02346094-00000001-00001736-y@#Sedar#2015#ENB#Q1#ENB-Q1-2015-FS-EN-PDF 002002001130Enbridge Inc. 2015050620150506073241101
02346094-00000001-00001736-y@#Sedar#2015#ENB#Q1#ENB-Q1-2015-FS-EN-PDF
02346094
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Other Issuers
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Continuous Disclosure
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Interim financial statements/report - English
20150506
20150506
BC
AB
SK
MB
ON
QC
NB
NS
PE
NF
00001736
Enbridge Inc.
Enbridge Inc.
Tyler W. Robinson
403
231-5935
403
231-5929
Canada
29250N
099199010000000000000090000090990999999999999999999999999999999999999999999999999999999999999999999999999999999999999999999999999999999999999999999999
001
19871215
1231
052
00111111111100000999
10000000000009999999
PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
CST Trust Company
Societe de fiducie CST
006
20140114
14:05:53
1
ENB
20150331
002
30th Floor
425 - 1 Street S.W.
Calgary
Alberta
Canada
T2P 3L8
403
231-3900
403
231-5929
30th Floor
425 - 1 Street S.W.
Calgary
Alberta
Canada
T2P 3L8
403
231-3900
403
231-5929
1
CONSOLIDATED STATEMENTS OF EARNINGS
See accompanying notes to the unaudited interim consolidated financial statements.
Three months ended
March 31,
2015
2014
(unaudited; millions of Canadian dollars, except per share amounts)
Revenues
Commodity sales
5,231
8,006
Gas distribution sales
1,591
1,111
Transportation and other services
1,107
1,404
7,929
10,521
Expenses
Commodity costs
5,042
7,733
Gas distribution costs
1,364
846
Operating and administrative
991
745
Depreciation and amortization
474
366
Environmental costs, net of recoveries
(11)
5
7,860
9,695
69
826
Income from equity investments
133
114
Other expense
(457)
(138)
Interest expense
(251)
(238)
(506)
564
Income taxes recovery/(expense) (Note 11)
285
(117)
Earnings/(loss) from continuing operations
(221)
447
Discontinued operations (Note 4)
Earnings from discontinued operations before income taxes
-
73
Income taxes from discontinued operations
-
(27)
Earnings from discontinued operations
-
46
Earnings/(loss)
(221)
493
Earnings attributable to noncontrolling interests and
redeemable noncontrolling interests
(90)
(48)
Earnings/(loss) attributable to Enbridge Inc.
(311)
445
Preference share dividends
(72)
(55)
Earnings/(loss) attributable to Enbridge Inc. common shareholders
(383)
390
Earnings/(loss) attributable to Enbridge Inc. common shareholders
Earnings/(loss) from continuing operations
(383)
344
Earnings from discontinued operations, net of tax
-
46
(383)
390
Earnings/(loss) per common share attributable to Enbridge Inc. common
shareholders (Note 7)
Continuing operations
(0.46)
0.42
Discontinued operations
-
0.06
(0.46)
0.48
Diluted earnings/(loss) per common share attributable to Enbridge Inc. common
shareholders (Note 7)
Continuing operations
(0.46)
0.41
Discontinued operations
-
0.06
(0.46)
0.47
2
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
See accompanying notes to the unaudited interim consolidated financial statements.
Three months ended
March 31,
2015
2014
(unaudited; millions of Canadian dollars)
Earnings/(loss)
(221)
493
Other comprehensive income/(loss), net of tax
Change in unrealized loss on cash flow hedges
(505)
(304)
Change in unrealized loss on net investment hedges
(426)
(89)
Other comprehensive income from equity investees
9
4
Reclassification to earnings of realized cash flow hedges
(9)
40
Reclassification to earnings of unrealized cash flow hedges
(30)
20
Reclassification to earnings of pension plans and other postretirement
benefits (OPEB) amortization amounts
4
1
Change in foreign currency translation adjustment
1,597
523
Other comprehensive income
640
195
Comprehensive income
419
688
Comprehensive income attributable to noncontrolling interests and
redeemable noncontrolling interests
(125)
(141)
Comprehensive income attributable to Enbridge Inc.
