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 located at the terminus of the Alliance System (Alliance). The energy services businesses

undertake physical commodity marketing activity and manage the Company’s volume commitments on the Alliance,

Vector and other pipeline systems.

SPONSORED INVESTMENTS

Sponsored Investments includes the Company’s 21.8% 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 67.7% 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 NGL. The primary operations of the Fund include renewable power

generation projects, crude oil and liquids pipeline and storage businesses in Western Canada and a 50% interest in the

Canadian portion of the Alliance System (Alliance Pipeline Canada).

CORPORATE

Corporate consists of the Company’s investment in Noverco Inc. (Noverco), new business development activities,

general corporate investments and financing costs not allocated to the business segments.

Management’s Discussion and Analysis > 3

Performance Overview

(millions of Canadian dollars, except per share amounts)

Earnings attributable to common shareholders

Liquids Pipelines

Gas Distribution

Gas Pipelines, Processing and Energy Services

Sponsored Investments

Corporate

Earnings per common share 1
Diluted earnings per common share 1

Adjusted earnings 2
Liquids Pipelines

Gas Distribution

Gas Pipelines, Processing and Energy Services

Sponsored Investments

Corporate

Adjusted earnings per common share 1,2

Cash flow data

Cash provided by operating activities

Cash used in investing activities

Cash provided by financing activities

Dividends

Common share dividends declared
Dividends paid per common share 1

Revenues

Commodity sales

Gas distribution sales

Transportation and other services

Total assets

Total long-term liabilities

Three Months Ended December 31,

Year Ended December 31,

2012

2011

2012

2011

2010

136

127

(52)

(136)

146

0.19

0.18

183

(23)

327

0.42

502

(2,182)

1,725

227

0.2825

5,111

585

1,477

7,173

47,172

25,345

203

(226)

156

(63)

159

0.21

126

(16)

273

0.36

823

(2,676)

1,435

190

0.2450

5,195

568

1,546

7,309

41,949

24,074

726

207

(478)

282

(127)

610

0.79

0.78

684

176

154

263

(28)

1,249

1.62

2,874

(6,204)

4,395

895

1.13

19,101

1,910

4,295

25,306

47,172

25,345

505

(88)

305

269

(171)

820

1.09

1.08

536

173

163

244

(16)

1,100

1.46

3,371

(5,079)

2,030

759

0.98

20,611

1,906

4,536

27,053

41,949

24,074

531

150

125

944

1.27

1.26

511

162

123

206

(25)

977

1.32

1,877

(3,902)

1,957

648

0.85

15,863

1,814

3,843

21,520

36,423

22,171

1
2

Comparative amounts were restated to reflect two-for-one stock split which was effective May 25, 2011.
Adjusted earnings and adjusted earnings per common share are non-GAAP measures that do not have any standardized meaning prescribed by generally accepted
accounting principles. For more information on non-GAAP measures see page 9.

4 < EN BR IDGE I NC. 2012 FINANCIAL REPO RT

EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS

Earnings attributable to common shareholders were $610

million ($0.79 per common share) for the year ended

December 31, 2012 compared with $820 million ($1.09 per

common share) for the year ended December 31, 2011 and

$944 million ($1.27 per common share) for the year ended

December 31, 2010. The Company has delivered significant

earnings growth from operations over the course of the last

three years, as discussed below in Performance Overview –

Adjusted Earnings; however, the positive impact of this

growth was reduced by a number of unusual, non-recurring

or non-operating factors, the most significant of which are

changes in unrealized derivative fair value and foreign

exchange gains or losses. The Company has a comprehensive

long-term economic hedging program to mitigate exposures

to interest rate, foreign exchange and commodity price

exposures. The changes in unrealized mark-to-market

accounting impacts from this program create volatility in

short-term earnings but the Company believes over the

long-term it supports reliable cash flows and dividend

EARNINGS APPLICABLE TO COMMON SHAREHOLDERS
(millions of Canadian dollars)

2
5
5
5
,
1

2
1
2
3
,
1

2
7
6
6

2
5
4
6

2
0
0
2 7
5
1
6

2
6
5
5

1
4
4
9

1
0
2
8

1
0
1
6

growth. Earnings for 2012 and 2011 were also negatively

impacted by the transfer of assets between entities under

common control of Enbridge. Intercompany gains realized

as a result of these asset transfers for both years have been

eliminated for accounting purposes; however, income taxes

of $56 million and $98 million for the years ended December 31,

2012 and 2011, respectively, incurred on the related capital gains

remain as charges to consolidated earnings.

Other significant items impacting the comparability of earnings year-over-year were costs and related insurance

recoveries associated with the Lines 6A, 6B and Line 14 crude oil releases. Earnings for the years ended December 31,

2012, 2011 and 2010 included the Company’s after-tax share of EEP’s costs, before insurance recoveries and excluding

fines and penalties, of $9 million, $33 million and $103 million, respectively, related to these incidents. Insurance

recoveries recorded for the years ended December 31, 2012 and 2011 were $24 million and $50 million after-tax

attributable to Enbridge, respectively, related to the Line 6B crude oil release. See Sponsored Investments – Enbridge

Energy Partners L.P. – Lakehead System Lines 6A and 6B Crude Oil Releases.

Fourth quarter earnings drivers were largely consistent with year-to-date trends and continued to include changes
in unrealized fair value derivative and foreign exchange gains and losses. Aside from operating factors discussed in

Performance Overview – Adjusted Earnings, factors unique to the fourth quarter of 2012 included a $105 million asset

impairment to Stingray and Garden Banks assets within Enbridge Offshore Pipelines (Offshore), $56 million of income

taxes on the intercompany gain on sale to the Fund not eliminated for accounting purposes and a $63 million gain on

recognition of a regulatory asset related to other postretirement benefits (OPEB) within EGD.

Earnings for the comparable fourth quarter of 2011 reflected the discontinuance of rate-regulated accounting at

Enbridge Gas New Brunswick Inc. (EGNB), which resulted in a write-off of a deferred regulatory asset and certain

capitalized operating costs, totaling $262 million, net of tax. See Gas Distribution – Other Gas Distribution and

Storage – Enbridge Gas New Brunswick Inc. – Regulatory Matters.

Management’s Discussion and Analysis > 5

ADJUSTED EARNINGS
(millions of Canadian dollars)

2
7
7
6

2
7
3
6

2
3
9
5

2
7
3
5

2
6
9
4

2
1
9
4

1
9
4
2

1
0
0
1

1
7
7
9

2
5
5
8

ADJUSTED EARNINGS

A key tenet of the Company’s investor value proposition is
“visible growth”, supported by an ongoing focus on safe and
reliable operations and a disciplined approach to investment
and project execution. The Company has consistently
delivered on this proposition, growing adjusted earnings from
$1.32 per common share in 2010 to $1.46 per common
share in 2011 and $1.62 per common share in 2012.

The upward trend in adjusted earnings over these years was
predominantly attributable to strong operating performance
from the Company’s Liquids Pipelines assets as well as
contributions from new assets placed into service.
Incremental oil sands production in Alberta and strong
production growth out of the Bakken in North Dakota has
increased volumes transported on the Canadian Mainline
system and the Lakehead System owned by EEP. The increase
in volumes most notably impacted adjusted earnings from
mid-2011 onward when the Competitive Toll Settlement
(CTS) on the Canadian Mainline took effect. Under the
CTS, Canadian Mainline earnings are exposed to volume
and cost variability. In 2012, the Company also began
realizing earnings from its 50% interest in the Seaway Crude

Pipeline System (Seaway Pipeline). The Seaway Pipeline, which commenced southbound service from the United States
midwest to the Gulf Coast in May 2012, has experienced strong volumes since inception as shippers have sought to
transport their product to locations where realized prices are more favourable. Similarly, adjusted earnings growth on
the Spearhead Pipeline increased in 2012 as it also benefited from producers’ desire to move crude onward to Gulf
Coast markets in order to capture attractive price differentials. In addition to the Seaway Pipeline, other new assets
commencing operations and contributing to adjusted earnings growth included the Cedar Point Wind Energy
Project (Cedar Point) in late 2011 and the Silver State North Solar Project (Silver State) in 2012.

The Company has also seen a marked increase in operating costs over this time frame. Under the umbrella of its
Operational Risk Management Plan (ORM Plan) launched in 2011, the Company has bolstered spending in the areas
of system integrity, environmental and safety programs to ensure the safe and reliable operations of all of its assets.

Other factors which contributed to changes in adjusted earnings year-over-year included market factors impacting
the Company’s Energy Services and natural gas businesses, as well as increased preference share dividends due to the
Company’s increased activity in the capital markets to prefund future growth projects. Energy Services experienced
strong adjusted earnings growth from 2010 to 2011 but saw this growth temper somewhat in 2012 as changing market
conditions gave rise to fewer margin opportunities in crude oil and NGL marketing. Within Sponsored Investments,
EEP’s natural gas business reflected a similar trend with growth in adjusted earnings in 2011 over 2010 owing to
higher natural gas volumes and contributions from acquired assets, followed by a decline in 2012 due to persistent
weakness in natural gas commodity prices. Aux Sable contributed to growth over both the 2011 and 2012 time periods
as new assets were placed into service and realized fractionation margins remained high.

With respect to the fourth quarter of 2012, many of these same annual trends continued. The primary drivers
of adjusted earnings growth period-over-period included strong volumes on the Company’s liquids pipelines assets
both in Canada and the United States, including contributions from new assets such as the Seaway Pipeline, customer
expansion at EGD and growth in the Company’s renewable energy portfolio. Contributions from the Gas Pipelines,
Processing and Energy Services segment were relatively flat as higher adjusted earnings from Aux Sable were offset
by fewer margin opportunities in liquids marketing and increased costs within Offshore.

6 < EN BR IDGE I NC. 2012 FINANCIAL REPO RT

CASH FLOWS

Cash provided by operating activities was $2,874 million for the year ended December 31, 2012, mainly driven

by strong operating performance from the Company’s core assets, particularly from Liquids Pipelines and the

cash flow generation from growth projects placed into service in recent years. Offsetting this cash inflow were

changes in operating assets and liabilities which fluctuate in the normal course due to various factors impacting

the timing of cash receipts and payments.

In 2012, the Company was active in the capital markets with the issuance of $2,634 million in preference shares,

common shares of approximately $384 million and $2,199 million in medium-term notes and also significantly

bolstered its liquidity through the securement of additional credit facilities. The proceeds of the capital market

transactions, together with cash from operations, were more than sufficient to finance the Company’s $6.2 billion

net investment in expansion initiatives during 2012 and provides financing flexibility for the Company’s growth

opportunities in 2013.

DIVIDENDS

The Company has paid common share dividends since

its inception in 1953. In December 2012, the Company

announced a 12% increase in its quarterly dividend to

$0.315 per common share, or $1.26 annualized effective

March 1, 2013. Assuming this currently announced quarterly

dividend is annualized for 2013, the Company has generated

compound annual average growth of 11.7% since 2003.

The Company continues to target a dividend payout of

approximately 60% to 70% of adjusted earnings over the

longer term. In 2012, the dividend payout was 70%

(2011 – 67%; 2010 – 64%) of adjusted earnings per share.

REVENUES

The Company generates revenue from three primary sources:

commodity sales, gas distribution sales and transportation

DIVIDENDS PER COMMON SHARE
(millions of Canadian dollars)

4
7
.
6 0
6
.
0

2
6
.
0

7
5
.
2 0
5
.
6 0
4
.
0

1
4
.
0

6
2
1

3
1

8
9
.
0

5
8
.
0

and other services. Commodity sales of $19,101 million for

13e

the year ended December 31, 2012 (2011 – $20,611 million;

2010 – $15,863 million) were earned through the

Company’s energy services operations. Revenues from these operations depends on activity levels, which vary from

year to year depending on market conditions and commodity prices. Commodity prices do not directly impact earnings

since such earnings reflect a margin or percentage of revenue which depends more on differences in commodity prices

between locations and points in time than on the absolute level of prices.

Gas distribution sales are primarily earned by EGD and are recognized in a manner consistent with the underlying

rate-setting mechanism mandated by the regulator. Revenues generated by the gas distribution businesses are driven

by volumes delivered, which vary with weather and customer base, as well as regulator-approved rates. The cost of

natural gas is charged to customers through rates but does not ultimately impact earnings due to the pass through

nature of these costs.

Management’s Discussion and Analysis > 7

Transportation and other services revenues are earned from the Company’s crude oil and natural gas pipeline

transportation businesses and also includes power production revenue from the Company’s portfolio of renewable

power generation assets. For the Company’s transportation assets operating under market-based arrangements,

revenues are driven by volumes transported and tolls. For rate-regulated assets, revenues are charged in accordance

with tolls established by the regulator and, in most cost-of-service based arrangements, is reflective of the Company’s

cost to provide the service plus a regulator-approved rate of return.

FORWARD-LOOKING INFORMATION

Forward-looking information, or forward-looking statements, have been included in this MD&A to provide the Company’s
shareholders and potential investors with information about the Company and its subsidiaries and affiliates, including
management’s assessment of Enbridge’s 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’’ 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: expected earnings/(loss) or adjusted earnings/(loss);
expected earnings/(loss) or adjusted earnings/(loss) per share; expected future cash flows; expected costs related to projects
under construction; expected in-service dates for projects under construction; expected capital expenditures; estimated future
dividends; and expected costs related to leak remediation and potential insurance recoveries.

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 expected supply and demand for crude oil, natural gas,
NGL and green energy; prices of crude oil, natural gas, NGL and green energy; expected exchange rates; inflation; interest
rates; the availability and price of labour and pipeline construction materials; operational reliability; customer and
regulatory approvals; maintenance of support and regulatory approvals for the Company’s projects; anticipated in-service
dates; and weather. Assumptions regarding the expected supply and demand of crude oil, natural gas, NGL and green
energy, and the prices of these commodities, are material to and underlie all forward-looking statements. These factors are
relevant to 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, may impact levels of demand for the Company’s services and cost of inputs, and are therefore inherent
in all forward-looking statements. Due to the interdependencies and correlation of these macroeconomic factors, the impact
of any one assumption on a forward-looking statement cannot be determined with certainty, particularly with respect to
expected earnings/(loss) or adjusted earnings/(loss) and associated per share amounts, or estimated future dividends. The
most relevant assumptions associated with forward-looking statements on projects under construction, including estimated
in-service date and expected capital expenditures include: 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;
and the impact of weather and customer and regulatory approvals on construction schedules.

Enbridge’s forward-looking statements are subject to risks and uncertainties pertaining to operating performance,
regulatory parameters, project approval and support, weather, economic and competitive conditions, exchange rates, interest
rates, commodity prices and supply 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 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.

8 < EN BR IDGE I NC. 2012 FINANCIAL REPO RT

NON-GAAP MEASURES

This MD&A contains references to adjusted earnings/(loss), which represent earnings or loss attributable to common

shareholders adjusted for unusual, non-recurring or non-operating factors on both a consolidated and segmented

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 earnings/(loss) provides useful

information to investors and shareholders as it provides increased transparency and predictive value. Management uses

adjusted earnings/(loss) to set targets, assess performance of the Company and set the Company’s dividend payout

target. Adjusted earnings/(loss) and adjusted earnings/(loss) for each of the segments are not measures that have a

standardized meaning prescribed by U.S. GAAP and are not considered GAAP measures; therefore, these measures may

not be comparable with similar measures presented by other issuers. See Non-GAAP Reconciliations for a reconciliation

of the GAAP and non-GAAP measures.

Corporate Vision, Strategy and Values

VISION

Enbridge’s vision is to be the leading energy delivery company in North America. The Company transports, distributes

and generates energy and its primary purpose is to deliver the energy North Americans need in the safest, most reliable

and most efficient way possible.

Among its peers, Enbridge strives to be the leader, which means not only leadership in value creation for shareholders

but also leadership with respect to safety, operational reliability, environmental stewardship, customer service, employee

satisfaction and community investment. Value for shareholders is evident in the Company’s proven investment value

proposition which combines visible growth, a reliable business model and a growing income stream.

STRATEGY

The Company’s initiatives center around six areas of strategic emphasis. These strategies are reviewed at least annually

with direction from its Board of Directors.

1. Commitment to Operational Safety and Reliability, and Environmental Protection;

2. Focus on Project Execution;

3. Attracting, Retaining and Developing Highly Capable People;

4. Preserving Financial Strength and Flexibility;

5. Strengthening Core Businesses; and

6. Developing New Platforms for Growth and Diversification.

COMMITMENT TO OPERATIONAL SAFETY AND RELIABILITY, AND ENVIRONMENTAL PROTECTION

Operations safety and system integrity continues to be Enbridge’s number one priority and sets the foundation for

the strategic plan. An important element of this priority is the ORM Plan which broadly aims to position Enbridge
as the industry leader for system integrity, environmental and safety programs, and charts the course for best-in-class

practices. Through the ORM Plan, the Company has enhanced its integrity management, leak detection and control

systems. The ORM Plan has also bolstered incident response capabilities, employee and public safety, and improved

communication with landowners and first responders. Further, in an ongoing commitment to foster a positive pervasive

safety culture, Life Saving Rules were rolled out in early 2012 to all employees which support the goal of ensuring every

employee returns home safely at the end of the day and that the Company’s customers and communities in which it

operates are kept safe.

Management’s Discussion and Analysis > 9

FOCUS ON PROJECT EXECUTION

Timely and cost-effective execution of the existing slate of $27 billion in commercially secured projects continues

to be a key priority for the Company. Enbridge believes project execution is a core competency and the Company

continues to build upon its rigorous project management processes, primarily through the Major Projects group.

The key strategy for Major Projects of delivering projects safely, on time and on budget is supported by repeatable

and competitive proposal development; long-term supply chain agreements; quality design, materials and construction;

extensive public consultation; robust cost, schedule and risk controls; developed project management expertise; and

efficient project transition to operating units.

ATTRACTING, RETAINING AND DEVELOPING HIGHLY CAPABLE PEOPLE

Investing in the attraction, retention and development of employees and future leaders is fundamental to executing

Enbridge’s aggressive growth strategy and creating sustainability for future success. People-related focus areas include

broadening recruiting efforts beyond traditional industry and geographical reaches, ensuring succession capability

through accelerated leadership development programs and building change management capabilities throughout the

enterprise to ensure projects and initiatives achieve the intended benefits. Furthermore, Enbridge strives to maintain

industry competitive compensation and retention programs that provide both short-term and long-term incentives.

PRESERVING FINANCIAL STRENGTH AND FLEXIBILITY

The maintenance of adequate financial strength and flexibility is crucial to Enbridge’s growth strategy. Enbridge’s

financial strategies are designed to ensure the Company has sufficient financial flexibility to meet its capital requirements.

To support this objective, the Company develops financing plans and strategies to maintain or improve its credit

ratings, diversify its funding sources and maintain substantial standby bank credit capacity and access to capital markets

in both Canada and the United States.

A key tenet of the Company’s reliable business model is mitigation of exposure to market price risks. The Company

has robust risk management processes which ensure earnings volatility from market price risk is managed within the

parameters of its earnings-at-risk policy. Enbridge will continue to proactively hedge interest rate, foreign exchange

and commodity price exposures. Management of counterparty credit risk also remains an ongoing priority.

The Company continually assesses ways to generate value for shareholders, including reviewing opportunities that

may lead to acquisitions, dispositions or other strategic transactions, some of which may be material. Opportunities

are screened, analyzed and must meet operating, strategic and financial benchmarks before being pursued.

STRENGTHENING CORE BUSINESSES

The Company has an established history of delivering on its value proposition through its Liquids Pipelines and

gas transportation businesses which serve the transportation needs of key North American crude oil and natural gas

markets. Shifting supply and demand fundamentals and North American price dislocations are driving significant

infrastructure investment opportunities that Enbridge is well suited to capture in these core business segments.

Within the Liquids Pipelines segment, strategies are focused on expanding access to new markets in North America

for growing production from western Canada and the Bakken, expanding the capacity of the mainline pipeline system

and strengthening the Company’s position in the Alberta oil sands and Bakken regions to ensure growing production

volumes ultimately flow on Enbridge’s downstream systems.

1 0 < EN BR IDGE I NC. 2012 FINANCIAL REPO RT

Through Enbridge’s new market access initiatives, shippers will be provided greater connectivity to markets in Ontario,

Quebec, the Gulf Coast and upper-midwest, with the objective of being able to secure the best pricing for their

products. Significant market access programs announced in 2012 included the Gulf Coast Access, Eastern Access

and Light Oil Market Access programs. To facilitate these downstream growth projects and continued growth in base

volumes, a number of supporting mainline expansions are being undertaken. The Company’s efforts to expand market

access and provide better netbacks for producers include further initiatives to access the Canadian and United States

east coast and eastern Gulf Coast markets, as well as development of the proposed Northern Gateway Project

(Northern Gateway), which would provide access to markets off the Pacific coast of Canada.

Regional liquids pipeline development involves projects which connect new oil sands production to existing hubs

on the Canadian Mainline. Enbridge, the largest pipeline operator in the oil sands region of Alberta, is currently

developing close to $3.5 billion of commercially secured regional oil sands transportation facilities that are expected

to be placed into service between 2012 and 2015, including the twinning and expansion of its Athabasca Pipeline

and the expansion of its Waupisoo Pipeline. The Company also has $3.2 billion of secured system expansion projects

in Saskatchewan and North Dakota, where Enbridge believes it is strategically located to capture increased production

from the Bakken play.

The fundamentals of the natural gas market in North America have been altered significantly in recent years

with the emergence of unconventional shale gas plays. The Company’s natural gas strategies include leveraging

competitive advantages of its existing assets and expanding its footprint in these emerging areas. Alliance is well

positioned to service developing regions in northeast British Columbia and the Bakken play, and is evaluating

opportunities to expand its service offerings in those areas as well as strategies to attract liquids rich gas onto the

system. Development of shale plays is also creating the need for additional Canadian midstream infrastructure; an

opportunity which fits with the Company’s investment value proposition and which can leverage existing operational

expertise. The Company’s first operations within this space are expected to commence with the completion of its

Peace River Arch (PRA) Gas Development in 2013. Within the United States gas business, strategic priorities include

expanding gathering and processing capacity, particularly in the Granite Wash area, and seeking opportunities to expand

its service offerings, including NGL transportation. In addition to these onshore strategies, the Company continues to

pursue crude oil and natural gas gathering expansion opportunities for ultra-deep projects in the Gulf of Mexico.

DEVELOPING NEW PLATFORMS FOR GROWTH AND DIVERSIFICATION

The development of new platforms to diversify and sustain long-term growth is an important strategy for Enbridge.

The Company is currently focusing its development efforts towards securing investment opportunities in renewable

and gas-fired power generation, power transmission and select international assets. The Company also invests in early

stage energy technologies that complement the Company’s core businesses.

Enbridge has advanced its renewable power strategy considerably over the last several years and has interests in a

renewable energy portfolio with a generation capacity of more than 1,300 MW. Future investment may include earlier

stage development opportunities, including expansion of existing sites. The Company is also assessing opportunities to

invest in gas-fired generation, which is projected to grow significantly over the long-term based on natural gas supply

fundamentals and the long-term natural gas price outlook. Power transmission is also an attractive growth opportunity

and a complement to the Company’s electricity generation platform. There is substantial need for new transmission

infrastructure in North America, with risk and return profiles that fit Enbridge’s investment value proposition.

The Company is targeting completion of construction of the initial phase of its first transmission project, the

Montana-Alberta Tie-Line (MATL), by the middle of 2013.

Management’s Discussion and Analysis > 11

CORPORATE VALUES

Enbridge adheres to a strong set of core values that govern how it conducts its business and pursues strategic priorities.

In light of the significant growth in employees in recent years and projected future growth, the Company recently

refreshed and re-emphasized these values, articulated as: “Enbridge employees demonstrate integrity, safety and respect

in support of our communities, the environment and each other”. Employees are required to uphold these values

in their interactions with each other, with customers, suppliers, landowners, community members and all others with

whom the Company deals, and to ensure the Company’s business decisions are consistent with these values.

MAINTAINING THE COMPANY’S SOCIAL LICENSE

Earning and maintaining “social license”—the approval and acceptance of the communities in which the Company

is proposing projects—is critical to Enbridge’s ability to execute on its growth plans. To earn the public’s trust,

and to protect and reinforce the Company’s reputation with its stakeholders, Enbridge is committed to integrating

Corporate Social Responsibility (CSR) into every aspect of its business. The Company defines CSR as conducting

business in an ethical and responsible manner, protecting the environment and the safety of people, providing

economic and other benefits to the communities in which the Company operates, supporting universal human

rights and employing a variety of policies, programs and practices to manage corporate governance and ensure fair,

full and timely disclosure. The Company provides its stakeholders with open, transparent disclosure of its CSR

performance and prepares its annual CSR Report using the Global Reporting Initiative sustainability reporting

guidelines, which serve as a generally accepted framework for reporting on an organization’s economic, environmental
and social performance. The 2012 CSR Report can be found at csr.enbridge.com. None of the information contained
on, or connected to, the Enbridge website is incorporated or otherwise part of this MD&A.

One of Enbridge‘s CSR environmental objectives is its Neutral Footprint plan, which includes initiatives to counteract

the environmental impact of all Enbridge’s pipeline expansion projects within five years of their occurrence. Neutral

Footprint initiatives include:

•

planting a tree for every tree the Company removes to build new facilities;

conserving an acre of land for every acre of wilderness the Company permanently impacts; and

generating a kilowatt of renewable energy for every kilowatt the Company’s expansions consume.

Progress updates on the Company’s Neutral Footprint initiatives can be found at enbridge.com/neutralfootprint and
in the annual CSR Report. None of the information contained on, or connected to, the Enbridge website is incorporated
or otherwise part of this MD&A.

To complement community investments in its Canadian and United States operating areas, Enbridge created the

energy4everyone foundation (the Foundation) in 2009. The Foundation aims to leverage the expertise and resources

of the Canadian energy industry to affect significant positive change through the delivery and deployment of affordable,

reliable and sustainable energy services and technologies in communities in need around the world. To date, the

Foundation has completed projects in Costa Rica, Ghana, Nicaragua, Peru and Tanzania.

1 2 < EN BR IDGE I NC. 2012 FINANCIAL REPO RT

Industry Fundamentals

SUPPLY AND DEMAND FOR LIQUIDS

Enbridge has an established and successful history of being the largest

transporter of crude oil to the United States, the world’s largest market.

While United States demand for Canadian crude oil production will support

the use of Enbridge infrastructure for the foreseeable future, North

American and global crude oil supply and demand fundamentals are shifting

and Enbridge has a crucial role to play in this transition by developing

long-term transportation options that enable the efficient flow of crude

oil from supply regions to end-use markets.

Overall, global energy consumption is expected to continue to grow;

however, growth in crude oil demand is expected to be increasingly driven

by emerging markets, such as China, India and the Middle East. In

Organisation for Economic Co-operation and Development countries,

including Canada, the United States and western Europe, conservation,

stagnant population growth and a shift to alternative energy will reduce

crude oil demand over the long term. Accordingly, there is a strategic

opportunity for North American producers to meet growing global demand

outside North America. Access to new markets is expected to improve

netbacks for domestic producers as land-locked North American crude

has, of late, traded at significant discounts to world oil prices.

In terms of supply, the Western Canada Sedimentary Basin (WCSB)

continues to be viewed as one of the world’s largest and most secure supply

CANADIAN CRUDE OIL PRODUCTION
(thousands of barrels per day)

8
2
6
3

3
3
2

9
8
9

3
3
8

13e

Oil Sands
Other

Sources: National Energy Board
Canadian Association of Petroleum Producers.

sources of crude oil, and production from this region is expected to increase over the long term through continued

investment in the Alberta oil sands. Investment in the WCSB has recovered significantly since the period of economic

downturn in 2009 and 2010. Several new projects and expansions of existing oil sands production facilities have been

added or accelerated due to supportive oil prices and the emergence of increased foreign investment.

One of the most fundamental shifts in crude oil supply in recent years is the emergence of shale oil plays. Shale

oil plays, such as the Bakken in North Dakota, will be significant contributors to the overall forecasted increase in

North American crude production. Increased production from these plays has been facilitated by new drilling and

completion methods, which include hydraulic fracturing and horizontal drilling techniques.

The substantial growth in North American supply without a corresponding increase in domestic demand has

introduced a number of challenges for the industry. In recent years, inventory levels have increased and several

transportation bottlenecks have arisen within North America. A notable bottleneck exists in Cushing, Oklahoma,
a major pipeline and storage hub, which has experienced heightened receipt of product without commensurate

takeaway capacity. The oversupply to this land-locked market has resulted in a divergence between West Texas

Intermediate (WTI) and world pricing, resulting in lower netbacks for North American producers than could

otherwise be achieved if selling into global markets. In 2012, this price differential ranged from US$10 to as

high as US$23 per barrel.

For WCSB producers, the oversupply on the continental United States continues to have an adverse effect on heavy

crude oil prices from western Canada. With the United States over supplied and with insufficient access to alternative

markets, including Asia, heavy crude oil prices for western Canada are expected to remain significantly discounted

against WTI.

Management’s Discussion and Analysis > 13

Enbridge’s role in helping to address evolving supply and demand fundamentals, and improving netbacks for producers,

is to provide expanded pipeline capacity and sustainable connectivity to alternative markets. In 2012, Enbridge

announced a record number of commercially secured projects within Liquids Pipelines to create additional market

access solutions and regional oil sands infrastructure. Most notably, the Company’s announced market access initiatives

included a $5.8 billion upsized Gulf Coast Access Program, a $2.7 billion Eastern Access Program and a $6.2 billion

Light Oil Market Access Program. The Company is developing additional initiatives to access Canadian and United

States east coast and eastern Gulf Coast markets. Despite these initiatives, and those of competitors, North American oil

prices, including heavy oil prices from western Canada, will likely continue to lag behind world prices, heightening the

need for pipeline access to growing Asian markets. Details of the Company’s Northern Gateway, a proposed pipeline

system from Alberta to the coast of British Columbia, and associated marine terminal, along with the Company’s other

projects under development, can be found in Growth Projects – Commercially Secured Projects and Growth Projects –

Other Projects Under Development.

NORTH AMERICAN NATURAL
GAS PRODUCTION
(billions of cubic feet per day)

7
7

9
7

3
7

SUPPLY AND DEMAND FOR NATURAL GAS

Strong growth in North American natural gas production over the past few

years has created an oversupplied market and a weak price environment.

Although production growth is slowing, North America will continue

to be over supplied until significant incremental gas demand arises.

North American gas demand has been outpaced by robust supply growth

as a prolonged and fragile economic recovery has translated into weak

industrial gas demand growth, despite relatively low gas prices. Further,

consecutive warm winters have curbed heating demand. In contrast, low gas

prices have supported gas-fired power generation as displacement of less

competitive coal-fired generation reached unprecedented levels over the past

year. Low gas prices are expected to persist, which should enable continued

displacement of coal-fired generation. Any future retirement of older, less

efficient coal generators could also potentially increase the share of overall

power production portfolio held by gas-fired generation. Within Canada,

natural gas demand growth is expected to be driven primarily by oil

sands development.

13e

Strong production growth from shale plays, supported by technological

Shale
Other

Sources: Energy Information Administration (United States),
National Energy Board (Canada), Enbridge research.

advancements in drilling techniques, has propelled United States domestic

gas production to historic highs and has resulted in an enormous resource

base. However, as the North American market has become oversupplied,

gas prices have weakened and producers have in turn sharply reduced

drilling activity except in regions where the gas is rich in NGL. Dry gas

production has been supplanted by production from increased rich-gas

drilling and associated gas volumes from oil drilling. However, the overall rate of gas production growth has slowed

from prior years. In addition, the development of shale plays in close proximity to major gas markets, such as the

Marcellus and Utica shale plays in the northeast United States, have been shifting North American gas flows, creating

opportunities for new regional infrastructure but also challenges for existing infrastructure serving more traditional

supply areas.

North American gas prices in 2012 fell to 10-year lows as rising gas production outpaced modest demand growth.

While gas prices have recovered somewhat, the expectation is that gas prices will remain relatively low until there is

more pervasive demand recovery.

1 4 < EN BR IDGE I NC. 2012 FINANCIAL REPO RT

Similar to crude oil, significant differentials exist between North American and world gas prices. Globally, liquefied

natural gas (LNG) is being supplied to meet increasing energy demand as gas supplies in certain regions are abundant

and gas is cleaner burning than other forms of hydrocarbons. The price for LNG in the world market is more closely

linked to crude prices, providing an opportunity to capture more favourable netbacks on LNG exports from North

America. Based on these fundamentals, there is an increasing probability that one or more projects to export LNG off

the west Coast of Canada will proceed.

The NGL which can be extracted from liquids-rich gas streams include ethane, propane, butane, pentanes plus

and natural gasoline, which are used in a variety of industrial, commercial and other applications. Prices for NGL

are generally closely correlated with crude oil prices. In the current environment, where the differential between

crude oil and natural gas prices is expected to remain historically wide, producers are being incented to shift drilling

activity to rich gas regions in order to take advantage of strong NGL fractionation margins. This, in turn, is expected

to drive a need for additional midstream processing facilities and transportation solutions to move growing supplies

of NGL to market.

In response to these evolving natural gas and NGL fundamentals, Enbridge believes it is well positioned to provide

value added solutions to producers. Alliance is uniquely configured to transport liquids-rich gas and is currently

evaluating service offerings to best meet the needs of producers. The focus on liquids-rich gas development also creates

opportunities for Aux Sable, a 50%-owned extraction and fractionation facility near Chicago, Illinois at the terminus

of Alliance. Enbridge is also responding to the need for regional infrastructure with additional United States gathering

and processing investments and is growing its Canadian midstream business. In addition, Enbridge is a partner in

the Texas Express Pipeline (TEP) that will increase NGL pipeline capacity into Mont Belvieu, Texas, with an expected

in-service date of mid-2013.

SUPPLY AND DEMAND FOR GREEN ENERGY

While traditional forms of energy are expected to continue to represent the major source of North American energy

supply for the foreseeable future, a shift to a lower carbon-intensive economy has gained momentum. Over the last

several years, many large power and infrastructure players, including Enbridge, have increased investment in renewable

assets. Enbridge now has interests in more than 1,300 MW of renewable generation capacity.

Over the longer term, North American economic growth is anticipated to drive growing electricity consumption.

In turn, growing electricity demand is expected to drive new generation capacity growth. The general consensus

of energy analysts appears to be that the new generation capacity mix over the next 20 years will shift to lower

carbon options such as natural gas or renewable sources of power generation. Although coal and nuclear facilities

will continue to provide core electricity generation needs in North America, various emission regulations are anticipated

which are expected to force the retirement of aging coal-fired units and restrict the permitting of new coal-fired

electrical generation facilities (absent carbon capture and storage technologies). Most North American jurisdictions

have also established or are in the process of establishing renewable portfolio standards which mandate the inclusion

of a certain proportion of renewable energy generation in their future electricity generation mix. As a result, according
to the United States Energy Information Administration, North America is expected to require sizable new generation

capacity from alternative sources in order to meet growing electricity demand. Natural gas and renewable energy

sources, including biomass, hydro, solar and wind, are likely to play an increasingly important role in the supply

of longer-term electricity needs.

Management’s Discussion and Analysis > 15

The United States National Renewable Energy Laboratory reports that North America has significant wind and solar

resources, with wind alone having the potential to provide capacity for over 10,000 gigawatts of power generation.

Solar resources in southwestern states such as Arizona, California, Colorado and Nevada are considered by many to

be the best in the world for large-scale solar plants. According to Environment Canada, Canada also has an abundance

of wind and solar resources, particularly with strong wind resources in the northeastern regions. Expanding renewable

energy infrastructure in North America is not without challenges as these high quality wind and solar resources are

often found in regions which are not in close proximity to high demand markets, requiring the need for new

transmission capacity.

To date, the profitability of renewable energy projects has in part been supported by certain tax and government

incentives. In the near-term, uncertainty over the continuing availability of tax or other government incentives, and

the ability to secure long-term power purchase agreements (PPA) through government or investor-owned power

authorities will hinder the pace of future new renewable capacity development. However, over time renewable

generation is expected to be competitive with other modes of generation as wind turbine and solar panel costs

continue to decline.

Enbridge owns nine wind farms and four solar farms, including the recently announced investment in the Massif

du Sud Wind Project (Massif du Sud) in Quebec, and will continue to seek new opportunities to grow its portfolio

of renewable power generation capacity. As noted, incremental renewable power generation requires increased

transmission infrastructure. Enbridge expects to commence operating its first significant power transmission line,

running between Montana and Alberta, in 2013, and will continue to seek opportunities to invest in new transmission

facilities which meet the Company’s investment criteria.

Growth Projects – Commercially Secured Projects

In 2012, Enbridge secured a record number of new infrastructure growth projects. In aggregate, the Company

added approximately $14 billion of projects across several business units, bringing the total inventory of commercially

secured projects to approximately $27 billion. All of these projects are expected to come into service by 2016, and

enable the Company to generate industry leading adjusted earnings per share growth over this period.

The bulk of new projects secured were within Liquids Pipelines and Sponsored Investments, highlighted by three

major new market access initiatives. The $5.8 billion Gulf Coast Access Program, which includes the Seaway Pipeline,

the Flanagan South Pipeline Project and elements of the Canadian Mainline and Lakehead System Mainline expansions,

is expected to provide capacity for as much as 850,000 barrels per day (bpd) of crude oil to reach the large refinery

markets in the Gulf Coast. The $2.7 billion Eastern Access Program is expected to allow for greater access for crude oil

into Chicago, further east into Toledo and ultimately into Ontario and Quebec. The Eastern Access Program includes

the Company’s Toledo pipeline expansion, Line 9 reversal, the existing Spearhead North pipeline expansion, Line 6B

replacement and Line 5 expansion. Finally, the $6.2 billion Light Oil Market Access Program brings together a group

of projects to support the increasing supply of light oil from Canada and the Bakken and also supplement the Eastern

Access Program through the upsize of the Line 9B and Line 6B capacity expansion. The Light Oil Market Access

Program also includes the Southern Access Extension, Canadian Mainline System Terminal Flexibility and Connectivity

and twinning of the Spearhead North pipeline and Line 61 expansion included within the Lakehead System Mainline

Expansion. These market access initiatives include several mainline system expansion projects which are designed

to ensure that there is sufficient capacity to feed these new extensions.

1 6 < EN BR IDGE I NC. 2012 FINANCIAL REPO RT

The table below summarizes the current status of the Company’s commercially secured projects, organized by business

Estimated
Capital Cost 1

Expenditures to Date 2

Expected
In-Service Date

Status

segment.

(Canadian dollars, unless stated otherwise)

LIQUIDS PIPELINES

1. Edmonton Terminal Expansion

2. Wood Buffalo Pipeline

3. Woodland Pipeline

4. Waupisoo Pipeline Capacity Expansion

5. Seaway Crude Pipeline System

Acquisition/Reversal/Expansion
Twinning/Extension

6. Suncor Bitumen Blend

7. Norealis Pipeline

8. Eddystone Rail Project

$0.2 billion

$0.4 billion

$0.3 billion

US$1.3 billion
US$1.1 billion

$0.2 billion

$0.5 billion

US$0.1 billion

$0.2 billion

$0.3 billion

US$1.2 billion
US$0.1 billion

$0.1 billion

$0.2 billion

No significant
expenditures to date

9. Athabasca Pipeline Capacity Expansion

$0.4 billion

$0.2 billion

10. Eastern Access 3

Toledo Expansion
Line 9 Reversal

US$0.2 billion
$0.4 billion

US$0.1 billion
No significant
expenditures to date

11. Flanagan South Pipeline Project

US$2.8 billion

US$0.2 billion

12. Canadian Mainline Expansion

$0.6 billion

13. Athabasca Pipeline Twinning

$1.2 billion

14. Edmonton to Hardisty Expansion

$1.8 billion

15. Southern Access Extension

US$0.8 billion

16. Canadian Mainline System Terminal

$0.6 billion

Flexibility and Connectivity

GAS DISTRIBUTION

17. Greater Toronto Area Project

$0.6 billion

GAS PIPELINES, PROCESSING AND ENERGY SERVICES

No significant
expenditures to date

2012

2012 – 2013
(in phases)

Complete

2012 – 2013
2014

Complete
Pre-construction

2013

2013 – 2014
(in phases)

Under construction

Pre-construction

Under construction

2013
2013 – 2014

Under construction
Pre-construction

2014

2014 – 2015
(in phases)

2015

2013 – 2016
(in phases)

Pre-construction

2015

Pre-construction

18. Silver State North Solar Project 4

US$0.2 billion

2012

Complete

19. Massif du Sud Wind Project

20. Lac Alfred Wind Project

21. Cabin Gas Plant

22. Peace River Arch Gas Development

$0.2 billion

$0.3 billion

$0.8 billion

$0.3 billion

$0.1 billion

$0.2 billion

$0.7 billion

$0.1 billion

23. Tioga Lateral Pipeline

US$0.1 billion

24. Venice Condensate Stabilization Facility

US$0.2 billion

25. Walker Ridge Gas Gathering System

26. Big Foot Oil Pipeline

27. Heidelberg Lateral Pipeline

US$0.4 billion

US$0.2 billion

US$0.1 billion

No significant
expenditures to date

US$0.1 billion

No significant
expenditures to date

2012 – 2013

Complete

2013
(in phases)

Under construction

To be determined

Deferred

2012 – 2014
(in phases)

2013

2014

2016

Under construction

Pre-construction

Management’s Discussion and Analysis > 17

Estimated
Capital Cost 1

Expenditures to Date 2

Expected
In-Service Date

Status

(Canadian dollars, unless stated otherwise)

SPONSORED INVESTMENTS

28. EEP – Bakken Expansion Program

US$0.3 billion

US$0.2 billion

29. The Fund – Bakken Expansion Program

$0.2 billion

$0.1 billion

30. EEP – Berthold Rail Project

US$0.1 billion

31. EEP – Ajax Cryogenic Processing Plant

US$0.2 billion

32. EEP – Cushing Terminal Storage

US$0.2 billion

US$0.1 billion

US$0.2 billion

US$0.1 billion

Expansion Project

33. EEP – South Haynesville Shale Expansion

US$0.3 billion

US$0.2 billion

34. EEP – Bakken Access Program

35. EEP – Texas Express Pipeline

36. EEP – Line 6B 75-Mile Replacement

US$0.1 billion

US$0.4 billion

US$0.3 billion

US$0.1 billion

US$0.2 billion

Program

37. EEP – Eastern Access

US$2.6 billion

US$0.3 billion

38. EEP – Lakehead System Mainline Expansion US$2.4 billion

39. EEP – Sandpiper Project

US$2.5 billion

No significant
expenditures to date

CORPORATE

2013

2012 – 2013
(in phases)

2012+
(in phases)

2013

2013 – 2016
(in phases)

2014 – 2016
(in phases)

Substantially
complete

Under construction

Pre-construction

2016

Pre-construction

40. Montana-Alberta Tie-Line

US$0.4 billion

US$0.3 billion

2013 – 2014
(in stages)

Under construction

2
3
4

These amounts are estimates and subject to upward or downward adjustment based on various factors. As appropriate, the amounts reflect Enbridge’s share of joint
venture projects.
Expenditures to date reflect total cumulative expenditures incurred from inception of project up to December 31, 2012.
See Growth Projects – Commercially Secured Projects – Sponsored Investments – Enbridge Energy Partners, L.P. – Eastern Access for project discussion.
Expenditures to date reflect total expenditures before receipt of US$55 million payment from the United States Treasury. See Growth Projects – Commercially Secured
Projects – Gas Pipelines, Processing and Energy Services – Silver State North Solar Project.

Risks related to the development and completion of growth projects are described under Risk Management and

Financial Instruments – General Business Risks.