294
547
Preference share dividends
(72)
(55)
Comprehensive income attributable to Enbridge Inc. common shareholders
222
492
3
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
See accompanying notes to the unaudited interim consolidated financial statements.
Three months ended
March 31,
2015
2014
(unaudited; millions of Canadian dollars, except per share amounts)
Preference shares
Balance at beginning of period
6,515
5,141
Preference shares issued
-
270
Balance at end of period
6,515
5,411
Common shares
Balance at beginning of period
6,669
5,744
Dividend reinvestment and share purchase plan
155
106
Shares issued on exercise of stock options
13
24
Balance at end of period
6,837
5,874
Additional paid-in capital
Balance at beginning of period
2,549
746
Drop down of interest to Enbridge Energy Partners, L.P. (Note 9)
218
-
Stock-based compensation
16
12
Options exercised
(5)
(9)
Dilution gains and other
34
(4)
Balance at end of period
2,812
745
Retained earnings
Balance at beginning of period
1,571
2,550
Earnings/(loss) attributable to Enbridge Inc.
(311)
445
Preference share dividends
(72)
(55)
Common share dividends declared
(396)
(291)
Dividends paid to reciprocal shareholder
6
4
Redemption value adjustment attributable to redeemable noncontrolling interests
182
(148)
Balance at end of period
980
2,505
Accumulated other comprehensive income/(loss) (Note 8)
Balance at beginning of period
(435)
(599)
Other comprehensive income attributable to Enbridge Inc. common shareholders
605
102
Balance at end of period
170
(497)
Reciprocal shareholding - balance at beginning and end of period
(83)
(86)
Total Enbridge Inc. shareholders' equity
17,231
13,952
Noncontrolling interests
Balance at beginning of period
2,015
4,014
Earnings attributable to noncontrolling interests
74
45
Other comprehensive income/(loss) attributable to noncontrolling interests, net of tax
Change in unrealized loss on cash flow hedges
(111)
(70)
Change in foreign currency translation adjustment
157
155
Reclassification to earnings of realized cash flow hedges
(4)
10
Reclassification to earnings of unrealized cash flow hedges
(23)
3
19
98
Comprehensive income attributable to noncontrolling interests
93
143
Distributions
(158)
(130)
Contributions
525
41
Drop down of interest to Enbridge Energy Partners, L.P. (Note 9)
(304)
-
Dilution loss
(53)
-
Other
2
(2)
Balance at end of period
2,120
4,066
Total equity
19,351
18,018
Dividends paid per common share
0.465
0.350
4
CONSOLIDATED STATEMENTS OF CASH FLOWS
See accompanying notes to the unaudited interim consolidated financial statements.
Three months ended
March 31,
2015
2014
(unaudited; millions of Canadian dollars)
Operating activities
Earnings/(loss)
(221)
493
Earnings from discontinued operations
-
(46)
Depreciation and amortization
474
366
Deferred income taxes
(322)
69
Changes in unrealized loss on derivative instruments, net
1,483
244
Cash distributions in excess of equity earnings
46
12
Gain on disposition
(5)
(16)
Hedge ineffectiveness (Note 10)
(18)
26
Inventory revaluation allowance
43
2
Other
(106)
34
Changes in regulatory assets and liabilities
11
5
Changes in environmental liabilities, net of recoveries
(10)
(46)
Changes in operating assets and liabilities
135
(829)
Cash provided by continuing operations
1,510
314
Cash provided by discontinued operations (Note 4)
-
19
1,510
333
Investing activities
Additions to property, plant and equipment
(1,590)
(2,408)
Long-term investments
(142)
(313)
Additions to intangible assets
(19)
(53)
Acquisition
(106)
-
Proceeds from disposition
-
19
Affiliate loans, net
3
3
Changes in restricted cash
(12)
5
Cash provided by continuing operations
(1,866)
(2,747)
Cash provided by discontinued operations (Note 4)
-
4
(1,866)
(2,743)
Financing activities
Net change in bank indebtedness and short-term borrowings
(456)
361
Net change in commercial paper and credit facility draws
1,021
838
Debenture and term note issues
-
1,528
Debenture and term note repayments
(376)
(200)
Contributions from noncontrolling interests
525
41
Distributions to noncontrolling interests
(158)
(130)
Distributions to redeemable noncontrolling interests
(27)
(18)
Preference shares issued
-
268
Common shares issued
8
16