LIQUIDS PIPELINES

EDMONTON TERMINAL EXPANSION

The Edmonton Terminal Expansion Project involved expanding the tankage of the mainline terminal at Edmonton,

Alberta. The expansion was required to accommodate growing oil sands production receipts both from Enbridge’s

Waupisoo Pipeline and other non-Enbridge pipelines. Construction was completed and the project was placed into

service in December 2012, adding four tanks, three booster pumps and related infrastructure, and expanding the

tankage of the mainline terminal by one million barrels. The project was completed under budget with a final cost

of approximately $0.2 billion.

1 8 < EN BR IDGE I NC. 2012 FINANCIAL REPO RT

Norman Wells

Zama

7
3
Fort McMurray

Edmonton

14
Hardisty

Blaine

Portland

Casper

Salt Lake City

Superior

Montreal

Toronto

Sarnia

Toledo

Chicago

Patoka

Wood River

Cushing

Current Assets
Growth Opportunities

Houston

New Orleans

Liquids Pipelines
1 Edmonton Terminal Expansion
2 Wood Buffalo Pipeline
3 Woodland Pipeline
4 Waupisoo Pipeline Capacity Expansion
5 Seaway Crude Pipeline System

(including acquisition, reversal, expansion,
twinning and extension)
6 Suncor Bitumen Blend
7 Norealis Pipeline
8 Eddystone Rail Project

9 Athabasca Pipeline Capacity Expansion
10 Eastern Access (Toledo expansion

and Line 9 reversal)

11 Flanagan South Pipeline Project
12 Canadian Mainline Expansion
13 Athabasca Pipeline Twinning
14 Edmonton to Hardisty Expansion
15 Southern Access Extension
16 Canadian Mainline System

Terminal Flexibility and Connectivity

Management’s Discussion and Analysis > 19

WOOD BUFFALO PIPELINE

Under an agreement with Suncor Energy Inc. (Suncor), Enbridge constructed a new, 95-kilometre (59-mile), 30-inch

diameter crude oil pipeline, connecting the Athabasca Terminal, adjacent to Suncor’s oil sands plant, to the Cheecham

Terminal, which is the origin point of Enbridge’s Waupisoo Pipeline. The Waupisoo Pipeline delivers crude oil from

several oil sands projects to the Edmonton, Alberta mainline hub. The new Wood Buffalo Pipeline was placed into

service in October 2012 and it parallels the existing Athabasca Pipeline. Additional expenditures will be incurred in

2013 and the estimated capital cost remains at approximately $0.4 billion, with expenditures to date of approximately

$0.3 billion.

WOODLAND PIPELINE

Enbridge entered into a joint venture agreement with Imperial Oil Resources Ventures Limited and ExxonMobil

Canada Properties to provide for the transportation of blended bitumen from the Kearl oil sands mine to crude oil

hubs in the Edmonton, Alberta area. The project is being phased with the mine expansion, with the first phase

involving construction of a new 140-kilometre (87-mile) 36-inch diameter pipeline from the mine to the Cheecham

Terminal, and service on Enbridge’s existing Waupisoo Pipeline from Cheecham to the Edmonton area. The total

estimated cost of the Phase I pipeline from the mine to the Cheecham Terminal and related facilities is approximately

$0.5 billion, of which Enbridge’s share is approximately $0.3 billion. Enbridge’s share of total project expenditures

to date is approximately $0.3 billion. Although the completed pipeline was available for service in November 2012,

Enbridge expects the pipeline will be placed into service in the first quarter of 2013, commensurate with the start-up

of the Kearl oil sands mine.

WAUPISOO PIPELINE CAPACITY EXPANSION

The Waupisoo Pipeline Capacity Expansion provided 65,000 bpd of additional capacity in the fourth quarter of 2012.

Two stations that will provide a further 190,000 bpd of additional capacity have been completed and are anticipated to

be placed into service in the third quarter of 2013 when they are expected to be required to accommodate additional

throughput. The total cost of the project was approximately $0.3 billion.

SEAWAY CRUDE PIPELINE SYSTEM

ACQUISITION OF INTEREST

In 2011, Enbridge acquired a 50% interest in the Seaway Pipeline at a cost of approximately US$1.2 billion. Seaway

Pipeline includes the 805-kilometre (500-mile), 30-inch diameter long-haul system from Freeport, Texas to Cushing,

Oklahoma. For further details about Seaway Pipeline refer to Liquids Pipelines – Seaway Pipeline.

REVERSAL AND EXPANSION

The flow direction of the Seaway Pipeline has been reversed, enabling it to transport crude oil from the oversupplied

hub in Cushing, Oklahoma to the Gulf Coast. The initial reversal of the pipeline and preliminary service commenced

in the second quarter of 2012, providing initial capacity of 150,000 bpd. Further pump station additions and

modifications were completed in January 2013, increasing capacity available to shippers to up to approximately
400,000 bpd, depending on crude slate. Actual throughput experienced to date in 2013 has been curtailed due to

constraints on third party takeaway facilities. A lateral from the Seaway Jones Creek tankage to the ECHO crude oil

terminal in Houston, Texas should eliminate these constraints when it comes into service, expected in the fourth

quarter of 2013.

2 0 < EN BR IDGE I NC. 2012 FINANCIAL REPO RT

TWINNING AND EXTENSION

In March 2012, based on additional capacity commitments from shippers, plans were announced to proceed with

an expansion of the Seaway Pipeline through construction of a second line that is expected to more than double

its capacity to 850,000 bpd in mid-2014. This 30-inch diameter pipeline will follow the same route as the existing

Seaway system. Included in the project scope is a 105-kilometre (65-mile), 36-inch new-build lateral from the

Seaway Jones Creek facility southwest of Houston, Texas into Enterprise Product Partners L.P.’s (Enterprise) ECHO

crude oil terminal (ECHO Terminal) southeast of Houston.

In addition, a 137-kilometre (85-mile) pipeline will be constructed from the ECHO Terminal to the Port Arthur/

Beaumont, Texas refining center to provide shippers access to the region’s heavy oil refining capabilities. This extension will

offer capacity of 560,000 bpd and, subject to regulatory approvals, is expected to be available in the first quarter of 2014.

Including the acquisition of the 50% interest in the Seaway Pipeline, Enbridge’s total expected cost for the Seaway

Pipeline is approximately US$2.4 billion. The acquisition, reversal and expansion are expected to cost US$1.3 billion,

with the twinning, extension and lateral to the ECHO Terminal components of the project expected to cost approximately

US$1.1 billion. Total expenditures incurred to date were approximately US$1.3 billion.

SUNCOR BITUMEN BLEND

In September 2012, Enbridge entered into an agreement with Suncor for a Bitumen Blend project, which includes

the construction of a new 350,000 barrel tank, new blend and diluent lines and pumping capacity to connect with

Suncor’s lines just outside Enbridge’s Athabasca Tank Farm. These new facilities will enable Suncor to transport

blended bitumen volumes from its Firebag production into the Wood Buffalo pipeline. The estimated cost for the

project is approximately $0.2 billion, with expenditures to date of approximately $0.1 billion. The Bitumen Blend

project is expected to be in-service in the second quarter of 2013.

SOUTH CHEECHAM RAIL AND TRUCK TERMINAL

The Company has partnered with Keyera Corp. to construct the South Cheecham Rail and Truck Terminal (the Terminal),

located approximately 75 kilometres (47 miles) southeast of Fort McMurray, Alberta. The Terminal, to be developed in

phases, will be a multi-purpose hydrocarbon rail and truck terminal, designed to support bitumen producers within the

Athabasca oil sands area and facilitate product in and out. In addition to the facilities for handling diluent and diluted

bitumen at the Terminal, the initial phase is planned to include a diluted bitumen pipeline connection to Enbridge’s existing

Cheecham Terminal. Construction is underway and completion of the first phase is expected to take place in the second

quarter of 2013 for a total cost of approximately $90 million. Enbridge’s share of the project costs will be based upon its

50% joint venture interest.

NOREALIS PIPELINE

In order to provide pipeline and terminaling services to the proposed Husky Energy Inc. operated Sunrise Oil Sands

Project, the Company is undertaking construction of a new originating terminal (Norealis Terminal), a 112-kilometre

(66-mile) 24-inch diameter pipeline from the Norealis Terminal to the Cheecham Terminal, and additional tankage at
Cheecham. The estimated cost of the project is approximately $0.5 billion, with expenditures to date of approximately

$0.2 billion. The project is expected to be available for service by the end of 2013.

Management’s Discussion and Analysis > 21

EDDYSTONE RAIL PROJECT

In November 2012, the Company announced that it had entered into a joint venture agreement with Canopy

Prospecting Inc. to develop a unit-train unloading facility and related local pipeline infrastructure near Philadelphia,

Pennsylvania to deliver Bakken and other light sweet crude oil to Philadelphia area refineries. The Eddystone Rail

Project will include leasing portions of a power generation facility and reconfiguring existing track to accommodate

120-car unit-trains, installing crude oil offloading equipment, refurbishing an existing 200,000 barrel tank and

upgrading an existing barge loading facility. Subject to regulatory and other approvals, the project is expected to

be placed into service by the end of 2013 to receive and deliver an initial capacity of 80,000 bpd, expandable to

160,000 bpd. The total estimated cost of the project is approximately US$68 million and Enbridge’s share of

the project costs will be based upon its 75% joint venture interest.

ATHABASCA PIPELINE CAPACITY EXPANSION

The Company is undertaking an expansion of its Athabasca Pipeline to its full capacity to accommodate additional

contractual commitments, including incremental production from the Christina Lake Oilsands Project operated by

Cenovus Energy Inc. This expansion is expected to increase the capacity of the Athabasca Pipeline to its maximum

capacity of approximately 570,000 bpd, depending on the mix of crude oil types. The estimated cost of the entire

expansion is approximately $0.4 billion, with expenditures to date of approximately $0.2 billion. The initial expansion

to 430,000 bpd of capacity is expected to be placed into service by the end of the first quarter of 2013. The balance

of additional capacity is expected to be available by early 2014. The Athabasca Pipeline transports crude oil from

various oil sands projects to the mainline hub at Hardisty, Alberta.

FLANAGAN SOUTH PIPELINE PROJECT

The 950-kilometre (590-mile) Flanagan South Pipeline will have an initial capacity of approximately 585,000 bpd

to transport crude oil from the Company’s terminal at Flanagan, Illinois to Cushing, Oklahoma. The 36-inch

diameter pipeline will be installed adjacent to the Company’s Spearhead Pipeline for the majority of the route.

Subject to regulatory and other approvals, the pipeline is expected to be in service by mid-2014. The estimated

cost of the project is approximately US$2.8 billion, with expenditures to date of approximately US$0.2 billion.

CANADIAN MAINLINE EXPANSION

In May 2012, Enbridge announced an estimated $0.2 billion expansion of the Alberta Clipper line between Hardisty,

Alberta and the Canada/United States border near Gretna, Manitoba. The current scope of the project involves

the addition of pumping horsepower sufficient to raise the capacity of the Alberta Clipper line by 120,000 bpd

to a capacity of 570,000 bpd and is expected to be in service by mid-2014. The expansion remains subject to

National Energy Board (NEB) approval.

In January 2013, Enbridge announced a further expansion of the Canadian Mainline system between Hardisty, Alberta

and the Canada/United States border near Gretna, Manitoba, at an estimated cost of $0.4 billion, bringing the total

expected cost for the expansion to approximately $0.6 billion. Subject to NEB approval, the current scope of the

additional expansion involves the addition of pumping horsepower sufficient to raise the capacity of the Alberta

Clipper line by another 230,000 bpd to its full capacity of 800,000 bpd. This component of the expansion is

expected to be in service in 2015.

ATHABASCA PIPELINE TWINNING

This project involves the twinning of the southern section of the Company’s Athabasca Pipeline from Kirby Lake,

Alberta to the Hardisty, Alberta crude oil hub to provide additional capacity to serve expected oil sands growth in the

Kirby Lake producing region. The expansion project, with an estimated cost of approximately $1.2 billion, will include

345 kilometres (210 miles) of 36-inch pipeline adjacent to the existing Athabasca Pipeline right-of-way. The initial

annual capacity of the pipeline will be approximately 450,000 bpd, with expansion potential to 800,000 bpd. The line

is expected to enter service in 2015.

2 2 < EN BR IDGE I NC. 2012 FINANCIAL REPO RT

EDMONTON TO HARDISTY EXPANSION

In November 2012, the Company announced plans to proceed with an expansion of the Canadian Mainline

system between Edmonton, Alberta and Hardisty, Alberta. The expansion project, with an estimated cost of

approximately $1.8 billion, will include 181 kilometres (112 miles) of new 36-inch diameter pipeline, expected

to generally follow the same route as Enbridge’s existing Line 4 pipeline, and new terminal facilities at Edmonton

which include five new 500,000 barrel tanks and connections into existing infrastructure at Hardisty Terminal.

The initial capacity of the new line is expected to be approximately 570,000 bpd, with expansion potential to

800,000 bpd. Subject to regulatory approvals, the project is expected to be placed into service in 2015.

SOUTHERN ACCESS EXTENSION

In December 2012, Enbridge announced that it will undertake the Southern Access Extension project, which will

consist of the construction of a new 265-kilometre (165-mile), 24-inch diameter crude oil pipeline from Flanagan

to Patoka, Illinois as well as additional tankage and two new pump stations. Subject to regulatory approval, the project

is expected to be placed into service in 2015 at an approximate cost of US$0.8 billion. The initial capacity of the new

line is expected to be approximately 300,000 bpd. The Company also announced a binding open season to solicit

commitments from shippers for capacity on the proposed pipeline. The open season closed in January 2013 and the

Company is evaluating the results. Prior to launching the open season, Enbridge had already received sufficient capacity

commitments from an anchor shipper to support the 24-inch pipeline as proposed.

CANADIAN MAINLINE SYSTEM TERMINAL FLEXIBILITY AND CONNECTIVITY

In December 2012, as part of the Light Oil Market Access Program initiative, the Company announced that it will

undertake the Canadian Mainline System Terminal Flexibility and Connectivity project in order to accommodate

additional light oil volumes and enhance the operational flexibility of the Canadian mainline terminals. The cost of

the project is expected to be approximately $0.6 billion, with varying completion dates between 2013 and 2016

related to existing terminal facility modifications, comprised of upgrading existing booster pumps, additional

booster pumps and new tank line connections.

GAS DISTRIBUTION

GREATER TORONTO AREA PROJECT

In September 2012, EGD announced plans to expand its

natural gas distribution system in the Greater Toronto Area

(GTA) to meet the demands of growth and continue the safe

and reliable delivery of natural gas to current and future

customers. At an expected cost of approximately $0.6 billion,

the proposed GTA project will consist of two segments of

pipeline and related facilities to upgrade the existing distribution

system that delivers natural gas to several municipalities in

Ontario. In December 2012, the Company filed an application

with the Ontario Energy Board (OEB), and, subject to OEB

approval, construction is targeted to start in 2014, with

completion expected by the end of 2015.

Ontario

Quebec

Toronto

New York

Gas Distribution
17 Greater Toronto Area Project

Management’s Discussion and Analysis > 23

GAS PIPELINES, PROCESSING AND ENERGY SERVICES

SILVER STATE NORTH SOLAR PROJECT

In March 2012, Enbridge secured a 100% interest in the development of the 50-MW Silver State, located 65 kilometres

(40 miles) south of Las Vegas, Nevada. The project, which began commercial operation in May 2012, was constructed

under a fixed-price engineering, procurement and construction agreement with First Solar. First Solar is providing

operations and maintenance services under a long-term contract. Energy output is being delivered to NV Energy, Inc.

under a 25-year PPA. The Company’s total investment in the project was approximately US$0.2 billion. In October

2012, the Company received a US$55 million payment from the United States Treasury under a program which

reimburses eligible applicants for a portion of costs related to installing specified renewable energy property.

MASSIF DU SUD WIND PROJECT

In December 2012, Enbridge secured a 50% interest in the 150-MW Massif du Sud development, located 100

kilometres (60 miles) east of Quebec City, Quebec. Project construction was completed in December 2012

and commercial operation commenced in January 2013. Massif du Sud delivers energy to Hydro-Quebec under

a 20-year PPA. The Company’s total investment in the project is approximately $0.2 billion with expenditures to

date of approximately $0.1 billion. Additional expenditures are expected to be incurred into 2013.

LAC ALFRED WIND PROJECT

Enbridge secured a 50% interest in the development of the 300-MW Lac Alfred Wind Project (Lac Alfred), located

400 kilometres (250 miles) northeast of Quebec City in Quebec’s Bas-Saint-Laurent region. The project is being

constructed under a fixed price, turnkey, engineering, procurement and construction agreement and is being

undertaken in two phases. Phase 1, providing 150-MW, was completed and commenced commercial operations in

January 2013, with Phase 2, for the remaining 150-MW, expected to be completed in the third quarter of 2013.

Lac Alfred is delivering energy to Hydro-Quebec under a 20-year PPA. The Company’s total investment in the

project is expected to be approximately $0.3 billion, with expenditures to date of approximately $0.2 billion.

CABIN GAS PLANT

In 2011, the Company secured a 71% interest in the development of the Cabin Gas Plant (Cabin), located 60

kilometres (37 miles) northeast of Fort Nelson, British Columbia in the Horn River Basin. The Company’s total

investment in phases 1 and 2 of Cabin was expected to be approximately $1.1 billion. In October 2012, the Company

and its partners announced plans to defer both the commissioning of phase 1 and the construction of phase 2. In

December 2012, Enbridge began earning fees for its investment made to date in both phases 1 and 2. Under the

deferral, the Company’s total investment in phases 1 and 2 is now expected to be approximately $0.8 billion, with

expenditures to date of approximately $0.7 billion. Additional expenditures related to the deferral will continue to

be incurred in 2013.

PEACE RIVER ARCH GAS DEVELOPMENT

In November 2012, the Company completed the acquisition from Encana Corporation (Encana) of certain sour gas

gathering and compression facilities. These facilities, which are either currently in service or under construction, are

located in the PRA region of northwest Alberta. The project will be completed in phases with new gathering lines

expected to be in service in late 2013 and new NGL handling facilities expected to be completed in first quarter of

2014. Enbridge’s investment in the PRA Gas Development is expected to be approximately $0.3 billion, with

expenditures to date of approximately $0.1 billion. Enbridge is also working exclusively with Encana on facility scoping

for development of additional major midstream facilities in the liquids-rich PRA region. Financial terms of the PRA Gas

Development are expected to be substantially consistent with previously established terms of the Cabin development.

2 4 < EN BR IDGE I NC. 2012 FINANCIAL REPO RT

Fort St. John

Fort McMurray

Edmonton

Hardisty

Superior

Quebec City

Toronto

Sarnia

Denver

Chicago

Toledo

Cushing

Houston

New Orleans

Current Assets
Growth Opportunities

Gas Pipelines, Processing and Energy Services
18 Silver State North Solar Project
19 Massif du Sud Wind Project
20 Lac Alfred Wind Project
21 Cabin Gas Plant
22 Peace River Arch Gas Development

23 Tioga Lateral Pipeline
24 Venice Condensate Stabilization Facility
25 Walker Ridge Gas Gathering System
26 Big Foot Oil Pipeline
27 Heidelberg Lateral Pipeline

Management’s Discussion and Analysis > 25

TIOGA LATERAL PIPELINE

Alliance Pipeline US is constructing a natural gas pipeline lateral and associated facilities to connect production from

the Hess Tioga field processing plant in the Bakken region of North Dakota to the Alliance mainline near Sherwood,

North Dakota. The 124-kilometre (77-mile) Tioga Lateral Pipeline will facilitate movement of liquids-rich natural gas to

NGL processing facilities owned by Aux Sable at the terminus of Alliance. The pipeline will have an initial design capacity

of approximately 106 million cubic feet per day (mmcf/d), which can be expanded based on shipper demand. Through its

50% ownership interest in Alliance Pipeline US, Enbridge’s expected cost related to the project is approximately US$0.1

billion. In October 2012, Alliance Pipeline US executed a contract with Hess Corporation (Hess) as an anchor shipper.

Aux Sable Liquids Products and Hess have reached a concurrent agreement for the provision of NGL services. Regulatory

approval from the Federal Energy Regulatory Commission (FERC) was received in September 2012 and construction

commenced early October 2012, with an expected third quarter 2013 in-service date.

VENICE CONDENSATE STABILIZATION FACILITY

The Company is carrying out an estimated US$0.2 billion expansion of the Venice Condensate Stabilization Facility

(Venice) at its Venice, Louisiana facility within its Offshore business. Expenditures to date are approximately US$0.1

billion. The expanded condensate processing capacity is required to accommodate additional natural gas production

from the Olympus offshore oil and gas development. Natural gas production from Olympus will move to Enbridge’s

onshore facility at Venice via Enbridge’s Mississippi Canyon offshore pipeline system where it will be processed to

separate and stabilize the condensate. The expansion, which is expected to more than double the capacity of the facility

to approximately 12,000 barrels of condensate per day, is expected to be in service in late 2013.

WALKER RIDGE GAS GATHERING SYSTEM

The Company executed definitive agreements in 2010 with Chevron USA, Inc. (Chevron) and Union Oil Company

of California to expand its central Gulf of Mexico offshore pipeline system. Under the terms of the agreements,

Enbridge will construct, own and operate the Walker Ridge Gas Gathering System (WRGGS) to provide natural gas

gathering services to the proposed Jack, St. Malo and Big Foot ultra-deep water developments. The WRGGS includes

274 kilometres (170 miles) of 8-inch or 10-inch diameter pipeline at depths of up to approximately 2,150 meters

(7,000 feet) with capacity of 0.1 billion cubic feet per day (bcf/d). WRGGS is expected to be in service in 2014

and is expected to cost approximately US$0.4 billion, with expenditures to date of approximately US$0.1 billion.

BIG FOOT OIL PIPELINE

The Company executed definitive agreements in 2011 with Chevron, Statoil Gulf of Mexico LLC and Marubeni

Oil & Gas (USA) Inc. to construct and operate a 64-kilometre (40-mile) 20-inch oil pipeline with capacity of

100,000 bpd from the proposed Big Foot ultra-deep water development in the Gulf of Mexico. This crude oil

pipeline project is complementary to Enbridge’s plans to construct the WRGGS. The estimated cost of the

Big Foot Oil Pipeline, which will be located about 274 kilometres (170 miles) south of the coast of Louisiana,

is approximately US$0.2 billion, with expenditures to date of approximately US$0.1 billion. This project is

expected to be in service in 2014.

HEIDELBERG LATERAL PIPELINE

In November 2012, Enbridge announced it will build, own and operate a crude oil pipeline in the Gulf of Mexico

to connect the proposed Heidelberg development, operated by Anadarko Petroleum Corporation (Anadarko), to

an existing third-party system. The Heidelberg Lateral Pipeline (Heidelberg), a 20-inch, 55-kilometre (34-mile)

pipeline, will originate in Green Canyon Block 860, approximately 320 kilometres (200 miles) southwest of

New Orleans, Louisiana, and in an estimated 1,600 metres (5,300 feet) of water. Subject to regulatory and

other approvals, as well as sanctioning of the development by Anadarko and its project co-owners, Heidelberg

is expected to be operational by 2016 at an approximate cost of US$0.1 billion.

2 6 < EN BR IDGE I NC. 2012 FINANCIAL REPO RT

SPONSORED INVESTMENTS

BAKKEN EXPANSION PROGRAM

A joint project to further expand crude oil pipeline capacity to accommodate growing crude oil production

from the Bakken and Three Forks formations located in Montana, North Dakota, Saskatchewan and Manitoba

is being undertaken by EEP and the Fund. Upon completion, which is expected in the first quarter of 2013,

and subject to NEB approval, the Bakken Expansion Program will provide capacity of 145,000 bpd. The United

States component is being undertaken by EEP and the Canadian component is being undertaken by the Fund.

The estimated capital cost for the Canadian portion remains at approximately $0.2 billion, with expenditures

incurred to the end of December 2012 of approximately $0.1 billion. The estimated capital cost for the United

States portion of the project is now approximately US$0.3 billion, with expenditures incurred to the end of

December 2012 of approximately US$0.2 billion.

ENBRIDGE ENERGY PARTNERS, L.P.

BERTHOLD RAIL PROJECT

The Berthold Rail project will expand capacity into the Berthold Terminal by 80,000 bpd and includes the construction

of a three-unit train loading facility, crude oil tankage and other terminal facilities adjacent to existing infrastructure.

The first phase of terminal facilities was completed in September 2012, providing additional capacity of 10,000 bpd

to the Berthold Terminal. The loading facility and crude oil tankage are expected to be placed into service in the first

quarter of 2013. The estimated cost of the project is approximately US$0.1 billion, with project expenditures to date

of approximately US$0.1 billion.

AJAX CRYOGENIC PROCESSING PLANT

EEP is constructing an additional natural gas processing plant and other facilities on its Anadarko System. The Ajax

Plant, with a planned capacity of 150 mmcf/d, is expected to be in service mid-2013. When operational, the Ajax

Plant, in conjunction with the Allison Plant, is expected to increase total processing capacity on the Anadarko System

to approximately 1,200 mmcf/d. The estimated cost of the project is approximately US$0.2 billion, with expenditures

to date of approximately US$0.2 billion.

CUSHING TERMINAL STORAGE EXPANSION PROJECT

EEP has completed construction and placed into service 13 new crude oil storage tanks at its Cushing Terminal

with an approximate shell capacity of 4.4 million barrels. With five tanks completed in 2011, the remaining eight tanks

were placed into service throughout 2012. In July 2012, engineering design commenced on an additional three new

tanks and associated infrastructure totaling 936,000 barrels of incremental shell capacity at EEP’s Cushing Terminal,

at an estimated cost of US$39 million. The expected in-service date for the three tanks is now the fourth quarter of

2013. The total estimated cost to construct the 16 storage tanks and infrastructure, as required, is approximately

US$0.2 billion, with expenditures to date of approximately US$0.1 billion.

SOUTH HAYNESVILLE SHALE EXPANSION

EEP has expanded its East Texas natural gas pipeline system by constructing three lateral pipelines into the East Texas

portion of the Haynesville shale, together with a large diameter lateral pipeline from Shelby County to Carthage.

The expansion, completed in the second quarter of 2012 at an approximate cost of US$0.1 billion, increased capacity

of EEP’s East Texas system by 900 mmcf/d.

Management’s Discussion and Analysis > 27

Edmonton

Hardisty

Superior

Toronto

Sarnia

Chicago

Toledo

Flanagan

Cushing

Houston

New Orleans

Current Assets
Growth Opportunities

Sponsored Investments
28 EEP – Bakken Expansion Program
29 The Fund – Bakken Expansion Program
30 EEP – Berthold Rail Project
31 EEP – Ajax Cryogenic Processing Plant
32 EEP – Cushing Terminal Storage Expansion Project
33 EEP – South Haynesville Shale Expansion

34 EEP – Bakken Access Program
35 EEP – Texas Express Pipeline
36 EEP – Line 6B 75-Mile Replacement Program
37 EEP – Eastern Access
38 EEP – Lakehead System Mainline Expansion
39 EEP – Sandpiper Project

2 8 < EN BR IDGE I NC. 2012 FINANCIAL REPO RT

EEP plans to invest an additional US$0.2 billion, with expenditures to date of approximately US$0.1 billion, to expand

its East Texas system, including the construction of gathering and related treating facilities. EEP has signed long-term

agreements with four major natural gas producers along the Texas side of the Haynesville shale to provide gathering,

treating and transmission services. Completion of the additional expansion is dependent on drilling plans of these

producers. Due to lower levels of producer activity in response to weak natural gas prices, EEP has deferred portions

of its Haynesville natural gas expansion pending increases in drilling activity.

BAKKEN ACCESS PROGRAM

The Bakken Access Program represents an upstream expansion that will further complement EEP’s Bakken expansion.

This expansion program will enhance crude oil gathering capabilities on the North Dakota System by 100,000 bpd.

The program involves increasing pipeline capacity, constructing additional storage tanks and adding truck access

facilities at multiple locations in western North Dakota at an approximate cost of US$0.1 billion, with expenditures

to date of approximately US$0.1 billion. The Bakken Access Program is expected to be in service by mid-2013.

TEXAS EXPRESS PIPELINE

The TEP is a joint venture with Enterprise, Anadarko and DCP Midstream LLC to design and construct a new

NGL pipeline and two new NGL gathering systems which EEP will build and operate. EEP will invest approximately

US$0.4 billion in the TEP, which will originate in Skellytown, Texas and extend approximately 935 kilometres

(580 miles) to NGL fractionation and storage facilities in Mont Belvieu, Texas. Expenditures to date are approximately

US$0.2 billion. TEP is expected to have an initial capacity of approximately 280,000 bpd and will be expandable to

approximately 400,000 bpd. Approximately 250,000 bpd of capacity has been subscribed on the pipeline.

One of the new NGL gathering systems will connect TEP to natural gas processing plants in the Anadarko/Granite

Wash production area located in the Texas Panhandle and western Oklahoma, while the second will connect TEP to

central Texas Barnett Shale processing plants. Subject to regulatory approvals and finalization of commercial terms,

the pipeline and portions of the gathering systems are expected to begin service in the third quarter of 2013.

LINE 6B 75-MILE REPLACEMENT PROGRAM

This program includes the replacement of 120 kilometres (75 miles) of non-contiguous sections of Line 6B of

EEP’s Lakehead System. The Line 6B pipeline runs from Griffith, Indiana through Michigan to the international

border at the St. Clair River. The new segments are expected to be placed in service during 2013 in consultation with,

and to minimize impact to, refiners and shippers served by Line 6B crude oil deliveries. These costs will be recovered

through EEP’s tariff surcharge that is part of the system-wide rates for the Lakehead System. The total capital for this

replacement program is estimated to be US$0.3 billion, with expenditures to date of approximately US$0.2 billion.

EASTERN ACCESS

The Eastern Access initiative includes several crude oil pipeline projects announced by Enbridge and EEP in

2011 and 2012 to provide increased access to refineries in the United States upper mid-west and eastern Canada.

The current scope of Enbridge projects includes a reversal of its Line 9 and expansion of the Toledo Pipeline.
The current scope of EEP projects includes an expansion of its Line 5 as well as United States mainline system

expansions involving the Spearhead North Pipeline (Line 62) and further segments of Line 6B. The individual

projects are further described below.

Enbridge plans to reverse a portion of its Line 9A in western Ontario to permit crude oil movements eastbound

from Sarnia as far as Westover, Ontario at a revised estimated cost of approximately $48 million. With NEB approval

received in July 2012, the Line 9A reversal is expected to be in service in late 2013.

Management’s Discussion and Analysis > 29

Enbridge also plans to undertake a full reversal of its 240,000 bpd Line 9B from Westover, Ontario to Montreal,

Quebec to serve refineries in Quebec. The Line 9B reversal is expected to be completed at an estimated cost of

approximately $0.3 billion. Following an open season held on the Line 9B reversal project, further commitments

were received that required an additional 80,000 bpd of delivery capacity within Ontario and Quebec. The Line 9B

capacity expansion is expected to be completed at an estimated cost of approximately $0.1 billion. Subject to NEB

regulatory approval, the Line 9B reversal and Line 9B capacity expansion are expected to be available for service in

2014 at a total estimated cost of approximately $0.4 billion.

Enbridge is also undertaking an 80,000 bpd expansion of its Toledo Pipeline (Line 17), which connects with the

EEP mainline at Stockbridge, Michigan and serves refineries at Toledo, Ohio and Detroit, Michigan. The Toledo

Pipeline expansion is expected to be available for service by the second quarter of 2013 at a cost of approximately

US$0.2 billion, with expenditures to date of approximately US$0.1 billion.

Both the Toledo Pipeline and Line 9 assets are included in the Company’s Liquids Pipelines segment.

EEP is expanding its Line 5 light crude oil line between Superior, Wisconsin and Sarnia, Ontario by 50,000 bpd,

at a cost of approximately US$0.1 billion. The Line 5 expansion is targeted to be in service during the first quarter

of 2013.

EEP is also undertaking the expansion of its Line 62 between Flanagan and Griffith, Indiana by adding horsepower to

increase capacity from 130,000 bpd to 235,000 bpd and adding a 330,000 barrel tank at Griffith. The Line 62 capacity

expansion project is expected to be placed into service by the end of 2013. EEP also plans to replace additional sections

of Line 6B in Indiana and Michigan to increase capacity from 240,000 bpd to 500,000 bpd, with a target in-service

date of early 2014. The replacement of these sections of Line 6B is in addition to the Line 6B Replacement Program

announced in 2011 and discussed previously. The expected cost of the United States mainline expansions is US$2.2

billion, and includes the US$0.1 billion cost of the previously discussed Line 5 expansion.

In December 2012, Enbridge and EEP announced a further upsizing of EEP’s Line 6B component of the Eastern

Access Expansion initiative. The Line 6B capacity expansion from Griffith to Stockbridge, Michigan will increase

capacity from 500,000 bpd to 570,000 bpd and will involve the addition of new pumps, existing station modifications

and breakout tankage at the Griffith and Stockbridge terminals. Subject to regulatory and other approvals, the project

is expected to be placed into service in 2016 at an estimated capital cost of approximately US$0.4 billion.

The total estimated cost of the United States mainline expansions, including the Line 6B capacity expansion project, is

approximately US$2.6 billion, with expenditures to date of approximately US$0.3 billion. The Eastern Access projects

will be funded 60% by Enbridge and 40% with EEP having the option to reduce its funding and associated economic

interest in the project by up to 15% before June 30, 2013. Furthermore, within one year of the final in-service date of

the collective projects, EEP will have the option to increase its economic interest held at that time by up to 15%.

LAKEHEAD SYSTEM MAINLINE EXPANSION

In 2012, Enbridge and EEP announced several projects to expand capacity of the Lakehead System mainline between

its origin at the Canada/United States border, near Neche, North Dakota, to Flanagan, Illinois. Included in the

expansion are Alberta Clipper (Line 67) and Southern Access (Line 61).

The current scope of the Alberta Clipper expansion between the border and Superior, Wisconsin consists of two phases.

The initial phase, announced in May 2012, includes a planned increase in capacity from 450,000 bpd to 570,000 bpd

at an estimated capital cost of approximately US$0.2 billion. In January 2013, EEP announced a further expansion of

the Lakehead System mainline between the border and Superior, to increase capacity from 570,000 bpd to 800,000

bpd, at an estimated capital cost of approximately US$0.2 billion. Subject to finalization of scope and regulatory and

shipper approvals, including an amendment to the current Presidential border crossing permit to allow for operation of

Line 67 at its currently planned operating capacity of 800,000 bpd, the target in-service dates for the proposed projects
are mid-2014 for the initial phase and 2015 for the second phase. Both phases of the Alberta Clipper expansion would

require only the addition of pumping horsepower and no pipeline construction.

3 0 < EN BR IDGE I NC. 2012 FINANCIAL REPO RT

The current scope of the Southern Access expansion between Superior and Flanagan, Illinois also consists of two

phases. The initial phase, announced in May 2012, includes a planned increase in capacity from 400,000 bpd

to 560,000 bpd at an estimated capital cost of approximately US$0.2 billion. In December 2012, EEP announced

a further expansion of the Southern Access line between Superior and Flanagan, to increase capacity from 560,000 bpd

to 1,200,000 bpd at an estimated capital cost of approximately US$1.3 billion. Both phases of the expansion would

require only the addition of pumping horsepower and crude oil tanks at existing sites with no pipeline construction.

Subject to finalization of scope and regulatory approvals, the target in-service date for the first phase of the expansion is

expected to be in mid-2014. For the second phase of the expansion, which is also subject to finalization of design and

regulatory approvals, the pump station expansion is expected to be available for service in 2015, with additional tankage

requirements expected to be completed in 2016.

As part the Light Oil Market Access Program, Enbridge and EEP announced the capacity expansion of the Lakehead

System between Flanagan, Illinois and Griffith, Indiana. This section of the Lakehead System will be expanded by

constructing a 122-kilometre (76-mile), 36-inch diameter twin of the existing Spearhead North Pipeline (Line 62).

The project is expected to be completed at an estimated cost of approximately US$0.5 billion. The new line will have

an initial capacity of 570,000 bpd and is expected to be placed into service in 2015.

The projects collectively referred to as the Lakehead System Mainline Expansion are expected to cost approximately

US$2.4 billion and will operate on a cost-of-service basis. The projects will be funded 60% by Enbridge and 40% by

EEP under similar joint funding arrangement terms to those described under Growth Projects – Commercially Secured

Projects – Sponsored Investments – Eastern Access. Furthermore, within one year of the final in service date, EEP will

also have the option to increase its economic interest held at that time by up to 15%.

SANDPIPER PROJECT

In December 2012, Enbridge and EEP announced the Light Oil Market Access Program which consists of several

individual projects. As part of this initiative, EEP plans to undertake the Sandpiper Project which will expand and

extend EEP’s North Dakota feeder system. The Bakken takeaway capacity of the North Dakota System will be

expanded by 225,000 bpd to a total of 580,000 bpd, with a target in-service date in 2016. The expansion will involve

construction of an approximate 965-kilometre (600-mile) 24-inch diameter line from Beaver Lodge, North Dakota,

to the Superior, Wisconsin, mainline system terminal. The new line will twin the 210,000 bpd North Dakota System

mainline, which now terminates at Clearbrook Terminal in Minnesota, adding 225,000 bpd of capacity on the twin line

between Beaver Lodge and Clearbrook, and 375,000 bpd of capacity between Clearbrook and Superior. The Sandpiper

Project will be fully funded by EEP at an estimated capital cost of approximately US$2.5 billion. Subject to finalization

of scope and regulatory approval, the capital cost will be rolled into the existing North Dakota System rate base, with

the associated cost of service to be recovered in tolls.

Management’s Discussion and Analysis > 31

CORPORATE

MONTANA-ALBERTA TIE-LINE

Lethbridge

MATL is a 345-kilometre (215-mile) transmission line

from Great Falls, Montana to Lethbridge, Alberta, designed

to take advantage of the growing supply of electric power in

Montana and buoyant power demand in Alberta. The total

expected cost for both the first 300-MW phase of MATL and

the expansion for an additional 300-MW has been increased

to approximately US$0.4 billion, with expenditures to date

of approximately US$0.3 billion. The permits required for

construction had been previously obtained and in December

2012 the Alberta Utility Commission in Canada approved

the Company’s updated design modifications. The system’s

north-bound capacity, which is fully contracted, is now

targeted to be in service in the second quarter of 2013, with

the expansion targeted to be completed by the end of 2014.

NEAL HOT SPRINGS GEOTHERMAL PROJECT

The Company has partnered with U.S. Geothermal Inc.

(U.S. Geothermal) to develop the 35-MW (22-MW, net)

Neal Hot Springs Geothermal Project located in

Canada

United States

Great Falls

Corporate
40 Montana-Alberta Tie-Line

Malheur County, Oregon. U.S. Geothermal is constructing the plant and will operate the facility. The project

declared commercial operation in November 2012, with the facility delivering electricity to the Idaho Power

grid under a 25-year PPA. Enbridge invested approximately US$33 million for a 41% interest in the project.

Growth Projects – Other Projects Under Development

The following projects are also currently under development by the Company, but have not yet met Enbridge’s

criteria to be classified as commercially secured.

LIQUIDS PIPELINES

WOODLAND PIPELINE EXTENSION

In September 2012, Enbridge received approval from the Alberta Energy Resources Conservation Board (ERCB)

to construct the Woodland Pipeline Extension Project. The project will extend the Woodland Pipeline south from

Enbridge’s Cheecham Terminal to its Edmonton Terminal. The extension is a proposed 385-kilometre (228-mile),

36-inch diameter pipeline, requiring an investment of approximately $1.0 billion to $1.4 billion for an initial capacity

of 400,000 bpd, expandable to 800,000 bpd. The estimated investment remains subject to finalization of scope and
a definitive cost estimate. All major environmental approvals have been received and, subject to final commercial

approval, Enbridge anticipates a 2015 in-service date. Project expenditures to date are approximately $0.1 billion,

with pre-development costs being backstopped by shippers pending final commercial approval.

3 2 < EN BR IDGE I NC. 2012 FINANCIAL REPO RT

TRUNKLINE JOINT VENTURE

In February 2013, Enbridge entered into an agreement with Energy Transfer Partners L.P. (Energy Transfer) on the

terms for joint development of a project to provide access to the eastern Gulf Coast refinery market from the Patoka,

Illinois hub. Subject to FERC approval, the project will involve the conversion from natural gas service of certain

segments of pipeline that are currently in operation as part of the natural gas system of Trunkline Gas Company, LLC,

a wholly owned subsidiary of Energy Transfer and Energy Transfer Equity, L.P. The converted pipeline is expected

to have a capacity of up to 420,000 to 660,000 bpd, depending on crude slate and the level of subscriptions received

in an open season, and is expected to be in service by early 2015. Enbridge and Energy Transfer would each own a

50% interest in the venture. Enbridge’s participation in the venture is subject to a minimum level of commitments

being obtained in the open season and on completion of due diligence on the conversion cost. Depending on the

level of commitments and finalization of scope and capital cost estimates, Enbridge expects to invest approximately

US$1.2 billion to US$1.7 billion.

NORTHERN GATEWAY PROJECT

Northern Gateway involves constructing a twin 1,177-kilometre (731-mile) pipeline system from near Edmonton,

Alberta to a new marine terminal in Kitimat, British Columbia. One pipeline would transport crude oil for export from

the Edmonton area to Kitimat and is proposed to be a 36-inch diameter line with an initial capacity of 525,000 bpd.

The other pipeline would be used to import condensate and is proposed to be a 20-inch diameter line with an initial

capacity of 193,000 bpd.

Northern Gateway submitted an application to the NEB in May 2010. The Joint Review Panel (JRP) established

to review the proposed project, pursuant to the NEB Act and the Canadian Environmental Assessment Act, has a

broad mandate to assess the potential environmental effects of the project and to determine if it is in the public

interest. Following sessions with the public, including Aboriginal groups, and the provision of additional information

by Northern Gateway, the JRP issued a Hearing Order in May 2011 outlining the procedures to be followed.

In August 2011, Northern Gateway filed commercial agreements with the NEB which provide for committed long-

term service and capacity on both the proposed crude oil export and condensate import pipelines. Capacity has also

been reserved for use by uncommitted shippers.

In the fall of 2011, Northern Gateway responded to written questions by intervenors and government participants.

In a Procedural Direction issued in December 2011, the JRP indicated community hearings would be scheduled so

the Panel would hear all oral evidence from registered intervenors first, followed by oral statements from registered

participants. Community hearings for oral evidence and statements took place between January and August 2012 in

various communities. A written record of what was said each day in the community hearings is available on the Panel’s

website. Intervenors responded to questions by Northern Gateway on July 6, 2012. Northern Gateway filed reply

evidence to the evidence of the intervenors on July 20, 2012. The reply evidence contained details of further

enhancements in pipeline design and operations. These extra measures, estimated to cost an additional $400 million

to $500 million, together with additional marine infrastructure, result in a total estimated project cost of approximately

$6.6 billion. The enhancements include: increasing pipeline wall thickness of the oil pipeline; additional pipeline wall

thickness for water crossings such as major tributaries to the Fraser, Skeena and Kitimat Rivers; increasing the number

of remotely-operated isolation valves by 50% within British Columbia to protect high-value fish habitat; increasing

frequency of in-line inspection surveys across the entire Northern Gateway pipeline system by a minimum of 50% over

and above current standards; installing dual leak detection systems; and staffing pump stations in remote locations on

a 24 hour/7 day basis for on-site monitoring, heightened security and rapid response to abnormal conditions.

The final hearings commenced on September 4, 2012 where Northern Gateway, intervenors, government participants

and the JRP questioned those who have presented oral or written evidence.

Management’s Discussion and Analysis > 33

The final hearings and the remaining oral statements from interested parties who do not reside along the pipeline

corridor or shipping routes are expected to be completed by May 2013. Based on this projected schedule, the JRP

expects to issue its reports and findings on the proposed project by December 2013.

Of the 45 Aboriginal groups eligible to participate as equity owners, 26 have signed up to do so. Subject to continued

commercial support, regulatory and other approvals, and adequately addressing landowner and local community

concerns (including those of Aboriginal communities), the Company currently estimates that Northern Gateway could

be in service in 2018 at the earliest.

On February 23, 2012, Transport Canada published its TERMPOL Review Process Report of the Northern Gateway’s

proposed marine operations. Transport Canada has filed the results of the study with the federal JRP tasked with assessing

the project. The study reviewed the marine operations associated with the Northern Gateway terminal and associated

tanker traffic in Canadian waters. The review concluded that: “While there will always be residual risk in any project, after

reviewing the proponent’s studies and taking into account the proponent’s commitments, no regulatory concerns have

been identified for the vessels, vessel operations, the proposed routes, navigability, other waterway users and the marine

terminal operations associated with vessels supporting the Northern Gateway.” The TERMPOL report was prepared and

approved by Canadian government authorities including Transport Canada; Environment Canada; Fisheries and Oceans

Canada; Canadian Coast Guard; and Pacific Pilotage Authority Canada. The Gitxaala First Nations (Gitxaala) filed a

Notice of Judicial Review with the Federal Court of Canada challenging the TERMPOL process on the grounds that

there had not been adequate consultation with the Gitxaala with respect to the potential impacts on its Rights and Title

resulting from the routine operation of the tankers servicing the Northern Gateway terminal in Kitimat. Following the

hearing, the Federal Court of Canada issued a decision rejecting the Gitxaala challenge.

Expenditures to date, which relate primarily to the regulatory process, are approximately $0.3 billion, of which

approximately half is being funded by potential shippers on Northern Gateway. Given the many uncertainties

surrounding the Northern Gateway, including final ownership structure, the potential financial impact of the

project cannot be determined at this time.

The JRP posts public filings related to Northern Gateway on its website at http://gatewaypanel.review-examen.gc.ca/

clf-nsi/hm-eng.html and Enbridge also maintains a Northern Gateway website in addition to information available on

www.enbridge.com. The full regulatory application submitted to the NEB and the 2010 Enbridge Northern Gateway
Community Social Responsibility Report are available on www.northerngateway.ca. None of the information contained
on, or connected to, the JRP website, the Northern Gateway website or Enbridge’s website is incorporated in or

otherwise part of this MD&A.

GAS PIPELINES, PROCESSING AND ENERGY SERVICES

NEXUS GAS TRANSMISSION PROJECT

In September 2012, Enbridge, DTE Energy Company (DTE) and Spectra Energy Corp (Spectra) announced the

execution of a Memorandum of Understanding to jointly develop the NEXUS Gas Transmission System (NEXUS),

a project that will move growing supplies of Ohio Utica shale gas to markets in the United States midwest, including

Ohio and Michigan and Ontario, Canada. The proposed NEXUS project will originate in northeastern Ohio, include

approximately 400 kilometres (250 miles) of large diameter pipe, and be capable of transporting one bcf/d of natural

gas. The line will follow existing utility corridors to an interconnect in Michigan and utilize the existing Vector pipeline

to reach the Ontario market. Upon completion, Spectra would become a 20% owner in Vector, a joint venture between

DTE and Enbridge. The next steps include analyzing open season service requests from the October 2012 open season

and working with potential customers to formalize these requests into binding contract commitments. The targeted

in-service date is late 2016.

3 4 < EN BR IDGE I NC. 2012 FINANCIAL REPO RT

Liquids Pipelines

EARNINGS

(millions of Canadian dollars)

Canadian Mainline

Regional Oil Sands System

Southern Lights Pipeline

Seaway Pipeline

Spearhead Pipeline

Feeder Pipelines and Other

Adjusted earnings

Canadian Mainline – Line 9 tolling adjustment

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

Canadian Mainline – shipper dispute settlement

Regional Oil Sands System – prior period adjustment

Regional Oil Sands System – asset impairment write-off

Regional Oil Sands System – gain on acquisition

Spearhead Pipeline – changes in unrealized derivative fair value gains

2012

2011

432

110

684

–

(6)

–

336

111

(3)

–

536

(48)

–

(8)

–

Earnings attributable to common shareholders

726

505

Liquids Pipelines adjusted earnings were $684 million in 2012 compared

with adjusted earnings of $536 million in 2011 and $511 million in 2010.

The Company continued to realize earnings growth on the Canadian

Mainline in 2011 and 2012, primarily due to strong volume throughput

and favourable operating performance under the CTS which took effective

July 1, 2011. Other factors which contributed to the adjusted earnings

increase included earnings from Seaway Pipeline since the initial reversal in

May 2012, increased volumes on Spearhead Pipeline, as well as increased

earnings from a number of the Company’s feeder pipelines.

LIQUIDS PIPELINES EARNINGS
(millions of Canadian dollars)

1
6
2
7

4
8
6

1
1
3
5

1
1
5

6
3
5

1
5
0
5

2
5
4
4

4
5
4

Liquids Pipelines earnings were impacted by the following adjusting items:

2
8
2
3

2
3
3

2010

326

–

511

–

531

• Canadian Mainline earnings for 2012 and 2011 included Line 9 tolling

adjustments related to services provided in prior periods.

• Canadian Mainline earnings for 2012 and 2011 reflected changes in

unrealized fair value gains and losses on derivative financial instruments

used to risk manage exposures inherent within the CTS, namely foreign

exchange, power cost variability and allowance oil commodity prices.
• Canadian Mainline earnings for 2011 included $14 million from the

settlement of a shipper dispute related to oil measurement adjustments

in prior years.

• Regional Oil Sands System earnings for 2012 included a revenue

recognition adjustment related to prior periods.

• Regional Oil Sands System earnings for 2011 included the write-off

of development expenditures on certain project assets.

• Regional Oil Sands System earnings for 2010 included a gain on

step-acquisition of crude oil storage assets.

GAAP Earnings
Adjusted Earnings

•

Spearhead Pipeline earnings for 2011 included changes in unrealized fair value gains on derivative financial
instruments used to manage exposures to allowance oil commodity prices.

Management’s Discussion and Analysis > 35

CANADIAN MAINLINE

The mainline system is comprised of Canadian Mainline

and Lakehead System (the portion of the mainline in

the United States that is operated by Enbridge and

owned by EEP). Enbridge has operated, and frequently

expanded, the mainline system since 1949. Through six

adjacent pipelines, with a combined capacity of approximately

2.5 million bpd, which cross the Canada/United States

border near Gretna, Manitoba and Neche, North Dakota,

the system transports various grades of crude oil and

diluted bitumen from western Canada to the midwest

region of the United States and eastern Canada. Also

included within the Canadian Mainline and located in

eastern Canada are two crude oil pipelines and one

refined products pipeline with a combined capacity

of 0.4 million bpd.

COMPETITIVE TOLL SETTLEMENT

LIQUIDS PIPELINES

Zama

Waupisoo Pipeline

Edmonton

Hardisty

Blaine

NW System

Fort McMurray

Athabasca System

Enbridge System

Portland

Olympic Pipeline

Frontier Pipeline

Gretna

Salt Lake
City

Casper

Chicago

Spearhead Pipeline

Cushing

Seaway Crude
Pipeline System

Montreal

Toronto

Buffalo

Sarnia
Toledo
Chicap Pipeline

Patoka

Mustang Pipeline

Canadian Mainline tolls are governed by the 10-year settlement reached between Enbridge and shippers on its mainline

system and approved by the NEB in 2011. The CTS, which took effect on July 1, 2011, covers local tolls to be charged

for service on the mainline system (with the exception of Lines 8 and 9). Under the terms of the CTS, the initial

Canadian Local Toll (CLT), applicable to deliveries within western Canada, was based on the 2011 Incentive Tolling

Settlement (ITS) toll and will be subsequently adjusted by 75% of the Canada Gross Domestic Product at Market Price

Index, effective July 1, for each of the remaining nine years of the settlement.

The CTS also provides for an International Joint Tariff (IJT) for crude oil shipments originating in Canada on the

mainline system and delivered in the United States off the Lakehead System, and into eastern Canada. The IJT, which

is based on a fixed toll for the term of the settlement that was negotiated between Enbridge and shippers, will be

adjusted annually by the same factor as the CLT.

In limited circumstances the shippers or Enbridge may elect to renegotiate the toll. If a renegotiation of the toll is

triggered, Enbridge and the shippers will meet and use reasonable efforts to agree on how the CTS can be amended

to accommodate the event.

Local tolls for service on the Lakehead System will not be affected by the CTS and will continue to be established by

EEP’s existing toll agreements. Under the terms of the IJT agreement between Enbridge and EEP, the Company’s

share of the IJT toll relating to pipeline transportation of a batch from any western Canada receipt point to the United

States border is equal to the IJT toll applicable to that batch’s United States delivery point less the Lakehead System’s

local toll to that delivery point. This amount is referred to as the Canadian Mainline IJT Residual Toll.

The IJT is designed to provide mainline shippers with a stable and competitive long-term toll, preserving and

enhancing throughput on both the Canadian Mainline and Lakehead System. Earnings under the CTS are subject

to variability in volume throughput, as well as capital and operating costs, and the United States dollar exchange rate.

The Company may utilize derivative financial instruments to hedge foreign exchange rate risk on United States dollar

denominated revenues and commodity price risk resulting from exposure to crude oil and power prices.

3 6 < EN BR IDGE I NC. 2012 FINANCIAL REPO RT

INCENTIVE TOLLING

Prior to the CTS taking effect on July 1, 2011, tolls on Canadian Mainline

were governed by various agreements which were subject to NEB approval.

These agreements included both the 2011 and 2010 ITS applicable to

the Canadian Mainline (excluding Lines 8 and 9), the Terrace agreement,

the SEP II Risk Sharing agreement, the Alberta Clipper agreement and

the Southern Access Expansion agreement which were recovered via the

CANADIAN MAINLINE—
AVERAGE DELIVERIES
(thousands of barrels per day)

2
2
5

2
6
5

7
3
5

4
5
5

6
4
6

Mainline Expansion Toll.

RESULTS OF OPERATIONS

Canadian Mainline adjusted earnings were $432 million for the year

ended December 31, 2012 compared with $336 million for the year ended

December 31, 2011 and $326 million for the year ended December 31,

2010. The comparability of Canadian Mainline earnings year-over-year is

affected by the change in tolling methodology. As noted previously, from

July 1, 2011 onward, Canadian Mainline earnings (excluding Lines 8 and 9)

were governed by the CTS, whereas operations for the first six months of

2011 and for the year ended December 31, 2010 were governed by a series

of agreements, the most significant being the ITS applicable to the mainline

system and the Terrace and Alberta Clipper agreements. Under the CTS,

earnings are subject to variability in volume throughput and operating costs

compared with prior tolling arrangements which were based on a cost-of-service methodology.

Canadian Mainline revenues for the year ended December 31, 2012 reflected increased volumes and a higher Canadian

Mainline IJT Residual Benchmark Toll which, under the IJT, is impacted by changes in the Lakehead System Local Toll.

Volume throughput in 2012 was impacted by market conditions as incremental oil sands crude production in Alberta and

strong production growth out of the Bakken in North Dakota bolstered supply to midwest markets and placed increased

downward pressure on crude oil prices in that market. This discounted crude oil, coupled with strong refining margins,

increased demand in the midwest for Canadian and Bakken crude oil supply and drove increased long haul barrels on

Canadian Mainline and EEP’s Lakehead System. However, during the fourth quarter of 2012, Canadian Mainline was

not able to capture the full throughput benefit of the increased supply available to it due to capacity limitations which

arose from pressure restrictions being applied to certain lines pending completion of inspection and repair programs.

The Company expects that capacity limitations will continue to constrain throughput during the first quarter of 2013

and, to a diminishing extent, for the remainder of 2013. An increase in operating and administrative costs, primarily

due to higher employee related costs and higher leak remediation costs, also impacted 2012 adjusted earnings.

Management’s Discussion and Analysis > 37

Supplemental information on Canadian Mainline adjusted earnings for the year ended December 31, 2012 and for the

six month period from July 1, the effective date of the CTS, to December 31, 2011 is as follows:

(millions of Canadian dollars)

Revenues

Expenses

Operating and administrative

Power

Depreciation and amortization

Other income/(expense)

Interest expense

Income taxes

Adjusted earnings

Year ended
December 31,

Six months
ended December 31,

2012

1,367

382

112

219

713

654

(4)

(131)

519

(87)

432

2012

711

192

110

359

352

(1)

(66)

285

(48)

237

2011

618

194

104

352

266

(66)

205

(31)

174

Effective United States to Canadian dollar exchange rate 1

0.971

0.974

0.972

December 31,
IJT Benchmark Toll 2 (United States dollars per barrel)
Lakehead System Local Toll 3 (United States dollars per barrel)
Canadian Mainline IJT Residual Benchmark Toll 4 (United States dollars per barrel)

2012

3.94

1.85

2.09

2011

3.85

2.01

1.84

1
2

Inclusive of realized gains or losses on foreign exchange derivative financial instruments.
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, 2012, the IJT benchmark toll increased from
US$3.85 to US$3.94.
The Lakehead System Local Toll is per barrel of heavy crude oil transported from Neche, North Dakota to Chicago, Illinois. Effective April 1, 2012, this toll decreased from
US$2.01 to US$1.76 and, effective July 1, 2012, this toll increased from US$1.76 to US$1.85.
The Canadian Mainline IJT Residual Benchmark Toll is per barrel of heavy crude oil transported from Hardisty, Alberta to Gretna, Manitoba. Effective April 1, 2012, this
toll increased from US$1.84 to US$2.09, with no change effective July 1, 2012. For any shipment, this toll is the difference between the IJT toll for that shipment and the
Lakehead System Local Toll for that shipment.

THROUGHPUT VOLUME 1

1,687

1,659

2012

1,617

1,622

Total

1,646

1,602

1,457

2011

1,565

1,594

Total

1,554

Throughput volume, presented in thousand barrels per day, represents mainline deliveries ex-Gretna, Manitoba which is made up of United States and eastern Canada
deliveries from western Canada.

3 8 < EN BR IDGE I NC. 2012 FINANCIAL REPO RT

Canadian Mainline revenues include the portion of the system covered by the CTS as well as revenues from Lines 8 and 9

in eastern Canada. Lines 8 and 9 are currently tolled on a separate basis and comprise a relatively small proportion of total

Canadian Mainline revenues. CTS revenues include transportation revenues, the largest component, as well as allowance

oil and revenues from receipt and delivery charges. Transportation revenues include revenues for volumes delivered off the

Canadian Mainline at Gretna and on to the Lakehead System, to which Canadian Mainline IJT residual tolls apply, and

revenues for volumes delivered to other western Canada delivery points, to which the CLT applies. Despite the many

factors which affect Canadian Mainline revenues, the primary determinants of those revenues will be throughput volume

ex-Gretna, the United States dollar Canadian Mainline IJT Residual Benchmark Toll and the effective foreign exchange

rate at which resultant revenues are converted into Canadian dollars. The Company currently utilizes derivative financial

instruments to hedge foreign exchange rate risk on United States dollar denominated revenues. The exact relationship

between the primary determinants and actual Canadian Mainline revenues will vary somewhat from quarter to quarter

but is expected to be relatively stable on average for a year, absent a systematic shift in receipt and delivery point mix

or in crude oil type mix.

The largest components of operating and administrative expense are employee related costs, pipeline integrity, repairs and

maintenance, rents and leases and property taxes. Operating and administrative costs are relatively insensitive to throughput

volumes. The primary drivers of future increases in operating costs are expected to be normal escalation in wage rates, prices

for purchased services, the addition of new facilities and more extensive integrity and maintenance programs.

Power, the most significant variable operating cost, is subject to variations in operating conditions, including system
configuration, pumping patterns and pressure requirements; however, the primary determinants of this cost are the

power prices in various jurisdictions and throughput volume. The relationship of power consumption to throughput

volume is expected to be roughly proportional over a moderate range of volumes. The Company currently utilizes

derivative financial instruments to hedge power prices.

Depreciation and amortization expense will adjust over time as a result of additions to property, plant and equipment

due to new facilities, including integrity capital expenditures.

Canadian Mainline income taxes reflect current income taxes only. Under the CTS, the Company retains the ability

to recover deferred income taxes under an NEB order governing flow-through income tax treatment and, as such,

an offsetting regulatory asset related to deferred income taxes is recognized as incurred.

The preceding financial overview includes expectations regarding future events and operating conditions that the

Company believes are reasonable based on currently available information; however, such statements are not

guarantees of future performance and are subject to change.

Prior to the implementation of the CTS, revenues on the Canadian Mainline was recognized in a manner consistent

with the underlying agreements as approved by the regulator, in accordance with rate-regulated accounting. The

Company discontinued the application of rate-regulated accounting to its Canadian Mainline (excluding Lines 8 and 9)

on a prospective basis commencing July 1, 2011. A regulatory asset of approximately $470 million related to deferred

income taxes recorded at the date of discontinuance continued to be recognized as the Company retains the ability to

recover deferred income taxes under an NEB order governing flow-through income tax treatment. The regulatory asset

balance at the date of discontinuance related to tolling deferrals recognized in prior periods is being recovered through

a surcharge to the CLT and IJT.

Management’s Discussion and Analysis > 39

REGIONAL OIL SANDS SYSTEM

Regional Oil Sands System consists of two long haul

Wood Buffalo Pipeline

Woodland Pipeline

pipelines, the Athabasca Pipeline and the Waupisoo Pipeline,

Fort McMurray
Cheecham

Waupisoo Pipeline

Edmonton

Hardisty

Athabasca System

Kerrobert

Calgary

as well as the recently completed lateral pipeline and the

receipt Wood Buffalo Pipeline. Regional Oil Sands System

also includes a variety of other facilities such as the MacKay

River, Christina Lake, Surmont and Long Lake facilities, as

well as the Woodland Pipeline. It also includes two large

terminals: the Athabasca Terminal located north of Fort

McMurray, Alberta and the Cheecham Terminal, located

95 kilometres (59 miles) south of Fort McMurray where

the Waupisoo Pipeline initiates.

The Athabasca Pipeline is a 540-kilometre (335-mile)

synthetic and heavy oil pipeline, built in 1999, which links the

Athabasca oil sands in the Fort McMurray, Alberta region to

a pipeline hub at Hardisty, Alberta. The Athabasca Pipeline

has an ultimate design capacity of approximately 570,000

bpd, dependent on the viscosity of crude being shipped. It is currently configured to transport approximately 345,000

bpd. The Company has a long-term (30-year) take-or-pay contract with the major shipper on the Athabasca Pipeline

which commenced in 1999. Revenues are recorded based on the contract terms negotiated with the major shipper,

rather than the cash tolls collected.

The Waupisoo Pipeline is a 380-kilometre (236-mile) synthetic and heavy oil pipeline that entered service in 2008

and provides access to the Edmonton market for oil sands producers. The Waupisoo Pipeline initiates at Enbridge’s

Cheecham Terminal and terminates at its Edmonton Mainline Terminal. The pipeline had an initial design capacity,

dependent on crude slate, of up to 350,000 bpd. The pipeline capacity was expanded to 415,000 bpd in the fourth

quarter of 2012 and can ultimately be expanded to 600,000 bpd. Enbridge has a long-term (25-year) take-or-pay

commitment with multiple shippers on the Waupisoo Pipeline who collectively have contracted for approximately

three-quarters of the capacity.

Prior to December 10, 2012 Regional Oil Sands System included the Hardisty Storage Caverns which included four

salt caverns totaling 3.1 million barrels of storage capacity. The capacity at the facility is fully subscribed under long-

term contracts that generate revenues from storage and terminaling fees. Along with the Hardisty Contract Terminals,

the Hardisty Storage Caverns were transferred to the Fund in December 2012. See Sponsored Investments – Enbridge

Income Fund – Crude Oil Storage and Renewable Energy Transfers for details of the transfer.

RESULTS OF OPERATIONS

Adjusted earnings for the year ended December 31, 2012 were $110 million compared with $111 million for the year
ended December 31, 2011. Higher shipped volumes and increased tolls on certain laterals, and higher earnings from an

annual escalation in storage and terminaling fees were more than offset by higher operating and administrative expense,

and higher depreciation expense. Adjusted earnings for 2012 also included contributions from new regional

infrastructure, the Woodland and Wood Buffalo pipelines, placed into service in the fourth quarter, although offset by

earnings no longer being generated on assets sold to the Fund in December.

4 0 < EN BR IDGE I NC. 2012 FINANCIAL REPO RT

Adjusted earnings increased from $73 million for the year ended December

31, 2010 to $111 million for the year ended December 31, 2011. This

increase in adjusted earnings reflected higher shipped volumes and increased

tolls, as well as the continued positive impact of terminal infrastructure

additions. Adjusted earnings for 2011 also included the impact of lower

depreciation expense due to extended estimated useful lives of certain assets

reflecting increased probable reservoir supply and commercial viability.

ELK POINT PUMP STATION FACILITY OIL RELEASE

On June 19, 2012, Enbridge reported an oil release at its Elk Point pumping

station on Line 19 (Athabasca Pipeline), approximately 70 kilometres

(44 miles) south of Bonnyville, Alberta and approximately 24 kilometres

(15 miles) from the town of Elk Point, Alberta. On June 24, 2012, the

Company restarted the Elk Point pumping station after completing necessary

repairs. The contaminated soil and free product has been removed from the

site for processing and disposal. On-going environmental testing and

monitoring of the site is being conducted. Estimated volume of the release is

approximately 1,400 barrels which were largely contained within the station.

SOUTHERN LIGHTS PIPELINE

The 180,000 bpd, 20-inch diameter Southern Lights Pipeline was placed

into service on July 1, 2010 transporting diluent from Chicago, Illinois to

REGIONAL OIL SANDS SYSTEM—
AVERAGE DELIVERIES
(thousands of barrels per day)

4
1
4

4
3
3

1
9
2

9
5
2

2
0
2

Edmonton, Alberta. Enbridge receives tariff revenues under long-term (15-year) contracts with committed shippers.

Tariffs provide for recovery of all operating and debt financing costs plus a return on equity (ROE) of 10%.

Uncommitted volumes, up to a specified amount, generate tariff revenues that are fully credited to all shippers.

Enbridge retains 25% of uncommitted tariff revenues on volumes above the specified amount, with the remainder

being credited to shippers.

Both the Canadian and United States uncommitted rates on Southern Lights Pipeline for 2010, 2011 and 2012

were challenged by certain shippers. The Canadian Southern Lights toll hearing was held before NEB panel members

in November 2011. On February 9, 2012, the NEB issued its decision rejecting the challenge from uncommitted

shippers and stating that tolls in place were just and reasonable, and more recently approved the 2010, 2011 and

2012 interim tolls as final. A FERC hearing was held in January 2012. Briefs were filed on February 27, 2012 and

March 28, 2012 and an initial decision was issued on June 5, 2012. The initial decision found that the uncommitted

rates were just and reasonable. The parties have filed briefs in response to this decision and the case is awaiting a final

decision from the FERC.

RESULTS OF OPERATIONS

Southern Lights earnings decreased to $71 million for the year ended December 31, 2012 compared with $75 million

for the year ended December 31, 2011 due to higher income tax expense which exceeded the deemed tax recovery in

rates. For the year ended December 31, 2010, earnings of $82 million included leasing income from a pipeline until it

was transferred to the mainline system effective May 1, 2010.

Management’s Discussion and Analysis > 41

SEAWAY PIPELINE

In 2011, Enbridge acquired a 50% interest in the 1,078-kilometre (670-mile) Seaway Pipeline including the 805-kilometre

(500-mile), 30-inch diameter long-haul system from Freeport, Texas to Cushing, Oklahoma, as well as the Texas City

Terminal and Distribution System which serves refineries in the Houston and Texas City areas. The Seaway Pipeline also

includes 6.8 million barrels of crude oil tankage on the Texas Gulf Coast.

The reversal of the Seaway Pipeline, enabling it to transport crude oil from the oversupplied hub in Cushing, Oklahoma

to the Gulf Coast, was completed in May 2012, providing initial capacity of 150,000 bpd. In January 2013, further

pump station additions and modifications were completed, increasing capacity available to shippers to up to 400,000

bpd, depending on crude slate. Actual throughput experienced to date in 2013 has been curtailed due to constraints

on third party takeaway facilities. A lateral from the Seaway Jones Creek tankage to the ECHO crude oil terminal in

Houston, Texas should eliminate these constraints when it comes into service, expected in the fourth quarter of 2013.

Tolls are based on the contract terms agreed upon with shippers during the open seasons.

Seaway Pipeline filed for market-based rates in December 2011. As the FERC had not issued a ruling on this application,

Seaway Pipeline filed for initial rates in order to have rates in effect by the in-service date. The uncommitted rate on the

Seaway Pipeline has been challenged by several shippers. A FERC hearing has been scheduled for March 2013.

RESULTS OF OPERATIONS

Seaway Pipeline earnings for the year ended December 31, 2012 of $24 million reflected preliminary service at an

approximate capacity of 150,000 bpd which commenced in May 2012. Subsequent to year end, in January 2013, with

further pump station additions and modifications, the reversal was completed, increasing to its intended capacity of

400,000 bpd. The $3 million loss recognized for the year ended December 31, 2011 was related to early stage business

development costs that were not eligible for capitalization.

SPEARHEAD PIPELINE—
AVERAGE DELIVERIES
(thousands of barrels per day)

4
4
1

1
2
1

0
1
1

2
8

SPEARHEAD PIPELINE

Spearhead Pipeline delivers crude oil from the Flanagan, Illinois delivery

point of the Lakehead System to Cushing, Oklahoma. The pipeline was

1
5
1

originally placed into service in March 2006 and the Spearhead Pipeline

Expansion was completed in May 2009, increasing capacity from 125,000

bpd to 193,300 bpd.

Initial committed shippers and expansion shippers currently account for

more than 70% of the 193,300 bpd capacity on Spearhead. Both the initial

committed shippers and expansion shippers were required to enter into

10-year shipping commitments at negotiated rates that were offered during

the open season process. The balance of the capacity is currently available to

uncommitted shippers on a spot basis at FERC approved rates.

RESULTS OF OPERATIONS

Spearhead Pipeline adjusted earnings were $37 million for the year ended

December 31, 2012 compared with $17 million for the year ended

December 31, 2011. Spearhead Pipeline adjusted earnings increased as a

result of higher volumes and tolls, partially offset by higher operating and

administrative costs, including power and repairs and maintenance. Volumes

significantly increased over 2011 due to higher commodity price differentials

which increased demand at Cushing, Oklahoma in anticipation of additional

capacity on the Seaway Pipeline for further transportation to the Gulf Coast.

4 2 < EN BR IDGE I NC. 2012 FINANCIAL REPO RT

Spearhead Pipeline adjusted earnings were $17 million for the year ended December 31, 2011 compared with

$29 million for the year ended December 31, 2010. The decrease in Spearhead Pipeline adjusted earnings primarily

reflected lower throughput volumes as a result of market pricing dynamics at the time which weakened demand at

Cushing, partially offset by the recognition of make-up rights which expired in the period.

FEEDER PIPELINES AND OTHER

Feeder Pipelines and Other primarily includes the Company’s 85% interest in Olympic Pipe Line Company (Olympic),

the largest refined products pipeline in the State of Washington, transporting approximately 290,000 bpd of gasoline,

diesel and jet fuel. It also includes the NW System, which transports crude oil from Norman Wells in the Northwest

Territories to Zama, Alberta; interests in a number of liquids pipelines in the United States; and business development

costs related to Liquids Pipelines activities.

Prior to December 10, 2012, Feeder Pipelines and Other also included the Hardisty Contract Terminals, which is

comprised of 19 tanks with a working capacity of approximately 7.5 million barrels of storage capacity. Along with

the Hardisty Storage Caverns, the Hardisty Contract Terminals were transferred to the Fund in December 2012.

See Sponsored Investments – Enbridge Income Fund – Crude Oil Storage and Renewable Energy Transfers for details

of the transfer.

RESULTS OF OPERATIONS

In 2012, Feeder Pipelines and Other earnings were $10 million compared with nil for the year ended December 31,

2011 and earnings of $1 million in 2010. The increase in earnings was primarily a result of a higher contribution from

Olympic due to a tariff increase, higher volumes on Toledo Pipeline and increased terminaling fees. In 2011, earnings

from Toledo Pipeline were negatively impacted by integrity work on Lines 6A and 6B of EEP’s Lakehead System.

The decrease in earnings from 2010 to 2011 reflected higher business development costs.

BUSINESS RISKS

The risks identified below are specific to the Liquids Pipelines business. General risks that affect the Company as a

whole are described under Risk Management and Financial Instruments – General Business Risks.

SUPPLY AND DEMAND

The profitability of the Company’s liquids pipelines depends to some extent on the volume of products transported on

its pipeline systems. The volume of shipments depends primarily on the supply of, and demand for, crude oil and other

liquid hydrocarbons from western Canada. Investment levels and related development activities by crude oil producers

in conventional and oil sands production directly impacts the level of supply from the WCSB. Investment levels are

influenced by crude oil producers’ expectations of crude oil prices, future operating costs, United States demand and

availability of markets for produced crude oil. Demand depends, among other things, on weather, gasoline price and

consumption, manufacturing levels, alternative energy sources and global supply disruptions. Crude oil prices have

been and are expected to be sustained at levels that will incent continued development of oil sands and conventional

exploration and drilling, increasing production, and creating increased demand for new pipeline infrastructure to

access markets both in North America and abroad.

Management’s Discussion and Analysis > 43

VOLUME RISK

A decrease in volumes transported by certain of the Company’s liquids pipelines, including the Company’s mainline

system and the base Lakehead System owned by EEP, can directly and adversely affect revenues and earnings. Shippers

are not required to enter into long-term shipping commitments on Enbridge’s Canadian Mainline; rather, monthly

volume nominations are accepted. A decline in volumes transported can be influenced by factors beyond the

Company’s control, including competition, regulatory action, weather, storage levels, alternative energy sources,

decreased demand, fluctuations in commodity prices, economic conditions, supply disruptions, availability of supply

connected to the systems and adequacy of infrastructure to move supply into and out of the systems. This risk is

partially mitigated by the CTS agreement, which allows Enbridge to negotiate an amendment to the agreement in

the event certain minimum threshold volumes are not met.

MARKET PRICE RISK

The CTS agreement for the Canadian Mainline exposes the Company to risks related to movements in foreign

exchange rates, interest rates and commodity prices, particularly power prices. Foreign exchange risk arises as the

Company’s IJT under the CTS is charged in United States dollars. These risks have been substantially managed

through the Company’s hedging program by using financial contracts to fix the prices of United States dollars,

commodities and interest rates. Certain of these financial contracts do not qualify for cash flow hedge accounting and,

therefore, the Company’s earnings are exposed to associated changes in the mark-to-market value of these contracts.

COMPETITION

Competition among existing pipelines is based primarily on the cost of transportation, access to supply, the quality

and reliability of service, contract carrier alternatives and proximity to markets. Other competing carriers are available

to ship western Canadian liquids hydrocarbons to markets in either Canada or the United States. Competition also

arises from existing and proposed pipelines that provide, or are proposed to provide, access to market areas currently

served by the Company’s liquids pipelines. One such competing project serves markets at Wood River, Illinois and

Cushing, Oklahoma. This pipeline has a capacity of 590,000 bpd, and could connect to a proposed 700,000 bpd

pipeline serving Gulf Coast refineries, which is expected to be in-service in late 2013. Commercial support has also

been announced for the construction of additional ex-Alberta capacity of 830,000 bpd to Steele City, Nebraska,

with an expected in-service date of 2015, to further supply WCSB crude to the Gulf Coast. Additionally, due to deep

discounting of WCSB commodities compared with WTI pricing and the relatively long lead-times required to build

new pipeline capacity, transportation of crude oil by rail is gaining favour with shippers seeking flexibility in accessing

current markets. While pricing differentials remain high, shipper support for pipeline expansion out of the WCSB

could be tempered. However, the Company believes that its liquids pipelines continue to provide attractive options

to producers in the WCSB due to its competitive tolls and multiple delivery and storage points. Enbridge’s current

complement of growth projects to expand market access are also expected to provide shippers long-term competitive

solutions for oil transport. The Company’s existing right-of-way for the Canadian Mainline also provides a competitive

advantage as it can be difficult and costly to obtain rights of way for new pipelines traversing new areas.

POTENTIAL PRESSURE RESTRICTIONS

The Company’s liquids systems consist of individual pipelines of varying ages. With appropriate inspection and

maintenance, the physical life of a pipeline is indefinitely long; however, as pipelines age the level of expenditures

required for inspection and maintenance may increase. Pressure restrictions may from time to time be established on

the Company’s pipelines. Pressure restrictions reduce the available capacity of the applicable line segment and could

result in a loss of throughput if and when the full capacity of that line segment would otherwise have been utilized.

Certain of the Company’s liquids pipelines, including the Company’s Canadian Mainline, could be adversely affected by

pressure restrictions that reduce volumes transported. Temporary pressure restrictions have been established on some

sections of certain pipelines pending completion of specific inspection and repair programs, and had the effect of

limiting throughput during the fourth quarter of 2012.

4 4 < EN BR IDGE I NC. 2012 FINANCIAL REPO RT

REGULATION

The Canadian Mainline and other liquids pipelines are subject to the actions of various regulators, including the NEB.

Actions of the regulators related to tariffs, tolls and facilities impact earnings from those operations. The Company

believes that regulatory risk is reduced through the negotiation of long-term agreements with shippers, such as the

CTS, which govern the majority of the segment’s assets.

Gas Distribution

EARNINGS

(millions of Canadian dollars)

Enbridge Gas Distribution Inc. (EGD)

Other Gas Distribution and Storage

Adjusted earnings

EGD – (warmer)/colder than normal weather

EGD – tax rate changes

EGD – recognition of regulatory asset

Other Gas Distribution and Storage – regulatory deferral write-off

Earnings/(loss) attributable to common shareholders

Adjusted earnings from Gas Distribution were $176 million for the year

ended December 31, 2012 compared with $173 million for 2011 and

$162 million for the year ended December 31, 2010. The increase in

Gas Distribution’s adjusted earnings over these years primarily resulted

from customer growth and favourable performance by EGD under its

Incentive Regulation (IR) arrangement. In 2012, adjusted earnings were

negatively impacted by changes in rate setting methodology applicable

to gas distribution operations in New Brunswick.

Gas Distribution earnings were impacted by the following adjusting items:

• EGD earnings were adjusted to reflect the impact of weather.

• Earnings from EGD for 2012 reflected the impact of unfavourable

tax rate changes on deferred income tax liabilities.

• EGD earnings for 2012 included the recognition of a regulatory

asset related to recovery of OPEB costs pursuant to an OEB rate

order. See Gas Distribution – Enbridge Gas Distribution Inc. – 2013

Rate Application.

• Other Gas Distribution and Storage earnings for 2011 reflected the

discontinuation of rate-regulated accounting for EGNB and the related

write-off of a deferred regulatory asset and certain capitalized operating

costs, net of tax. See Gas Distribution – Other Gas Distribution and

Storage – Enbridge Gas New Brunswick Inc. – Regulatory Matters.

2012

2011

2010

149

176

(23)

(9)

–

207

135

173

–

(262)

(88)

132

162

(12)

–

150

GAS DISTRIBUTION EARNINGS
(millions of Canadian dollars)

1
7
0
2

3
7
1

6
7
1

2
6
8
1

4
5
1

2
6
1

1
0
5
1

2
1
6
1

1
4
1

1
)

8
8

(

GAAP Earnings
Adjusted Earnings

Management’s Discussion and Analysis > 45

ENBRIDGE GAS DISTRIBUTION–
NUMBER OF ACTIVE CUSTOMERS
(thousands)

8
9
8
1

7
3
9

1
8
9

7
9
9
1

2
3
0

ENBRIDGE GAS DISTRIBUTION INC.

EGD is Canada’s largest natural gas distribution company and has been in

operation for more than 160 years. It serves approximately two million

customers in central and eastern Ontario and parts of northern New York

State. EGD’s utility operations are regulated by the OEB and by the New

York State Public Service Commission.

INCENTIVE REGULATION

In 2007, the Company filed a rate application requesting a revenue cap

incentive rate mechanism calculated on a revenue per customer basis with

the OEB for the 2008 to 2012 period. The OEB approved the settlement

agreement with customer representatives and the Company moved to an

IR methodology, which remained in effect through 2012. The objectives

of the settlement agreement were as follows:

•

reduce regulatory costs;

provide incentives for improved efficiency;

provide more flexibility for utility management; and

provide more stable rates to customers.

Under the settlement agreement, the Company was allowed to earn and

fully retain 100 basis points (bps) over the base return. Any return over

100 bps was required to be shared with customers on an equal basis.

The earnings sharing mechanism resulted in the return of revenue to customers of $10 million for the year ended

December 31, 2012 (2011 – $13 million; 2010 – $19 million).

2013 RATE APPLICATION

In January 2012, the Company filed an application with the OEB to set rates for 2013 on a cost of service basis and

on October 3, 2012 the Company filed with the OEB a settlement agreement reached with its interveners relating

to the Company’s 2013 rate application. The settlement agreement was approved by the OEB on November 2, 2012,

which resolved all elements of the rate application except a requested change in deemed equity supporting the rate

base which was heard by the OEB in November 2012. In its final decision issued on February 7, 2013, the OEB

denied the Company’s requested increase in the deemed equity level.

The settlement agreement approved in November 2012 also established the right to recover an existing OPEB liability

of approximately $89 million ($63 million after-tax). The amount will be collected in rates over a 20-year time period

commencing in 2013. The rate order further provided for future OPEB and pension costs, determined on an accrual

basis, to be recovered in rates.

4 6 < EN BR IDGE I NC. 2012 FINANCIAL REPO RT

RESULTS OF OPERATIONS

Adjusted earnings for the year ended December 31, 2012

were $149 million compared with $135 million for the year

ended December 31, 2011. The increase in EGD’s adjusted

earnings was primarily due to customer growth, favourable

rate variances and higher pipeline capacity optimization. This

growth was partially offset by an increase in system integrity

and safety-related costs and higher employee costs, as well as

higher depreciation due to a higher in-service asset base.

Adjusted earnings for the year ended December 31, 2011

were $135 million compared with $132 million for the year

ended December 31, 2010. The increase in EGD’s adjusted

GAS DISTRIBUTION

Enbridge Gas New Brunswick

Moncton

Quebec City

Montreal

Ottawa

Toronto

Enbridge Gas Distribution

earnings was primarily due to customer growth, lower interest

Chicago

expense and lower taxes. These positive impacts were partially

offset by higher customer support costs, as well as an increase

in system integrity and employee related expenses. Depreciation

expense also increjased due to a higher overall asset base.

OTHER GAS DISTRIBUTION AND STORAGE

Other Gas Distribution includes natural gas distribution utility operations in Quebec and New Brunswick, the

most significant being EGNB (100% owned and operated by the Company), which owns the natural gas distribution

franchise in the province of New Brunswick. EGNB has approximately 11,000 customers and is regulated by the

New Brunswick Energy and Utilities Board (EUB).

ENBRIDGE GAS NEW BRUNSWICK INC. – REGULATORY MATTERS

On December 9, 2011 the Government of New Brunswick tabled and then subsequently passed legislation related

to the regulatory process for setting rates for gas distribution within the province. The legislation permitted the

government to implement new regulations which could affect the franchise agreement between EGNB and the

province, impact prior decisions by the province’s independent regulator and influence the regulator’s future decisions.

However, significant details of the rate setting process were left to be established in the new regulations and, as such,

the effect of such legislation was not determinable at that time.

A final rates and tariffs regulation was subsequently enacted by the Government of New Brunswick on April 16, 2012.

Based on the amended rate setting methodology and specific conditions outlined therein, EGNB no longer met the

criteria for the continuation of rate-regulated accounting. As a result, the Company eliminated from its Consolidated

Statements of Financial Position a deferred regulatory asset of $180 million and a regulatory asset with respect to

capitalized operating costs of $103 million, net of an income tax recovery of $21 million. As the final rates and tariffs

regulation published on April 16, 2012 provided further evidence of a condition that existed on December 31, 2011,

the charge totaling $262 million, after tax, was reflected as a subsequent event in the Company’s Consolidated Financial

Statements for the year ended December 31, 2011 presented in accordance with U.S. GAAP and filed in May 2012.

The charge reflected Management’s best estimate based on facts available at the time and may be subject to further

revision based on future actions or interpretations of the regulator, the Government of New Brunswick or other

factors, including legal proceedings which Enbridge has commenced.

Management’s Discussion and Analysis > 47

On April 26, 2012, the Company, Enbridge Energy Distribution Inc. (EEDI) and EGNB commenced an action

against the Province of New Brunswick in the New Brunswick Court of Queen’s Bench, claiming damages in the

amount of $650 million as a result of the continuing breaches by the province of the General Franchise Agreement

it signed with Enbridge in 1999. Additionally, on May 2, 2012, the Company, EEDI and EGNB filed a Notice of

Application with the New Brunswick Court of Queen’s Bench seeking a declaration from the Court that the rates

and tariffs regulation is invalid. In a decision released on August 23, 2012, the Court dismissed EGNB’s Application.

EGNB has filed a Notice of Appeal with the New Brunswick Court of Appeal and a hearing of the appeal is expected

to be held during the first quarter of 2013. On September 20, 2012, the EUB issued a decision regarding EGNB’s

rates that were to take effect as of October 1, 2012. The EUB’s decision applies the rate-setting methodology set out

in the rates and tariffs regulation. EGNB has filed an application for judicial review of the EUB’s rate order with the

New Brunswick Court of Appeal, which is expected to hear the application during the first half of 2013, sometime

after the hearing of the appeal of the August 2012 New Brunswick Court of Queen’s Bench decision discussed

above. There is no assurance these actions will be successful or will result in any recovery.

RESULTS OF OPERATIONS

Other Gas Distribution and Storage adjusted earnings were $27 million for the year ended December 31, 2012

compared with $38 million for the year ended December 31, 2011. This adjusted earnings decrease was primarily

due to the change in rate setting methodology applicable to EGNB enacted in 2012. Effective January 1, 2012,

the discontinuance of rate-regulated accounting at EGNB resulted in earnings subject to increased variability,

including quarterly seasonality, as there was no further accumulation of the regulatory deferral account. Earnings

for 2012 were impacted by lower volume due to a decrease in demand for natural gas, which was the result of

a warmer than normal winter.

Adjusted earnings for the year ended December 31, 2011 were $38 million compared with $30 million for the year

ended December 31, 2010, primarily due to an increased contribution from Enbridge’s Ontario unregulated gas

storage business.

BUSINESS RISKS

The risks identified below are specific to Gas Distribution business. General risks that affect the Company as a whole

are described under Risk Management and Financial Instruments – General Business Risks.

REGULATION

The utility operations of Gas Distribution are regulated by the OEB and EUB among others. Regulators’ future actions

may differ from current expectations, or future legislative changes may impact the regulatory environment in which

Gas Distribution operates. To the extent that the regulators’ future actions are different from current expectations, the

timing and amount of recovery or refund of amounts recorded on the Consolidated Statements of Financial Position,

or that would have been recorded on the Consolidated Statements of Financial Position in absence of the effects of

regulation, could be different from the amounts that are eventually recovered or refunded.

In 2012, EGD operated under the IR Framework which permitted it to recover, with OEB approval, certain costs that

were beyond management control, but that were necessary for the maintenance of its services. The IR Framework also

included a mechanism to reassess the IR plan and return to cost of service if there were significant and unanticipated

developments that threaten the sustainability of the IR plan. The above noted terms set out in the settlement agreement

mitigated the Company’s risk to factors beyond management’s control. Commencing in 2013, EGD’s rates will be

established on a cost of service basis, under which EGD will be entitled to recover costs of providing its service and to

earn a specified ROE. Rate relief may be sought for significant amounts that were not forecasted; however, to the

extent the OEB denies recovery of such costs, the Company’s earnings may be impacted.