Preference share dividends
(71)
(54)
Common share dividends
(241)
(185)
225
2,465
Effect of translation of foreign denominated cash and cash equivalents
61
18
Increase/(decrease) in cash and cash equivalents
(70)
73
Cash and cash equivalents at beginning of period - discontinued operations
-
20
Cash and cash equivalents at beginning of period - continuing operations
1,261
756
Cash and cash equivalents at end of period
1,191
849
5
CONSOLIDATED STATEMENTS OF FINANCIAL POSITION
March 31,
2015
December 31,
2014
(unaudited; millions of Canadian dollars; number of shares in millions)
Assets
Current assets
Cash and cash equivalents
1,191
1,261
Restricted cash
59
47
Accounts receivable and other (Note 5)
5,392
5,504
Accounts receivable from affiliates
86
241
Inventory
1,041
1,148
7,769
8,201
Property, plant and equipment, net
57,861
53,830
Long-term investments
6,120
5,408
Deferred amounts and other assets
3,210
3,208
Intangible assets, net
1,235
1,166
Goodwill
525
483
Deferred income taxes
745
561
77,465
72,857
Liabilities and equity
Current liabilities
Bank indebtedness
269
507
Short-term borrowings
823
1,041
Accounts payable and other
7,287
6,444
Accounts payable to affiliates
45
80
Interest payable
325
264
Environmental liabilities
158
161
Current maturities of long-term debt (Note 6)
660
1,004
9,567
9,501
Long-term debt (Note 6)
35,785
33,423
Other long-term liabilities
5,740
4,041
Deferred income taxes
4,948
4,842
56,040
51,807
Contingencies (Note 13)
Redeemable noncontrolling interests
2,074
2,249
Equity
Share capital
Preference shares
6,515
6,515
Common shares (855 and 852 outstanding at March 31, 2015 and
December 31, 2014, respectively)
6,837
6,669
Additional paid-in capital
2,812
2,549
Retained earnings
980
1,571
Accumulated other comprehensive income/(loss) (Note 8)
170
(435)
Reciprocal shareholding
(83)
(83)
Total Enbridge Inc. shareholders’ equity
17,231
16,786
Noncontrolling interests
2,120
2,015
19,351
18,801
77,465
72,857
See accompanying notes to the unaudited consolidated financial statements.
6
NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
1. BASIS OF PRESENTATION
The accompanying unaudited interim consolidated financial statements of Enbridge Inc. (Enbridge or the
Company) have been prepared in accordance with accounting principles generally accepted in the United
States of America (U.S. GAAP) and Regulation S-X for interim consolidated financial information.
Accordingly, they do not include all of the information and footnotes required by U.S. GAAP for complete
consolidated financial statements and should be read in conjunction with the Company’s consolidated
financial statements and notes thereto for the year ended December 31, 2014. In the opinion of
management, the interim consolidated financial statements contain all adjustments, consisting only of
normal recurring adjustments with the exception of an out-of-period adjustment further described in Note
3, Segmented Information, which management considers necessary to present fairly the Company’s
financial position as at March 31, 2015 and results of operations and cash flows for the three month s
ended March 31, 2015 and 2014. These interim consolidated financial statements follow the same
significant accounting policies as those included in the Company’s consolidated financial statements as at
and for the year ended December 31, 2014, except for the adoption of new standards (Note 2). Amounts
are stated in Canadian dollars unless otherwise noted.
The Company’s operations and earnings for interim periods can be affected by seasonal fluctuations
within the gas distribution utility business, as well as other factors such as the supply of and demand for
crude oil and natural gas.
2. SIGNIFICANT ACCOUNTING POLICIES
ADOPTION OF NEW STANDARDS
Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity
Effective January 1, 2015, the Company prospectively adopted Accounting Standards Update (ASU)
2014-08 which changes the criteria and disclosures for reporting discontinued operations. The revised
criteria will in general, result in fewer transactions being categorized as discontinued operations. There
was no material impact to the consolidated financial statements as a result of adopting this update.