4 8 < EN BR IDGE I NC. 2012 FINANCIAL REPO RT

In 2012, the Government of New Brunswick enacted a final rates and tariffs regulation amending the rate setting

methodology applicable to EGNB, resulting in a write-off of certain regulatory balances totaling $262 million, net of

tax, reflected as a subsequent event in the Consolidated Statements of Earnings for the year ended December 31, 2011.

The Company commenced actions against the Province of New Brunswick; however, there is no assurance these actions

will be successful or will result in any recovery.

NATURAL GAS COST RISK

EGD does not profit from the sale of natural gas nor is it at risk for the difference between the actual cost of natural gas

purchased and the price approved by the OEB. This difference is deferred as a receivable from or payable to customers

until the OEB approves its refund or collection. EGD monitors the balance and its potential impact on customers and

may request interim rate relief to recover or refund the natural gas cost differential. While the cost of natural gas does not

impact EGD’s earnings, it does affect the amount of EGD’s investment in gas in storage. EGNB is also subject to natural

gas cost risk as increases in natural gas prices that cannot be charged to customers could negatively impact earnings.

VOLUME RISK

Since customers are billed on a volumetric basis, EGD’s ability to collect its total revenue requirement (the cost

of providing service) depends on achieving the forecast distribution volume established in the rate-making process.

The probability of realizing such volume is contingent upon four key forecast variables: weather, economic conditions,

pricing of competitive energy sources and growth in the number of customers.

Weather is a significant driver of delivery volumes, given that a significant portion of EGD’s customer base uses natural gas

for space heating. Distribution volume may also be impacted by the increased adoption of energy efficient technologies,

along with more efficient building construction, that continues to place downward pressure on consumption. In addition,

conservation efforts by customers may further contribute to a decline in annual average consumption.

Sales and transportation of gas for customers in the residential and small commercial sectors account for approximately

80% of total distribution volume. Sales and transportation service to large volume commercial and industrial customers

is more susceptible to prevailing economic conditions. As well, the pricing of competitive energy sources affects volume

distributed to these sectors as some customers have the ability to switch to an alternate fuel. Customer additions from

all market sectors are important as continued expansion adds to the total consumption of natural gas.

Even in those circumstances where EGD attains its total forecast distribution volume, it may not earn its expected

ROE due to other forecast variables such as the mix between the higher margin residential and commercial sectors

and the lower margin industrial sector. EGNB is also subject to volume risk as the impact of weather conditions on

demand for natural gas could result in earnings fluctuations.

Management’s Discussion and Analysis > 49

Gas Pipelines, Processing and Energy Services

EARNINGS

(millions of Canadian dollars)

Aux Sable

Energy Services

Alliance Pipeline US

Vector Pipeline

Enbridge Offshore Pipelines (Offshore)

Other

Adjusted earnings

Aux Sable – changes in unrealized derivative fair value gains/(loss)

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

Energy Services – credit recovery

Offshore – asset impairment loss

Offshore – property insurance recoveries from hurricanes

Other – changes in unrealized derivative fair value gains

Earnings/(loss) attributable to common shareholders

2012

2011

2010

(3)

154

(537)

–

(105)

–

(478)

(7)

163

(7)

125

–

305

123

(8)

–

125

GAS PIPELINES, PROCESSING AND
ENERGY SERVICES EARNINGS
(millions of Canadian dollars)

2
7
6
7

2
8
2
4

1
4
1

6
1
1

1
5
2
1

3
2
1

1
5
0
3

3
6
1

4
5
1

1
)
8
7
4
(

GAAP Earnings
Adjusted Earnings

Adjusted earnings from Gas Pipelines, Processing and Energy Services were

$154 million for the year ended December 31, 2012 compared with $163

million for the year ended December 31, 2011 and $123 million for the

year ended December 31, 2010. Notable trends over these years included

favourable performance from Aux Sable, due to higher realized fractionation

margins and new assets placed into service, and continued weakness in the

Company’s Offshore operations. The variability in earnings year-over-year

attributable to Energy Services is due to changing market conditions which

give rise to greater or fewer margin opportunities.

Gas Pipelines, Processing and Energy Services earnings were impacted by

the following adjusting items:

• Aux Sable earnings for each period reflected changes in the fair value

of unrealized derivative financial instruments related to the Company’s

forward gas processing risk management position.

• Energy Services earnings for each period reflected 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. A gain or loss on such a financial derivative

corresponds to a similar but opposite loss or gain on the value of the

underlying physical transaction which is expected to be realized in the

future when the physical transaction settles. Unlike the change in the

value of the financial derivative, the loss or gain on the value of the

underlying physical transaction is not recorded for financial statement

purposes until the periods in which it is realized.

5 0 < EN BR IDGE I NC. 2012 FINANCIAL REPO RT

• Energy Services earnings for 2010 included partial recoveries from the sale of its receivable from Lehman Brothers.

• Offshore earnings for 2012 were impacted by an asset impairment loss related to certain of its assets, predominantly

located within the Stingray and Garden Banks corridors. See Gas Pipelines, Processing and Energy Services – Enbridge

Offshore Pipelines – Asset Impairment for further details.

• Offshore earnings for 2010 included insurance proceeds related to the replacement of damaged infrastructure

as a result of a 2008 hurricane.

• Other earnings for 2011 reflected changes in the fair value of unrealized derivative financial instruments.

AUX SABLE

Enbridge owns 42.7% of Aux Sable, a NGL extraction and fractionation business, which owns and operates a plant

near Chicago, Illinois at the terminus of Alliance. The plant extracts NGL from the liquids-rich natural gas transported

on Alliance, as necessary to meet gas quality specifications of downstream transmission and distribution companies and

to take advantage of positive fractionation spreads.

Aux Sable sells its NGL production to a single counterparty under a long-term contract. Aux Sable receives a fixed

annual fee and a share of any net margin generated from the business in excess of specified natural gas processing

margin thresholds (the upside sharing mechanism). In addition, Aux Sable is compensated for all operating, maintenance

and capital costs associated with its facilities subject to certain limits on capital costs. The counterparty supplies, at

its cost, all make-up gas and fuel gas requirements of the Aux Sable plant and pays market rates for the capacity on

Alliance held by an Aux Sable affiliate. The contract is for an initial term of 20 years, expiring March 31, 2026, and

may be extended by mutual agreement for 10-year terms.

Aux Sable also owns and operates facilities upstream of Alliance that deliver liquids-rich gas volumes into the pipeline

for further processing at the Aux Sable plant. These facilities include the Prairie Rose Pipeline and the Palermo

Conditioning Plant in the Bakken area of North Dakota and the Septimus Gas Plant and the Septimus Pipeline

in the Montney area of British Columbia.

Aux Sable has contracted capacity of the Septimus Pipeline and the Septimus Gas Plant to a producer under a 10-year

take-or-pay contract which provides for a return on and of invested capital. Actual operating costs are recovered from

the producer. Additional revenues are earned by Aux Sable based on a sharing of NGL margin available.

In 2012, 80% of the capacity in the Palermo Gas Plant and the Prairie Rose Pipeline was contracted to producers

under take-or-pay contracts. Several producers’ contract commitments decline over the next few years while certain

producer contract commitments continue through 2020 under 10-year take or pay contracts or with life-of-lease

reserve dedication.

RESULTS OF OPERATIONS

Aux Sable adjusted earnings were $68 million for the year ended December 31, 2012 compared with $55 million

for the year ended December 31, 2011 and $37 million for the year ended December 31, 2010. Adjusted earnings

increased primarily due to higher realized fractionation margins and earnings contributions from the Prairie Rose

Pipeline and the Palermo Conditioning Plant acquired in July 2011.

BUSINESS RISKS

The risks identified below are specific to Aux Sable. General risks that affect the entire Company are described under

Risk Management and Financial Instruments – General Business Risks.

COMMODITY PRICE RISK

Aux Sable’s margin earned through the upside sharing mechanism is subject to commodity price risk arising from

movements in natural gas and NGL prices and differentials. These risks may be mitigated through the Company’s

risk management activities.

Management’s Discussion and Analysis > 51

VOLUME RISK

A decrease in gas volumes or a decrease in the NGL content of the gas stream delivered by Alliance to the Aux Sable

plant can directly and adversely affect the margin earned through the upside sharing mechanism. Alliance is well

positioned to deliver incremental liquids-rich gas production from new developments in the Montney and Bakken

regions, thereby mitigating volume risk. In addition, Aux Sable attracts liquids-rich gas to Alliance through inducement

and rich gas premium contracts with producers.

ENERGY SERVICES

Energy Services provides energy supply and marketing services to North American refiners, producers and other

customers. Crude oil and NGL marketing services are provided by Tidal Energy. This business transacts at many North

American market hubs and provides its customers with various services, including transportation, storage, supply

management, hedging programs and product exchanges. Tidal Energy is primarily a physical barrel marketing company

focused on capturing value from quality, time and location differentials when opportunities arise. To execute these

strategies, Energy Services may lease storage or rail cars, as well as hold nomination or contractual rights on both third

party and Enbridge-owned pipelines and storage facilities. Any commodity price exposure created from this physical

business is closely monitored and must comply with the Company’s formal risk management policies.

Tidal Energy also provides natural gas marketing services, including marketing natural gas to optimize commitments

on certain natural gas pipelines. To the extent transportation costs exceed the basis (location) differential, earnings

will be negatively affected. Tidal Energy also provides natural gas supply, transportation, balancing and storage for

third parties, leveraging its natural gas marketing expertise and access to transportation capacity.

RESULTS OF OPERATIONS

Energy Services adjusted earnings decreased from $56 million for the year ended December 31, 2011 to $40 million

for the year ended December 31, 2012. The decline was primarily due to changing market conditions which gave rise

to fewer margin opportunities in crude oil and NGL marketing.

Energy Services adjusted earnings were $56 million for the year ended December 31, 2011 compared with $21 million

for the year ended December 31, 2010. This increase was primarily attributable to crude oil marketing strategies

designed to capture basis (location) differentials and tank management revenue when opportunities arise. Partially

offsetting positive earnings contributions from crude oil services were declines in natural gas marketing due to narrower

natural gas basis (location) spreads, which impact the Company’s merchant capacity on certain natural gas pipelines.

Earnings from Energy Services are dependent on market conditions, including, but not limited to, quality, time and

location differentials, and may not be indicative of results to be achieved in future periods.

BUSINESS RISKS

The risks identified below are specific to Energy Services. General risks that affect the entire Company are described

under Risk Management and Financial Instruments – General Business Risks.

COMMODITY PRICE RISK

Energy Services generates margin by capitalizing on quality, time and location differentials when opportunities arise.

Volatility in commodity prices and changing marketing conditions could limit margin opportunities. Furthermore,

commodity prices could have negative earnings impacts if the cost of the commodity is greater than resell prices

achieved by the Company. Energy Services activities are conducted in compliance with and under the oversight of the

Company’s formal risk management policies.

5 2 < EN BR IDGE I NC. 2012 FINANCIAL REPO RT

ALLIANCE PIPELINE US—AVERAGE
THROUGHPUT VOLUMES
(millions of cubic feet per day)

9
0
6
1

1
0
6
1

0
0
6
1

4
6
5
1

3
5
5
1

ALLIANCE PIPELINE US

Alliance, which includes both the Canadian and United States portions

of the pipeline system, consists of an approximately 3,000-kilometre

(1,864-mile) integrated, high-pressure natural gas transmission pipeline

system and an approximately 730-kilometre (454-mile) lateral pipeline

system and related infrastructure. Alliance transports liquids-rich natural

gas from northeast British Columbia, northwest Alberta and the Bakken

area in North Dakota to Channahon, Illinois. Alliance Pipeline US and

Alliance Pipeline Canada have firm service shipping contract capacity to

deliver 1.405 bcf/d and 1.325 bcf/d, respectively. Enbridge owns 50%

of Alliance Pipeline US, while the Fund, described under Sponsored

Investments, owns 50% of Alliance Pipeline Canada.

Alliance connects with Aux Sable (of which Enbridge owns 42.7%), a NGL

extraction and fractionation facility in Channahon, Illinois. The natural gas

may then be transported to two local natural gas distribution systems in the

Chicago area and five interstate natural gas pipelines, providing shippers

with access to natural gas markets in the midwestern and northeastern

United States and eastern Canada. Alliance Pipeline US is adjacent to the

Bakken oil formation in North Dakota which offers new incremental

sources of liquids-rich natural gas for delivery to downstream markets.

In February 2010, a new receipt point on the pipeline near Towner, North Dakota was placed into service. The receipt

point connects to the Prairie Rose Pipeline, which initially provided access to a shipper operating out of the Bakken

formation with a firm transportation contract for an initial contract capacity of 40 mmcf/d under a 10-year contract.

An additional 40 mmcf/d of firm transportation capacity at this same receipt point became effective February 2011.

The Prairie Rose Pipeline was acquired by Aux Sable in 2011.

TRANSPORTATION CONTRACTS

Alliance Pipeline US has long-term, take-or-pay contracts to transport substantially all its 1.405 bcf/d of natural

gas capacity, with terms ending on December 1, 2015. A small percentage of natural gas is being contracted on

a short-term basis with an annual renewal option. These contracts permit Alliance Pipeline US, whose operations

are regulated by the FERC, to recover the cost of service, which includes operating and maintenance costs, the cost

of financing, an allowance for income tax, an annual allowance for depreciation and an allowed ROE of 10.9%.

RESULTS OF OPERATIONS

Alliance Pipeline US earnings of $24 million for the year ended December 31, 2012 were comparable with earnings

of $26 million and $25 million for the years ended December 31, 2011 and 2010, respectively, reflecting its stable,

cost-of-service commercial construct.

Management’s Discussion and Analysis > 53

VECTOR PIPELINE—AVERAGE
THROUGHPUT VOLUMES
(millions of cubic feet per day)

5
2
5
1

4
3
5
1

6
5
4
1

1
2
3
1

4
3
3
1

VECTOR PIPELINE

Vector, which includes both the Canadian and United States portions of

the pipeline system, consists of 560 kilometres (348 miles) of mainline

natural gas transmission pipeline between the Chicago, Illinois hub and

the storage complex at Dawn, Ontario. Vector’s primary sources of supply

are through interconnections with Alliance and the Northern Border

Pipeline in Joliet, Illinois. Vector has the capacity to deliver a nominal

1.3 bcf/d and is operating at or near capacity. The Company provides

operating services to and holds a 60% joint venture interest in Vector.

TRANSPORTATION CONTRACTS

The total long haul capacity of Vector is approximately 87% committed

through November 2015. Approximately 55% of the long haul capacity

is committed through firm negotiated rate transportation contracts with

shippers and approved by the FERC, while the remaining committed

capacity is sold at market rates. In December 2012, shippers under

negotiated rate transportation contracts which represent 27% of the

systems long haul capacity elected to extend their commitments beyond

December 1, 2015 for one additional year and preserve the option to

continue their commitments on an annual basis. The remaining 28%

of negotiated rate transportation contract shippers elected not to extend

their commitments beyond its original contract term of November 2015.

Vector is entitled to additional compensation from shippers that elected not

to extend their contracts beyond 2015.

Transportation service is provided through a number of different forms of service agreements such as Firm Transportation

Service and Interruptible Transportation Service. Vector is an interstate natural gas pipeline with FERC and NEB

approved tariffs that establish the rates, terms and conditions governing its service to customers. On the United States

portion of Vector, tariff rates are determined using a cost of service methodology and tariff changes may only be

implemented upon approval by the FERC. For 2012, the FERC approved maximum tariff rates included an underlying

weighted average after-tax ROE component of 11.2%. On the Canadian portion, Vector is required to file its negotiated

tolls calculation with the NEB on an annual basis. Tolls are calculated on a levelized basis that include a rate of return

incentive mechanism based on construction costs and are subject to a rate cap. In 2012, maximum tariff tolls include

a ROE component of 10.5% after-tax.

RESULTS OF OPERATIONS

Vector earnings were $16 million for the year ended December 31, 2012 comparable with $18 million for the year

ended December 31, 2011 and $15 million for the year ended December 31, 2010.

BUSINESS RISKS

The risks identified below are specific to both Alliance Pipeline US and Vector. General risks that affect the entire

Company are described under Risk Management and Financial Instruments – General Business Risks.

5 4 < EN BR IDGE I NC. 2012 FINANCIAL REPO RT

SUPPLY AND DEMAND

Currently, natural gas pipeline capacity out of the WCSB

exceeds supply, due to the low price of natural gas and

increased production from new shale gas discoveries. Alliance

Pipeline US and Vector have been unaffected by this excess

supply environment to date mainly because of long-term

NATURAL GAS PIPELINES

Fort St. John

capacity contracts extending primarily to 2015. However,

Edmonton

excess capacity out of the WCSB and depressed natural gas

prices have led to a reduction or deferral of investment in

upstream gas development, and could negatively impact

re-contracting beyond this term. Re-contracting risk is

mitigated to some extent as Alliance Pipeline US is well

positioned to deliver incremental liquids-rich gas production

from new developments in the Montney and Bakken regions.

Alliance Pipeline US is also engaged with market participants

in developing new receipt facilities and services to expand its

reach in transporting liquids-rich gas to premium markets.

Alliance Pipeline
(Canada)

Regina

Superior

Alliance Pipeline (US)

Vector Pipeline

Toronto

Sarnia

Chicago

In addition, Aux Sable, through its participation in midstream businesses upstream of Alliance Pipeline US, attracts

liquids-rich gas to Alliance Pipeline US by offering incremental value for producers’ NGL. Vector’s interruptible

capacity could be negatively impacted by the basis (location) differential in the price of natural gas between Chicago,

Illinois and Dawn, Ontario relative to the transportation toll.

COMPETITION

Alliance Pipeline US faces competition for pipeline transportation services to the Chicago area from both existing

and proposed pipeline projects. Competing pipelines provide natural gas transportation services from the WCSB and

the Bakken to natural gas markets in the midwestern United States. In addition, there are several proposals to convert

or upgrade existing pipelines or to build new pipelines to serve these markets. Any new or upgraded pipelines could

either allow shippers greater access to natural gas markets or offer natural gas transportation services that are more

desirable than those provided by Alliance Pipeline US because of location, facilities or other factors. In addition, these

pipelines could charge rates or provide transportation services to locations that result in greater net profit for shippers,

with the effect of forcing Alliance Pipeline US to realize lower revenues and cash flows. Shippers on Alliance Pipeline

US currently have access to additional high compression delivery capacity at no additional cost, other than fuel

requirements, serving to enhance the competitive position of Alliance Pipeline US.

Vector faces competition for pipeline transportation services to its delivery points from new supply sources and

traditional low cost pipelines, which could offer transportation that is more desirable to shippers because of cost,

supply location, facilities or other factors. Vector has mitigated this risk by entering into long-term firm transportation

contracts and the effectiveness of these contracts is evidenced by the increased utilization of the pipeline since its
construction, despite the presence of transportation alternatives.

Vector and Alliance pipelines also face potential competition from new sources of natural gas such as the Marcellus

shale formation, which is among the largest gas plays in North America. The Marcellus shale formation is in close

proximity to the Chicago Hub. The development of the Marcellus shale formation could provide an alternate source

of gas to the Chicago Hub as well as decrease the northeastern region of the United States’ reliance on natural gas

imports from Canada.

Management’s Discussion and Analysis > 55

REGULATION

Both the United States portion of Vector and Alliance Pipeline US operations are subject to regulation by the FERC.

If tariff rates are protested, the timing and amount of recovery or refund of amounts recorded on the Consolidated

Statements of Financial Position could be different from the amounts that are eventually recovered or refunded. In

addition, future profitability of the entities could be negatively impacted. On a yearly basis, following consultation

with shippers, Alliance Pipeline US files its annual rates with the FERC for approval.

FERC has intensified its oversight of financial reporting, risk standards and affiliate rules and has issued new standards

on managing gas pipeline integrity. The Company continues ongoing dialogue with regulatory agencies and participates

in industry groups to ensure it is informed of emerging issues in a timely manner.

ENBRIDGE OFFSHORE PIPELINES

Dallas

Houston

New Orleans

Gulf of Mexico

ENBRIDGE OFFSHORE PIPELINES

Offshore is comprised of 13 natural gas gathering and

FERC-regulated transmission pipelines and one oil pipeline

with a capacity of 60,000 bpd, in five major corridors in the

Gulf of Mexico, extending to deepwater developments. These

pipelines include almost 2,400 kilometres (1,500 miles) of

underwater pipe and onshore facilities with total capacity

of approximately 7.3 bcf/d. Offshore currently moves

approximately 40% of offshore deepwater gas production

through its systems in the Gulf of Mexico.

TRANSPORTATION CONTRACTS

The primary shippers on the Offshore systems are producers

who execute life-of-lease commitments in connection with

transmission and gathering service contracts. In exchange,

Offshore provides firm capacity for the contract term at

an agreed upon rate. The firm capacity made available

generally reflects the lease’s maximum sustainable production. The transportation contracts allow the shippers to

define a maximum daily quantity (MDQ), which corresponds with the expected production life. The contracts

typically have minimum throughput volumes which are subject to take-or-pay criteria, but also provide the shippers

with flexibility, subject to advance notice criteria, to modify the projected MDQ schedule to match current delivery

expectations. The majority of long-term transport rates are market-based, with revenue generation directly tied to

actual production deliveries. Some of the systems operate under a cost-of-service methodology while others have

minimum take-or-pay obligations.

The business model utilized on a go forward basis and included in the WRGGS, Big Foot, Venice and Heidelberg

commercially secured projects differs from the historic model. These new projects have a base level return which is

locked in through take or pay commitments. If volumes reach producer anticipated levels, the return on these projects

may increase. In addition, Enbridge has minimal capital cost risk on these projects and commercial agreements continue

to contain life-of-lease commitments. The WRGGS and Big Foot project agreements provide for recovery of actual

capital costs to complete the project in fees payable by producers over the contract term. The Venice project provides

for a capital cost risk sharing mechanism whereby Enbridge is exposed to a portion of the capital costs in excess of

an agreed upon target. Conversely, Enbridge can recover in fees from producers a portion of the capital cost savings

below the agreed upon target. Adjustment is allowed for many of the Heidelberg project variables affecting its cost,

with Enbridge bearing the residual capital cost risk after these adjustments have been applied.

5 6 < EN BR IDGE I NC. 2012 FINANCIAL REPO RT

ASSET IMPAIRMENT

In December 2012, the Company recorded an impairment charge of

$166 million ($105 million after-tax) related to certain of its Offshore

assets, predominantly located within the Stingray and Garden Banks

corridors in the Gulf of Mexico. The Company had been pursuing

alternative uses for these assets; however, due to changing competitive

conditions in the fourth quarter of 2012, the Company concluded that

such alternatives were no longer likely to proceed. In addition, unique

to these assets is their significant reliance on natural gas production from

shallow water areas in the Gulf of Mexico which have been challenged

by macro-economic factors including prevalence of onshore shale gas

production, hurricane disruptions, additional regulation and the low

natural gas commodity price environment.

RESULTS OF OPERATIONS

For the year ended December 31, 2012, Offshore incurred an adjusted

loss of $3 million compared with a loss of $7 million for the year ended

December 31, 2011. Offshore realized a second year of consecutive losses

due to weak volumes from delayed drilling programs and more scheduled

production outages by producers in the Gulf of Mexico. The decrease in

loss year-over-year resulted from a higher transportation rate for volumes

shipped on the Stingray Pipeline System, a reduction in interest expense

and a $2 million favourable impact related to the reversal of a shipper reserve

pertaining to a rate case from 2011.

ENBRIDGE OFFSHORE PIPELINES—
AVERAGE THROUGHPUT VOLUMES
(millions of cubic feet per day)

7
3
0
2

2
6
9

2
7
6
1

5
9
5
1

0
4
5
1

For the year ended December 31, 2011, Offshore incurred a loss of $7 million compared with adjusted earnings

of $23 million for the year ended December 31, 2010. The decrease in adjusted earnings reflected continued

volume declines due to the slower regulatory permitting process and delayed drilling programs by producers.

Increased operating and administrative costs, including higher insurance premiums and employee benefits as

well as increased depreciation expense, also contributed to the decrease in earnings from the prior year.

BUSINESS RISKS

The risks identified below are specific to Offshore. General risks that affect the Company as a whole are described

under Risk Management and Financial Instruments – General Business Risks.

WEATHER

Adverse weather, such as hurricanes, may impact Offshore’s financial performance directly or indirectly. Direct impacts

may include damage to offshore facilities resulting in lower throughput, as well as inspection and repair costs. Indirect

impacts may include damage to third party production platforms, onshore processing plants and pipelines that may

decrease throughput on offshore systems. Offshore’s insurance policy includes specific coverage related to named

windstorms (such as hurricanes), for all systems, but does not cover business interruption. The occurrence of hurricanes

in the Gulf Coast increases the cost and availability of insurance coverage and Enbridge may not be able, or may choose

not, to insure against this risk in the future. Enbridge facilities are engineered to withstand hurricane forces and constant

monitoring of weather allows for timely evacuation of personnel and shutdown of facilities; however, damages to assets

may still occur.

Management’s Discussion and Analysis > 57

COMPETITION

There is competition for new and existing business in the Gulf of Mexico, with an increasing number of competitors

willing to construct and operate production host platforms for future deepwater prospects. Offshore has been able

to capture key opportunities, allowing it to more fully utilize existing capacity. Offshore’s gas pipelines serve a majority

of the strategically located deepwater host platforms, positioning it favourably to make incremental investments for

new platform connections and receive additional transportation volumes from sub-sea development of smaller fields

tied back to existing host platforms. Offshore is also able to construct pipelines to transport crude oil, diversifying

the risk of declining gas production, as demonstrated with the planned Big Foot Oil and Heidelberg pipelines. Given

rates of decline, offshore pipelines typically have available capacity, resulting in significant competition for new

developments in the Gulf of Mexico. Competing developments may impact the recoverability of the Company’s

long-lived offshore assets.

SUPPLY AND DEMAND

Low natural gas prices, in part due to the prevalence of onshore shale gas, have resulted in reduced investment in

exploration activities and producing infrastructure. Offshore diversifies its risk of declining gas production through the

construction of crude oil pipelines as noted above. To date, crude oil prices have supported stable offshore investment;

however, a future decline in crude oil prices could change the potential for future investment opportunities. Further,

a sustained decline in either natural gas or crude oil commodity prices could impact the recoverability of long-lived

offshore assets.

In the fourth quarter of 2012, Offshore recognized an impairment charge of $105 million, net of tax, primarily related

to shallow water natural gas assets, due to changing competitive conditions and sustained weakness in natural gas prices.

REGULATION

The transportation rates on many of Offshore’s transmission pipelines are generally based on a regulated cost of service

methodology and are subject to regulation by the FERC. These rates are subject to challenge from time-to-time.

The Macondo oil spill in 2010 has altered the offshore regulatory environment. Although the moratorium on

deepwater drilling has been lifted, future deepwater drilling activity will be subject to heightened regulation and

oversight. Increased regulation may impact the levels and timing of future exploration and drilling activity in the region

and the resultant production volumes available to ship on the Offshore system. The shifting business environment

could result in increases in available capacity, resulting in heightened competition.

OTHER RISKS

Other risks directly impacting financial performance include underperformance relative to expected reservoir

production rates, delays in project start-up timing, changes in plans by shippers and capital expenditures in excess

of those estimated. Capital risk is mitigated in some circumstances by having area producers as joint venture partners

or through cost of service tolling arrangements or other pre-arranged terms in commercial agreements. Start-up delays

are mitigated by the right to collect stand-by fees.

5 8 < EN BR IDGE I NC. 2012 FINANCIAL REPO RT

OTHER

Other includes operating results from the Company’s investments in renewable energy projects and business

development expenditures.

WIND AND SOLAR RESOURCES TRANSFER

In May 2012, the Company acquired from Renewable Energy Systems Canada Inc. the remaining 10% interest in

the Greenwich Wind Energy Project (Greenwich) through Greenwich Windfarm, LP, for $27 million, increasing its

ownership to 100%. On December 10, 2012, Greenwich, the Amherstburg Solar Project (Amherstburg) and the

Tilbury Solar Project (Tilbury) were transferred to the Fund. See Sponsored Investments – Enbridge Income Fund –

Crude Oil Storage and Renewable Energy Transfers for details of the transfer.

In October 2011, ownership of the Ontario Wind, Sarnia Solar and Talbot Wind energy projects was transferred to the

Fund with earnings contributions from these assets, net of noncontrolling interests, reflected within the Sponsored

Investments segment effective October 21, 2011.

RESULTS OF OPERATIONS

Other adjusted earnings for the year ended December 31, 2012 were $9 million compared with $15 million for the

year ended December 31, 2011. The decrease in adjusted earnings was primarily due to the sale of Ontario Wind,

Sarnia Solar and Talbot Wind energy projects to the Fund in October 2011, followed by the sale of Greenwich,

Amherstburg and Tilbury to the Fund in December 2012. Higher business development costs also contributed to the

decrease in adjusted earnings. Partially offsetting this increase were the contributions from Cedar Point and Greenwich,

which were commissioned in late 2011, and Silver State which was commissioned in early 2012.

Other adjusted earnings increased from $2 million for the year ended December 31, 2010 to $15 million for the

year ended December 31, 2011. This increase reflected strong contributions primarily from the Sarnia Solar expansion

and Talbot Wind Energy Project, both of which were completed in the latter part of 2010. In addition, adjusted

earnings for 2011 reflected several newly constructed green energy projects, including Cedar Point, Greenwich

and Amherstburg.

Sponsored Investments

EARNINGS

(millions of Canadian dollars)

Enbridge Energy Partners, L.P. (EEP)

Enbridge Energy, Limited Partnership (EELP) – Alberta Clipper US

Enbridge Income Fund (the Fund)

Adjusted earnings

EEP – leak insurance recoveries

EEP – leak remediation costs and lost revenue

EEP – changes in unrealized derivative fair value gains/(loss)

EEP – NGL trucking and marketing investigation costs

EEP – prior period adjustment

EEP – shipper dispute settlement

EEP – lawsuit settlement

EEP – impact of unusual weather conditions

EEP – Lakehead System billing correction

EEP – asset impairment loss

Earnings attributable to common shareholders

2012

2011

2010

141

263

(9)

(2)

(1)

–

151

244

(33)

(3)

–

(1)

–

282

269

122

206

–

(106)

(1)

–

(2)

Management’s Discussion and Analysis > 59

SPONSORED INVESTMENTS EARNINGS
(millions of Canadian dollars)

1
2
8
2

3
6
2

1
9
6
2

4
4
2

6
0
2

1
5
1

2
1
4
1

2
1
1
1

1
0
1

1
8
9

GAAP Earnings
Adjusted Earnings

Adjusted earnings from Sponsored Investments were $263 million for

the year ended December 31, 2012 compared with $244 million for the

year ended December 31, 2011. The increase in adjusted earnings resulted

primarily from increased contributions from the Fund following the transfer

of certain renewable energy and crude oil storage assets from Enbridge and

its wholly-owned subsidiaries in late 2012 and late 2011.

Adjusted earnings from Sponsored Investments were $244 million for the

year ended December 31, 2011 compared with $206 million in 2010. The

increase in adjusted earnings resulted primarily from increased contributions

from EEP as a result of positive operating factors, including growth projects,

and contributions from renewable energy assets transferred to the Fund.

Sponsored Investments earnings were impacted by the following

adjusting items:

• Earnings from EEP for 2012 and 2011 included insurance recoveries

associated with the Line 6B crude oil release. See Sponsored

Investments – Enbridge Energy Partners, L.P. – Lakehead System

Lines 6A and 6B Crude Oil Releases – Line 6B Crude Oil Release.

• Earnings from EEP for each period included a charge related to

estimated costs, before insurance recoveries, associated with the Lines

6A, 6B and Line 14 crude oil releases. EEP earnings from 2010 also

included a charge of $3 million (net to Enbridge) related to lost revenue

as a result of the crude oil releases. See Sponsored Investments – Enbridge

Energy Partners, L.P. – Lakehead System Line 14 Crude

Oil Release and Sponsored Investments – Enbridge Energy Partners,

L.P. – Lakehead System Lines 6A and 6B Crude Oil Releases.

• Earnings from EEP included changes in the unrealized fair value on derivative financial instruments in each period.

• EEP earnings for 2012 and 2011 reflected charges for legal and accounting costs associated with an investigation

at a NGL trucking and marketing subsidiary, which was concluded in the first quarter of 2012.

• EEP earnings for 2012 reflected a non-recurring out-of-period adjustment.

• EEP earnings for 2011 included proceeds from the settlement of a shipper dispute related to oil measurement

adjustments in prior years.

• EEP earnings for 2011 included proceeds related to the settlement of a lawsuit during the first quarter of 2011.

• EEP earnings for 2011 included an unfavourable effect related to decreased volumes due to uncharacteristically

cold weather in February 2011 that disrupted normal operations of its natural gas systems.

• EEP earnings for 2010 included Lakehead System billing corrections.

• EEP earnings for 2010 included charges related to asset impairment losses.

6 0 < EN BR IDGE I NC. 2012 FINANCIAL REPO RT

ENBRIDGE ENERGY PARTNERS, L.P.

EEP owns and operates crude oil and liquid petroleum

transportation and storage assets and natural gas and NGL

gathering, treating, processing, transportation and marketing

assets in the United States. Significant assets include the

Lakehead System, which is the extension of the Canadian

Mainline in the United States, the Mid-Continent crude oil

system consisting of an interstate crude oil pipeline and

storage facilities, a crude oil gathering system and interstate

pipeline system in North Dakota and natural gas assets

located primarily in Texas. Subsidiaries of Enbridge provide

services to EEP in connection with the operation of its liquids

assets, including the Lakehead System.

In September 2010, EEP acquired the entities that comprise

the Elk City Natural Gas Gathering and Processing System

(Elk City System) for US$686 million. The Elk City System

ENBRIDGE ENERGY PARTNERS, L.P.

Blaine

Seattle

Calgary

Portland

Regina

Cromer

Gretna

Minot

North Dakota System

Clearbrook

Superior

Casper

Lakehead System

Salt Lake City

Chicago

Sarnia

Toledo

Patoka
Wood River

Ozark Pipeline

Cushing

Natural Gas Assets

Dallas

Houston

New Orleans

Enbridge Inc.
Liquids Pipelines
Gas Pipelines

extends from southwestern Oklahoma to Hemphill County in the Texas Panhandle and consists of approximately

1,290 kilometres (800 miles) of natural gas gathering and transportation pipelines, one carbon dioxide treating plant

and three cryogenic processing plants with a total capacity of 370 mmcf/d and a combined NGL production capability

of 20,000 bpd. The acquisition of the Elk City System complements EEP’s existing Anadarko natural gas system by

providing additional processing capacity and expansion capability.

OWNERSHIP INTEREST

Enbridge’s ownership interest in EEP is impacted by EEP’s issuance and sale of its Class A common units.

To the extent Enbridge does not fully participate in these offerings, the Company’s ownership interest in EEP is

reduced. At December 31, 2012, Enbridge’s ownership interest in EEP was 21.8% (2011 – 23.0%; 2010 – 25.5%).

The Company’s average ownership interest in EEP during 2012 was 23.0% (2011 – 24.4%; 2010 – 26.7%).

DISTRIBUTIONS

EEP makes quarterly distributions of its available cash to its common unitholders. Under the Partnership Agreement,

Enbridge Energy Company, Inc. (EECI), a wholly owned subsidiary of Enbridge, as general partner (GP), receives

incremental incentive cash distributions, which represent incentive income on the portion of cash distributions (on

a per unit basis) that exceed certain target thresholds as follows:

Quarterly cash distributions per unit: 1

Up to $0.295 per unit

First target – $0.295 per unit up to $0.350 per unit

Second target – $0.350 per unit up to $0.495 per unit

Over second target – cash distributions greater than $0.495 per unit

Distributions restated to reflect EEP’s two-for-one stock split which was effective April 2011.

Unitholders including
Enbridge

GP Interest

98%

85%

75%

50%

15%

25%

50%

In July 2012, EEP increased its quarterly distribution to $0.5435 per unit from $0.5325. Of the $141 million

Enbridge recognized as adjusted earnings from EEP during 2012, $59 million (2011 – $46 million; 2010 – $33

million) were GP incentive earnings, while the remainder was Enbridge’s limited partner share of EEP’s earnings.

Management’s Discussion and Analysis > 61

RESULTS OF OPERATIONS

Adjusted earnings from EEP were $141 million for the year ended December 31, 2012 compared with $151 million

for the year ended December 31, 2011. Adjusted earnings from EEP for 2012 included higher GP incentive income

and strong results from the liquids business primarily due to higher average delivery volumes and increased tolls on all

major liquids systems, as well as contributions from storage terminal and other facilities that were placed into service

during 2012. Earnings from the natural gas business decreased as a result of lower natural gas and NGL prices.

Earnings were also negatively impacted by an increase in operating and administrative costs, specifically pipeline

integrity costs, personnel costs and higher property taxes.

EEP adjusted earnings increased from $122 million for the year ended December 31, 2010 to $151 million for the year

ended December 31, 2011. The increase was primarily attributable to strong results from its natural gas business as a

result of higher natural gas and NGL volumes, including those associated with the acquisition of the Elk City System

in September 2010, as well as higher GP incentive income. Increased volumes in liquids pipelines and a full year

contribution from Alberta Clipper also drove higher earnings in 2011. These positive factors were partially offset by

an increase in operating and administrative costs and higher financing costs.

LAKEHEAD SYSTEM LINE 14 CRUDE OIL RELEASE

On July 27, 2012, a release of crude oil was detected on Line 14 of EEP’s Lakehead System near Grand Marsh,

Wisconsin. The estimated volume of oil released was approximately 1,700 barrels. EEP received a Corrective Action

Order (CAO) from the Pipeline and Hazardous Materials Safety Administration (PHMSA) on July 30, 2012, followed

by an amended CAO on August 1, 2012. The CAOs required EEP to take certain corrective actions, some of which have

already been completed and some are still ongoing, as part of an overall plan for its Lakehead System. A notable part of

the CAOs was to hire an independent third party pipeline expert to review and assess EEP’s overall integrity program.

An independent third party expert was contracted during the third quarter of 2012 and its work is currently ongoing.

Upon restart of Line 14 on August 7, 2012, PHMSA restricted the operating pressure to 80% of the pressure in place

at the time immediately prior to the incident. The pressure restrictions will remain in place until such time EEP can

demonstrate that the root cause of the incident has been remediated.

EEP has revised the disclosed estimate for repair and remediation related costs associated with this crude oil release as

at December 31, 2012 to approximately US$10 million ($1 million after-tax attributable to Enbridge), inclusive of

approximately US$2 million of lost revenue, and excluding any fines and penalties. Despite the efforts EEP has made

to ensure the reasonableness of its estimate, changes to the estimated amounts associated with this release are possible

as more reliable information becomes available. EEP will be pursuing claims under Enbridge’s comprehensive insurance

policy, although it does not expect any recoveries to be significant.

LAKEHEAD SYSTEM LINES 6A AND 6B CRUDE OIL RELEASES

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.
EEP estimates that approximately 20,000 barrels of crude oil were leaked at the site, a portion of which reached the

Talmadge Creek, a waterway that feeds the Kalamazoo River. The released crude oil affected approximately 61 kilometres

(38 miles) of shoreline along the Talmadge Creek and Kalamazoo River waterways, including residential areas, businesses,

farmland and marshland between Marshall and downstream of Battle Creek, Michigan. In response to the release, a

unified command structure was established under the jurisdiction of the Environmental Protection Agency (EPA),

the Michigan Department of Natural Resources and Environment and other federal, state and local agencies.

6 2 < EN BR IDGE I NC. 2012 FINANCIAL REPO RT

During the second quarter of 2012, local authorities allowed the Kalamazoo River and Morrow Lake, which were affected

by the Line 6B crude oil release, to be re-opened for recreational use. EEP continues to perform necessary remediation,

restoration and monitoring of the areas affected by the Line 6B crude oil release. EEP expects to make payments for

additional costs associated with submerged oil and sheen monitoring and recovery operations, including reassessment,

remediation and restoration of the area, air and groundwater monitoring, scientific studies and hydrodynamic modeling,

along with legal, professional and regulatory costs through future periods. All of the initiatives EEP is undertaking in the

monitoring and restoration phase are intended to restore the crude oil release area to the satisfaction of the appropriate

regulatory authorities.

On July 2, 2012, EEP received a Notice of Probable Violation (NOPV) from the PHMSA related to the July 26, 2010

Line 6B crude oil release, which resulted in payment of a US$3.7 million civil penalty in the third quarter of 2012. EEP

included the amount of the penalty in its total estimated cost for the Line 6B crude oil release. In addition, on July 10,

2012 the National Transportation Safety Board presented the results of its investigation into the Line 6B crude oil

release and subsequently publicly posted its final report on July 26, 2012.

As at December 31, 2012, EEP revised the total incident cost accrual to US$820 million ($137 million after-tax

attributable to Enbridge), primarily due to an estimate of extended oversight by regulators and additional legal costs

associated with various lawsuits, which is an increase of US$55 million ($8 million after-tax attributable to Enbridge)

from its estimate at December 31, 2011. This total estimate is before insurance recoveries and excludes additional

fines and penalties, which may be imposed by federal, state and local government agencies, other than the PHMSA

civil penalty described above. On October 3, 2012, EEP received a letter from the EPA regarding a Proposed Order for

potential incremental containment and active recovery of submerged oil. EEP is in discussions with the EPA regarding

the agency’s intent with respect to certain elements of the Proposed Order and the appropriate scope of these activities.

The nature and scope of any additional remediation activities that regulators may require is currently uncertain. Studies

and additional technical evaluation by EEP, the EPA and other regulatory agencies may need to be completed before a

final determination of any additional remediation activities can be determined. EEP has accrued the estimated costs it

deemed likely to be incurred. However, when a final determination of the appropriate nature and scope of any

additional remediation is made, it could result in significant cost being accrued.

Expected losses associated with the Line 6B crude oil release included those costs that were considered probable

and that could be reasonably estimated at December 31, 2012. Despite the efforts EEP has made to ensure the

reasonableness of its estimates, 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, in addition to fines and penalties and expenditures associated with litigation

and settlement of claims.

LINE 6A CRUDE OIL RELEASE

A release of crude oil from Line 6A of EEP’s Lakehead System was reported in an industrial area of Romeoville,

Illinois on September 9, 2010. EEP estimates that approximately 9,000 barrels of crude oil were released, of which

approximately 1,400 barrels were removed from the pipeline as part of the repair. Some of the released crude oil went

onto a roadway, into a storm sewer, a waste water treatment facility and then into a nearby retention pond. All but a

small amount of the crude oil was recovered. EEP completed excavation and replacement of the pipeline segment and

returned it to service on September 17, 2010. The cause of the crude oil release remains subject to investigation by

federal and state environmental and pipeline safety regulators.

EEP continues to monitor the areas affected by the crude oil release from Line 6A of its Lakehead System near

Romeoville, Illinois in September 2010 for any additional requirements; however, the cleanup, remediation and

restoration of the areas affected by the release have been completed.

Management’s Discussion and Analysis > 63

In connection with this crude oil release, the cost estimate as at December 31, 2012 remains at approximately

US$48 million ($7 million after-tax attributable to Enbridge), before insurance recoveries and excluding fines and

penalties. EEP has the potential of incurring additional costs in connection with this crude oil release, including

fines and penalties as well as expenditures associated with litigation. EEP is pursuing recovery of the costs associated

with the Line 6A crude oil release from third parties; however, there can be no assurance that any such recovery will

be obtained.

INSURANCE RECOVERIES

EEP is included in the comprehensive insurance program that is maintained by Enbridge for its subsidiaries and

affiliates which renews in May of each year. In the unlikely event multiple insurable incidents occur which exceed

coverage limits within the same insurance period, the total insurance coverage will be allocated among the Enbridge

entities on an equitable basis based on an insurance allocation agreement EEP has entered into with Enbridge and one

of Enbridge’s subsidiaries. The insurance program includes commercial liability insurance coverage that is consistent

with coverage considered customary for its industry and includes coverage for environmental incidents such as those

incurred for the crude oil releases from Lines 6A and 6B, excluding costs for fines and penalties. The claims for the

crude oil release for Line 6B are covered by Enbridge’s comprehensive insurance policy that expired on April 30, 2011,

which had an aggregate limit of US$650 million for pollution liability. Based on EEP’s remediation spending through

December 31, 2012, Enbridge and its affiliates have exceeded the limits of their coverage under this insurance policy.

Additionally, fines and penalties would not be covered under the existing insurance policy.

For the years ended December 31, 2012 and 2011, EEP recognized US$170 million ($24 million after-tax attributable

to Enbridge) and US$335 million ($50 million after-tax attributable to Enbridge), respectively, of insurance recoveries

as reductions to Environmental costs in the Consolidated Statements of Earnings. As at December 31, 2012, EEP had

recorded total insurance recoveries of US$505 million ($74 million after-tax attributable to Enbridge) for the Line 6B

crude oil release and expects to recover the balance of the aggregate liability insurance coverage of US$145 million

from its insurers in future periods. EEP will record receivables for additional amounts received through insurance

recoveries during the period it deems recovery to be probable.

Effective May 1, 2012, Enbridge renewed its comprehensive insurance program, through April 30, 2013, with a

current liability aggregate limit of US$660 million, including sudden and accidental pollution liability.

LEGAL AND REGULATORY PROCEEDINGS

A number of United States governmental agencies and regulators have initiated investigations into the Line 6A and

Line 6B crude oil releases. Approximately 30 actions or claims have been filed against Enbridge, EEP or their affiliates

in United States federal and state courts in connection with the Line 6B crude oil release, including direct actions and

actions seeking class status. Based on the current status of these cases, EEP does not expect the outcome of these

actions to be material. As noted above, on July 2, 2012, PHMSA announced a NOPV related to the Line 6B crude oil

release, including a civil penalty of US$3.7 million that EEP paid in the third quarter of 2012. One claim related to the

Line 6A crude oil release has been filed against Enbridge, EEP or their affiliates by the State of Illinois in the Illinois
state court. The parties are currently operating under an agreed interim order.

6 4 < EN BR IDGE I NC. 2012 FINANCIAL REPO RT

ENBRIDGE ENERGY, LIMITED PARTNERSHIP – ALBERTA CLIPPER US

In July 2009, the Company committed to fund 66.7% of the cost to construct the United States segment of the

Alberta Clipper Project. The Company funded 66.7% of the project’s equity requirements through EELP, while

66.7% of the debt funding was made through EEP. EELP – Alberta Clipper US earnings are the Company’s earnings

from its investment in EELP which undertook the project. The Alberta Clipper Project was placed into service on

April 1, 2010. Alberta Clipper is a 1,670-kilometre (1,000 mile) crude oil pipeline that provides service between

Hardisty, Alberta and Superior, Wisconsin with capacity of 450,000 bpd.

RESULTS OF OPERATIONS

Earnings from EELP – Alberta Clipper US were $38 million for the year ended December 31, 2012 compared

with $42 million for both the years ended December 31, 2011 and 2010. These earnings, which represent the

Company’s earnings from its 66.7% investment in a series of equity within EELP which owns the United States

segment of Alberta Clipper, decreased due to a reduction in rates which took effect April 1, 2012.

BUSINESS RISKS

The risks identified below are specific to EEP and EELP. General risks that affect the Company as a whole are

described under Risk Management and Financial Instruments – General Business Risks.

SUPPLY AND DEMAND

The profitability of EEP depends to some extent on the volume of products transported on its pipeline systems.

The volume of shipments on EEP’s Lakehead System depends primarily on the supply of western Canadian crude

oil and the demand for crude oil in the Great Lakes and Midwest regions of the United States and eastern Canada.

Investment levels and related development activities by crude oil producers in conventional and oil sands production

directly impacts the level of supply from the WCSB. Investment levels are influenced by crude oil producers’

expectations of crude oil prices, future operating costs, United States demand and availability of markets for produced

crude oil. Demand depends, among other things, on weather, gasoline price and consumption, manufacturing levels,

alternative energy sources and global supply disruptions.

EEP’s natural gas gathering assets are also subject to changes in supply and demand for natural gas, NGL and related

products. Commodity prices impact the willingness of natural gas producers to invest in additional infrastructure to

produce natural gas and, with current low natural gas prices, infrastructure plans have been increasingly deferred or

cancelled. These assets are also subject to competitive pressures from third-party and producer-owned gathering systems.

Supply for the marketing operations depends to a large extent on the natural gas reserves and rate of drilling within the

areas served by the natural gas business. Demand is typically driven by weather-related factors, with respect to power

plant and utility customers, and industrial demand. EEP’s marketing business uses third party storage to balance supply

and demand factors.

Management’s Discussion and Analysis > 65

VOLUME RISK

A decrease in volumes transported by EEP’s systems can directly and adversely affect revenues and results of operations.

A decline in volumes transported can be influenced by factors beyond EEP’s control, including competition, regulatory

actions, government actions, weather, storage levels, alternative energy sources, decreased demand, fluctuations in

commodity prices, economic conditions, supply disruptions, availability of supply connected to the systems and

adequacy of infrastructure to move supply into and out of the systems. To the extent commodity price differentials exist

between markets serviced by the Company’s assets and other market hubs, producers may be incented to seek alternate

transportation options, such as rail, thereby decreasing volumes available to ship on the Company’s systems.

COMPETITION

EEP’s Lakehead System, the United States portion of the liquids pipelines mainline, is a major crude oil export conduit

from the WCSB. Other existing competing carriers and pipeline proposals to ship western Canadian liquids hydrocarbons

to markets in the United States represent competition for the Lakehead System. Further details on such competing

projects are described within Liquids Pipelines – Business Risks. EEP’s Mid-Continent and North Dakota systems also

face competition from existing competing pipelines, proposed future pipelines and alternative gathering facilities,

predominately rail, available to producers or the ability of the producers to build such gathering facilities. Competition

for EEP’s storage facilities includes large integrated oil companies and other midstream energy partnerships.

Other interstate and intrastate natural gas pipelines (or their affiliates) and other midstream businesses that gather, treat,

process and market natural gas or NGL represent competition to EEP’s natural gas segment. The level of competition

varies depending on the location of the gathering, treating and processing facilities. However, most natural gas

producers and owners have alternate gathering, treating and processing facilities available to them, including those

owned by competitors that are substantially larger than EEP.

EEP’s marketing segment has numerous competitors, including large natural gas marketing companies, marketing

affiliates of pipelines, major oil and natural gas producers, independent aggregators and regional marketing companies.

REGULATION

In the United States, the interstate oil pipelines owned and operated by EEP and certain activities of EEP’s intrastate

natural gas pipelines are subject to regulation by the FERC or state regulators and its financial condition and results of

operations could worsen if tariff rates were protested. While gas gathering pipelines are not currently subject to FERC

rate regulation, proposals to more actively regulate intrastate gathering pipelines are currently being considered in

certain of the states in which EEP operates. In addition, the FERC has also taken an interest in regulating gas gathering

systems that connect into interstate pipelines.

MARKET PRICE RISK

EEP’s gas processing business is subject to commodity price risk arising from movements in natural gas and NGL prices

and differentials. These risks have been managed by using physical and financial contracts to fix the prices of natural gas

and NGL. Certain of these financial contracts do not qualify for cash flow hedge accounting and; therefore, EEP’s
earnings are exposed to associated changes in the mark-to-market value of these contracts.

6 6 < EN BR IDGE I NC. 2012 FINANCIAL REPO RT

ENBRIDGE INCOME FUND

The Fund is involved in the generation and transportation of

energy through its crude oil and liquids pipeline and storage

Fort St. John

business in Western Canada (Liquids Transportation and

Storage), interests in more than 500 MW of renewable power

generation capacity and its 50% interest in Alliance Pipeline

Canada. Liquids Transportation and Storage operates a crude

oil gathering system and trunkline pipeline in southern

Saskatchewan and southwestern Manitoba, connecting

to Enbridge’s mainline pipeline to the United States

(the Saskatchewan System). The Fund’s renewable power

portfolio includes the 190-MW Ontario Wind Project, the

99-MW Talbot Wind Project and the 80-MW Sarnia Solar

Project. In December 2012, the Fund completed the

acquisition of crude oil storage facilities along with additional

wind and solar energy assets from Enbridge and its wholly-

owned subsidiaries, as discussed below.

CRUDE OIL STORAGE AND RENEWABLE ENERGY TRANSFERS

Alliance Pipeline (Canada)

Edmonton

Hardisty

Regina

Saskatchewan
System

Alliance Pipeline (US)

NRGreen Waste-heat
Power Generation
Liquids Pipelines
Gas Pipelines

Crude Oil
Storage
Wind Assets
Solar Assets

Chicago

In December 2012, ENF and the Fund finalized the acquisition of Hardisty Storage Caverns, Hardisty Contract

Terminals, Greenwich, and Amherstburg and Tilbury projects from Enbridge and its wholly-owned subsidiaries for

an aggregate purchase price of approximately $1.2 billion, financed in part by the issuance of additional ordinary trust

units of the Fund to ENF and additional Enbridge Commercial Trust (ECT) preferred units to Enbridge. ENF in turn

issued additional common shares to the public and to Enbridge. Enbridge also provided bridge debt financing (Bridge

Financing) to the Fund for the balance of the purchase price, which was repaid in December 2012. Enbridge’s overall

economic interest in the Fund was reduced from 69.2% to 67.7% upon completion of the transaction.

In October 2011, the Fund also acquired the Ontario Wind, Sarnia Solar and Talbot Wind energy projects from a

wholly-owned subsidiary of Enbridge for an aggregate price of approximately $1.2 billion. The transaction was financed

by the Fund through a combination of debt and equity, including the issuance of additional ordinary trust units of the

Fund to ENF and ECT preferred units to Enbridge. ENF in turn issued additional common shares to the public and

to Enbridge. Enbridge’s overall economic interest in the Fund was reduced from 72.3% to 69.2% upon completion of

the transaction and associated financing.

The asset transfers described above occurred between entities under common control of Enbridge, and the intercompany

gains realized by the selling entities in each of the years ended December 31, 2012 and 2011 have been eliminated

from the Consolidated Financial Statements of Enbridge. Income taxes of $56 million and $98 million for the years

ended December 31, 2012 and 2011, respectively, incurred on the related capital gains remain as charges to

consolidated earnings. The Company retains the benefit of cash taxes paid in the form of increased tax basis of its

investment in the underlying entities; however, accounting recognition of such benefit is not permitted until such

time as the entities are sold outside of the consolidated group.

Through these transactions, which essentially resulted in a partial monetization of these assets by Enbridge through

sale to noncontrolling interests (being ENF’s public shareholders), Enbridge realized a source of funds of $213 million

and $210 million, as presented within Financing Activities on the Consolidated Statements of Cash Flows for the years

ended December 31, 2012 and 2011, respectively. In December 2012, the Fund issued $500 million in medium-term

notes. The funds from this issuance, together with its cash on hand and draws on the Fund’s committed credit facility,

were used to repay the $582 million Bridge Financing to Enbridge.

Management’s Discussion and Analysis > 67

SASKATCHEWAN SYSTEM SHIPPER COMPLAINT

On December 17, 2010, the Saskatchewan System filed amended tariffs for the Westspur pipeline with the NEB with

an effective date of February 1, 2011. In January 2011, a shipper on the Westspur system requested the NEB make the

tolls “interim” effective February 1, 2011 pending discussions between the shipper and the Saskatchewan System on

information requests put forward by the shipper. Subsequently, the shipper filed a complaint with the NEB on the basis

that the information provided was not adequate to allow an assessment to be made of the reasonableness of the tolls.

Six parties have filed letters with the NEB supporting the shipper’s complaint. As directed by the NEB, negotiation

among the parties has been ongoing and as of February 14, 2013, the Fund continues to review the structure of its

tolls with shippers.

INCENTIVE AND MANAGEMENT FEES

Enbridge receives an annual base management fee for administrative and management services it provides to the Fund,

plus incentive fees. Incentive fees are paid to Enbridge based on cash distributions paid by the Fund that exceed a base

distribution amount. In 2012, the Company received intercompany incentive fees of $12 million (2011 – $10 million;

2010 – $8 million) before income taxes. Enbridge also provides management services to ENF. No additional fee is

charged to ENF for these services provided the Fund is paying a fee to Enbridge.

CORPORATE RESTRUCTURING

In 2010, a plan of arrangement (the Plan) to restructure the Fund took effect. Under the Plan all publicly held trust

units and five million units held by Enbridge were exchanged on a one-for-one basis for shares of a taxable Canadian

corporation, ENF. The business of ENF is generally limited to investment in the Fund. Following completion of the

Plan, the Company retained its overall economic interest in the Fund and remained the primary beneficiary of the Fund

both before and after the Plan through a combined direct and indirect investment in the Fund voting units and a

non-voting preferred unit investment. As such, Enbridge continues to consolidate the Fund under variable interest

entity accounting rules.

RESULTS OF OPERATIONS

Earnings from the Fund totaled $84 million for the year ended December 31, 2012 compared with $51 million for the

year ended December 31, 2011. The increased earnings from the Fund reflected a full year of earnings from the assets

acquired from a wholly-owned subsidiary of Enbridge in October 2011. Earnings also reflected the December 2012

transfer of Hardisty Storage Caverns, Hardisty Contract Terminals, Greenwich, Amherstburg and Tilbury projects.

Partially offsetting the earnings contributions were increased interest costs, higher business development expense and

non-cash deferred income taxes.

Earnings from the Fund increased from $42 million for the year ended December 31, 2010 to $51 million in 2011.

The increased earnings reflected increased contributions from the Saskatchewan System following substantial

completion of its Phase II expansion project in December 2010, as well as contribution from the wind and solar

resources acquired by the Fund in October 2011. These positive impacts were partially offset by higher operating

and administrative costs as a result of the 2011 asset acquisition and an increase in interest expense and taxes.

6 8 < EN BR IDGE I NC. 2012 FINANCIAL REPO RT

BUSINESS RISKS

Risks for Alliance Pipeline Canada are similar to those identified for Alliance Pipeline US in the Gas Pipelines,

Processing and Energy Services segment. The following risks generally relate to the Saskatchewan System and

the wind and solar businesses, as indicated. General risks that affect the Company as a whole are described under

Risk Management and Financial Instruments – General Business Risks.

SASKATCHEWAN SYSTEM

COMPETITION

The Saskatchewan System faces competition in pipeline transportation from other pipelines as well as other forms

of transportation, most notably rail. These alternative transportation options could charge rates or provide service

to locations that result in greater net profit for shippers, thereby reducing shipments on the Saskatchewan System

or resulting in pressure to reduce tolls. The Saskatchewan System’s right-of-way and expansion efforts provide a

competitive advantage and the Company believes its tolls are competitive relative to alternative pipeline transportation

options; however, the Fund is currently engaged in discussions with shippers regarding the reasonableness of its tolls.

REGULATION

The Fund’s 50% interest in Alliance Pipeline Canada and certain pipelines within the Saskatchewan System are subject

to the actions of various regulators, including the NEB. Actions of the regulators related to tariffs, tolls and facilities

impact earnings and the success of expansion projects. Delays in regulatory approvals could result in cost escalations

and construction delays. Changes in regulation, including decisions by regulators on the applicable tariff structure or

changes in interpretations of existing regulations by courts or regulators, could adversely affect the results of operations

of the Fund and could adversely impact the timing and amount of recovery or settlement of regulatory balances.

WIND AND SOLAR

REGULATION

The Fund’s wind and solar assets which operate in Ontario are classified as intermittent generators under the

Independent Electricity System Operator (IESO) market rules. IESO market rules allow delivery of electrical energy

to the transmission and distribution grid as it is produced regardless of prevailing power price. Recent amendments

to these market rules allow the IESO to curtail intermittent generators during periods of surplus base load generation

when the prevailing power price falls below a threshold. As the wind and solar assets currently operate under long-term

PPAs the Fund is in discussions with the Ontario Power Authority to determine its rights and obligations under its PPA

for economic compensation during future periods of economic curtailment.

AVAILABILITY OF TRANSMISSION

The ability to deliver electricity is affected by the availability of the various transmission and distributions systems in the

areas in which it operates. The failure of existing transmission or distribution facilities or lack of adequate transmission

or distribution capacity could have a material adverse effect on the ability to deliver electricity and receive payment

under the PPA.

WEATHER

Earnings from wind and solar projects are highly dependent on weather and atmospheric conditions. While the

expected energy yields for the wind and solar projects are predicted using long-term historical data, wind and solar

resources will be subject to natural variation from year to year and from season to season. Any prolonged reduction

in wind or solar resources at any of the wind or solar facilities could lead to decreased earnings for the Fund.

Management’s Discussion and Analysis > 69

Corporate

EARNINGS

(millions of Canadian dollars)

Noverco

Other Corporate

Adjusted loss

Noverco – equity earnings adjustment

Noverco – changes in unrealized derivative fair value loss

Other Corporate – changes in unrealized derivative fair value gains/(loss)

Other Corporate – foreign tax recovery

Other Corporate – unrealized foreign exchange gains/(loss) on translation of

intercompany balances, net

Other Corporate – impact of tax rate changes

Other Corporate – tax on intercompany gain on sale

Earnings/(loss) attributable to common shareholders

2012

2011

2010

(55)

(28)

(12)

(10)

(22)

(17)

(11)

(56)

(127)

(40)

(16)

–

(87)

–

(98)

(171)

(46)

(25)

–

Total adjusted loss from Corporate was $28 million for the year ended December 31, 2012 compared with adjusted

losses of $16 million for the year ended December 31, 2011 and $25 million for the year ended December 31, 2010.

Corporate earnings/(loss) were impacted by the following adjusting items:

• Earnings from Noverco for 2012 included an unfavourable equity earnings adjustment related to prior periods.

• Earnings from Noverco for 2012 included changes in the unrealized fair value loss of derivative financial instruments.

• Loss for each year included changes in the unrealized fair value gains and losses on derivative financial instruments

related to forward foreign exchange risk management positions.

• Loss for 2012 were impacted by taxes related to a historical foreign investment.

• Loss for each year included net unrealized foreign exchange gains and losses on the translation of foreign-

denominated intercompany balances.

• Loss for 2012 and 2011 reflected tax rate changes.

• Loss for 2012 and 2011 were impacted by tax on an intercompany gain of sale. See Sponsored Investments –

Enbridge Income Fund – Crude Oil Storage and Renewable Energy Transfers for details of the transactions.

NOVERCO

At December 31, 2012, Enbridge owned an equity interest in Noverco through ownership of 38.9% (2011 – 38.9%;

2010 – 32.1%) of its common shares and an investment in preferred shares. Noverco is a holding company that owns

approximately 71% of Gaz Metro Limited Partnership (Gaz Metro), a natural gas distribution company operating in

the province of Quebec with interests in subsidiary companies operating gas transmission, gas distribution and power

distribution businesses in the province of Quebec and the state of Vermont. Effective September 2010, Gaz Metro

became a privately held limited partnership as a result of a reorganization of its publicly held partnership units, which

were exchanged on a one-for-one basis for common shares in Valener Inc., a new publicly listed corporation.

7 0 < EN BR IDGE I NC. 2012 FINANCIAL REPO RT

Noverco also holds, directly and indirectly, an investment in Enbridge common shares. In early 2012, Noverco advised

Enbridge that the substantial increase in the value of these shares over the last decade had resulted in a significant shift

in the balance of Noverco’s asset mix. The Board of Directors of Noverco authorized its manager to sell a portion of its

Enbridge common share holding and rebalance Noverco’s asset mix. On March 22, 2012, Noverco sold 22.5 million

Enbridge common shares through a secondary offering. Enbridge’s share of the proceeds of approximately $317

million was received as a dividend from Noverco on May 18, 2012 and was used to pay a portion of the Company’s

quarterly dividend on June 1, 2012. This portion of the quarterly dividend did not qualify for the enhanced dividend

tax credit in Canada and, accordingly, was not designated as an “eligible dividend”. For United States tax purposes,

the dividend was a “qualified dividend”.

A significant portion of the Company’s earnings from Noverco is in the form of dividends on its preferred share

investments which are based on the yield of 10-year Government of Canada bonds plus a margin of 4.3% to 4.4%.

Virtually all of Noverco’s residual earnings are from Gaz Metro’s regulated assets. Rates for these natural gas and

electricity distribution networks are established primarily using a cost-of-service method. Consequently, Gaz Metro’s

profitability is dependent on its ability to invest in the development of its rate base and on the rates of return on

deemed equity authorized by the regulatory agencies. Weather variations do not affect Noverco’s earnings as Gaz

Metro is not exposed to weather risk.

RESULTS OF OPERATIONS

Noverco adjusted earnings were $27 million for the year ended December 31, 2012 compared with $24 million for the

year ended December 31, 2011 and $21 million for the year ended December 31, 2010. Noverco adjusted earnings for

each year reflected contributions from the Company’s increased preferred share investment and Noverco’s underlying

gas distribution investments.

OTHER CORPORATE

Corporate also consists of the new business development activities, general corporate investments and financing costs

not allocated to the business segments. Other corporate costs include dividends on preference shares as such dividends

are a deduction in determining earnings attributable to common shareholders.

PREFERENCE SHARE ISSUANCES

Since July 2011, the Company has issued 146 million preference shares for gross proceeds of approximately $3,660

million with the following characteristics. See Liquidity and Capital Resources – Outstanding Share Data.

Gross Proceeds

Initial Yield

Dividend 1

Per Share Base
Redemption
Value 2

Redemption
and Conversion

Option Date 2,3

Right to
Convert Into 3,4

$500 million

$450 million

$500 million

$350 million

(Canadian dollars, unless otherwise stated)
Series B 5
Series D 5
Series F 5
Series H 5
Series J 5
Series L 5
Series N 5
Series P 5
Series R 5

$450 million

$400 million

US$200 million

US$400 million

4.0%

$1.00

US$1.00

$1.00

$25

US$25

$25

June 1, 2017

March 1, 2018

June 1, 2018

September 1, 2018

June 1, 2017

September 1, 2017

December 1, 2018

March 1, 2019

June 1, 2019

Series C

Series E

Series G

Series I

Series K

Series M

Series O

Series Q

Series S

1
2

The holder is entitled to receive a fixed, cumulative, quarterly preferential dividend per year, as declared by the Board of Directors of the Company.
The Company may at its option, redeem all or a portion of the 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.
The holder will have the right, subject to certain conditions, to convert their shares into Cumulative Redeemable Preference Shares of a specified series on the Conversion
Option Date and every fifth anniversary thereafter.
Holders will be entitled to receive quarterly floating rate cumulative dividends per share at a rate equal to: $25 x (number of days in quarter/365) x (90-day Government of
Canada treasury bill rate + 2.4% (Series C), 2.4% (Series E), 2.5% (Series G), 2.1% (Series I), 2.7% (Series O), 2.5% (Series Q) or 2.5% (Series S)); or US$25 x (number of
days in quarter/365) x (90-day United States Government treasury bill rate + 3.1% (Series K) or 3.2% (Series M)).
See Liquidity and Capital Resources – Outstanding Share Data for dividends declared on December 6, 2012.

Management’s Discussion and Analysis > 71

RESULTS OF OPERATIONS

Other Corporate adjusted loss was $55 million for the year ended December 31, 2012 compared with $40 million for

the year ended December 31, 2011. Although net Corporate segment financing costs decreased in 2012 compared

with 2011, this decrease was more than offset by increased preference share dividends and higher personnel costs.

Adjusted loss from Corporate was $40 million for the year ended December 31, 2011 compared with $46 million for

the year ended December 31, 2010. The decreased adjusted loss reflected lower interest expense, partially offset by an

increase in preference share dividends following the issuance of 38 million preference shares during the year, as well as

higher tax expense.

Liquidity and Capital Resources

The maintenance of financial strength and flexibility is fundamental to Enbridge’s growth strategy, particularly in light

of the unprecedented level of growth projects secured or under development. With continued volatility in global capital

markets, the Company’s access to timely funding may be subject to risks from factors outside its control, including but

not limited to, United States economic uncertainty and slow economic recovery. To mitigate such risks, the Company

actively manages financing plans and strategies to ensure it maintains sufficient liquidity to meet routine operating and

future capital requirements. The Company targets to maintain sufficient liquidity to bridge fund through any periods

of protracted capital markets disruption, up to one year.

In the near term, the Company generally expects to utilize cash from operations and the issuance of debt, 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 also maintains a longer horizon funding

plan which considers growth capital needs and identifies potential sources of debt and equity funding alternatives, with

the objective of maintaining access to low cost capital.

Several of the Company’s growth projects that will be undertaken jointly with EEP will be funded 60% by Enbridge

and 40% by EEP, with EEP having the option to reduce its funding and associated economic interest in the projects by

up to 15% before June 30, 2013. Furthermore, within one year of the final in-service date of either the Eastern Access

or Lakehead System Mainline Expansion projects, EEP will have the option to increase its economic interest held at

those times in each project by up to 15%.

In accordance with its funding plan, the Company has been active in the capital markets with the following issuances

during 2012:

• Corporate – $2,710 million in preference shares; $400 million in common equity; $750 million of

medium-term notes;

• Enbridge Pipelines Inc. (EPI) – $100 million Century Bond; $150 million of medium-term notes;

• ENF/the Fund – $213 million in ENF common equity; $1,199 million of medium-term notes in the Fund; and

• EEP – US$447 million in Class A common units.

In addition to these debt and equity issuances, the Company received a $317 million one-time dividend from its

investment in Noverco which resulted from Noverco’s disposal of Enbridge shares via a secondary offering, as well

as the monetization of crude oil storage and renewable energy assets through sale to the Fund.

To ensure ongoing liquidity and mitigate the risk of capital market disruption, Enbridge also has a significant amount

of committed bank credit facilities which were further bolstered in 2012. The Company’s net available liquidity of

$10,799 million at December 31, 2012 was inclusive of approximately $1,297 million of unrestricted cash and cash

equivalents, net of bank indebtedness. In addition to ensuring adequate liquidity, the Company actively manages its

bank funding sources to optimize pricing and other terms. The following table provides details of the Company’s credit

facilities at December 31, 2012 and 2011.

7 2 < EN BR IDGE I NC. 2012 FINANCIAL REPO RT

(millions of Canadian dollars)

Liquids Pipelines

Gas Distribution

Sponsored Investments

Corporate

Southern Lights project financing 3

Total credit facilities

2011

2012

Maturity Dates 1

Total Facilities

Draws 2

Available

2014

2014 – 2017

2014

300

717

2,534

5,653

9,204

1,576

10,780

300

712

3,162

9,108

13,282

1,484

14,766

590

1,645

1,520

3,780

1,429

5,209

275

122

1,517

7,588

9,502

9,557

1
2
3

Total facilities include $35 million in demand facilities with no maturity date.
Includes facility draws, letters of credit and commercial paper issuances that are back-stopped by the credit facility.
Total facilities inclusive of $60 million for debt service reserve letters of credit.

The Company’s credit facility agreements include standard default and covenant provisions whereby accelerated

repayment may be required if the Company were to default on payment or violate certain covenants. As in prior years,

the Company expects to continue to comply with these provisions and therefore not trigger any early repayments.

As at December 31, 2012, the Company was in compliance with all debt covenants.

With increased borrowing, the Company actively manages certain financial ratios measuring the Company’s ability to

service its debt from operating cash flows. The Company’s internal cash flow growth maintains the financial ratios at

a strong level. The Company’s access to liquidity from diversified funding sources and its ability to service its debt has

allowed it to maintain a stable risk profile, which has led to sustained investment-grade ratings from the major credit

rating agencies. The Company also continues to manage its debt-to-capitalization ratio to maintain a strong balance

sheet. The Company’s debt-to-capitalization ratio, including bank indebtedness and short-term borrowings, was

61.4% at December 31, 2012 compared with 65.6% at December 31, 2011.

The Company invests a portion of its surplus cash in short-term investment grade instruments with creditworthy

counterparties. Short-term investments were $950 million as at December 31, 2012 compared with $73 million

as at December 31, 2011. This $877 million increase was due to the timing of cash generated from debt and equity

market transactions and will be used to fund the Company’s growth projects in 2013.

There are no material restrictions on the Company’s cash with the exception of restricted cash of $7 million related

to Southern Lights project financing and cash in trust of $12 million for specific shipper commitments.

Excluding current maturities of long-term debt, the Company had a positive working capital position of $183 million

at December 31, 2012 compared to negative working capital of $164 million for the year ended December 31, 2011.

Working capital includes the current portion of unrealized fair value derivative gains and losses related to the

Company’s risk management activities. The net liability position for current derivatives was $692 million and $394

million for the years ended December 31, 2012 and 2011, respectively. Actual cash outflows to be incurred to settle

these liabilities depend on foreign exchange rates, interest rates or commodity prices in effect when derivative contracts

outstanding mature; therefore, working capital at a point in time may not be representative of actual future cash flows.

Further, working capital will fluctuate from time to time due to natural gas inventory and borrowing levels at EGD,

which in turn are impacted by weather and commodity prices, as well as general activity levels within the Company’s

Energy Services businesses, among others. Changes in commodity prices also impact accounts receivable and other,

inventory and accounts payable and other within Energy Services and EGD.

Management’s Discussion and Analysis > 73

December 31,

(millions of Canadian dollars)
Cash and cash equivalents 1
Accounts receivable and other 2

Inventory

Bank indebtedness

Short-term borrowings
Accounts payable and other 3

Interest payable

Environmental liabilities

Working capital

2012

2011

1,795

4,026

779

(479)

(583)

(5,052)

(196)

(107)

183

740

4,084

823

(102)

(548)

(4,801)

(185)

(175)

(164)

1
2
3

Includes short-term investments and restricted cash of amounts in trust.
Includes Accounts receivable from affiliates.
Includes Accounts payable to affiliates.

The net available liquidity, together with cash from operations and the proceeds of capital market transactions, is

expected to be sufficient to finance all currently secured capital projects and provide flexibility for new investment

opportunities in the short-term, in the event of unforeseen economic disturbances.

OPERATING ACTIVITIES

Cash provided by operating activities for the year ended December 31,

2012 was $2,874 million compared with $3,371 million for the year ended

December 31, 2011 and $1,877 for the year ended December 31, 2010.

The most significant factor which impacted the decline in cash provided

by operating activities was a $1,063 million unfavourable variance in the

changes in operating assets and liabilities. Working capital fluctuated due to

variations in commodity prices and sales volumes within Energy Services,

the timing of tax payments, the payment of power deposits to support the

Company’s growth projects, as well as general variations in activity levels

within the Company’s businesses. In addition, cash from operating activities

during the fourth quarter of 2012 included an outflow of US$202 million

related to a voluntary pre-payment of certain derivative liabilities. The

payment was transacted to optimize cash management opportunities and

did not alter the risk management properties of the derivative position.

The cash outflows within operating activities were partially offset by the

favourable operating performance of the Canadian Mainline under CTS,

strong volumes across all of the Company’s liquids pipelines assets and

general cash growth from development projects placed in service in recent
years. Additionally, the Company received a $317 million one-time dividend

from its investment in Noverco. During 2012, Noverco had realized a

substantial gain on the disposition of a portion of its investment in Enbridge

shares and subsequently distributed the proceeds from this transaction to

its shareholders, by way of dividend.

CASH PROVIDED BY
OPERATING ACTIVITIES
(millions of Canadian dollars)

1
1
7
3
,
3

1
4
7
8
,
2

2
7
1
0
,
2

1
7
7
8
,
1

2
2
7
3
,
1

7 4 < EN BR IDGE I NC. 2012 FINANCIAL REPO RT

INVESTING ACTIVITIES

Cash used in investing activities was $6,204 million for the year ended December 31, 2012 compared with $5,079

million and $3,902 million for the corresponding periods of 2011 and 2010, respectively. Cash used in investing

activities has increased on a year-over-year basis primarily due to capital expenditure activity, predominantly directed to

the construction of the Company’s expansion initiatives, all of which are described in Growth Projects – Commercially

Secured Projects and Growth Projects – Other Projects Under Development. A summary of additions to property, plant and

equipment for the years ended December 31, 2012, 2011 and 2010 is as follows:

Year ended December 31,

(millions of Canadian dollars)

Liquids Pipelines

Gas Distribution

Gas Pipelines, Processing and Energy Services

Sponsored Investments

Corporate

Total capital expenditures

2012

2011

2010

2,091

438

837

1,993

109

5,468

955

483

850

1,187

3,508

684

387

1,114

868

–

3,053

Other notable investing activities in 2012 included the acquisition of Silver State and PRA Gas Development, as

well as the remaining 10% interest in Greenwich, for $340 million. The Company also provided additional funding

of $531 million to various investments and joint ventures, namely TEP and Seaway Pipeline. In comparison, for the

year ended December 31, 2011, the Company acquired its original 50% interest in Seaway Pipeline for $1,192 million,

increased its Noverco preferred shares investment by $144 million and provided additional funding of $179 million to

various equity investments. In 2010, the cash used in investing activities included the acquisition of Elk City System for

$705 million.

FINANCING ACTIVITIES

Cash generated from financing activities was $4,395 million for the year

ended December 31, 2012 compared with $2,030 million and $1,957

million for the corresponding periods of 2011 and 2010, respectively.

The increase in cash provided by financing activities was primarily due

to the issuance of redeemable preference shares of $2,634 million in 2012,

compared with $926 million in 2011 and nil in 2010, as well as a common

equity issuance of $384 million. This cash inflow was partially offset by

payments of common and preference share dividends of $690 million in

2012 (2011 – $537 million; 2010 – $433 million).

In 2012, the Company was also successful in issuing debenture and term

notes for net proceeds of $2,199 million (2011 – $1,604 million; 2010 –

$3,220 million), as well as making draws on short-term borrowings and

bank indebtedness of $412 million (2011 – $224 million; 2010 – $165

million repayment). This was partially offset by repayments of term notes,

commercial paper and credit facility draws of $803 million in 2012

(2011 – $864 million; 2010 – $843 million). Funds for debt retirements

are generated through cash provided from operating activities as well as

through the issuance of replacement debt.

CAPITAL EXPENDITURES
AND INVESTMENTS
(millions of Canadian dollars)

8
6
4
,
5

8
0
5
,
3

3
5
0
,
3

Liquids Pipelines
Gas Distribution
Gas Pipelines, Processing
and Energy Services
Sponsored Investments
Corporate

Management’s Discussion and Analysis > 75

Cash generated from financing activities for the years ended December 31, 2012 and 2011 also included contributions,

net of distributions, from third-party investors in the Fund of $164 million and $175 million, respectively. In both

2012 and 2011, the Fund acquired certain crude oil storage and renewable energy assets from Enbridge, which it

financed in part through the issuance of equity to its public noncontrolling interest holders. In 2012, the Company

also received contributions, net of distributions, from third-party investors, primarily from EEP, of $27 million

(2011 – $518 million; 2010 – $121 million).

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 year ended December 31, 2012, dividends declared were $895

million (2011 – $759 million), of which $597 million (2011 – $530 million) were paid in cash and reflected in financing

activities. The remaining $297 million (2011 – $229 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 years ended December 31, 2012 and

2011, 33.2% and 30.2%, respectively, of total dividends declared were reinvested.

OUTSTANDING SHARE DATA 1

Preference Shares, Series A 2
Preference Shares, Series B 2,3
Preference Shares, Series D 2,4
Preference Shares, Series F 2,5
Preference Shares, Series H 2,6
Preference Shares, Series J 2,7
Preference Shares, Series L 2,8
Preference Shares, Series N 2,9
Preference Shares, Series P 2,10
Preference Shares, Series R 2,11

Common Shares – issued and outstanding (voting equity shares)

Stock Options – issued and outstanding (14,611,123 vested)

Number

5,000,000

20,000,000

18,000,000

20,000,000

14,000,000

8,000,000

16,000,000

18,000,000

16,000,000

806,456,150

31,907,543

1 Outstanding share data information is provided as at February 8, 2013.
2

All preference shares are non-voting equity shares. Preference Shares, Series A may be redeemed any time at the Company’s option. For all other series of Preference
Shares, the Company may at its option, redeem all or a portion of the 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 On June 1, 2017, and on June 1 every five years thereafter, the holders of Preference Shares, Series B will have the right to elect to convert (subject to certain provisions)

any or all of their Preference Shares, Series B into an equal number of Cumulative Redeemable Preference Shares, Series C.

4 On March 1, 2018, and on March 1 every five years thereafter, the holders of Preference Shares, Series D will have the right to elect to convert (subject to certain provisions)

any or all of their Preference Shares, Series D into an equal number of Cumulative Redeemable Preference Shares, Series E.

5 On June 1, 2018, and on June 1 every five years thereafter, the holders of Preference Shares, Series F will have the right to elect to convert (subject to certain provisions)

any or all of their Preference Shares, Series F into an equal number of Cumulative Redeemable Preference Shares, Series G.

6 On September 1, 2018, and on September 1 every five years thereafter, the holders of Preference Shares, Series H will have the right to elect to convert (subject to certain

provisions) any or all of their Preference Shares, Series H into an equal number of Cumulative Redeemable Preference Shares, Series I.

7 On June 1, 2017, and on June 1 every five years thereafter, the holders of Preference Shares, Series J will have the right to elect to convert (subject to certain provisions)

any or all of their Preference Shares, Series J into an equal number of Cumulative Redeemable Preference Shares, Series K.

8 On September 1, 2017, and on September 1 every five years thereafter, the holders of Preference Shares, Series L will have the right to elect to convert (subject to certain

provisions) any or all of their Preference Shares, Series L into an equal number of Cumulative Redeemable Preference Shares, Series M.

9 On December 1, 2018, and on December 1 every five years thereafter, the holders of Preference Shares, Series N will have the right to elect to convert (subject to certain

provisions) any or all of their Preference Shares, Series N into an equal number of Cumulative Redeemable Preference Shares, Series O.

10 On March 1, 2019, and on March 1 every five years thereafter, the holders of Preference Shares, Series P will have the right to elect to convert (subject to certain provisions)

any or all of their Preference Shares, Series P into an equal number of Cumulative Redeemable Preference Shares, Series Q.

11 On June 1, 2019 and on June 1 every five years thereafter, the holders of Preference Shares, Series R will have the right to elect to convert (subject to certain provisions)

any or all of their Preference Shares, Series R into an equal number of Cumulative Redeemable Preference Shares, Series S.

7 6 < EN BR IDGE I NC. 2012 FINANCIAL REPO RT

Effective May 25, 2011, a two-for-one stock split of the Company’s common shares was completed. All references to

the number of shares outstanding, earnings per common share, diluted earnings per common share, adjusted earnings

per common share, dividends per common share and outstanding option information have been retroactively restated

to reflect the impact of the stock split.

On December 6, 2012, the Enbridge Board of Directors declared the following quarterly dividends. All dividends are

payable on March 1, 2013 to shareholders of record on February 15, 2013.

Common Shares

Preference Shares, Series A

Preference Shares, Series B

Preference Shares, Series D

Preference Shares, Series F

Preference Shares, Series H

Preference Shares, Series J

Preference Shares, Series L

Preference Shares, Series N

Preference Shares, Series P
Preference Shares, Series R 1

$0.31500

$0.34375

$0.25000

US$0.25000

$0.25000

$0.23560

This first dividend declared for the Preference Shares, Series R includes accrued dividends from December 5, 2012, the date the shares were issued. The regular quarterly
dividend of $0.25 per share will take effect on June 1, 2013. See Corporate – Other Corporate – Preference Share Issuances.

Commitments and Contingencies

CAPITAL EXPENDITURE COMMITMENTS

The Company has signed contracts for the purchase of services, pipe and other materials, as well as transportation,

totaling $4,639 million which are expected to be paid over the next five years.

CONTRACTUAL OBLIGATIONS

Payments due for contractual obligations over the next five years and thereafter are as follows:

(millions of Canadian dollars)
Long-term debt 1

Capital and operating leases
Long-term contracts 2,3
Pension obligations 4

Total contractual obligations

Total

Less than 1 year

1 – 3 years

3 – 5 years

After 5 years

21,428

329

5,691

140

27,588

1,234

3,322

140

4,736

2,195

925

–

3,200

2,320

421

–

2,813

15,679

137

1,023

–

16,839

1
2

Excludes interest. Changes to the planned funding requirements are dependent on the terms of any debt refinancing agreements.
Approximately $2,507 million of these contracts are commitments for materials related to the construction of growth projects. Changes to the planned funding requirements,
including cancellation, are dependent on changes to the related projects.
Contracts totaling $161 million are within proportionately consolidated joint venture entities and contracts totaling $88 million are within equity investments which the
Company is guaranteeing.
Assumes only required payments will be made into the pension plans in 2013. Contributions are made in accordance with independent actuarial valuations as at December
31, 2012. Contributions, including discretionary payments, may vary pending future benefit design and asset performance.

Management’s Discussion and Analysis > 77

UNITED STATES LEGAL AND REGULATORY PROCEEDINGS

A number of United States governmental agencies and regulators have initiated investigations into the Line 6A and

Line 6B crude oil releases. Approximately 30 actions or claims have been filed against Enbridge, EEP or their affiliates

in United States federal and state courts in connection with the Line 6B crude oil release, including direct actions and

actions seeking class status. Based on the current status of these cases, EEP does not expect the outcome of these

actions to be material. On July 2, 2012, PHMSA announced a NOPV related to the Line 6B crude oil release,

including a civil penalty of US$3.7 million that EEP paid in the third quarter of 2012. One claim related to the Line

6A crude oil release has been filed against Enbridge, EEP or their affiliates by the State of Illinois in the Illinois state

court. The parties are currently operating under an agreed interim order. As at December 31, 2012, the Company was

not aware of any claims related to the Line 14 crude oil release. See Sponsored Investments – Enbridge Energy Partners,

L.P. – Lakehead System Lines 6A and 6B Crude Oil Releases and Sponsored Investments – Enbridge Energy Partners,

L.P. – Lakehead System Line 14 Crude Oil Release.

ENBRIDGE GAS NEW BRUNSWICK INC.

REGULATORY MATTERS

In 2011, the Government of New Brunswick passed legislation related to the regulatory process for setting rates for

gas distribution within the province. A final rates and tariffs regulation was subsequently enacted by the Government

of New Brunswick in April 2012. Based on the amended rate setting methodology and specific conditions outlined

therein, EGNB no longer met the criteria for the continuation of rate-regulated accounting. As a result, the Company

eliminated from its 2011 Consolidated Statements of Financial Position a deferred regulatory asset and certain

capitalized operating costs totaling $262 million, net of tax. In April 2012, the Company, Enbridge EEDI and EGNB

commenced an action against the Province of New Brunswick in the New Brunswick Court of Queen’s Bench, claiming

damages as a result of the continuing breaches by the province of the General Franchise Agreement it signed with

Enbridge in 1999. Additionally, on May 2, 2012, the Company, EEDI and EGNB filed a Notice of Application with

the New Brunswick Court of Queen’s Bench seeking a declaration from the Court that the rates and tariffs regulation

is invalid. In a decision released on August 23, 2012, the Court dismissed EGNB’s application. EGNB has filed a

Notice of Appeal with the New Brunswick Court of Appeal and a hearing of the appeal is expected to be held during

the first half of 2013. There is no assurance these actions will be successful or will result in any recovery. See Gas

Distribution – Other Gas Distribution and Storage – Enbridge Gas New Brunswick Inc. – Regulatory Matters.