FUTURE ACCOUNTING POLICY CHANGES
Measurement Date of Defined Benefit Obligation and Plan Assets
ASU 2015-04 was issued in April 2015 with the intent to simplify the fair value measurement of defined
benefit plan assets and obligations. For entities with a fiscal year end that does not coincide with a month
end, the new standard permits an entity to measure its defined benefit plan assets and obligations using
the month end that is closest to the entity’s fiscal year end. In addition, where there are significant events
in an interim period that would trigger a re-measurement of the plan assets and obligations, an entity is
also permitted to re-measure such assets and obligations using the month end that is closest to the date
of the significant event. The accounting update is effective for financial statements issued for fiscal years
beginning after December 15, 2015 and is to be applied on a prospective basis. The adoption of the
pronouncement is not anticipated to have a material impact on the Company’s consolidated financial
statements.
Simplifying the Presentation of Debt Issuance Costs
ASU 2015-03 was issued in April 2015 with the intent to simplify the presentation of debt issuance costs.
The new standard requires a debt issuance cost related to a recognized debt liability to be presented in
the balance sheet as a direct deduction from the carrying amount of that debt liability, as consistent with
the presentation of debt discounts or premiums. This accounting update is effective for financial
statements issued for fiscal years beginning after December 15, 2015 on a retrospective basis. The
adoption of the pronouncement is not anticipated to have a material impact on the Company’s
consolidated financial statements.
7
Amendments to the Consolidation Analysis
ASU 2015-02, issued in February 2015, revises the current consolidation guidance which results in a
change in the determination of whether an entity consolidates certain types of legal entities. The
Company is currently assessing the impact of the new standard on its consolidated financial statements.
The new standard is effective for annual and interim reporting periods beginning after December 15, 2015
and may be applied on a full or modified retrospective basis.
Revenue from Contracts with Customers
ASU 2014-09 was issued in May 2014 with the intent of significantly enhancing comparability of revenue
recognition practices across entities and industries. The new standard provides a single principles-based,
five-step model to be applied to all contracts with customers and introduces new, increased disclosure
requirements. The Company is currently assessing the impact of the new standard on its consolidated
financial statements. The new standard is effective for annual and interim periods beginning on or after
December 15, 2016 and may be applied on either a full or modified retrospective basis.
3. SEGMENTED INFORMATION
Three months ended March 31, 2015
Liquids
Pipelines
Gas
Distribution
Gas Pipelines,
Processing
and Energy
Services
Sponsored
Investments Corporate
1
Consolidated
(millions of Canadian dollars)
Revenues
29 1,788 4,232 1,880 - 7,929
Commodity and gas distribution costs
- (1,364) (4,092) (948) (2) (6,406)
Operating and administrative
(422) (134) (55) (384) 4 (991)
Depreciation and amortization
(150) (77) (48) (194) (5) (474)
Environmental costs, net of recoveries
12 - - (1) - 11
(531) 213 37 353 (3) 69
Income from equity investments
60 - 14 45 14 133
Other income/(expense)
(4) (1) 6 (9) (449) (457)
Interest income/(expense)
(142) (42) (30) (86) 49 (251)
Income taxes recovery/(expense)
196 (31) (12) (82) 214 285
Earnings/(loss)
(421) 139 15 221 (175) (221)
(Earnings)/loss attributable to noncontrolling
interests and redeemable noncontrolling
interests
(1) - 1 (90) - (90)
Preference share dividends
- - - - (72) (72)
Earnings/(loss) attributable to Enbridge Inc.