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 LEGAL AND REGULATORY PROCEEDINGS

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.

7 8 < EN BR IDGE I NC. 2012 FINANCIAL REPO RT

Quarterly Financial Information 1

2012

Total

(millions of Canadian dollars, except for per share amounts)

Revenues

Earnings attributable to common shareholders

Earnings per common share

Diluted earnings per common share

Dividends per common share

EGD – warmer/(colder) than normal weather

Changes in unrealized derivative fair value and

intercompany foreign exchange loss

2011

(millions of Canadian dollars, except for per share amounts)

Revenues

Earnings attributable to common shareholders
Earnings per common share 2
Diluted earnings per common share 2
Dividends per common share 2

EGD – warmer/(colder) than normal weather

Changes in unrealized derivative fair value and
intercompany foreign exchange (gains)/loss

6,627

264

0.35

0.34

5,718

0.01

5,788

189

0.24

7,173

146

0.19

0.18

0.2825

110

6,529

364

0.49

0.48

–

252

6,938

302

0.40

–

6,277

(5)

(0.01)

0.2450

(11)

(18)

(2)

(18)

–

242

(1)

7,309

159

0.21

0.2450

(241)

25,306

610

0.79

0.78

1.13

536

Total

27,053

820

1.09

1.08

0.98

(1)

(35)

1 Quarterly financial information has been extracted from financial statements prepared in accordance with U.S. GAAP.
2

Comparative amounts were restated to reflect two-for-one stock split which was effective May 25, 2011.

Several factors impact comparability of the Company’s financial results on a quarterly basis, including, but not limited

to, 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.

EGD and the Company’s other gas distribution businesses are subject to seasonal demand. A significant portion

of gas distribution customers use natural gas for space heating; therefore, volumes delivered and resulting revenues

and earnings typically increase during the winter months of the first and fourth quarters of any given year. Revenues

generated by EGD and other gas distribution businesses also vary from quarter-to-quarter with fluctuations in the

price of natural gas, although earnings remain neutral due to the pass through nature of these costs. Gas Distribution’s

earnings for the fourth quarter of 2011 included an extraordinary charge totaling $262 million, after-tax, as a result

of the discontinuance of rate-regulated accounting at EGNB and the related write-off of a deferred regulatory asset

and certain capitalized operating costs.

The Company actively manages its exposure to market price risks including, but not limited to, commodity prices

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.

Management’s Discussion and Analysis > 79

In the fourth quarter of 2012, the Company recorded an impairment charge of $166 million ($105 million after-tax)

related to certain of its Offshore assets, predominantly located within the Stingray and Garden Banks corridors. The

Company had been pursuing alternative uses for these assets; however, due to changing competitive conditions in the

fourth quarter of 2012, the Company concluded that such alternatives were no longer likely to proceed. Also included

in the fourth quarter of 2012 was a $63 million gain on recognition of a regulatory asset related to OPEB within EGD.

Fourth quarter earnings for 2012 and 2011 were also impacted by the impact of asset transfers between entities under

common control of Enbridge, resulting in income taxes of $56 million and $98 million, respectively, incurred on the

related capital gains.

Reflected in earnings is the Company’s share of leak remediation costs and lost revenue associated with the Lines 6A,

6B and Line 14 crude oil releases. For the second, third and fourth quarter of 2012, these amounts were $2 million,

$7 million and nil (2011 – $6 million, $21 million and $6 million), respectively. Earnings also reflected insurance

recoveries associated with the Line 6B crude oil release of $24 million in the third quarter of 2012 and $5 million,

$3 million, $13 million and $29 million in the first, second, third and fourth quarters of 2011, respectively.

Finally, the Company is in the midst of a substantial 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 in-service dates, are described in Growth Projects – Commercially Secured

Projects and Growth Projects – Other Projects Under Development.

Related Party Transactions

All related party transactions are provided in the normal course of business and, unless otherwise noted, are measured

at the exchange amount, which is the amount of consideration established and agreed to by the related parties.

Vector, a joint venture, contracts the services of Enbridge to operate the pipeline. Amounts for these services, which

are charged at cost in accordance with service agreements, were $4 million for the year ended December 31, 2012

(2011 – $6 million; 2010 – $7 million).

Certain wholly-owned subsidiaries within the Gas Distribution and Gas Pipelines, Processing and Energy Services

segments have transportation commitments with several joint venture affiliates that are accounted for using the equity

method. Total amounts charged for transportation services were $127 million, $106 million and $102 million for the

years ended December 31, 2012, 2011 and 2010, respectively.

Amounts receivable from affiliates include a series of loans to Vector totaling $178 million (2011 – $190 million),

included in Deferred amounts and other assets, which require quarterly interest payments at annual interest rates

from 5% to 8%.

Risk Management and Financial Instruments

MARKET PRICE RISK

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 (collectively, market price risk).

Formal risk management policies, processes and systems have been designed to mitigate these risks.

The following summarizes the types of market price 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.

8 0 < EN BR IDGE I NC. 2012 FINANCIAL REPO RT

FOREIGN EXCHANGE RISK

The Company’s earnings, cash flows and OCI are subject to foreign exchange rate variability, primarily arising from its

United States dollar denominated investments and subsidiaries, and certain revenues denominated in United States

dollars and certain expenses denominated in Euros. The Company has implemented a policy whereby it economically

hedges a minimum level of foreign currency denominated earnings exposures identified over the next five year period.

The Company may also hedge anticipated foreign currency denominated purchases or sales and foreign currency

denominated debt, as well as certain equity investment balances and net investments in foreign denominated

subsidiaries. The Company uses a combination of qualifying and non-qualifying derivative instruments to manage

variability in cash flows arising from its United States dollar investments and subsidiaries, and primarily non-qualifying

derivative instruments to manage variability arising from certain revenues denominated in United States dollars.

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 through 2016 with an average swap rate

of 2.2%.

The Company’s earnings and cash flows are also exposed to variability in longer term interest rates ahead of anticipated

fixed rate 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 through 2016. Future fixed rate term debt issuances of $10,547

million have been hedged at an average swap rate of 3.5%.

The Company also monitors its debt portfolio mix of fixed and variable rate debt instruments to maintain a

consolidated portfolio of debt which stays within its Board of Directors approved policy limit band of a maximum of

25% floating rate debt as a percentage of total debt outstanding. The Company uses primarily 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 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.

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 Stock Units. The

Company uses a combination of qualifying and non-qualifying derivative instruments to manage equity price risk.

Management’s Discussion and Analysis > 81

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

The following table presents the effect of derivative instruments on the Company’s consolidated earnings and

consolidated comprehensive income.

Year ended December 31,

(millions of Canadian dollars)

Amount of unrealized gains/(loss) recognized in OCI

Cash flow hedges

Foreign exchange contracts

Interest rate contracts

Commodity contracts

Other contracts

Net investment hedges

Foreign exchange contracts

Amount of (gains)/loss reclassified from Accumulated other comprehensive

income (AOCI) to earnings (effective portion)

Cash flow hedges

Foreign exchange contracts 1
Interest rate contracts 2
Commodity contracts 3
Other contracts 4

Amount of (gains)/loss reclassified from AOCI to earnings

(ineffective portion and amount excluded from effectiveness testing)

Cash flow hedges

Interest rate contracts 2
Commodity contracts 3

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

Foreign exchange contracts 1
Interest rate contracts 2
Commodity contracts 3
Other contracts 4

2012

2011

2010

(12)

(46)

(3)

(8)

(1)

(3)

(1)

(3)

120

(2)

(765)

(2)

(649)

(22)

(724)

(26)

(694)

(10)

(55)

(2)

(66)

(179)

280

114

(25)

(217)

128

(1)

(96)

(7)

(116)

(61)

–

(3)

(12)

–

1
2
3
4

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

8 2 < EN BR IDGE I NC. 2012 FINANCIAL REPO RT

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 manage this risk, the Company forecasts cash requirements over a 12

month rolling time period to determine whether sufficient funds will be available. The Company’s primary sources of

liquidity and capital resources are funds generated from operations, the issuance of commercial paper and draws under

committed credit facilities and long-term debt which includes debentures and medium-term notes. The Company

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. In addition, the Company maintains sufficient liquidity

through committed credit facilities with a diversified group of banks and institutions which, if necessary, enables the

Company to fund all anticipated requirements for one year without accessing the capital markets. The Company is in

compliance with all the terms and conditions of its committed credit facilities as at December 31, 2012. As a result, all

credit facilities are available to the Company and the banks are obligated to fund and have been funding the Company

under the terms of the facilities.

CREDIT RISK

Entering into derivative financial instruments may result in exposure to credit risk. Credit risk arises from the possibility

that a counterparty will default on its contractual obligations. 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, frequent assessment of counterparty credit ratings and

netting arrangements.

The Company generally has a policy of entering into individual International Swaps and Derivatives Association

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 these 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 Gas Distribution, credit risk

is mitigated by the 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.

FAIR VALUE MEASUREMENTS

The Company uses the most observable inputs available to estimate the fair value of its derivatives. When possible, the

Company estimates the fair value of its derivatives based on quoted market prices. If quoted market prices are not
available, the Company uses estimates from third party brokers. For non-exchange traded derivatives classified in Levels

2 and 3, the Company uses standard valuation techniques to calculate the estimated fair value. These methods include

discounted cash flows for forwards and swaps and Black-Scholes-Merton pricing models for options. Depending on

the type of derivative and nature of the underlying risk, the Company uses observable market prices (interest, foreign

exchange, commodity and share) and volatility as primary inputs to these valuation techniques. Finally, the Company

considers its own credit default swap spread as well as the credit default swap spreads associated with its counterparties

in its estimation of fair value.

Management’s Discussion and Analysis > 83

GENERAL BUSINESS RISKS

STRATEGIC AND COMMERCIAL RISKS

PUBLIC OPINION

The Company’s reputation is one of its most valuable assets. Public opinion or reputation risk is the risk of negative

impacts on the Company’s business, operations or financial condition resulting from changes in the Company’s

reputation with stakeholders, special interest groups, political leadership, the media or other entities. Public opinion

may be influenced by media attention directed to development projects such as Northern Gateway. Potential impacts

of a negative public opinion may include loss of business, legal action, increased regulatory oversight and costs.

Reputation risk often arises as a consequence of some other risk event, such as in connection with operational,

regulatory or legal risks. Therefore, reputation risk cannot be managed in isolation from other risks. The Company

manages reputation risk by:

•

having formal risk management policies, procedures and systems in place to identify, assess and mitigate risks

to the Company;

operating to the highest ethical standards, with integrity, honesty and transparency, and maintaining positive

relationships with customers, investors, employees, partners, regulators and other stakeholders;

having health, safety and environment management systems in place, as well as policies, programs and practices

for conducting safe and environmentally sound operations;

having strong corporate governance practices, including a Statement on Business Conduct, with which all

employees are required to certify their compliance on an annual basis, and whistleblower procedures, which

allow employees to report suspected ethical concerns on a confidential and anonymous basis; and

•

pursuing socially responsible operations as a longer-term corporate strategy (implemented through the Company’s

CSR Policy, Climate Change Policy, Aboriginal and Native American Policy and the Neutral Footprint Initiative).

PROJECT EXECUTION

As the Company increases its slate of growth projects, it continues to focus on completing projects safely, on-time

and on-budget. However, the Company faces the challenge of scaling the business to manage an unprecedented

number of commercially secured growth projects. The Company’s ability to successfully execute the development

of its organic growth projects may be influenced by capital constraints, third-party opposition, changes in shipper

support over time, delays in or changes to government and regulatory approvals, cost escalations, construction delays,

inadequate resources and in-service delays (collectively, Execution Risk). Customer trends are toward expecting the

Company to assume more risk and accept lower returns. Early stage project risks include right-of-way procurement,

special interest group opposition, Crown consultation and environmental and regulatory permitting. Cost escalations

or missed in-service dates on future projects may impact future earnings and may hinder the Company’s ability to

secure future projects. Construction delays due to regulatory delays, contractor or supplier non-performance and

weather conditions may impact project development.

The Company strives to be an industry leader in project execution through its Major Projects group. Major Projects

is centralized and has a clearly defined governance structure and process for all major projects, with dedicated resources

organized to lead and execute each major project. Capital constraints and cost escalation risks are mitigated through

structuring of commercial agreements, typically where shippers retain complete or a share of capital cost excess. Early

stage project risks are mitigated by early assessment of stakeholder issues to develop proactive relationships and specific

action plans. Detailed cost tracking and centralized purchasing is used on all major projects to facilitate optimum

pricing and service terms. Strategic relationships have been developed with suppliers and contractors. Enhanced

recruiting, and outsourcing where necessary, has been introduced to ensure sufficient resources to address the

increasing volume of growth projects.

8 4 < EN BR IDGE I NC. 2012 FINANCIAL REPO RT

PLANNING AND INVESTMENT ANALYSIS

The Company evaluates the value proposition for expansion projects, new acquisitions or divestitures on an ongoing

basis. Planning and investment analysis is highly dependent on accurate forecasting assumptions and to the extent that

these assumptions do not materialize, financial performance may be lower or more volatile than expected. Volatility in

the economy, change in cost estimates, project scoping and risk assessment could result in a loss in profits for the

Company. Large scale acquisitions may involve significant pricing and integration risk.

The planning and investment analysis process involves all levels of management and Board of Directors’ review to

ensure alignment across the Company. A centralized corporate development group which is appropriately staffed

rigorously evaluates all major investment proposals with consistent due diligence processes, including a thorough

review of the asset quality, systems and financial performance of the assets being assessed.

HUMAN RESOURCES

As growth in WCSB production maintains its momentum it has presented both opportunities and challenges for

the Company. In response to the demands of the announced list of growth projects, the Company expects to add

approximately 2,500 permanent additions to its workforce over the next five years. However, the robust economic

situation in Alberta has led to a substantially tighter employment market in the province. As the Company continues

through a period of growth, attracting and retaining adequate personnel who adhere to Enbridge’s values will be

critical to fulfilling the Company’s growth plan.

ECONOMIC REGULATION

Many of the Company’s pipeline operations are regulated and are subject to regulatory risk. The nature and degree

of regulation and legislation affecting energy companies in Canada and the United States has changed significantly in

past years and there is no assurance that further substantial changes will not occur. These changes may adversely affect

toll structures or other aspects of pipeline operations or the operations of shippers. Recently, shippers have challenged

toll increases on various pipelines owned by Enbridge and some of Enbridge’s competitors. Enbridge retains dedicated

professional staff and maintains strong relationships with customers, interveners and regulators to help minimize

economic and regulation risk.

OPERATIONAL RISKS

ENVIRONMENTAL INCIDENT

An environmental incident could have lasting reputational impacts to Enbridge and could impact its ability to work

with various stakeholders. In addition to the cost of remediation activities (to the extent not covered by insurance)

environmental incidents may lead to an increased cost of operation and insuring the Company’s assets, thereby

negatively impacting earnings. The Company mitigates risk of environmental incident through its ORM Plan, which

broadly aims to position Enbridge as the industry leader for system integrity, environmental and safety programs.

Through the ORM Plan, the Company has expanded its maintenance, excavation and repair programs which are

supported by operating and capital budgets directed to pipeline integrity. Emergency response plans, operator training

and landowner education programs are included in the Company’s response preparedness.

The Company also recently completed a new state-of-the-art control centre. The new control centre was designed

with enhanced security measures. The Company also revised and enhanced all of its control room procedures pertaining

to decision making, pipeline start-ups and shutdowns, leak detection system alarms, communication protocols and

suspected column separations. The Company contributes to research and development initiatives for technological

advances to further enhance safety and integrity of pipelines.

Management’s Discussion and Analysis > 85

The Company maintains comprehensive insurance coverage for its subsidiaries and affiliates which renews annually.

The program includes commercial liability insurance coverage that is consistent with coverage considered customary

for its industry and includes coverage for environmental incidents. The total insurance coverage will be allocated on

an equitable basis in the unlikely event multiple insurable incidents exceeding the Company’s coverage limits are

experienced by Enbridge subsidiaries or affiliates within the same insurance period.

PUBLIC, WORKER AND CONTRACTOR SAFETY

Several of the Company’s pipeline systems run adjacent to populated areas and a major incident could result in injury

to members of the public. A public safety incident could result in reputational damage to the Company, material repair

costs or increased costs of operating and insuring the Company’s assets.

The safety of the Company’s current and future personnel is a Company priority. As part of the ORM Plan, the

Company initiated Enbridge’s Life Saving Rules. The Life Saving Rules are designed to highlight key processes and

rules to ensure public, worker and contractor safety. The Company also introduced new Safety Culture training sessions

for all employees.

Also, within EGD, the Company completed construction of the Enbridge Operations and Technology Centre in 2012.

The new training facility provides employees real-life simulations of major incidents and teaches the appropriate actions

to resolve them in a safe and controlled environment. Additionally, in 2012, EGD’s on-going pipeline integrity

program completed the replacement of all remaining cast iron and bare steel pipe in its gas distribution system.

SERVICE INTERRUPTION INCIDENT

A service interruption due to a major power disruption or curtailment on commodity supply could have a significant

impact on the Company’s ability to operate its assets. Specifically, for Gas Distribution, any prolonged interruptions

would ultimately impact gas distribution customers. The Company mitigates service interruption risk through its

diversified sources of supply, storage withdrawal flexibility, backup power systems, critical parts inventory and

redundancies for critical equipment.

SYSTEMS SECURITY INCIDENT

The Company’s infrastructure, applications and data are becoming more integrated, creating increased risk a failure in

one system could lead to a failure of another system. There is also increasing industry-wide cyber-attacking activities

targeting industrial control systems. A successful cyber-attack could lead to unavailability, disruption or loss of key

functionalities within the Company’s industrial control systems.

The Company has broadened the scope and frequency of vulnerability assessments aimed at identification of potentially

exposed information systems. The Company also executed a company-wide security education and awareness program

in the past year. The Company has a centralized information office which supports the development of standardized

systems, use of industry proven packages where feasible, use of an information security risk management strategy and

disaster recovery plans for critical operations. Back-up computers are installed in business units for enterprise-wide

fail protection.

BUSINESS ENVIRONMENT RISKS

ABORIGINAL RELATIONS

Canadian judicial decisions have recognized that Aboriginal rights and treaty rights exist in proximity to the Company’s

operations and future project developments. The courts have also confirmed that the Crown has a duty to consult

with Aboriginal peoples when its decisions or actions may adversely affect Aboriginal rights and interests or treaty

rights. Crown consultation has the potential to delay regulatory approval processes and construction, which may

affect project economics. In some cases, respecting Aboriginal rights may mean regulatory approval is denied or made

economically challenging.

8 6 < EN BR IDGE I NC. 2012 FINANCIAL REPO RT

Given this environment and the breadth of relationships across the Company’s geographic span, Enbridge has

implemented the Aboriginal and Native American Policy. This Policy promotes the achievement of participative

and mutually beneficial relationships with Aboriginal and Native American groups affected by the Company’s projects

and operations. Specifically, the Policy sets out principles governing the Company’s relationships with Aboriginal and

Native American peoples and makes commitments to work with Aboriginal peoples and Native Americans so they may

realize benefits from the Company’s projects and operations. Notwithstanding the Company’s efforts to this end, the

issues are complex and the impact of Aboriginal and Native American relations on Enbridge’s operations and

development initiatives is uncertain.

SPECIAL INTEREST GROUPS INCLUDING NON-GOVERNMENTAL ORGANIZATIONS

The Company is exposed to the risk of higher costs, delays or even project cancellations due to increasing pressure on

governments and regulators by special interest groups, including non-governmental organizations. Recent Supreme

Court decisions have increased the ability of special interest groups to make claims and oppose projects in regulatory

and legal forums. In addition to issues raised by groups focused on particular project impacts, the Company and others

in the energy and pipeline businesses are facing opposition from organizations opposed to oil sands development and

shipment of production from oil sands regions.

The Company works proactively with special interest groups and non-governmental organizations to identify and

develop appropriate responses to their concerns regarding its projects. The Company is investing significant resources

in these areas. Its CSR program also reports on the Company’s responsiveness to environmental and community issues.

Please see Enbridge’s annual CSR Report, available online at csr.enbridge.com for further details regarding the CSR
program. None of the information contained on, or connected to, Enbridge’s website is incorporated in or otherwise
part of this MD&A.

Critical Accounting Estimates

DEPRECIATION

Depreciation of property, plant and equipment, the Company’s largest asset with a net book value at December 31,

2012 of $33,318 million (2011 – $29,074 million), or 70.6% of total assets, is generally provided on a straight-line

basis over the estimated service lives of the assets commencing when the asset is placed in service. When it is determined

that the estimated service life of an asset no longer reflects the expected remaining period of benefit, prospective

changes are made to the estimated service life. Estimates of useful lives are based on third party engineering studies,

experience and/or industry practice. There are a number of assumptions inherent in estimating the service lives of the

Company’s assets including the level of development, exploration, drilling, reserves and production of crude oil and

natural gas in the supply areas served by the Company’s pipelines as well as the demand for crude oil and natural gas

and the integrity of the Company’s systems. Changes in these assumptions could result in adjustments to the estimated

service lives, which could result in material changes to depreciation expense in future periods in any of the Company’s

business segments. For certain rate-regulated operations, depreciation rates are approved by the regulator and the
regulator may require periodic studies or technical updates on useful lives which may change depreciation rates.

ASSET IMPAIRMENT

The Company evaluates the recoverability of its property, plant and equipment when events or circumstances such as

economic obsolescence, business climate, legal or regulatory changes, or other factors indicate it may not recover the

carrying amount of the assets. The Company continually monitors its businesses, the market and business environments

to identify indicators that could suggest an asset may not be recoverable. An impairment loss is recognized when the

carrying amount of the asset exceeds its fair value as determined by quoted market prices in active markets or present

value techniques. The determination of the fair value using present value techniques requires the use of projections and

assumptions regarding future cash flows and weighted average cost of capital. Any changes to these projections and
assumptions could result in revisions to the evaluation of the recoverability of the property, plant and equipment and

the recognition of an impairment loss in the Consolidated Statements of Earnings.

Management’s Discussion and Analysis > 87

REGULATORY ASSETS AND LIABILITIES

Certain of the Company’s businesses are subject to regulation by various authorities, including but not limited to,

the NEB, the FERC, the ERCB and the 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 operations may differ from that

otherwise expected under U.S. GAAP for non rate-regulated entities. Also, the Company records regulatory assets

and liabilities to recognize the economic effects of the actions of the regulator. 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. On refund or recovery of

this difference, no earnings impact is recorded. As at December 31, 2012, the Company’s significant regulatory assets

totaled $1,246 million (2011 – $972 million) and significant regulatory liabilities totaled $882 million (2011 – $836

million). 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 differ significantly from those recorded.

POSTRETIREMENT BENEFITS

The Company maintains pension plans, which provide defined benefit and/or defined contribution pension benefits

and OPEB to eligible retirees. Pension costs and obligations for the defined benefit pension plans are determined using

the universal method. This method involves complex actuarial calculations using several assumptions including discount

rates, which were determined by referring to high-quality long-term corporate bonds with maturities that approximate

the timing of future payments the Company anticipates making under each of the respective plans, expected rates of

return on plan assets, health-care cost trend rates, projected salary increases, retirement age, mortality and termination

rates. These assumptions are determined by management and are reviewed annually by the Company’s actuaries. Actual

results that differ from assumptions are amortized over future periods and therefore could materially affect the expense

recognized and the recorded obligation in future periods. The actual return on plan assets exceeded the expected return

on plan assets by $24 million for the year ended December 31, 2012 (2011 – $76 million shortfall) as disclosed in

Note 24 to the 2012 Annual Consolidated Financial Statements. The difference between the actual and expected return

on plan assets is amortized over the remaining service period of the active employees.

The following sensitivity analysis identifies the impact on the December 31, 2012 Consolidated Financial Statements of

a 0.5% change in key pension and OPEB assumptions.

(millions of Canadian dollars)

Decrease in discount rate

Decrease in expected return on assets

Decrease in rate of salary increase

CONTINGENT LIABILITIES

Pensions Benefits

OPEB

Obligation

Expense

Obligation

Expense

141

–

(30)

(5)

–

Provisions for claims filed against the Company are determined on a case-by-case basis. Case estimates are reviewed on

a regular basis and are updated as new information is received. The process of evaluating claims involves the use of

estimates and a high degree of management judgment. Claims outstanding, the final determination of which could have

a material impact on the financial results of the Company and certain of the Company’s subsidiaries and investments,

including EGD and EECI, are detailed in the Commitments and Contingencies section of this report and are disclosed

in Note 28 of the 2012 Annual Consolidated Financial Statements. In addition, any unasserted claims that later may

become evident could have a material impact on the financial results of the Company and certain of the Company’s

subsidiaries and investments.

8 8 < EN BR IDGE I NC. 2012 FINANCIAL REPO RT

ASSET RETIREMENT OBLIGATIONS

In May 2009, the NEB released a report on the financial issues associated with pipeline abandonment and established

a goal for pipelines regulated under the NEB Act to begin collecting and setting aside funds to cover future

abandonment costs no later than January 1, 2015. Since then, the NEB has issued revised “base case assumptions”

based on feedback from member companies. Companies have the option to follow the base case assumptions or to

submit pipeline specific applications.

On November 29, 2011, as required by the NEB, the Company filed its estimated abandonment costs for its regulated

pipeline systems within EPI and Enbridge Pipelines (NW) Inc. (Group 1 companies) and Enbridge Southern Lights

GP Inc., Enbridge Bakken Pipeline Company Inc., Enbridge Pipelines (Westspur) Inc. and Vector Pipelines Limited

Partnership (Group 2 companies). In the fourth quarter of 2012, the NEB held a hearing on the abandonment costs

estimates for Group 1 companies with a decision expected in the first quarter of 2013. The NEB also requires regulated

pipeline companies file a proposed process and mechanism to set aside the funds for future abandonment costs by

February 28, 2013 for Group 1 companies and by May 31, 2013 for Group 2 companies. These costs would be

recovered from shippers through tolls in accordance with NEB’s determination that abandonment costs are a legitimate

cost of providing services and are recoverable upon NEB approval from users of the system. The NEB requires Group 1

and Group 2 companies to file proposals for collection of the funds in tolls by May 31, 2013.

All applications for both Enbridge and EPI will require NEB approval and will result in increased transportation tolls

and regulated liabilities. The specific toll impacts are uncertain at this time as the Company anticipates the NEB filings

in mid-2013 will go to hearing prior to NEB approval.

Currently, for certain of the Company’s assets, there is insufficient data or information to reasonably determine the

timing of settlement for estimating the fair value of the asset retirement obligation (ARO). In these cases, the ARO cost

is considered indeterminate for accounting purposes, as there is no data or information that can be derived from past

practice, industry practice or the estimated economic life of the asset.

Changes in Accounting Policies

UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES

The Company commenced reporting using U.S. GAAP as its primary basis of accounting effective January 1, 2012,

including restatement of comparative periods. As a Securities and Exchange Commission (SEC) registrant, the

Company is permitted to use U.S. GAAP for purposes of meeting both its Canadian and United States continuous

disclosure requirements.

To facilitate users’ understanding of the transition to U.S. GAAP, the Company restated its 2011 consolidated financial

statements, which were originally prepared in accordance with Part V – Pre-changeover Accounting Standards of the

Canadian Institute of Chartered Accountants Handbook, to U.S. GAAP, including full comparative information and

related note disclosure. The 2011 U.S. GAAP financial statements were filed with securities regulators in Canada and

the United States on May 2, 2012 and are available on SEDAR at www.sedar.com and on the Company’s website at
www.enbridge.com. None of the information contained on, or connected to, Enbridge’s website is incorporated or
otherwise part of this MD&A.

Management’s Discussion and Analysis > 89

FAIR VALUE MEASUREMENT

Effective January 1, 2012, the Company adopted Accounting Standards Update (ASU) 2011-04, which revised the

existing guidance on the disclosure of fair value measurements. Under the revised standard, the Company is required

to provide additional disclosures about fair value measurements, including a description of the valuation methodologies

used and information about the unobservable inputs and assumptions used in Level 3 fair value measurements, as well

as the level in the fair value hierarchy of items that are not measured at fair value but whose fair value disclosure is

required. As the adoption of this update impacted disclosure only, there was no impact to the Company’s earnings

or cash flows for the current or prior periods presented.

STATEMENT OF COMPREHENSIVE INCOME

Effective January 1, 2012, the Company adopted ASU 2011-05, which updated existing guidance on comprehensive

income, 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 did not affect the Company’s presentation of comprehensive income and did not impact the

Company’s consolidated financial statements.

GOODWILL IMPAIRMENT

Effective January 1, 2012, the Company adopted ASU 2011-08 which is intended to reduce the overall costs and

complexity of goodwill impairment testing. The standard allows an entity the option to first assess qualitative factors

to determine whether it is necessary to perform the current two-step goodwill impairment test. Under this option, an

entity is not required to calculate the fair value of a reporting unit unless the entity determines, based on a qualitative

assessment, it is more likely than not its fair value is less than its carrying amount. Adoption of this standard does not

change the current two-step goodwill impairment test.

FUTURE ACCOUNTING POLICY CHANGES

BALANCE SHEET OFFSETTING

ASU 2011-11 was issued in December 2011 and 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.

ACCUMULATED OTHER COMPREHENSIVE INCOME

ASU 2013-02 was issued in February 2013 and provides enhanced disclosures on amounts reclassified out of AOCI.

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 after December 15, 2012.

9 0 < EN BR IDGE I NC. 2012 FINANCIAL REPO RT

Controls and Procedures

DISCLOSURE CONTROLS AND PROCEDURES

Disclosure controls and procedures are designed to provide reasonable assurance that information required to be

disclosed in reports filed with, or submitted to, securities regulatory authorities is recorded, processed, summarized and

reported within the time periods specified under Canadian and United States securities law. As at December 31, 2012,

an evaluation was carried out under the supervision of and with the participation of Enbridge’s management, including

the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operations of Enbridge’s

disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934). Based on

that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the design and operation of

these disclosure controls and procedures were effective in ensuring that information required to be disclosed by

Enbridge in reports that it files with or submits to the SEC and the Canadian Securities Administrators is recorded,

processed, summarized and reported within the time periods required.

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Management of Enbridge is responsible for establishing and maintaining adequate internal control over financial

reporting as such term is defined in the rules of the SEC and the Canadian Securities Administrators. The Company’s

internal control over financial reporting is a process designed under the supervision and with the participation of

executive and financial officers to provide reasonable assurance regarding the reliability of financial reporting and the

preparation of the Company’s financial statements for external reporting purposes in accordance with U.S. GAAP.

The Company’s internal control over financial reporting includes policies and procedures that:

•

pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect transactions and

dispositions of assets of the Company;

provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial

statements in accordance with generally accepted accounting principles; and

provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or

disposition of the Company’s assets that could have a material effect on the financial statements.

The Company’s internal control over financial reporting may not prevent or detect all misstatements because of

inherent limitations. Additionally, projections of any evaluation of effectiveness to future periods are subject to the risk

that controls may become inadequate because of changes in conditions or deterioration in the degree of compliance

with the Company’s policies and procedures.

Management assessed the effectiveness of the Company’s internal control over financial reporting as at December 31,

2012, based on the framework established in Internal Control – Integrated Framework issued by the Committee of

Sponsoring Organizations of the Treadway Commission. Based on this assessment, Management concluded that the

Company maintained effective internal control over financial reporting as at December 31, 2012.

During the year ended December 31, 2012, there has been no material change in the Company’s internal control over

financial reporting.

The effectiveness of the Company’s internal control over financial reporting as at December 31, 2012 has been audited

by PricewaterhouseCoopers LLP, independent auditors appointed by the shareholders of the Company.

Management’s Discussion and Analysis > 91

Non-GAAP Reconciliations

(millions of Canadian dollars)

Earnings attributable to common shareholders

Adjusting items:

Liquids Pipelines

Canadian Mainline – Line 9 tolling adjustment

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

Canadian Mainline – shipper dispute settlement

Regional Oil Sands System – prior period adjustment

Regional Oil Sands System – asset impairment write-off

Regional Oil Sands System – gain on acquisition

Spearhead Pipeline – changes in unrealized derivative fair value gains

Gas Distribution

EGD – warmer/(colder) than normal weather

EGD – tax rate changes

EGD – recognition of regulatory asset

Other Gas Distribution and Storage – regulatory deferral write-off

Gas Pipelines, Processing and Energy Services

Aux Sable – changes in unrealized derivative fair value (gains)/loss

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

Energy Services – credit recovery

Offshore – asset impairment loss

Offshore – property insurance recovery from hurricanes

Other – changes in unrealized derivative fair value gains

Sponsored Investments

EEP – leak insurance recoveries

EEP – leak remediation costs and lost revenue

EEP – changes in unrealized derivative fair value (gains)/loss

EEP – NGL trucking and marketing investigation costs

EEP – prior period adjustment

EEP – shipper dispute settlement

EEP – lawsuit settlement

EEP – impact of unusual weather conditions

EEP – Lakehead System billing correction

EEP – asset impairment loss

Corporate

Noverco – equity earnings adjustment

Noverco – changes in unrealized derivative fair value loss

Other Corporate – changes in unrealized derivative fair value (gains)/loss

Other Corporate – foreign tax recovery

Other Corporate – unrealized foreign exchange (gains)/loss on translation of

intercompany balances, net

Other Corporate – impact of tax rate changes

Other Corporate – tax on intercompany gain on sale

Adjusted earnings

9 2 < EN BR IDGE I NC. 2012 FINANCIAL REPO RT

2012

610

(6)

(42)

–

(63)

–

(10)

537

–

105

–

(24)

(7)

–

(29)

2011

820

(10)

(14)

–

(1)

–

262

(125)

–

(24)

(50)

(3)

–

(8)

(1)

–

(24)

(6)

1,249

1,100

2010

944

–

(20)

–

(7)

(1)

–

(2)

–

106

–

(1)

–

(25)

–

(40)

–

977

MANAGEMENT’S REPORT

To the Shareholders of Enbridge Inc.

FINANCIAL REPORTING

Management of Enbridge Inc. (the Company) is responsible for the accompanying consolidated financial statements.

The consolidated financial statements have been prepared in accordance with accounting principles generally accepted

in the United States of America and necessarily include amounts that reflect management’s judgment and best estimates.

The Board of Directors and its committees are responsible for all aspects related to governance of the Company. The

Audit, Finance & Risk Committee (AF&RC) of the Board, composed of directors who are unrelated and independent,

has a specific responsibility to oversee management’s efforts to fulfil its responsibilities for financial reporting and

internal controls related thereto. The AF&RC meets with management, internal auditors and independent auditors to

review the consolidated financial statements and the internal controls as they relate to financial reporting. The AF&RC

reports its findings to the Board for its consideration in approving the consolidated financial statements for issuance to

the shareholders.

INTERNAL CONTROL OVER FINANCIAL REPORTING

Management is also responsible for establishing and maintaining adequate internal control over financial reporting.

The Company’s internal control over financial reporting includes policies and procedures to facilitate the preparation of

relevant, reliable and timely information, to prepare consolidated financial statements for external reporting purposes in

accordance with generally accepted accounting principles and provide reasonable assurance that assets are safeguarded.

Management assessed the effectiveness of the Company’s internal control over financial reporting as at December 31,

2012, based on the framework established in Internal Control – Integrated Framework issued by the Committee of

Sponsoring Organizations of the Treadway Commission. Based on this assessment, management concluded that the

Company maintained effective internal control over financial reporting as at December 31, 2012.

PricewaterhouseCoopers LLP, independent auditors appointed by the shareholders of the Company, conducts an

examination of the consolidated financial statements in accordance with Canadian generally accepted auditing

standards and the standards of the Public Company Accounting Oversight Board (United States).

AL MONACO

President & Chief Executive Officer

J. RICHARD BIRD

Executive Vice President &
Chief Financial Officer

February 14, 2013

Management’s Report > 93

INDEPENDENT AUDITOR’S REPORT

To the Shareholders of Enbridge Inc.

We have completed an integrated audit of Enbridge Inc.’s 2012 consolidated financial statements and its internal
control over financial reporting as at December 31, 2012 and audits of its 2011 and 2010 consolidated financial
statements. Our opinions, based on our audits, are presented below.

REPORT ON THE CONSOLIDATED FINANCIAL STATEMENTS

We have audited the accompanying consolidated financial statements of Enbridge Inc., which comprise the consolidated
statements of financial position as at December 31, 2012 and December 31, 2011 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, 2012, 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 also 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 company’s preparation and fair
presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the
circumstances. 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 on the consolidated financial statements.

OPINION

In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of
Enbridge Inc. as at December 31, 2012 and December 31, 2011 and results of its operations and its cash flows for each
of the three years in the period ended December 31, 2012 in accordance with accounting principles generally accepted
in the United States of America.

REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

We have also audited Enbridge Inc.’s internal control over financial reporting as at December 31, 2012, based on
criteria established in Internal Control – Integrated Framework, issued by the Committee of Sponsoring Organizations
of the Treadway Commission (COSO).

9 4 < EN BR IDGE I NC. 2012 FINANCIAL REPO RT

MANAGEMENT’S RESPONSIBILITY FOR INTERNAL CONTROL OVER FINANCIAL REPORTING

Management is responsible for maintaining effective internal control over financial reporting and for its assessment of
the effectiveness of internal control over financial reporting included in the accompanying management’s report on
internal control over financial reporting.

AUDITOR’S RESPONSIBILITY

Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our
audit. We conducted our audit of internal control over financial reporting in accordance with 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 effective internal control over financial reporting was
maintained in all material respects.

An audit of internal control over financial reporting includes obtaining an understanding of internal control over
financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating
effectiveness of internal control, based on the assessed risk, and performing such other procedures as we consider
necessary in the circumstances.

We believe that our audit provides a reasonable basis for our audit opinion on the company’s internal control over
financial reporting.

DEFINITION OF INTERNAL CONTROL OVER FINANCIAL REPORTING

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding
the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with
generally accepted accounting principles. A company’s internal control over financial reporting includes those policies
and procedures that: (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect
the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are
recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting
principles, and that receipts and expenditures of the company are being made only in accordance with authorizations
of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect
on the financial statements.

INHERENT LIMITATIONS

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate
because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.

OPINION

In our opinion, Enbridge Inc. maintained, in all material respects, effective internal control over financial reporting as
at December 31, 2012, based on criteria established in Internal Control – Integrated Framework issued by COSO.

Chartered Accountants

Calgary, Alberta, Canada

February 14, 2013

Independent Auditor’s Report > 95

CONSOLIDATED STATEMENTS OF EARNINGS

Year ended December 31,

(millions of Canadian dollars, except per share amounts)

Revenues

Commodity sales

Gas distribution sales

Transportation and other services

Expenses

Commodity costs

Gas distribution costs

Operating and administrative

Depreciation and amortization

Environmental costs, net of recoveries (Note 28)

Income from equity investments (Note 11)

Other income (Note 25)

Interest expense (Note 16)

Income taxes (Note 23)

Earnings before extraordinary loss

Extraordinary loss, net of tax (Note 5)

Earnings

(Earnings)/loss attributable to noncontrolling interests

and redeemable noncontrolling interests

Earnings attributable to Enbridge Inc.

Preference share dividends

Earnings attributable to Enbridge Inc. common shareholders

Earnings before extraordinary loss

Extraordinary loss, net of tax (Note 5)

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

Earnings before extraordinary loss

Extraordinary loss, net of tax

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

Earnings before extraordinary loss

Extraordinary loss, net of tax

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

2012

2011

2010

19,101

1,910

4,295

25,306

20,611

1,906

4,536

27,053

15,863

1,814

3,843

21,520

18,566

19,864

15,276

1,220

2,890

1,206

(88)

23,794

1,512

160

240

(841)

1,071

(128)

943

–

943

(228)

715

(105)

610

–

610

0.79

–

0.79

0.78

–

0.78

1,281

2,281

1,112

(116)

24,422

2,631

210

117

(928)

2,030

(526)

1,504

(262)

1,242

(409)

833

(13)

820

1,082

(262)

820

1.44

(0.35)

1.09

1.42

(0.34)

1.08

1,249

2,032

1,017

619

20,193

1,327

228

318

(865)

1,008

(227)

781

–

781

170

951

(7)

944

–

944

1.27

–

1.27

1.26

–

1.26

9 6 < EN BR IDGE I NC. 2012 FINANCIAL REPO RT

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Year ended December 31,

(millions of Canadian dollars)

Earnings

Other comprehensive income/(loss), net of tax

Change in unrealized loss on cash flow hedges

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

Other comprehensive income/(loss) from equity investees

Reclassification to earnings of realized cash flow hedges

Reclassification to earnings of unrealized cash flow hedges (Note 22)

Reclassification to earnings of pension plans and other postretirement

benefits amortization amounts

Actuarial loss on pension plans and other postretirement benefits

Change in foreign currency translation adjustment

Other comprehensive loss

Comprehensive income

Comprehensive (income)/loss attributable to noncontrolling interests

and redeemable noncontrolling interests

Comprehensive income attributable to Enbridge Inc.

Preference share dividends

Comprehensive income attributable to Enbridge Inc. common shareholders

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

2012

943

(176)

(56)

(159)

(331)

612

(164)

448

(105)

343

2011

1,242

(582)

(19)

(17)

(165)

151

(585)

657

(329)

328

(13)

315

2010

781

(156)

(15)

(3)

(54)

(376)

(533)

248

331

579

(7)

572

Consolidated FInancial Statements > 97

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

Year ended December 31,

(millions of Canadian dollars, except per share amounts)
Preference shares (Note 19)

Balance at beginning of year
Preference shares issued

Balance at end of year
Common shares (Note 19)

Balance at beginning of year
Common shares issued
Dividend reinvestment and share purchase plan
Shares issued on exercise of stock options

Balance at end of year
Additional paid-in capital

Balance at beginning of year
Stock-based compensation
Options exercised
Issuance of treasury stock (Note 11)
Dilution gains and other

Balance at end of year
Retained earnings

Balance at beginning of year
Earnings attributable to Enbridge Inc.
Preference share dividends
Common share dividends declared
Dividends paid to reciprocal shareholder
Redemption value adjustment attributable to redeemable noncontrolling interests (Note 18)

Balance at end of year
Accumulated other comprehensive loss (Note 21)

Balance at beginning of year
Other comprehensive loss attributable to Enbridge Inc. common shareholders

Balance at end of year
Reciprocal shareholding (Note 11)
Balance at beginning of year
Issuance of treasury stock
Acquisition of equity investment

Balance at end of year
Total Enbridge Inc. shareholders’ equity
Noncontrolling interests (Note 18)
Balance at beginning of year
Earnings/(loss) attributable to noncontrolling interests
Other comprehensive income/(loss) attributable to noncontrolling interests, net of tax

Change in unrealized loss on cash flow hedges
Change in foreign currency translation adjustment
Reclassification to earnings/(loss) of realized cash flow hedges
Reclassification to earnings/(loss) of unrealized cash flow hedges

Comprehensive income/(loss) attributable to noncontrolling interests
Distributions (Note 18)
Contributions (Note 18)
Dilution gains
Acquisitions (Note 6)
Other

Balance at end of year

Total equity

Dividends paid per common share

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

2012

2011

2010

1,056
2,651
3,707

3,969
388
297
78
4,732

242
26
(17)
236
35
522

3,926
715
(105)
(895)
20
(197)
3,464

(1,532)
(267)
(1,799)

(187)
61
–
(126)
10,500

3,141
241

(39)
(60)
23
13
(63)
178
(421)
382
6
(25)
(3)
3,258
13,758

1.13

125
931
1,056

3,683
–
229
57
3,969

131
18
(7)
–
100
242

3,993
833
(13)
(759)
25
(153)
3,926

(1,027)
(505)
(1,532)

(154)
–
(33)
(187)
7,474

2,424
416

(84)
66
(63)
4
(77)
339
(355)
735
22
(27)
3
3,141

10,615

0.98

125
–
125

3,379
–
224
80
3,683

90
13
(8)
–
36
131

3,828
951
(7)
(648)
19
(150)
3,993

(654)
(373)
(1,027)

(154)
–
–
(154)
6,751

2,740
(182)

(12)
(121)
(13)
(2)
(148)
(330)
(318)
358
15
(41)
–
2,424

9,175

0.85

9 8 < EN BR IDGE I NC. 2012 FINANCIAL REPO RT

CONSOLIDATED STATEMENTS OF CASH FLOWS

Year ended December 31,

(millions of Canadian dollars)
Operating activities

Earnings

Depreciation and amortization

Deferred income taxes (recovery)/expense (Note 23)

Changes in unrealized (gains)/loss on derivative instruments, net

Cash distributions in excess of equity earnings

Regulatory asset write-off (Note 5)

Gain on acquisition (Note 6)

Asset impairment (Note 9)

Allowance for equity funds used during construction

Other

Changes in regulatory assets and liabilities

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

Changes in operating assets and liabilities (Note 26)

Investing activities

Additions to property, plant and equipment

Long-term investments

Additions to intangible assets

Acquisitions, net of cash acquired (Note 6)

Affiliate loans, net

Proceeds on sale of investments and net assets

Government grant

Changes in restricted cash

Changes in construction payable

Financing activities

Net change in bank indebtedness and short-term borrowings

Net change in commercial paper and credit facility draws

Net change in Southern Lights project financing

Debenture and term note issues

Debenture and term note repayments

Repayment of acquired debt

Contributions from noncontrolling interests

Distributions to noncontrolling interests

Contributions from redeemable noncontrolling interests

Distributions to redeemable noncontrolling interests

Preference shares issued

Common shares issued

Preference share dividends

Common share dividends

Effect of translation of foreign denominated cash and cash equivalents

Increase/(decrease) in cash and cash equivalents

Cash and cash equivalents at beginning of year

Cash and cash equivalents at end of year
Supplementary cash flow information

Income taxes (received)/paid

Interest paid

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

2012

2011

2010

943

1,206

(40)

665

474

–

166

(1)

110

(26)

(660)

2,874

(5,468)

(531)

(163)

(340)

–

(2)

274

1,242

1,112

368

(73)

125

262

–

(3)

(118)

403

3,371

(3,508)

(1,515)

(154)

(33)

–

145

(2)

(19)

781

1,017

203

–

102

–

(22)

(96)

267

(424)

1,877

(3,053)

(35)

(56)

(850)

–

(5)

(6,204)

(5,079)

(3,902)

412

(294)

(13)

2,199

(349)

(160)

448

(421)

213

(49)

2,634

465

(93)

(597)

4,395

(12)

1,053

723

1,776

267

988

224

(630)

(62)

1,604

(234)

–

873

(355)

210

(35)

926

(7)

(530)

2,030

347

376

723

(28)

955

(165)

(212)

3,220

(631)

–

439

(318)

–

(23)

–

(7)

(426)

1,957

(12)

(80)

456

376

115

871

Consolidated FInancial Statements > 99

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

December 31,

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

Assets
Current assets

Cash and cash equivalents

Restricted cash

Accounts receivable and other (Note 7)

Accounts receivable from affiliates

Inventory (Note 8)

Property, plant and equipment, net (Note 9)

Long-term investments (Note 11)

Deferred amounts and other assets (Note 12)

Intangible assets, net (Note 13)

Goodwill (Note 14)

Deferred income taxes (Note 23)

Liabilities and equity
Current liabilities

Bank indebtedness

Short-term borrowings (Note 16)

Accounts payable and other (Note 15)

Accounts payable to affiliates

Interest payable

Environmental liabilities (Note 28)

Current maturities of long-term debt (Note 16)

Long-term debt (Note 16)

Other long-term liabilities (Note 17)

Deferred income taxes (Note 23)

Commitments and contingencies (Note 28)

Redeemable noncontrolling interests (Note 18)

Equity

Share capital (Note 19)

Preference shares

Common shares (805 and 781 outstanding at December 31, 2012 and 2011, respectively)

Additional paid-in capital

Retained earnings

Accumulated other comprehensive loss (Note 21)

Reciprocal shareholding (Note 11)

Total Enbridge Inc. shareholders’ equity

Noncontrolling interests (Note 18)

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

Approved by the Board of Directors:

DAVID A. ARLEDGE, Chair

DAVID A. LESLIE, Director

1 00 < EN BR IDGE I NC. 2012 FINANCIAL REPO RT

2012

2011

1,776

4,014

779

6,600

33,318

3,386

2,622

817

419

723

4,029

823

5,647

29,074

3,081

2,500

711

440

47,172

41,494

479

583

5,052

–

196

107

652

7,069

20,203

2,541

2,601

32,414

102

548

4,753

185

175

354

6,165

19,251

2,208

2,615

30,239

1,000

640

3,707

4,732

522

3,464

(1,799)

(126)

10,500

3,258
13,758

47,172

1,056

3,969

242

3,926

(1,532)

(187)

7,474

3,141
10,615

41,494

NOTES TO THE 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 business 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, Seaway Pipeline, Spearhead Pipeline, Feeder Pipelines and Other.

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 and

gathering facilities and the Company’s energy services businesses, along with renewable energy projects.

Investments in natural gas pipelines include the Company’s interests in the United States portion of the Alliance System

(Alliance Pipeline US), the Vector Pipeline (Vector) 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 located at the terminus of the Alliance System. The energy services businesses undertake physical

commodity marketing activity and manage the Company’s volume commitments on the Alliance System, the Vector

Pipeline and other pipeline systems.

SPONSORED INVESTMENTS

Sponsored Investments includes the Company’s 21.8% (2011 – 23.0%) ownership interest in Enbridge Energy Partners,

L.P. (EEP), Enbridge’s 66.7% (2011 – 66.7%) investment in the United States segment of the Alberta Clipper Project

through EEP and Enbridge Energy, Limited Partnership and an overall 67.7% (2011 – 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 NGL. The primary operations of the Fund include renewable power

generation projects, crude oil and liquids pipeline and storage businesses in Western Canada and a 50% interest in

the Canadian portion of the Alliance System (Alliance Pipeline Canada).

CORPORATE

Corporate consists of the Company’s investment in Noverco Inc. (Noverco), new business development activities,

general corporate investments and financing costs not allocated to the business segments.

Notes to the Consolidated Financial Statements > 101

2. Summary of Significant Accounting Policies

These consolidated financial statements are prepared in accordance with accounting principles generally accepted

in the United States of America (U.S. GAAP). Amounts are stated in Canadian dollars unless otherwise noted.

The Company commenced reporting using U.S. GAAP as its primary basis of accounting effective January 1, 2012,

including restatement of comparative periods. As a Securities and Exchange Commission registrant, the Company

is permitted to use U.S. GAAP for purposes of meeting both its Canadian and United States continuous disclosure

requirements.

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

the 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 stock-based compensation (Note 20); fair value of financial instruments (Note 22); provisions

for income taxes (Note 23); assumptions used to measure retirement and other postretirement benefit obligations (OPEB)

(Note 24); commitments and contingencies (Note 28); fair value of asset retirement obligations (ARO); and estimates of losses

related to environmental remediation obligations (Note 28). 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.

1 02 < EN BR IDGE I NC. 2012 FINANCIAL REPO RT

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 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, the amount of revenue can be reliably measured and collectability is reasonably assured. 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 rate-regulated businesses, revenues are recognized in a manner that is consistent with the underlying agreements

as approved by the regulators. From July 1, 2011 onward, 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 on that date, the Company prospectively discontinued the application of rate-regulated accounting for those

assets 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. Estimates are based on historical consumption patterns and heating degree days experienced. Heating degree

days is a measure of coldness that is indicative of volumetric requirements for natural gas utilized for heating purposes

in the Company’s distribution franchise area.

For natural gas and marketing businesses, an estimate of revenues and commodity costs for the month of December is

included in the Consolidated Statements of Earnings for each year based on the best available volume and price data for

the commodity delivered and received.

Notes to the Consolidated Financial Statements > 103

DERIVATIVE INSTRUMENTS AND HEDGING

NON-QUALIFYING DERIVATIVES

Non-qualifying derivative instruments are used primarily to economically hedge foreign exchange, interest rate 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 revenues, 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 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/(loss) (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, 2012 or 2011.

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.

1 04 < EN BR IDGE I NC. 2012 FINANCIAL REPO RT

CLASSIFICATION OF DERIVATIVES

The Company recognizes the fair market value of derivative instruments on the Consolidated Statements 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.

Cash inflows and outflows related to derivative instruments are classified as Operating activities on the Consolidated

Statements of Cash Flows.

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.

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. To the extent an equity investee

undertakes activities necessary to commence its planned principal operations, the Company capitalizes interest costs

associated with its investment during such period.

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. Any investments which do trade on an active market

are measured at fair value through OCI. 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 equity in 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 the Fund trust units for cash, subject to certain

limitations. Redeemable noncontrolling interests are 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.

Notes to the Consolidated Financial Statements > 105

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

along 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. 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 of AOCI and are recognized in

earnings upon sale 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 comprised of natural gas in storage held in EGD and crude oil and natural gas held primarily by energy

services businesses. Natural gas in storage in EGD 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, other commodities inventory is recorded

to Commodity costs in the Consolidated Statements of Earnings at the weighted average cost of inventory, including

any adjustments recorded to reduce inventory to market value.

1 06 < EN BR IDGE I NC. 2012 FINANCIAL REPO RT

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.

For non rate-regulated assets depreciation is provided on a straight-line basis over the estimated useful lives of the

assets commencing when the asset is placed in service.

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; and deferred financing costs. Deferred financing costs

are amortized using the effective interest method over the term of the related debt.

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. The Company has the option to first assess qualitative factors to determine whether it is necessary to perform

the two-step goodwill impairment test. If the two-step goodwill impairment test is performed, 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.

Notes to the Consolidated Financial Statements > 107

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

ARO 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. ARO 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 ARO 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 estimate of future salary levels,

other cost escalations, retirement ages of employees and other actuarial factors including discount rates. The Company

determines discount rates by reference to rates of high-quality long-term corporate bonds with maturities that approximate

the timing of future payments the Company anticipates making under each of the respective plans. During the year

ended December 31, 2012, the Company refined the methodology by which it determines discount rates, in particular,

refining the method by which it estimates spreads for bonds with longer term maturities. 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, changes in headcount 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 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.

1 08 < EN BR IDGE I NC. 2012 FINANCIAL REPO RT

The overfunded or underfunded status of defined benefit pension and OPEB plans is 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 projected 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 utility operations of the Company expect to recover pension expense in future rates and therefore

record a corresponding regulatory asset to the extent such recovery is deemed to be probable. For years prior to 2012

an offsetting regulatory asset related to OPEB obligations was not recorded given recovery in rates was not probable.

Commencing in 2012, pursuant to a specific rate order allowing for recovery in rates of OPEB costs determined on an

accrual basis, an offsetting OPEB regulatory asset was recognized. In the absence of rate regulation, regulatory balances

would not be recorded and pension and OPEB costs would be charged to earnings on an accrual basis.

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 of the ISOs granted 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 of the PBSOs granted as calculated by

the Bloomberg barrier option valuation model and is recognized over the vesting period with a corresponding

credit to Additional paid-in capital. The options become exercisable when both 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 by preventing or eliminating

future contamination. 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. There is always a potential of incurring additional costs in connection with

environmental liabilities due to variations in any or all of the categories described above, including modified or revised

requirements from regulatory agencies, in addition to fines and penalties, as well as expenditures associated with

litigation and settlement of claims. 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.

Notes to the Consolidated Financial Statements > 109

Liabilities for other commitments and contingencies are recognized when, after fully analyzing available information, the

Company determines 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

FAIR VALUE MEASUREMENT

Effective January 1, 2012, the Company adopted Accounting Standards Update (ASU) 2011-04, which revised the

existing guidance on the disclosure of fair value measurements. Under the revised standard, the Company is required to

provide additional disclosures about fair value measurements, including a description of the valuation methodologies

used and information about the unobservable inputs and assumptions used in Level 3 fair value measurements, as well

as the level in the fair value hierarchy of items that are not measured at fair value but whose fair value disclosure is

required. As the adoption of this update impacted disclosure only, there was no impact to the Company’s earnings

or cash flows for the current or prior periods presented.

STATEMENT OF COMPREHENSIVE INCOME

Effective January 1, 2012, the Company adopted ASU 2011-05, which updates the existing guidance on comprehensive

income, 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 did not affect the Company’s presentation of comprehensive income and did not impact the

Company’s consolidated financial statements.

GOODWILL IMPAIRMENT

Effective January 1, 2012, the Company adopted ASU 2011-08 which is intended to reduce the overall costs and

complexity of goodwill impairment testing. The standard allows an entity the option to first assess qualitative factors

to determine whether it is necessary to perform the current two-step goodwill impairment test. Under this option, an

entity is not required to calculate the fair value of a reporting unit unless the entity determines, based on a qualitative

assessment, it is more likely than not its fair value is less than its carrying amount. Adoption of this standard does not

change the current two-step goodwill impairment test.

FUTURE ACCOUNTING POLICY CHANGES

BALANCE SHEET OFFSETTING

ASU 2011-11 was issued in December 2011 and 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.

ACCUMULATED OTHER COMPREHENSIVE INCOME

ASU 2013-02 was issued in February 2013 and provides enhanced disclosures on amounts reclassified out of AOCI.

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 after December 15, 2012.

11 0 < EN BR IDGE I NC. 2012 FINANCIAL REPO RT

4. Segmented Information

Year ended December 31, 2012

(millions of Canadian dollars)

Revenues

Commodity and gas distribution costs

Operating and administrative

Depreciation and amortization

Environmental costs, net of recoveries

Income/(loss) from equity investments

Other income/(expense)

Interest income/(expense)

Income taxes recovery/(expense)

Earnings/(loss)

Earnings attributable to noncontrolling interests and

redeemable noncontrolling interests

Preference share dividends

Earnings/(loss) attributable to Enbridge Inc.

common shareholders

Additions to property, plant and equipment 3

Total assets

Year ended December 31, 2011

(millions of Canadian dollars)

Revenues

Commodity and gas distribution costs

Operating and administrative

Depreciation and amortization

Environmental costs, net of recoveries

Income/(loss) from equity investments

Other income/(expense)

Interest expense

Income taxes recovery/(expense)

Earnings/(loss) before extraordinary loss

Extraordinary loss, net of tax

Earnings/(loss)

Earnings attributable to noncontrolling interests and

redeemable noncontrolling interests

Preference share dividends

Earnings/(loss) attributable to Enbridge Inc.

common shareholders

Additions to property, plant and equipment 3

Total assets

Liquids
Pipelines 1

Gas
Distribution

2,452

–

(943)

(363)

–

1,146

(7)

(250)

(205)

730

(4)

–

726

2,092

15,252

2,438

(1,220)

(528)

(336)

–

354

–

(164)

(66)

207

–

207

438

7,416

Gas Pipelines,
Processing
and Energy
Services 1

13,745

(14,283)

(289)

(62)

–

(889)

108

(51)

325

(477)

(1)

–

(478)

837

5,119

Sponsored Investments

Deferred income taxes 3

2012

2011

605

155

201

(882)

212

527

170

(836)

108

The asset represents the regulatory offset to deferred income tax liabilities that are expected to be recovered under flow-through income tax treatment. The recovery period
depends on future temporary differences.
Deferred transportation revenues are 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.
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.
The future removal and site restoration reserves balance results from amounts collected from customers by certain 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.
The pension plans and OPEB balances represent the regulatory offset to pension plan and OPEB obligations to the extent the amounts are expected to be collected from
customers in future rates. An OPEB balance of $89 million is expected to be collected on a straight-line basis over a 20-year period commencing in 2013, whereas the
settlement period for the pension regulatory asset is not determinable.

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, 2012,

cumulative costs relating to this consulting contract of $144 million (2011 – $133 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.

11 4 < EN BR IDGE I NC. 2012 FINANCIAL REPO RT

6. Acquisitions

ACQUISITIONS

SILVER STATE NORTH SOLAR PROJECT

On March 22, 2012, Enbridge acquired a 100% interest in the Silver State North Solar Project (Silver State), a solar

farm located in Nevada for cash consideration of $195 million (US$190 million). Silver State expands the Company’s

renewable energy business. Revenues and earnings of $10 million and $1 million, respectively, were recognized in

the year ended December 31, 2012. No revenues or earnings were recognized in any prior period as the solar project

commenced operations in the second quarter of 2012. Silver State is included within the Gas Pipelines, Processing

and Energy Services segment.

March 22,

(millions of Canadian dollars)

Fair value of net assets acquired:

Accounts receivable and other 1

Property, plant and equipment

Purchase price:

Cash

2012

141

195

The Company acquired the right to apply for a $54 million (US$55 million) United States Treasury grant under a program which reimburses eligible applicants for a portion of
costs related to installing specified renewable energy property. The grant, which was applied for subsequent to commercial operations, was received in October 2012.

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. Tonbridge is included within the Corporate segment.

October 13,

(millions of Canadian dollars)

Fair value of net assets acquired:

Working capital deficiency

Property, plant and equipment

Intangible assets

Long-term debt

Other long-term liabilities

Purchase price:

Cash (net of $15 million cash acquired)

2011

(5)

196

(182)

(21)

No revenues from Tonbridge were recognized in 2011 as the transmission line was not in service. A net loss of $1 million

was recognized in earnings for the period from October 13, 2011 to December 31, 2011 related to operating and

administrative expense. An unaudited proforma net loss of $38 million, including $6 million of transaction costs, would

have been recognized in earnings in 2011 had the acquisition occurred on January 1, 2011.

Notes to the Consolidated Financial Statements > 115

ELK CITY NATURAL GAS GATHERING AND PROCESSING SYSTEM

On September 16, 2010, EEP 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,

(millions of Canadian dollars)

Fair value of net assets acquired:

Current assets

Property, plant and equipment
Intangible assets 1

Other assets

Other long-term liabilities

Purchase price:

Cash

2010

503

194

(1)

705

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 November 2012, Enbridge acquired certain sour gas gathering and compression facilities for a purchase price of

$118 million. These facilities, which are currently in service or under construction, are located in the Peace River Arch

region of northwest Alberta and are presented within the Gas Pipelines, Processing and Energy Services segment. As

at December 31, 2012, the allocation of consideration paid to the assets was not complete as the Company had not yet

concluded its valuation.

In May 2012, Enbridge acquired the remaining 10% interest in the Greenwich Wind Energy Project (Greenwich)

through Greenwich Windfarm, LP, for cash consideration of $27 million, increasing its ownership interest to 100%.

The Company’s interest in Greenwich was consolidated and presented within the Gas Pipelines, Processing and Energy
Services segment until such time as it was transferred to the Fund in December 2012 (Note 18).

In October 2011, the Company acquired the remaining 10% interest in Talbot Windfarm, LP (Talbot) for $28 million,

increasing its ownership interest to 100%. The Company’s interest in Talbot was consolidated and presented within the

Gas Pipelines, Processing and Energy Services segment until such time as it was transferred to the Fund in October 2011.

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 controlled the entity,

it consolidated its interest in Olympic. Prior to August 2010, the entity was accounted for as a joint venture using the

equity method.

11 6 < EN BR IDGE I NC. 2012 FINANCIAL REPO RT

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 interests 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, 2010.

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.

Unaudited proforma consolidated revenues and earnings that give effect to all of the Company’s other 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.

7. Accounts Receivable and Other

December 31,

(millions of Canadian dollars)

Unbilled revenues

Trade receivables

Taxes receivable

Regulatory assets

Short-term portion of derivative assets (Note 22)

Prepaid expenses and deposits

Current deferred income taxes (Note 23)

Dividends receivable

Other

Allowance for doubtful accounts

Inventory

December 31,

(millions of Canadian dollars)

Natural gas

Other commodities

2012

2011

2,289

2,210

677

123

–

383

132

167

266

802

157

486

135

171

(49)

4,014

(58)

4,029

2012

2011

448

331

779

566

257

823

Commodity costs on the Consolidated Statements of Earnings included non-cash charges of $10 million (2011 – $9

million; 2010 – $9 million) for the year ended December 31, 2012 to reduce the cost basis of inventory to market value.

Notes to the Consolidated Financial Statements > 117

9. Property, Plant and Equipment

December 31,

(millions of Canadian dollars)

Liquids Pipelines

Pipeline
Pumping equipment, buildings, tanks and other 1

Land and right-of-way

Under construction

Accumulated depreciation

Gas Distribution

Gas mains, services and other

Land and right-of-way

Under construction

Accumulated depreciation

Gas Pipelines, Processing and Energy Services

Pipeline
Wind turbines, solar panels and other 1

Land and right-of-way

Under construction

Accumulated depreciation

Sponsored Investments

Pipeline
Pumping equipment, buildings, tanks and other 1
Wind turbines, solar panels and other 1

Land and right-of-way

Under construction

Accumulated depreciation

Corporate

Other

Under construction

Accumulated depreciation

Weighted Average
Depreciation Rate

2012

2011

2.6%

3.1%

2.4%

–

4.3%

2.5%

–

4.6%

4.9%

–

3.0%

3.3%

4.0%

2.4%

–

9.4%

–

8,249

5,094

225

1,675

15,243

(3,432)

11,811

7,583

102

7,764

(1,912)

5,852

544

519

1,477

2,546

(350)

2,196

6,890

4,787

1,544

642

2,002

15,865

(2,770)

13,095

105

296

401

(37)

364

7,538

5,017

232

1,111

13,898

(3,170)

10,728

6,846

137

7,062

(1,419)

5,643

568

781

512

1,868

(213)

1,655

6,600

3,792

1,074

611

913

12,990

(2,213)

10,777

230

301

(30)

271

In December 2012, wholly-owned subsidiaries of Enbridge sold two crude oil storage and three renewable energy assets to the Fund. As a result, at December 31, 2012,
$599 million and $338 million of Property, plant and equipment were reclassified from Liquids Pipelines and Gas Pipelines, Processing and Energy Services, respectively,
to Sponsored Investments. The December 31, 2011 balances of $600 million and $354 million, in Liquids Pipelines and Gas Pipelines, Processing and Energy Services,
respectively, have not been reclassified for presentation purposes.

Depreciation expense for the year ended December 31, 2012 was $1,174 million (2011 – $1,089 million;

2010 – $987 million).

33,318

29,074

11 8 < EN BR IDGE I NC. 2012 FINANCIAL REPO RT

GAS PIPELINES, PROCESSING AND ENERGY SERVICES

In December 2012, the Company recorded an impairment charge of $166 million ($105 million after-tax) related

to certain of its Enbridge Offshore Pipelines (Offshore) assets, predominantly located within the Stingray and Garden

Banks corridors in the Gulf of Mexico. The Company had been pursuing alternative uses for these assets; however, due

to changing competitive conditions in the fourth quarter of 2012, the Company concluded that such alternatives were

no longer likely to proceed. In addition, unique to these assets is their significant reliance on natural gas production

from shallow water areas of the Gulf of Mexico which have been challenged by macro-economic factors including

prevalence of onshore shale gas production, hurricane disruptions, additional regulation and the low natural gas

commodity price environment.

The impairment charge was based on the amount by which the carrying values of the assets exceeded fair value,

determined using expected discounted future cash flows, and is presented within Operating and administrative

expense on the Consolidated Statements of Earnings. The charge is inclusive of $50 million related to abandonment

costs now reasonably determined given the expected timing and scope of certain asset retirements.

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 67.7% (2011 – 69.2%; 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 certain assets acquired by the Fund from wholly-owned
subsidiaries of Enbridge from the dates of acquisition of October 2011 and December 2012 (Note 18). Earnings, cash
flows and financial position information exclude the effect of intercompany transactions.

Year ended December 31,

(millions of Canadian dollars)

Revenues

Operating and administrative expense

Depreciation and amortization

Income from equity investments

Interest expense and other

Income taxes

Earnings

(Earnings)/loss attributable to noncontrolling interest

Earnings attributable to Enbridge

Cash flows

Cash provided by operating activities

Cash used in investing activities

Cash provided by financing activities

Increase in cash and cash equivalents

2012

288

(83)

(87)

(68)

(35)

198

(158)

1,495

1,535

2011

146

(66)

(47)

(32)

(21)

140

(98)

381

423

2010

(52)

(19)

(13)

(17)

(11)

(107)

Notes to the Consolidated Financial Statements > 119

December 31,

(millions of Canadian dollars)

Current assets

Property, plant and equipment, net

Long-term investments

Deferred amounts and other assets

Current liabilities

Long-term debt

Other long-term liabilities

Deferred income taxes

Net assets before noncontrolling interests

11. Long-Term Investments

December 31,

(millions of Canadian dollars)

Equity Investments

Joint Ventures

Liquids Pipelines

Chicap Pipeline

Mustang Pipeline

Seaway Pipeline

Gas Pipelines, Processing and Energy Services

Offshore – various joint ventures

Vector

Alliance Pipeline US
Aux Sable 1

Other

Sponsored Investments

Alliance Pipeline Canada

Texas Express Pipeline

Other

Other Equity Investments

Corporate

Noverco Common Shares

Other

Other Long-Term Investments

Corporate

Noverco Preferred Shares

Other

2012

2011

224

2,390

314

179

(250)

(1,864)

(22)

(438)

533

109

1,349

343

125

(90)

(675)

(36)

(403)

722

Ownership Interest

2012

2011

43.8%

30.0%

50.0%

22.0% – 74.3%

60.0%

50.0%

42.7% – 50.0%

33.3% – 70.0%

50.0%

35.0%

50.0%

38.9%

8.9% – 41.0%

1,385

391

142

282

266

277

183

–

246

3,386

1,186

420

160

293

217

296

–

285

3,081

In July 2011, the Company, through its affiliate Aux Sable, acquired a 42.7% interest in the Palermo Conditioning Plant and the Prairie Rose Pipeline for $76 million.

Equity investments include the unamortized excess of the purchase price over the underlying net book value of the

investees’ assets at the purchase date which is comprised of $636 million (2011 – $651 million) in Goodwill and

$493 million (2011 – $450 million) in amortizable assets.

1 20 < EN BR IDGE I NC. 2012 FINANCIAL REPO RT

JOINT VENTURES

Summarized combined financial information of the Company’s interest in unconsolidated equity investments of joint

ventures is as follows:

Year ended December 31,

(millions of Canadian dollars)

Revenues

Commodity costs

Operating and administrative expense

Depreciation and amortization

Other expense

Interest expense

Earnings before income taxes

December 31,

(millions of Canadian dollars)

Current assets

Property, plant and equipment, net

Deferred amounts and other assets

Intangible assets

Goodwill

Current liabilities

Long-term debt

Other long-term liabilities

Net assets

ALLIANCE PIPELINE

2012

2011

2010

921

(236)

(244)

(159)

(81)

205

804

(138)

(200)

(158)

(3)

(87)

218

2012

299

3,192

204

639

(333)

(895)

(161)

3,019

771

(92)

(203)

(158)

(1)

(96)

221

2011

231

2,864

273

651

(230)

(926)

(245)

2,705

Certain assets of Alliance Pipeline Canada are pledged as collateral to Alliance Pipeline Canada lenders and to the

lenders of Alliance Pipeline US. As well, certain assets of Alliance Pipeline US are pledged as collateral to Alliance

Pipeline US lenders and to the lenders of Alliance Pipeline Canada.

OTHER EQUITY INVESTMENTS

NOVERCO

At December 31, 2012, Enbridge owned an equity interest in Noverco through ownership of 38.9% (2011 – 38.9%;

2010 – 32.1%) of its common shares and an investment in preferred shares. The preferred shares are entitled to a

cumulative preferred dividend based on the average yield of Government of Canada bonds maturing in 10 years plus

a range of 4.3% to 4.4%.

At December 31, 2011, Noverco owned an approximate 8.9% reciprocal shareholding in the Common Shares of the

Company. During the year ended December 31, 2012, Noverco sold 22.5 million Enbridge Common Shares through

a secondary offering, thereby reducing the Company’s reciprocal shareholding to 6.0%. Both the Company’s equity

investment in Noverco and Equity increased by $297 million, net of tax, as a result of this transaction. The Company’s

share of the proceeds of approximately $317 million was received as a dividend from Noverco in May 2012.

As a result of Noverco’s 6.0% (2011 – 8.9%; 2010 – 9.0%) reciprocal shareholding in Enbridge shares, the Company

has an indirect pro-rata interest of 2.1% (2011 – 3.5%) in its own shares. Both the equity investment in Noverco and

shareholders’ equity have been reduced by the reciprocal shareholding of $126 million at December 31, 2012 (2011 –

$187 million; 2010 – $154 million). Noverco records dividends paid by the Company as dividend income and the

Company eliminates these dividends from its equity earnings of Noverco. The Company records its pro-rata share of

dividends paid by the Company to Noverco as a reduction of dividends paid and an increase in the Company’s

investment in Noverco.

Notes to the Consolidated Financial Statements > 121

12. Deferred Amounts and Other Assets

December 31,

(millions of Canadian dollars)

Regulatory assets

Long-term portion of derivative assets (Note 22)

Affiliate long-term note receivable (Note 27)

Contractual receivables

Deferred financing costs

Other

2012

2011

1,284

1,000

408

182

303

127

318

562

194

288

132

324

2,622

2,500

At December 31, 2012, deferred amounts of $265 million (2011 – $255 million) were subject to amortization and are

presented net of accumulated amortization of $123 million (2011 – $106 million). Amortization expense for the year

ended December 31, 2012 was $25 million (2011 – $20 million; 2010 – $20 million).

13. Intangible Assets

December 31, 2012

(millions of Canadian dollars)

Software

Natural gas supply opportunities

Power purchase agreements

Transportation agreements

Other

December 31, 2011

(millions of Canadian dollars)

Software

Natural gas supply opportunities

Power purchase agreements

Transportation agreements

Other

Weighted Average
Amortization Rate

11.9%

3.8%

4.7%

2.9%

5.6%

Weighted Average
Amortization Rate

12.7%

3.6%

4.6%

2.9%

6.0%

Cost

622

291

1,068

Cost

471

296

925

Accumulated
Amortization

180

251

Accumulated
Amortization

155

214

Net

442

241

817

Net

316

257

711

Total amortization expense for intangible assets was $64 million (2011 – $58 million; 2010 – $52 million) for

the year ended December 31, 2012. The Company expects aggregate amortization expense for the years ending

December 31, 2013 through 2017 of $67 million, $61 million, $55 million, $49 million and $44 million, respectively.

1 22 < EN BR IDGE I NC. 2012 FINANCIAL REPO RT

14. Goodwill

(millions of Canadian dollars)

Balance at January 1, 2011

Foreign exchange and other

Balance at December 31, 2011

Transfer of assets to the Fund

Foreign exchange and other

Balance at December 31, 2012

Liquids
Pipelines

Gas
Distribution

Gas Pipelines,
Processing and
Energy Services

Sponsored Investments

Junior subordinated notes 3

Medium-term notes
Senior notes 4
Commercial paper and credit facility draws 5

Corporate

United States dollar term notes 6

Medium-term notes
Commercial paper and credit facility draws 7

Other 8

Total debt

Current maturities
Short-term borrowings 9

Long-term debt

Weighted Average
Interest Rate

Maturity

2012

2011

8.2%

4.9%

2.7%

2024

2015 – 2112

2014

9.9%

5.5%

2024

2014 – 2050

8.1%

3.8%

6.2%

2067

2013 – 2023

2013 – 2040

5.5%

4.5%

2014 – 2017

2013 – 2042

200

2,435

1,413

2,295

590

398

1,615

4,129

1,405

1,094

4,268

1,488

(14)

21,438

(652)

(583)

20,203

200

2,435

1,449

2,295

556

406

415

4,322

540

1,119

3,518

2,785

(11)

20,153

(354)

(548)

19,251

2012 – $357 million and US$1,061 million (2011 – $360 million and US$1,071 million).
Primarily capital lease obligations.
2012 – US$400 million (2011 – US$400 million).
2012 – US$4,150 million (2011 – US$4,250 million).
2012 – $250 million and US$1,160 million (2011 – $260 million and US$275 million).
2012 – US$1,100 million (2011 – US$1,100 million).
2012 – $1,140 million and US$350 million (2011 – $1,655 million and US$1,111 million).
Primarily debt discount.

1
2
3
4
5
6
7
8
9 Weighted average interest rate – 1.1% (2011 – 1.1%).

For the years ending December 31, 2013 through 2017, debenture and term note maturities are $649 million,

$1,287 million, $908 million, $998 million, $1,321 million, respectively, and $11,356 million thereafter. The

Company’s debentures and term notes bear interest at fixed rates and interest obligations for the years ending

December 31, 2013 through 2017 are $997 million, $976 million, $926 million, $901 million and $826 million,

respectively. At December 31, 2012 and 2011, all debt is unsecured except for the Southern Lights project financing

which is collateralized by the Southern Lights project assets.

1 24 < EN BR IDGE I NC. 2012 FINANCIAL REPO RT

INTEREST EXPENSE
Year ended December 31,

(millions of Canadian dollars)

Debentures and term notes

Commercial paper and credit facility draws

Southern Lights project financing

Capitalized

CREDIT FACILITIES

December 31, 2012

(millions of Canadian dollars)

Liquids Pipelines

Gas Distribution

Sponsored Investments

Corporate

Southern Lights project financing 3

Total credit facilities

2012

2011

2010

986

(216)

841

891

(75)

928

835

(73)

865

Maturity Dates 1

Total Facilities

Draws 2

Available

2014

2014 – 2017

2014

300

712

3,162

9,108

13,282

1,484

14,766

590

1,645

1,520

3,780

1,429

5,209

275

122

1,517

7,588

9,502

9,557

1
2
3

Total facilities include $35 million in demand facilities with no maturity date.
Includes credit facility draws, letters of credit and commercial paper issuances that are back-stopped by the credit facility.
Total facilities inclusive of $60 million for debt service reserve letters of credit.

Credit facilities carry a weighted average standby fee of 0.2% per annum on the unused portion and draws bear interest

at market rates. Certain credit facilities serve as a back-stop to the commercial paper programs and the Company has

the option to extend the facilities, which are currently set to mature from 2014 to 2017.

Commercial paper and credit facility draws, net of short-term borrowings, of $2,925 million (2011 – $3,359 million) are

supported by the availability of long-term committed credit facilities and therefore have been classified as long-term debt.

17. Other Long-Term Liabilities

December 31,

(millions of Canadian dollars)

Future removal and site restoration liabilities (Note 5)

Derivative liabilities (Note 22)

Pension and OPEB liabilities (Note 24)

Other

2012

2011

882

763

573

323

836

557

515

300

2,541

2,208

Notes to the Consolidated Financial Statements > 125

18. Noncontrolling Interests

December 31,

(millions of Canadian dollars)

EEP

Enbridge Energy Management, L.L.C. (EEM)

EGD preferred shares

Greenwich (Note 6)

Other

2012

2011

2,636

2,528

498

100

–

464

100

3,258

3,141

Noncontrolling interests in EEP represent the 78.2% interest in EEP not owned by the Company. During the year

ended December 31, 2012, EEP completed a listed share issuance, in which the Company did not participate, resulting

in an increase in the noncontrolling interests from 77.0% to 78.2%. The listed share issuance during the year ended

December 31, 2012 resulted in contributions of $382 million (2011 – $695 million; 2010 – $330 million) from

noncontrolling interest holders. During the year ended December 31, 2012, EEP also distributed $419 million

(2011 – $353 million; 2010 – $311 million) to its noncontrolling interest holders in line with EEP’s objective to

make quarterly distributions in an amount equal to its available cash, as defined in its partnership agreement and

as approved by EEP’s Board of Directors.

Noncontrolling interests in EEM represent the 83.2% of the listed shares of EEM not held by the Company. A listed

share issuance during the year ended December 31, 2011 resulted in contributions of $26 million from noncontrolling

interest holders.

The Company owns 100% of the outstanding common shares of EGD; however, the four million Cumulative

Redeemable EGD Preferred Shares held by third parties are entitled to a claim on the assets of EGD prior to the

common shareholder. The preferred shares have no fixed maturity date and have floating adjustable cash dividends

that are payable at 80% of the prime rate. EGD may, at its option, redeem all or a portion of the outstanding shares

for $25 per share plus all accrued and unpaid dividends to the redemption date. As at December 31, 2012, no

preferred shares have been redeemed.

REDEEMABLE NONCONTROLLING INTERESTS
Year ended December 31,

(millions of Canadian dollars)

Balance at beginning of year

Earnings/(loss)

Other comprehensive loss

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

Comprehensive loss

Distributions to unitholders

Contributions from unitholders

Redemption value adjustment

Balance at end of year

2012

2011

640

(13)

(1)

(14)

(49)

226

197

1,000

362

(7)

(3)

(10)

(33)

168

153

640

2010

236

(13)

(1)

(23)

–

150

362

Redeemable noncontrolling interests in the Fund at December 31, 2012 represented 67.7% (2011 – 64.6%; 2010 –

58.2%) of interests in the Fund’s trust units that are held by third parties.

1 26 < EN BR IDGE I NC. 2012 FINANCIAL REPO RT

In December 2012, the Fund acquired Greenwich, Amherstburg and Tilbury solar energy projects, Hardisty Caverns

and Hardisty Contract Terminals from Enbridge and wholly-owned subsidiaries of Enbridge for proceeds of $1.2

billion. In October 2011, the Fund acquired the Ontario Wind, Sarnia Solar and Talbot Wind energy projects from

a wholly-owned subsidiary of Enbridge for $1.2 billion. In both cases, ordinary trust units were issued by the Fund

to partially finance these acquisitions, resulting in an increase in interests held by third parties in 2012 and 2011

and contributions from noncontrolling unitholders of $226 million and $168 million, respectively.

Distributions to noncontrolling unitholders are made on a monthly basis in line with the Fund’s objective of

distributing a high proportion of its cash available for distribution, as approved by its Board of Trustees.

19. Share Capital

The authorized share capital of the Company consists of an unlimited number of common shares with no par value and

an unlimited number of preference shares.

COMMON SHARES

December 31,

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

Balance at beginning of year
Common Shares issued 1

Shares issued on exercise of stock options

Dividend Reinvestment and Share

Purchase Plan (DRIP)

Balance at end of year

2012

Number
of Shares

781

805

Amount

3,969

388

297

4,732

1 Gross proceeds – $400 million; net issuance costs – $12 million.

2011

Number
of Shares

Amount

2010

Number
of Shares

Amount

770

3,683

756

3,379

–

781

–

229

3,969

–

770

PREFERENCE SHARES

December 31,

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

Preference Shares, Series A

Preference Shares, Series B

Preference Shares, Series D

Preference Shares, Series F

Preference Shares, Series H

Preference Shares, Series J

Preference Shares, Series L

Preference Shares, Series N

Preference Shares, Series P

Preference Shares, Series R

Issuance costs

Balance at end of year

2012

Number
of Shares

Amount

2011

Number
of Shares

Amount

2010

Number
of Shares

125

500

450

500

350

199

411

450

400

(78)

3,707

–

125

500

450

–

(19)

1,056

–

224

3,683

Amount

125

–

125

Notes to the Consolidated Financial Statements > 127

Characteristics of the preference shares are as follows:

(Canadian dollars unless otherwise stated)

Preference Shares, Series A

Preference Shares, Series B

Preference Shares, Series D

Preference Shares, Series F

Preference Shares, Series H

Preference Shares, Series J

Preference Shares, Series L

Preference Shares, Series N

Preference Shares, Series P
Preference Shares, Series R 5

Initial Yield

Dividend 1

Per Share Base
Redemption

Value 2

Redemption and
Conversion
Option Date 2,3

Right to
Convert Into 3,4

5.5%

4.0%

$1.375

$1.000

US$1.000

$1.000

$25

US$25

$25

–

June 1, 2017

March 1, 2018

June 1, 2018

September 1, 2018

June 1, 2017

September 1, 2017

December 1, 2018

March 1, 2019

June 1, 2019

–

Series C

Series E

Series G

Series I

Series K

Series M

Series O

Series Q

Series S

1
2

The holder is entitled to receive a fixed, cumulative, quarterly preferential dividend per year, as declared by the Board of Directors of the Company.
Preference Shares, Series A may be redeemed any time at the Company’s option. For all other series of Preference Shares, the Company may at its option, redeem all or a
portion of the 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.
The holder will have the right, subject to certain conditions, to convert their shares into Cumulative Redeemable Preference Shares of a specified series on the Conversion
Option Date and every fifth anniversary thereafter.
Holders will be entitled to receive quarterly floating rate cumulative dividends per share at a rate equal to: $25 x (number of days in quarter/365) x (90-day Government of
Canada treasury bill rate + 2.4% (Series C), 2.4% (Series E), 2.5% (Series G), 2.1% (Series I), 2.7% (Series O), 2.5% (Series Q) or 2.5% (Series S)); or US$25 x (number of
days in quarter/365) x (90-day United States Government treasury bill rate + 3.1% (Series K) or 3.2% (Series M)).
A cash dividend of $0.2356 per share will be paid on March 1, 2013 to Series R shareholders. The regular quarterly dividend of $0.25 per share will begin in the second
quarter of 2013.

EARNINGS PER COMMON SHARE

Earnings per common share is calculated by dividing earnings attributable to common shareholders by the weighted

average number of common shares outstanding. The weighted average number of shares outstanding has been reduced

by the Company’s pro-rata weighted average interest in its own common shares of 20 million (2011 – 25 million;

2010 – 22 million), resulting from the Company’s reciprocal investment in Noverco.

The treasury stock method is used to determine the dilutive impact of stock options. This method assumes any

proceeds from the exercise of stock options would be used to purchase common shares at the average market price

during the period.

December 31,

(number of common shares in millions)

Weighted average shares outstanding

Effect of dilutive options

Diluted weighted average shares outstanding

2012

2011

2010

772

785

751

761

741

748

For the year ended December 31, 2012, 5,733,000 anti-dilutive stock options (2011 – 48,000; 2010 – 92,000) with a
weighted average exercise price of $38.32 (2011 – $32.02; 2010 – $27.84) were excluded from the diluted earnings

per share calculation.

STOCK SPLIT

Effective May 25, 2011, a two-for-one split of the common shares of the Company was completed. All references to the

number of shares outstanding, earnings per common share, diluted earnings per common share, dividends per common

share and outstanding option information have been retroactively restated to reflect the impact of the stock split.

1 28 < EN BR IDGE I NC. 2012 FINANCIAL REPO RT

DIVIDEND REINVESTMENT AND SHARE PURCHASE PLAN

Under the DRIP, registered shareholders may reinvest dividends in common shares of the Company and make

additional optional cash payments to purchase common shares, free of brokerage or other charges. Participants in

the Company’s DRIP receive a 2% discount on the purchase of common shares with reinvested dividends.

SHAREHOLDER RIGHTS PLAN

The Shareholder Rights Plan is designed to encourage the fair treatment of shareholders in connection with any

takeover offer for the Company. Rights issued under the plan become exercisable when a person and any related

parties acquires or announces its intention to acquire 20% or more of the Company’s outstanding common shares

without complying with certain provisions set out in the plan or without approval of the Company’s Board of

Directors. Should such an acquisition occur, each rights holder, other than the acquiring person and related parties,

will have the right to purchase common shares of the Company at a 50% discount to the market price at that time.

20. Stock Option and Stock Unit Plans

The Company maintains four long-term incentive compensation plans: the ISO Plan, the PBSO Plan, the PSU Plan

and the RSU Plan. A maximum of 60 million common shares were reserved for issuance under the 2002 ISO plan,

of which 46 million have been issued to date. In 2007, a new reserve of 33 million shares was approved and established

and in 2011 an increase of 19 million to the reserved common shares was approved, resulting in a total of 52 million

common shares being available for the 2007 ISO and PBSO plans, of which four million have been issued to date.