common shareholders
(422) 139 16 131 (247) (383)
Additions to property, plant and equipment
2
824 106 80 566 14 1,590
8
Three months ended March 31, 2014
Liquids
Pipelines
Gas
Distribution
Gas Pipelines,
Processing
and Energy
Services
Sponsored
Investments Corporate
1
Consolidated
(millions of Canadian dollars)
Revenues 447 1,285 6,422 2,367 - 10,521
Commodity and gas distribution costs - (846) (6,119) (1,614) - (8,579)
Operating and administrative (256) (133) (34) (323) 1 (745)
Depreciation and amortization (117) (84) (12) (149) (4) (366)
Environmental costs, net of recoveries - - - (5) - (5)
74 222 257 276 (3) 826
Income from equity investments
36 - 49 18 11 114
Other income/(expense)
1 3 5 (1) (146) (138)
Interest income/(expense)
(87) (40) (18) (111) 18 (238)
Income taxes recovery/(expense)
21 (49) (102) (51) 64 (117)
Earnings/(loss) from continuing operations
45 136 191 131 (56) 447
Discontinued operations
Earnings from discontinued operations before
income taxes - - 73 - - 73
Income taxes from discontinued operations - - (27) - - (27)
Earnings from discontinued operations - - 46 - - 46
Earnings/(loss) 45 136 237 131 (56) 493
Earnings attributable to noncontrolling interests
and redeemable noncontrolling interests (1) - - (47) - (48)
Preference share dividends
- - - - (55) (55)
Earnings/(loss) attributable to Enbridge Inc.
common shareholders 44 136 237 84 (111) 390
Additions to property, plant and equipment
2
1,498 97 118 682 14 2,409
1 Included within the Corporate segment was Interest income of $196 million (2014 - $155 million) charged to other operating
segments.
2 Includes allowance for equity funds used during construction.
OUT-OF-PERIOD ADJUSTMENT
Earnings attributable to Enbridge Inc. common shareholders for the three months ended March 31, 2015
were increased by an out-of-period adjustment of $71 million within the Corporate segment in respect of
an overstatement of deferred income tax expense in 2013 and 2014.
TOTAL ASSETS
March 31,
2015
December 31,
2014
(millions of Canadian dollars)
Liquids Pipelines
29,536
27,657
Gas Distribution
9,143
9,320
Gas Pipelines, Processing and Energy Services
8,183
7,601
Sponsored Investments
25,751
23,515
Corporate
4,852
4,764
77,465
72,857
4. DISCONTINUED OPERATIONS
In March 2014, the Company completed the sale of certain of its Enbridge Offshore Pipelines assets
located within the Stingray corridor to an unrelated third party for cash proceeds of $11 million (US$10
million), subject to working capital adjustments. The gain of $70 million (US$63 million), which resulted
from the cash proceeds and the disposition of net liabilities held for sale of $59 million (US$53 million), is
presented as Earnings from discontinued operations for the three months ended March 31, 2014. The
results of operations, including revenues of $4 million and related cash flows, have also been presented
as discontinued operations for the three months ended March 31, 2014. These amounts are included
within the Gas Pipelines, Processing and Energy Services segment.
9
5. ACCOUNTS RECEIVABLE AND OTHER
Pursuant to a Receivables Purchase Agreement (the Receivables Agreement) executed in 2013, certain
trade and accrued receivables (the Receivables) have been sold by certain Enbridge Energy Partners,
L.P. (EEP) subsidiaries to an Enbridge wholly-owned special purpose entity (SPE). The Receivables
owned by the SPE are not available to Enbridge except through its 100% ownership in such SPE. The
Receivables Agreement provides for purchases to occur on a monthly basis through to December 2016,
provided accumulated purchases net of collections do not exceed US$450 million at any one point. The
value of trade and accrued receivables outstanding owned by the SPE totalled US$364 million ($462
million) and US$378 million ($439 million) as at March 31, 2015 and December 31, 2014, respectively.
6. DEBT
The following table provides details of the Company’s committed credit facilities at March 31, 2015 and
December 31, 2014.
March 31, 2015
December 31,
2014
Maturity
Dates
Total
Facilities Draws
1
Available
Total
Facilities
(millions of Canadian dollars)
Liquids Pipelines
2016
300 296 4
300
Gas Distribution
2016-2019
1,009 829 180
1,008
Sponsored Investments
2016-2019
4,907 3,483 1,424
4,531
Corporate
2016-2019
13,365 6,857 6,508
12,772
Total committed credit facilities
19,581 11,465 8,116
18,611
1 Includes facility draws, letters of credit and commercial paper issuances that are back-stopped by the credit facility.
In addition to the committed credit facilities noted above, the Company also has $385 million (December
31, 2014 - $361 million) of uncommitted demand credit facilities, of which $103 million (December 31,
2014 - $80 million) was unutilized as at March 31, 2015.