The PSU and RSU plans grant notional units as if a unit was one Enbridge common share and are payable in cash.

INCENTIVE STOCK OPTIONS

Key employees are granted ISOs to purchase common shares at the market price on the grant date. ISOs vest in equal

annual installments over a four-year period and expire 10 years after the issue date.

December 31, 2012

(options in thousands; intrinsic value in millions of Canadian dollars)

Options outstanding at beginning of year

Options granted
Options exercised 1

Options cancelled or expired

Options outstanding at end of year
Options vested at end of year 2

Weighted
Average
Exercise Price

Weighted
Average
Remaining
Contractual
Life (years)

Aggregate
Intrinsic Value

21.19

38.32

16.99

27.78

25.69

20.33

6.7

5.2

375

261

Number

27,465

5,802

(5,796)

(103)

27,368

13,703

The total intrinsic value of ISOs exercised during the year ended December 31, 2012 was $130 million (2011 – $68 million; 2010 – $38 million) and cash received on exercise
was $69 million (2011 – $56 million; 2010 – $50 million).
The total fair value of options vested under the ISO Plan during the year ended December 31, 2012 was $19 million (2011 – $17 million; 2010 – $14 million).

Notes to the Consolidated Financial Statements > 129

Weighted average assumptions used to determine the fair value of the ISOs using the Black-Scholes-Merton option

pricing model are as follows:

Year ended December 31,
Fair value per option (Canadian dollars) 1

Valuation assumptions

Expected option term (years) 2
Expected volatility 3
Expected dividend yield 4
Risk-free interest rate 5

2012

4.81

19.7%

3.0%

1.3%

2011

4.19

18.6%

3.4%

2.9%

2010

3.44

19.7%

3.6%

2.7%

1 Options granted to United States employees are based on New York Stock Exchange prices. The option value and assumptions shown are based on a weighted average of

the United States and the Canadian options. The fair values per option were $4.65 (2011 – $4.01; 2010 – $3.28) for Canadian employees and US$5.58 (2011 – US$5.11;
2010 – US$4.00) for United States employees.
The expected option term is based on historical exercise practice.
Expected volatility is determined with reference to historic daily share price volatility and consideration of the implied volatility observable in call option values near the
grant date.
The expected dividend yield is the current annual dividend at the grant date divided by the current stock price.
The risk-free interest rate is based on the Government of Canada’s Canadian Bond Yields and the United States Treasury Bond Yields.

2
3

4
5

Compensation expense recorded for the year ended December 31, 2012 for ISOs was $23 million (2011 – $16 million;

2010 – $11 million). At December 31, 2012, unrecognized compensation cost related to non-vested stock-based

compensation arrangements granted under the ISO Plan was $30 million. The cost is expected to be fully recognized

over a weighted average period of approximately three years.

PERFORMANCE BASED STOCK OPTIONS

PBSOs are granted to executive officers and become exercisable when both performance targets and time vesting

requirements have been met. PBSOs were granted on September 16, 2002 under the 2002 plan and on August 15,

2007, February 19, 2008 and August 15, 2012 under the 2007 plan. All performance and time vesting conditions on

the 2002 grant were met prior to the term of the options expiring on September 16, 2010. All performance targets for

the 2007 and 2008 grants have been met. The time vesting requirements were fulfilled evenly over a five-year period

ending on August 15, 2012 with the options being exercisable until August 15, 2015. Time vesting requirements for

the 2012 grant will be fulfilled evenly over a five-year term, ending August 15, 2017. The 2012 grant’s performance

targets are based on the Company’s share price and must be met by February 15, 2019 or the options expire. If targets

are met by February 15, 2019, the options are exercisable until August 15, 2020.

December 31, 2012

(options in thousands; intrinsic value in millions of Canadian dollars)

Options outstanding at beginning of year

Options granted
Options exercised 1

Options outstanding at end of year
Options vested at end of year 2

Weighted
Average
Exercise Price

Weighted
Average
Remaining
Contractual
Life (years)

Aggregate
Intrinsic Value

18.52

39.34

18.29

29.56

18.54

5.3

2.6

Number

4,127

3,543

(966)

6,704

3,061

The total intrinsic value of PBSOs exercised during the year ended December 31, 2012 was $20 million (2011 – $2 million; 2010 – $26 million) and cash received on exercise
was $12 million (2011 – $3 million; 2010 – $27 million).
The total fair value of options vested under the PBSO Plan during the year ended December 31, 2012 was $1 million (2011 – $2 million; 2010 – $2 million).

1 30 < EN BR IDGE I NC. 2012 FINANCIAL REPO RT

Assumptions used to determine the fair value of the PBSOs using the Bloomberg barrier option valuation model

are as follows:

Year ended December 31,

Fair value per option (Canadian dollars)

Valuation assumptions

Expected option term (years) 1
Expected volatility 2
Expected dividend yield 3
Risk-free interest rate 4

2012

4.25

16.1%

2.8%

1.6%

1
2
3
4

The expected option term is based on historical exercise practice.
Expected volatility is determined with reference to historic daily share price volatility.
The expected dividend yield is the current annual dividend at the grant date divided by the current stock price.
The risk-free interest rate is based on the Government of Canada’s Canadian Bond Yields.

Compensation expense recorded for the year ended December 31, 2012 for PBSOs was $2 million (2011 – $2 million;

2010 – $2 million). At December 31, 2012, unrecognized compensation cost related to non-vested stock-based

compensation arrangements granted under the PBSO Plan was $14 million. The cost is expected to be fully recognized

over a weighted average period of approximately two years.

PERFORMANCE STOCK UNITS

The Company has a PSU Plan for executives where cash awards are paid following a three-year performance cycle. Awards

are calculated by multiplying the number of units outstanding at the end of the performance period by the Company’s

weighted average share price for 20 days prior to the maturity of the grant and by a performance multiplier. The

performance multiplier ranges from zero, if the Company’s performance fails to meet threshold performance levels,

to a maximum of two if the Company performs within the highest range of its performance targets. The 2010, 2011

and 2012 grants derive the performance multiplier through a calculation of the Company’s price/earnings ratio relative

to a specified peer group of companies and the Company’s earnings per share, adjusted for unusual, non-operating

or non-recurring items, relative to targets established at the time of grant. To calculate the 2012 expense, multipliers of

two, based upon multiplier estimates at December 31, 2012, were used for each of the 2010, 2011 and 2012 PSU grants.

December 31, 2012

(units in thousands; intrinsic value in millions of Canadian dollars)

Units outstanding at beginning of year

Units granted
Units matured 1

Dividend reinvestment

Units outstanding at end of year

Weighted
Average
Remaining
Contractual
Life (years)

Aggregate
Intrinsic Value

1.5

Number

937

307

(627)

652

The total amount paid during the year ended December 31, 2012 for PSUs was $25 million (2011 – $17 million; 2010 – $14 million).

Compensation expense recorded for the year ended December 31, 2012 for PSUs was $49 million (2011 – $42

million; 2010 – $27 million). As at December 31, 2012, unrecognized compensation expense related to non-vested

units granted under the PSU Plan was $25 million and is expected to be fully recognized over a weighted average

period of approximately two years.

Notes to the Consolidated Financial Statements > 131

RESTRICTED STOCK UNITS

Enbridge has a RSU Plan where cash awards are paid to certain non-executive employees of the Company following a

35 month maturity period. RSU holders receive cash equal to the Company’s weighted average share price for 20 days

prior to the maturity of the grant multiplied by the units outstanding on the maturity date.

December 31, 2012

(units in thousands; intrinsic value in millions of Canadian dollars)

Units outstanding at beginning of year

Units granted

Units cancelled
Units matured 1

Dividend reinvestment

Units outstanding at end of year

Weighted
Average
Remaining
Contractual
Life (years)

Aggregate
Intrinsic Value

1.5

Number

1,902

891

(114)

(939)

1,819

The total amount paid during the year ended December 31, 2012 for RSUs was $37 million (2011 – $39 million; 2010 – $24 million).

Compensation expense recorded for the year ended December 31, 2012 for RSUs was $32 million (2011 – $31

million; 2010 – $29 million). As at December 31, 2012, unrecognized compensation expense related to non-vested

units granted under the RSU Plan was $37 million and is expected to be fully recognized over a weighted average

period of approximately two years.

21. Components of Accumulated Other Comprehensive Loss

Changes in AOCI attributable to Enbridge common shareholders for the years ended December 31, 2012, 2011 and

2010, are as follows:

(millions of Canadian dollars)

Balance at January 1, 2010

Changes during the year

Tax impact

Balance at December 31, 2010

Changes during the year

Tax impact

Balance at December 31, 2011

Changes during the year

Tax impact

Balance at December 31, 2012

Cash Flow
Hedges

Net
Investment
Hedges

Cumulative
Translation
Adjustment

Equity
Investees

Pension and
OPEB Actuarial
Gain/(Loss)
Adjustment

(136)

(135)

(66)

(563)

153

(410)

(476)

(190)

(145)

(621)

429

(10)

480

(21)

(19)

461

(3)

474

(1,033)

(255)

–

(255)

(1,288)

–

(1,203)

(99)

–

(99)

(1,302)

(15)

(11)

(20)

(17)

(28)

(5)

(26)

(104)

(52)

(38)

(142)

(200)

(144)

(286)

(52)

(38)

(324)

Total

(654)

(379)

(373)

(1,027)

(719)

214

(505)

(1,532)

(318)

(267)

(1,799)

1 32 < EN BR IDGE I NC. 2012 FINANCIAL REPO RT

22. Derivative Financial Instruments and Hedging Activities

MARKET PRICE RISK

The Company’s earnings, cash flows and OCI are subject to movements in foreign exchange rates, interest rates,

commodity prices and the Company’s share price (collectively, market price risk). Formal risk management policies,

processes and systems have been designed to mitigate these risks.

The following summarizes the types of market price 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’s earnings, cash flows, and OCI are subject to foreign exchange rate variability, primarily arising from

its United States dollar denominated investments and subsidiaries, and certain revenues denominated in United States

dollars and certain expenses denominated in Euros. The Company has implemented a policy where it economically

hedges a minimum level of foreign currency denominated earnings exposures identified over the next five year period.

The Company may also hedge anticipated foreign currency denominated purchases or sales, foreign currency

denominated debt, as well as certain equity investment balances and net investments in foreign denominated

subsidiaries. The Company uses a combination of qualifying and non-qualifying derivative instruments to manage

variability in cash flows arising from its United States dollar investments and subsidiaries, and primarily non-qualifying

derivative instruments to manage variability arising from certain revenues denominated in United States dollars.

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 through 2016 with an average swap rate of 2.2%.

The Company’s earnings and cash flows are also exposed to variability in longer term interest rates ahead of anticipated

fixed rate 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 through 2016. A total of $10,547 million of future fixed rate term debt

issuances have been hedged at an average swap rate of 3.5%.

The Company also monitors its debt portfolio mix of fixed and variable rate debt instruments to maintain a consolidated

portfolio of debt which stays within its Board of Directors approved policy limit band of a maximum of 25% floating rate

debt as a percentage of total debt outstanding. The Company uses primarily 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 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.

Notes to the Consolidated Financial Statements > 133

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, RSUs (Note 20). The Company uses

a combination of qualifying and non-qualifying derivative instruments to manage equity price risk.

TOTAL DERIVATIVE INSTRUMENTS

The following table summarizes the balance sheet location and carrying value of the Company’s derivative instruments.

The Company did not have any outstanding fair value hedges at December 31, 2012 or 2011.

December 31, 2012

(millions of Canadian dollars)

Accounts receivable and other (Note 7)

Foreign exchange contracts

Interest rate contracts

Commodity contracts

Other contracts

Deferred amounts and other assets (Note 12)

Foreign exchange contracts

Interest rate contracts

Commodity contracts

Other contracts

Accounts payable and other (Note 15)

Foreign exchange contracts

Interest rate contracts

Commodity contracts

Other long-term liabilities (Note 17)

Foreign exchange contracts

Interest rate contracts

Commodity contracts

Total net derivative asset/(liability)

Foreign exchange contracts

Interest rate contracts

Commodity contracts

Other contracts

Derivative
Instruments
used as Cash
Flow Hedges

Derivative
Instruments
used as
Net Investment
Hedges

Non-Qualifying
Derivative
Instruments

Total Gross
Derivative
Instruments

Effects of
Netting

Total Net
Derivative
Instruments 1

(5)

(673)

(10)

(688)

(41)

(293)

(6)

(340)

(31)

(938)

(957)

–

(5)

–

(5)

–

210

127

354

225

298

(100)

(2)

(304)

(406)

(23)

(15)

(388)

(426)

312

(505)

(180)

230

145

402

315

416

(105)

(675)

(314)

(1,094)

(69)

(308)

(394)

(771)

371

(932)

(498)

(1,047)

–

(2)

(17)

–

(19)

–

(3)

(5)

–

(8)

–

230

128

383

315

408

(105)

(673)

(297)

(1,075)

(69)

(305)

(389)

(763)

371

(932)

(498)

(1,047)

1 34 < EN BR IDGE I NC. 2012 FINANCIAL REPO RT

December 31, 2011

(millions of Canadian dollars)

Accounts receivable and other (Note 7)

Foreign exchange contracts

Interest rate contracts

Commodity contracts

Other contracts

Deferred amounts and other assets (Note 12)

Foreign exchange contracts

Interest rate contracts

Commodity contracts

Other contracts

Accounts payable and other (Note 15)

Foreign exchange contracts

Interest rate contracts

Commodity contracts

Other long-term liabilities (Note 17)

Foreign exchange contracts

Interest rate contracts

Commodity contracts

Total net derivative asset/(liability)

Foreign exchange contracts

Interest rate contracts

Commodity contracts

Other contracts

Derivative
Instruments
used as Cash
Flow Hedges

Derivative
Instruments
used as
Net Investment
Hedges

Non-Qualifying
Derivative
Instruments

Total Gross
Derivative
Instruments

Effects of
Netting

Total Net
Derivative
Instruments 1

–

(4)

(477)

(32)

(513)

(35)

(415)

(29)

(479)

(20)

(891)

(42)

(947)

–

(5)

–

(5)

–

315

146

480

203

241

470

(275)

(8)

(107)

(390)

(51)

(20)

(91)

192

260

469

334

153

509

297

253

580

(279)

(485)

(139)

(903)

(91)

(435)

(49)

(575)

261

(883)

218

(389)

–

(4)

(19)

–

(23)

–

(3)

(15)

–

(18)

–

334

134

486

297

238

562

(279)

(481)

(120)

(880)

(91)

(432)

(34)

(557)

261

(883)

218

(389)

As presented in the Consolidated Statements of Financial Position.

Notes to the Consolidated Financial Statements > 135

The following table summarizes the maturity and notional principal or quantity outstanding related to the Company’s

derivative instruments.

December 31, 2012

2013

2014

2015

2016

2017

Thereafter

Foreign exchange contracts – United States

dollar forwards – purchase
(millions of United States dollars)

Foreign exchange contracts – United States

dollar forwards – sell
(millions of United States dollars)

Foreign exchange contracts – Euro dollar
forwards – purchase (millions of Euros)

Interest rate contracts – short-term

borrowings (millions of Canadian dollars)

Interest rate contracts – long-term debt

(millions of Canadian dollars)

Equity contracts (millions of Canadian dollars)

Commodity contracts – natural gas

(billions of cubic feet)

Commodity contracts – crude oil

(millions of barrels)

Commodity contracts – NGL (millions of barrels)

Commodity contracts – power
(megawatt hours (MWH))

558

468

413

2,088

2,402

2,751

2,323

2,557

3,644

4,590

–

3,591

3,055

–

3,455

1,760

–

3,157

1,142

–

2,841

–

158

–

171

–

December 31, 2011

2012

2013

2014

2015

2016

Thereafter

Foreign exchange contracts – United States

dollar forwards – purchase
(millions of United States dollars)

Foreign exchange contracts – United States

dollar forwards – sell
(millions of United States dollars)

Interest rate contracts – short-term

borrowings (millions of Canadian dollars)

Interest rate contracts – long-term debt

(millions of Canadian dollars)

Equity contracts (millions of Canadian dollars)

Commodity contracts – natural gas

(billions of cubic feet)

Commodity contracts – crude oil

(millions of barrels)

Commodity contracts – NGL (millions of barrels)

Commodity contracts – power (MWH)

287

468

2,017

3,227

2,650

1,865

3,237

2,000

2,182

2,787

1,650

–

2,583

2,641

750

–

2,039

2,428

–

418

180

215

–

1 36 < EN BR IDGE I NC. 2012 FINANCIAL REPO RT

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.

Year ended December 31,

(millions of Canadian dollars)

Amount of unrealized gains/(loss) recognized in OCI

Cash flow hedges

Foreign exchange contracts

Interest rate contracts

Commodity contracts

Other contracts

Net investment hedges

Foreign exchange contracts

Amount of (gains)/loss reclassified from AOCI to earnings (effective portion)

Foreign exchange contracts 1
Interest rate contracts 2
Commodity contracts 3
Other contracts 4

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

Interest rate contracts 2
Commodity contracts 3

2012

2011

2010

(12)

(46)

(3)

(8)

(1)

(3)

(1)

(3)

(22)

(724)

(26)

(694)

(10)

(55)

(2)

(66)

(25)

(217)

128

(1)

(96)

(7)

(116)

(61)

–

(3)

1
2
3
4

Reported within Other income in the Consolidated Statements of Earnings.
Reported within Interest expense in the Consolidated Statements of Earnings.
Reported within Commodity costs in the Consolidated Statements of Earnings.
Reported within Operating and administrative expense in the Consolidated Statements of Earnings.

The Company estimates that $101 million of AOCI related to cash flow hedges will be reclassified to earnings in

the next 12 months. Actual amounts reclassified to earnings depend on the foreign exchange rates, interest rates

and commodity prices in effect when derivative contracts that are currently outstanding mature. For all forecasted

transactions, the maximum term over which the Company is hedging exposures to the variability of cash flows is

60 months at December 31, 2012.

NON-QUALIFYING DERIVATIVES

The following table presents the unrealized gains and losses associated with changes in the fair value of the Company’s

non-qualifying derivatives.

Year ended December 31,

(millions of Canadian dollars)
Foreign exchange contracts 1
Interest rate contracts 2
Commodity contracts 3
Other contracts 4
Total unrealized derivative fair value gains/(loss)

2012

2011

2010

120

(2)

(765)

(2)

(649)

(179)

280

114

(3)

(12)

–

1
2
3
4

Notes to the Consolidated Financial Statements > 137

LIQUIDITY RISK

Liquidity risk is the risk that the Company will not be able to meet its financial obligations, including commitments and

guarantees (Notes 28 and 29), as they become due. In order to manage this risk, the Company forecasts cash requirements

over a 12 month rolling time period to determine whether sufficient funds will be available. The Company’s primary

sources of liquidity and capital resources are funds generated from operations, the issuance of commercial paper and

draws under committed credit facilities and long-term debt which includes debentures and medium-term notes. The

Company 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. In addition, the Company maintains

sufficient liquidity through committed credit facilities (Note 16) with a diversified group of banks and institutions which, if

necessary, enables the Company to fund all anticipated requirements for one year without accessing the capital markets.

The Company is in compliance with all the terms and conditions of its committed credit facilities as at December 31,

2012. As a result, all credit facilities are available to the Company and the banks are obligated to fund and have been

funding the Company under the terms of the facilities.

CREDIT RISK

Entering into derivative financial instruments may result in exposure to credit risk. Credit risk arises from the possibility

that a counterparty will default on its contractual obligations. 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, frequent assessment of counterparty credit ratings and

netting arrangements.

The Company generally has a policy of entering into individual International Swaps and Derivatives Association

(ISDA) 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 these counterparties in these particular circumstances.

At December 31, 2012 and 2011, the Company had group credit concentrations and maximum credit exposure, with

respect to derivative instruments, in the following counterparty segments:

December 31,

(millions of Canadian dollars)

Canadian financial institutions

United States financial institutions

European financial institutions
Other 1

2012

2011

306

129

244

128

807

431

287

257

112

1,087

1 Other is comprised of commodity clearing house and natural gas and crude physical counterparties.

As at December 31, 2012, the Company had provided letters of credit totaling $273 million in lieu of providing cash

collateral to its counterparties pursuant to the terms of the relevant ISDA agreements. The Company holds no cash

collateral on asset exposures at December 31, 2012 or 2011.

Gross derivative balances have been presented without the effects of collateral posted. Derivative assets are adjusted for

non-performance risk of the Company’s counterparties using their credit default swap spread rates and are reflected in

the fair value. For derivative liabilities, the Company’s non-performance risk is considered in the valuation.

1 38 < EN BR IDGE I NC. 2012 FINANCIAL REPO RT

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. Credit risk is mitigated by the 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.

FAIR VALUE MEASUREMENTS

The Company’s financial assets and liabilities measured at fair value on a recurring basis include derivative instruments.

The Company also discloses the fair value of other financial instruments not measured at fair value. The fair value of

financial instruments reflects the Company’s best estimates of market value based on generally accepted valuation

techniques or models and supported by observable market prices and rates. When such values are not available, the

Company uses discounted cash flow analysis from applicable yield curves based on observable market inputs to estimate

fair value.

FAIR VALUE OF DERIVATIVES

The Company categorizes its derivative instruments measured at fair value into one of three different levels depending

on the observability of the inputs employed in the measurement.

LEVEL 1

Level 1 includes derivatives measured at fair value based on unadjusted quoted prices for identical assets and liabilities in

active markets that are accessible at the measurement date. An active market for a derivative is considered to be a market

where transactions occur with sufficient frequency and volume to provide pricing information on an ongoing basis. The

Company’s Level 1 instruments consist primarily of exchange-traded derivatives used to mitigate the risk of crude oil

price fluctuations. The Company does not have any other financial instruments categorized as Level 1.

LEVEL 2

Level 2 includes derivative valuations determined using directly or indirectly observable inputs other than quoted prices

included within Level 1. Derivatives in this category are valued using models or other industry standard valuation

techniques derived from observable market data. Such valuation techniques include inputs such as quoted forward

prices, time value, volatility factors and broker quotes that can be observed or corroborated in the market for the entire

duration of the derivative. Derivatives valued using Level 2 inputs include non-exchange traded derivatives such as

over-the-counter foreign exchange forward and cross currency swap contracts, interest rate swaps, physical forward

commodity contracts, as well as commodity swaps and options for which observable inputs can be obtained.

The Company has also categorized the fair value of its held to maturity preferred share investment and long-term debt

as Level 2. The fair value of the Company’s held to maturity preferred share investment is primarily based on the yield

of certain Government of Canada bonds. The fair value of the Company’s long-term debt is based on quoted market

prices for instruments of similar yield, credit risk and tenor.

LEVEL 3

Level 3 includes derivative valuations based on inputs which are less observable, unavailable or where the observable

data does not support a significant portion of the derivatives’ fair value. Generally, Level 3 derivatives are longer dated

transactions, occur in less active markets, occur at locations where pricing information is not available or have no

binding broker quote to support Level 2 classification. The Company has developed methodologies, benchmarked

against industry standards, to determine fair value for these derivatives based on extrapolation of observable future

prices and rates. Derivatives valued using Level 3 inputs primarily include long-dated derivative power contracts and

NGL and natural gas contracts. The Company does not have any other financial instruments categorized in Level 3.

Notes to the Consolidated Financial Statements > 139

The Company uses the most observable inputs available to estimate the fair value of its derivatives. When possible,

the Company estimates the fair value of its derivatives based on quoted market prices. If quoted market prices are not

available, the Company uses estimates from third party brokers. For non-exchange traded derivatives classified in Levels

2 and 3, the Company uses standard valuation techniques to calculate the estimated fair value. These methods include

discounted cash flows for forwards and swaps and Black-Scholes-Merton pricing models for options. Depending on

the type of derivative and nature of the underlying risk, the Company uses observable market prices (interest, foreign

exchange, commodity and share) and volatility as primary inputs to these valuation techniques. Finally, the Company

considers its own credit default swap spread as well as the credit default swap spreads associated with its counterparties

in its estimation of fair value.

The Company has categorized its derivative assets and liabilities measured at fair value as follows:

December 31, 2012

(millions of Canadian dollars)

Financial assets

Current derivative assets

Foreign exchange contracts

Interest rate contracts

Commodity contracts

Other contracts

Long-term derivative assets

Foreign exchange contracts

Interest rate contracts

Commodity contracts

Other contracts

Financial liabilities

Current derivative liabilities

Foreign exchange contracts

Interest rate contracts

Commodity contracts

Long-term derivative liabilities

Foreign exchange contracts

Interest rate contracts

Commodity contracts

Total net financial asset/(liability)

Foreign exchange contracts

Interest rate contracts

Commodity contracts

Other contracts

Level 1

Level 2

Level 3

Total Gross
Derivative
Instruments

Effects of
Netting

–

(9)

–

(6)

–

(6)

230

281

315

407

(105)

(675)

(229)

(1,009)

(69)

(308)

(319)

(696)

371

(932)

(468)

(1,017)

–

118

–

118

–

(76)

–

(75)

–

(24)

–

(24)

230

145

402

315

416

(105)

(675)

(314)

(1,094)

(69)

(308)

(394)

(771)

371

(932)

(498)

(1,047)

–

(2)

(17)

–

(19)

–

(3)

(5)

–

(8)

–

Total

230

128

383

315

408

(105)

(673)

(297)

(1,075)

(69)

(305)

(389)

(763)

371

(932)

(498)

(1,047)

1 40 < EN BR IDGE I NC. 2012 FINANCIAL REPO RT

December 31, 2011

(millions of Canadian dollars)

Financial assets

Current derivative assets

Foreign exchange contracts

Interest rate contracts

Commodity contracts

Other contracts

Long-term derivative assets

Foreign exchange contracts

Interest rate contracts

Commodity contracts

Other contracts

Financial liabilities

Current derivative liabilities

Foreign exchange contracts

Interest rate contracts

Commodity contracts

Long-term derivative liabilities

Foreign exchange contracts

Interest rate contracts

Commodity contracts

Total net financial asset/(liability)

Foreign exchange contracts

Interest rate contracts

Commodity contracts

Other contracts

Level 1

Level 2

Level 3

Total Gross
Derivative
Instruments

Effects of
Netting

–

334

422

297

208

535

(279)

(485)

(59)

(823)

(91)

(435)

(30)

(556)

261

(883)

185

(422)

–

(80)

–

(19)

–

334

153

509

297

253

580

(279)

(485)

(139)

(903)

(91)

(435)

(49)

(575)

261

(883)

218

(389)

–

(4)

(19)

–

(23)

–

(3)

(15)

–

(18)

–

Total

334

134

486

297

238

562

(279)

(481)

(120)

(880)

(91)

(432)

(34)

(557)

261

(883)

218

(389)

Notes to the Consolidated Financial Statements > 141

The significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments were

as follows:

December 31, 2012

(Fair value in millions of Canadian dollars)
Commodity contracts – financial 1

Natural gas

Crude

Power

Commodity contracts – physical 1

Natural gas

Crude

NGL

Power

Commodity options 2

Natural gas

NGL

Fair
Value

Unobservable
Input

Minimum
Price

Maximum
Price

Weighted
Average Price

Forward gas price

Forward crude price

Forward power price

Forward gas price

Forward crude price

Forward NGL price

Forward power price

Option volatility

(3)

(60)

(12)

(1)

(24)

3.21

58.42

50.25

2.88

51.13

0.00

30.09

29.0%

33.0%

4.31

108.14

68.25

5.10

116.56

2.54

36.35

36.0%

104.0%

3.54

100.40

55.98

3.67

92.49

1.42

32.74

34.0%

57.0%

$/mmbtu3

$/barrel

$/MWH

$/mmbtu3

$/barrel

$/gallon

$/MWH

Financial and physical forward commodity contracts are valued using a market approach valuation technique.
Commodity options contracts are valued using an option model valuation technique.

1
2
3 One million British thermal units (mmbtu).

If adjusted, the significant unobservable inputs disclosed in the table above would have a direct impact on the fair

value of the Company’s Level 3 derivative instruments. The significant unobservable inputs used in the fair value

measurement of Level 3 derivative instruments include forward commodity prices and, for option contracts, price

volatility. Changes in forward commodity prices would result in significantly different fair values for the Company’s

Level 3 derivatives. Changes in price volatility would change the value of the option contracts. Generally speaking,

a change in the estimate of forward commodity prices is unrelated to a change in the estimate of price volatility.

Changes in net fair value of derivative assets and liabilities classified as Level 3 in the fair value hierarchy were as follows:

Year ended December 31,

(millions of Canadian dollars)

Level 3 net derivative asset/(liability) at beginning of year

Total unrealized gains/(loss)
Included in earnings 1

Included in OCI

Purchases

Settlements

Level 3 net derivative asset/(liability) at end of year

2012

2011

(69)

–

(24)

(41)

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

The Company’s policy is to recognize transfers as of the last day of the reporting period. There were no transfers

between levels as at December 31, 2012 or 2011.

1 42 < EN BR IDGE I NC. 2012 FINANCIAL REPO RT

FAIR VALUE OF OTHER FINANCIAL INSTRUMENTS

The Company recognizes equity investments in other entities not categorized as held to maturity at fair value, with

changes in fair value recorded in OCI, unless actively quoted prices are not available for fair value measurement in

which case these investments are recorded at cost. The carrying value of all equity investments recognized at cost

totaled $66 million at December 31, 2012 (2011 – $57 million).

The Company has a held to maturity preferred share investment carried at its amortized cost of $246 million at

December 31, 2012 (2011 – $285 million). These preferred shares are entitled to a cumulative preferred dividend

based on the average yield of Government of Canada bonds maturing in greater than 10 years plus a range of 4.3%

to 4.4%. At December 31, 2012, the fair value of this preferred share investment approximates its face value of

$580 million (2011 – $580 million).

At December 31, 2012, the Company’s long-term debt had a carrying value of $20,855 million (2011 – $19,605

million) and a fair value of $24,809 million (2011 – $22,620 million).

23. Income Taxes

INCOME TAX RATE RECONCILIATION
Year ended December 31,

(millions of Canadian dollars)

Earnings before income taxes and extraordinary loss

Combined statutory income tax rate

Income taxes at statutory rate

Increase/(decrease) resulting from:

Deferred income taxes related to regulated operations

Higher/(lower) foreign tax rates

Tax rates and legislated tax changes

Non-taxable items, net
Intercompany sale of investments 1
Noncontrolling interests in Limited Partnerships

Other

Income taxes before extraordinary loss

Effective income tax rate

2012

2011

2010

1,071

25.8%

276

(67)

(56)

(6)

(79)

(5)

128

2,030

27.2%

552

(35)

(16)

(130)

(9)

526

12.0%

25.9%

1,008

28.8%

290

(62)

(38)

(15)

(8)

–

227

22.5%

In December 2012 and October 2011, Enbridge and certain wholly-owned subsidiaries of Enbridge sold certain assets to the Fund. As these transactions occurred between
entities under common control of the Company, the intercompany gains realized as a result of these transfers have been eliminated, although current income tax expense
of $56 million and $98 million remain as a charge to earnings in 2012 and 2011, respectively. The Company retains the benefit of cash taxes paid in the form of increased
tax basis of its investment in the underlying entities; however, accounting recognition of such benefit is not permitted until such time as the entities are sold outside of the
consolidated group.

Notes to the Consolidated Financial Statements > 143

COMPONENTS OF PRETAX EARNINGS AND INCOME TAXES
Year ended December 31,

2012

2011

2010

(millions of Canadian dollars)

Earnings before income taxes and extraordinary loss

Canada

United States

Other

Current income taxes

Canada

United States

Other

Deferred income taxes

Canada

United States

Total income taxes before extraordinary loss

COMPONENTS OF DEFERRED INCOME TAXES

1,041

(177)

207

1,071

130

168

160

(200)

(40)

128

694

1,203

133

2,030

194

(30)

(6)

158

338

368

526

759

118

131

1,008

(24)

136

203

227

Deferred tax assets and liabilities are recognized for the future tax consequences of differences between carrying

amounts of assets and liabilities and their respective tax bases. Major components of deferred income tax assets and

liabilities are:

December 31,

(millions of Canadian dollars)

Deferred income tax liabilities

Property, plant and equipment

Investments

Regulatory liabilities

Other

Total deferred income tax liabilities

Deferred income tax assets

Financial instruments

Pension and OPEB plans

Loss carryforwards

Other

Total deferred income tax assets

Less valuation allowance

Total deferred income tax assets, net

Net deferred income tax liabilities

Presented as follows:

Assets

Accounts receivable and other (Note 7)

Deferred income taxes

Total deferred income tax assets

Liabilities

Accounts payable and other (Note 15)

Deferred income taxes

Total deferred income tax liabilities

Net deferred income tax liabilities

1 44 < EN BR IDGE I NC. 2012 FINANCIAL REPO RT

2012

2011

(1,325)

(1,479)

(221)

(144)

(3,169)

380

180

161

772

(27)

745

(1,499)

(973)

(197)

(117)

(2,786)

145

174

385

(45)

340

(2,424)

(2,446)

167

177

–

(2,601)

(2,424)

135

176

(7)

(2,615)

(2,622)

(2,446)

Valuation allowances have been established for certain loss and credit carryforwards that reduce deferred income

tax assets to an amount that will more likely than not be realized.

At December 31, 2012, the Company recognized the benefit of unused tax loss carryforwards of $183 million

(2011 – $214 million) in Canada which start to expire in 2022 and beyond.

At December 31, 2012, the Company recognized the benefit of unused tax loss carryforwards of $222 million

(2011 – $187 million) in the United States which start to expire in 2022 and beyond.

The Company has not provided for deferred income taxes on $548 million (2011 – $524 million) of foreign subsidiaries’

undistributed earnings as at December 31, 2012 as such earnings are intended to be indefinitely reinvested in the

operations and potential acquisitions. Upon distribution of these earnings in the form of dividends or otherwise, the

Company would be subject to income taxes. It is not practicable to determine the income tax liability that might be

incurred if these earnings were to be distributed.

The Company recognizes accrued interest and penalties related to unrecognized tax benefits as a component of

Income taxes. Income tax expense for the year ended December 31, 2012 included $1 million (2011 – $1 million;

2010 – $2 million recovery) of interest and penalties. As at December 31, 2012, interest and penalties of $10 million

(2011 – $9 million) have been accrued.

The Company and one or more of its subsidiaries are subject to taxation in Canada, the United States and other foreign

jurisdictions. The Company is under examination by certain tax authorities for the 2007 to 2011 tax years. The material

jurisdictions in which the Company is subject to potential examinations include the United States (Federal and Texas)

and Canada (Federal, Alberta and Ontario).

UNRECOGNIZED TAX BENEFITS
Year ended December 31,

(millions of Canadian dollars)

Unrecognized tax benefits at beginning of year

Gross increases for tax positions of current year

Gross decreases for tax positions of prior years

Reduction for lapse of statute of limitations

Unrecognized tax benefits at end of year

2012

2011

(5)

(1)

The unrecognized tax benefits at December 31, 2012, if recognized, would affect the Company’s effective income tax

rate. The gross increases for current year positions included $16 million in respect of filing positions based on substantively

enacted tax law and $22 million in respect of a request for refund of Texas Gross Margin Tax. Although U.S. GAAP only

permits recognition of tax positions based on enacted law it is widely accepted by the Canadian tax authorities to file and

remit taxes based on substantively enacted tax law. It is anticipated that the law will be enacted in 2013.

Notes to the Consolidated Financial Statements > 145

24. Retirement and Postretirement Benefits

PENSION PLANS

The Company has three registered pension plans which provide either defined benefit or defined contribution pension

benefits, or both, to employees of the Company. The Liquids Pipelines and Gas Distribution pension plans (collectively,

the Canadian Plans) provide Company funded defined benefit pension and/or defined contribution benefits to Canadian

employees of Enbridge. The Enbridge United States pension plan (the United States Plan) provides Company funded

defined benefit pension benefits for United States based employees. The Company has four supplemental pension plans

which provide pension benefits in excess of the basic plans for certain employees.

A measurement date of December 31, 2012 was used to determine the plan assets and accrued benefit obligation for

the Canadian and United States plans.

DEFINED BENEFIT PLANS

Benefits payable from the defined benefit plans are based on members’ years of service and final average remuneration.

These benefits are partially inflation indexed after a member’s retirement. Contributions by the Company are made in

accordance with independent actuarial valuations and are invested primarily in publicly-traded equity and fixed income

securities. The effective dates of the most recent actuarial valuations and the next required actuarial valuations for the

basic plans are as follows:

Canadian Plans

Liquids Pipelines

Gas Distribution

United States Plan

DEFINED CONTRIBUTION PLANS

Effective Date of Most Recently
Filed Actuarial Valuation

Effective Date of Next
Required Actuarial Valuation

December 31, 2011

December 31, 2012

December 31, 2009

December 31, 2012

December 31, 2011

December 31, 2012

Contributions are generally based on the employee’s age, years of service and remuneration. For defined contribution

plans, benefit costs equal amounts required to be contributed by the Company.

Sponsored Investments

Corporate

Earnings per common share 3
Diluted earnings per common share 3

Adjusted earnings

Liquids Pipelines

Gas Distribution

Gas Pipelines, Processing and Energy Services

Sponsored Investments

Corporate

Adjusted earnings per common share 3,4

Cash flow data

Cash provided by operating activities

Cash used in investing activities

Cash provided by financing activities

Dividends

Common share dividends declared
Dividends paid per common share 3

Shares outstanding (millions)

Weighted average common shares outstanding 3
Diluted weighted average common shares outstanding 3

2012 1

2011 1

2010 1

2009 2

2008 2

726

207

(478)

282

(127)

610

0.79

0.78

684

176

154

263

(28)

1,249

1.62

2,874

(6,204)

4,395

895

1.13

772

785

505

(88)

305

269

(171)

820

1.09

1.08

536

173

163

244

(16)

1,100

1.46

3,371

(5,079)

2,030

759

0.98

751

761

531

150

125

944

1.27

1.26

511

162

123

206

(25)

977

1.32

1,877

(3,902)

1,957

648

0.85

741

748

445

186

428

141

355

1,555

2.13

2.12

454

154

116

151

(20)

855

1.17

2,017

(3,306)

1,082

555

0.74

728

733

328

161

767

111

(46)

1,321

1.84

1.82

332

141

101

(38)

677

0.94

1,372

(2,853)

1,840

489

0.66

720

725

1
2
3
4

Financial information has been extracted from financial statements prepared in accordance with U.S. GAAP.
Financial information has been extracted from financial statements prepared in accordance with Canadian GAAP.
Comparative amounts were restated to reflect two-for-one stock split which was effective May 25, 2011.
Adjusted earnings represent earnings attributable to common shareholders adjusted for non-recurring or non-operating factors. Adjusted earnings and adjusted earnings
per common share are non-GAAP measures that do not have any standardized meaning prescribed by generally accepted accounting principles. For more information on
non-GAAP measures see page 9.

1 56 < EN BR IDGE I NC. 2012 FINANCIAL REPO RT

FIVE-YEAR CONSOLIDATED HIGHLIGHTS

(per share amounts in Canadian dollars)
Common share trading (TSX) 3

High

Low

Volume (millions)

Financial ratios

Return on average equity 4
Return on average capital employed 5
Debt to debt plus equity 6
Dividend payout ratio 7

Operating data
Liquids Pipelines – Average deliveries

(thousands of barrels per day)
Canadian Mainline 8
Regional Oil Sands System 9
Spearhead Pipeline

Gas Distribution – Enbridge Gas Distribution (EGD)

Volumes (billions of cubic feet)
Number of active customers (thousands) 10
Heating degree days 11

Actual

Forecast based on normal weather

Gas Pipelines, Processing and Energy Services – Average

throughput volume (millions of cublic feet per day)

Alliance Pipeline US

Vector Pipeline

Enbridge Offshore Pipelines

2012 1

2011 1

2010 1

2009 2

2008 2

43.05

35.39

43.02

365

6.3%

3.5%

67.1%

69.8%

1,646

414

151

395

2,032

3,194

3,532

1,553

1,534

1,540

38.17

27.05

38.09

396

11.3%

4.5%

72.9%

67.1%

1,554

334

426

1,997

3,597

3,602

1,564

1,525

1,595

29.13

23.02

28.14

461

14.1%

5.0%

73.7%

64.4%

1,537

291

144

409

1,963

3,466

3,546

1,600

1,456

1,962

24.46

17.60

24.32

457

22.2%

8.9%

66.2%

63.0%

1,562

259

121

408

1,937

3,767

3,514

1,601

1,334

2,037

21.64

16.55

19.78

585

22.2%

9.9%

66.6%

70.2%

1,522

202

110

433

1,898

3,802

3,543

1,609

1,321

1,672

1
2
3
4
5

Financial ratios have been calculated using information from financial statements prepared in accordance with U.S. GAAP.
Financial ratios have been calculated using information from financial statements prepared in accordance with Canadian GAAP.
Comparative amounts were restated to reflect two-for-one stock split which was effective May 25, 2011.
Earnings applicable to common shareholders divided by average equity.
Sum of after-tax earnings and after-tax interest expense, divided by weighted average capital employed. Capital employed is equal to the sum of equity, Enbridge Gas Distribution
preferred shares, deferred income taxes, deferred credits and total debt (including short-term borrowings).
Total debt (including short-term borrowings) divided by the sum of total debt and equity.
Dividends per common share divided by adjusted earnings per common share.
Canadian Mainline includes deliveries ex-Gretna, Manitoba, which is made up of United States and eastern Canada deliveries originating from western Canada.
Volumes are for the Athabasca mainline and the Waupisoo Pipeline and exclude laterals on the Regional Oil Sands System.

6
7
8
9
10 Number of active customers is the number of natural gas consuming EGD customers at the end of the period.
11 Heating degree days is a measure of coldness which is indicative of volumetric requirements for natural gas utilized for heating purposes in EGD’s franchise area. It is calculated

by accumulating, for the fiscal period, the total number of degrees each day by which the daily mean temperature falls below 18 degrees Celsius. The figures given are those
accumulated in the Greater Toronto Area.

Five-Year Consolidated Highlights > 157

GLOSSARY

AFUDC

allowance for funds used
during construction

Alliance

Alliance System

Amherstburg

Amherstburg Solar Project

AOCI

ASU

bcf/d

bpd

CLT

CSR

CTS

EECI

EEDI

EELP

EEM

EEP

EGD

EGNB

Enbridge

ENF

EPI

EUB

FERC

accumulated other comprehensive
income/(loss)

Accounting Standards Update

billion cubic feet per day

barrels per day

Canadian Local Toll

corporate social responsibility

Competitive Toll Settlement

Enbridge Energy Company, Inc.

Enbridge Energy Distribution Inc.

Enbridge Energy, Limited Partnership

Enbridge Energy Management, L.L.C.

Enbridge Energy Partners, L.P.

Enbridge Gas Distribution Inc.

Enbridge Gas New Brunswick Inc.

Enbridge Inc.

Enbridge Income Fund Holdings Inc.

Enbridge Pipelines Inc.

New Brunswick Energy and Utilities Board

Federal Energy Regulatory Commission

Greenwich

Greenwich Wind Energy Project

IJT

ISO

ITS

JRP

International Joint Tariff

incentive regulation

incentive stock options

incentive tolling settlement

Joint Review Panel

MD&A

Management’s Discussion
and Analysis

mmcf/d

million cubic feet per day

MWH

NEB

NGL

megawatts

megawatt hours

National Energy Board

natural gas liquids

Northern Gateway proposed Northern Gateway Project

OCI

OEB

Offshore

OPEB

ORM Plan

PBSO

PPA

PRA

PSU

ROE

RSU

other comprehensive income/(loss)

Ontario Energy Board

Enbridge Offshore Pipelines