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
2016 to 2019.
Commercial paper and credit facility draws, net of short-term borrowings, of $10,387 million (December
31, 2014 - $8,960 million) are supported by the availability of long-term committed credit facilities and
therefore have been classified as long-term debt.
10
7. 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 common
shares outstanding has been reduced by the Company’s pro-rata weighted average interest in its own
common shares of 12 million (2014 - 12 million) for the three months ended March 31, 2015, resulting
from the Company’s reciprocal investment in Noverco Inc.
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.
Three months ended
March 31,
2015
2014
(number of shares in millions)
Weighted average shares outstanding
841
820
Effect of dilutive options
13
10
Diluted weighted average shares outstanding
854
830
For the three months ended March 31, 2015, 5,851,770 anti-dilutive stock options (2014 - 12,209,636)
with a weighted average exercise price of $59.14 (2014 - $46.77) were excluded from the diluted
earnings per common share calculation.
8. COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME
Changes in Accumulated other comprehensive income/(loss) (AOCI) attributable to Enbridge common
shareholders for the three months ended March 31, 2015 and 2014 are as follows:
Cash Flow
Hedges
Net
Investment
Hedges
Cumulative
Translation
Adjustment
Equity
Investees
Pension and
OPEB
Amortization
Adjustment Total
(millions of Canadian dollars)
Balance at January 1, 2015
(488) 108 309 (5) (359) (435)
Other comprehensive income/(loss) retained in AOCI
(515) (457) 1,413 10 - 451
Other comprehensive gains/(loss) reclassified to earnings
Interest rate contracts
1
(7) - - - - (7)
Commodity contracts
2
(10) - - - - (10)
Other contracts
4
5 - - - - 5
Amortization of pension and OPEB actuarial loss
5
- - - - 6 6
(527) (457) 1,413 10 6 445
Tax impact
Income tax on amounts retained in AOCI
132 31 - (1) - 162
Income tax on amounts reclassified to earnings
- - - - (2) (2)
132 31 - (1) (2) 160
Balance at March 31, 2015
(883) (318) 1,722 4 (355) 170
11
Cash Flow
Hedges
Net
Investment
Hedges
Cumulative
Translation
Adjustment
Equity
Investees
Pension and
OPEB
Amortization
Adjustment Total
(millions of Canadian dollars)
Balance at January 1, 2014 (1) 378 (778) (15) (183) (599)
Other comprehensive income/(loss) retained in AOCI (308) (103) 368 4 - (39)
Other comprehensive gains/(loss) reclassified to earnings
Interest rate contracts
1
37 - - - - 37
Commodity contracts
2
4 - - - - 4
Foreign exchange contracts
3
15 - - - - 15
Other contracts
4
(4) - - - - (4)
Amortization of pension and OPEB actuarial loss
5
- - - - 3 3
(256) (103) 368 4 3 16
Tax impact
Income tax on amounts retained in AOCI
79 14 - - - 93
Income tax on amounts reclassified to earnings
(5) - - - (2) (7)
74 14 - - (2) 86
Balance at March 31, 2014 (183) 289 (410) (11) (182) (497)
1 Reported within Interest expense in the Consolidated Statements of Earnings.
2 Reported within Commodity costs in the Consolidated Statements of Earnings.
3 Reported within Other expense in the Consolidated Statements of Earnings.
4 Reported within Operating and administrative expense in the Consolidated Statements of Earnings.
5 These components are included in the computation of net periodic pension costs and are reported within Operating and administrative
expense in the Consolidated Statements of Earnings.
9. NONCONTROLLING INTERESTS
ALBERTA CLIPPER DROP DOWN
On January 2, 2015, Enbridge transferred its 66.7% interest in the United States segment of the Alberta
Clipper pipeline, held through a wholly-owned Enbridge subsidiary in the United States, to EEP for
aggregate consideration of $1.1 billion (US$1 billion), consisting of approximately $814 million (US$694
million) of Class E equity units issued to Enbridge by EEP and the repayment of approximately $359
million (US$306 million) of indebtedness owed to Enbridge. Prior to the transfer, EEP owned the
remaining 33.3% interest in the United States segment of the Alberta Clipper pipeline.
The Class E units issued to Enbridge are entitled to the same distributions as the Class A units held by
the public and are convertible into Class A units on a one-for-one basis at Enbridge's option. The
transaction applies to all distributions declared subsequent to the transfer. The Class E units are
redeemable at EEP's option after 30 years, if not converted by Enbridge prior to that time. The units have
a liquidation preference equal to their notional value at December 23, 2014 of US$38.31 per unit, which
was determined based on the trailing five-day volume-weighted average price of EEP's Class A common
units. Enbridge’s economic interest in EEP increased from 33.7% to 36.6% as a result of the transfer.
EEP recorded the Class E units at fair value. As a result, the Company recorded a decrease in
Noncontrolling interests of $304 million and increases in Additional paid-in capital and Deferred income
tax liabilities of $218 and $86 million, respectively.
EEP ISSUANCE OF CLASS A UNITS
In March 2015, EEP completed a listed share issuance. The Company participated only to the extent to
maintain its 2% General Partner interest, resulting in a decrease in the overall economic interest from
36.6% to 35.9%. The listed share issuance resulted in contributions of $366 million (US $289 million) from
noncontrolling interest holders.
12
10. RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
MARKET 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 risk). Formal risk management policies, processes and systems have been designed to mitigate
these risks.
The following summarizes the types of market risks to which the Company is exposed and the risk
management instruments used to mitigate them. The Company uses a combination of qualifying and non-
qualifying derivative instruments to manage the risks noted below.
Foreign Exchange Risk
The Company generates certain revenues, incurs expenses, and holds a number of investments and
subsidiaries that are denominated in currencies other than Canadian dollars. As a result, the Company’s
earnings, cash flows and OCI are exposed to fluctuations resulting from foreign exchange rate variability.
The Company has implemented a policy whereby, at a minimum, it hedges a level of foreign currency
denominated earnings exposures over a five year forecast horizon. A combination of qualifying and non-
qualifying derivative instruments is used to hedge anticipated foreign currency denominated revenues
and expenses, and to manage variability in cash flows. The Company hedges certain net investments in
United States dollar denominated investments and subsidiaries using foreign currency derivatives and
United States dollar denominated debt.
Interest Rate Risk
The Company’s earnings and cash flows are exposed to short-term interest rate variability due to the
regular repricing of its variable rate debt, primarily commercial paper. Pay fixed-receive floating interest
rate swaps and options are used to hedge against the effect of future interest rate movements. The
Company has implemented a program to significantly mitigate the impact of short-term interest rate
volatility on interest expense through 2019 via execution of floating to fixed interest rate swaps 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 2019 via execution of floating to fixed interest rate swaps with an average swap rate of
4.0%.
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 of a maximum
of 25% floating rate debt as a percentage of total debt outstanding. The Company primarily uses
qualifying derivative instruments to manage interest rate risk.
Commodity Price Risk
The Company’s earnings and cash flows are exposed to changes in commodity prices as a result of its
ownership interest 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 natural gas liquids
(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
13
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.
TOTAL DERIVATIVE INSTRUMENTS
The following table summarizes the Consolidated Statements of Financial Position location and carrying
value of the Company’s derivative instruments. The Company did not have any outstanding fair value
hedges as at March 31, 2015 or December 31, 2014.
The Company generally has a policy of entering into individual International Swaps and Derivatives
Association, Inc. (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 the
counterparties in these particular circumstances. The following table also summarizes the maximum
potential settlement in the event of these specific circumstances. All amounts are presented gross in the
Consolidated Statements of Financial Position.
Derivative
Instruments
Used as
Cash Flow
Hedges
Derivative
Instruments
Used as Net
Investment
Hedges
Non-
Qualifying
Derivative
Instruments
Total Gross
Derivative
Instruments
as Presented
Amounts
Available
for Offset
Total Net
Derivative
Instruments
March 31, 2015
(millions of Canadian dollars)
Accounts receivable and other
Foreign exchange contracts
4 5 1 10 (7) 3
Interest rate contracts
3 - - 3 (3) -
Commodity contracts
26 - 384 410 (164) 246
Other contracts
2 - 10 12 - 12
35 5 395 435 (174) 261
Deferred amounts and other assets
Foreign exchange contracts
74 11 - 85 (85) -
Interest rate contracts
- - - - - -
Commodity contracts
24 - 120 144 (12) 132
Other contracts
4 - 3 7 - 7
102 11 123 236 (97) 139
Accounts payable and other
Foreign exchange contracts
- (80) (442) (522) 7 (515)
Interest rate contracts
(684) - - (684) 3 (681)
Commodity contracts
- - (298) (298) 94 (204)
(684) (80) (740) (1,504) 104 (1,400)
Other long-term liabilities
Foreign exchange contracts
- (163) (2,214) (2,377) 85 (2,292)
Interest rate contracts
(974) - - (974) - (974)
Commodity contracts
- - (366) (366) 54 (312)
(974) (163) (2,580) (3,717) 139 (3,578)
Total net derivative asset/(liability)
Foreign exchange contracts
78 (227) (2,655) (2,804) - (2,804)
Interest rate contracts
(1,655) - - (1,655) - (1,655)
Commodity contracts
50 - (160) (110) (28)
1
(138)
Other contracts
6 - 13 19 - 19
(1,521) (227) (2,802) (4,550) (28) (4,578)
1 Amount available for offset includes $28 million of cash collateral.
14
Derivative
Instruments
Used as
Cash Flow
Hedges
Derivative
Instruments
Used as Net
Investment
Hedges
Non-Qualifying
Derivative
Instruments
Total Gross
Derivative
Instruments
as Presented
Amounts
Available
for Offset
Total Net
Derivative
Instruments December 31, 2014
(millions of Canadian dollars)
Accounts receivable and other
Foreign exchange contracts 3 7 3 13 (13) -
Interest rate contracts 8 - - 8 (7) 1
Commodity contracts 34 - 501 535 (130) 405
Other contracts 4 - 8 12 - 12
49 7 512 568 (150) 418
Deferred amounts and other assets
Foreign exchange contracts 33 18 - 51 (51) -
Interest rate contracts 5 - - 5 (5) -
Commodity contracts 17 - 118 135 (43) 92
Other contracts 5 - 3 8 - 8
60 18 121 199 (99) 100
Accounts payable and other
Foreign exchange contracts (3) (80) (218) (301) 13 (288)
Interest rate contracts (438) - - (438) 7 (431)
Commodity contracts - - (281) (281) 97 (184)
(441) (80) (499) (1,020) 117 (903)
Other long-term liabilities
Foreign exchange contracts - (49) (1,147) (1,196) 51 (1,145)
Interest rate contracts (576) - - (576) 5 (571)
Commodity contracts - - (306) (306) 43 (263)
(576) (49) (1,453) (2,078) 99 (1,979)
Total net derivative asset/(liability)
Foreign exchange contracts 33 (104) (1,362) (1,433) - (1,433)
Interest rate contracts (1,001) - - (1,001) - (1,001)
Commodity contracts 51 - 32 83 (33)
1
50
Other contracts 9 - 11 20 - 20
(908) (104) (1,319) (2,331) (33) (2,364)
1 Amount available for offset includes $33 million of cash collateral.
The following table summarizes the maturity and notional principal or quantity outstanding related to the
Company’s derivative instruments.
March 31, 2015
2015 2016 2017 2018 2019 Thereafter
Foreign exchange contracts - United States dollar
forwards - purchase (millions of United States
dollars)
272 25 413 2 2 2
Foreign exchange contracts - United States dollar
forwards - sell (millions of United States dollars)
2,478 2,690 2,832 3,100 2,441 2,901
Foreign exchange contracts - Euro forwards -
purchase (millions of Euros)
1 - - - - -
Interest rate contracts - short-term borrowings
(millions of Canadian dollars)
4,531 5,728 5,039 3,669 234 490
Interest rate contracts - long-term debt (millions of
Canadian dollars)
3,723 1,816 2,524 1,214 - -
Equity contracts (millions of Canadian dollars)
41 51 - - - -
Commodity contracts - natural gas (billions of cubic
feet)
(49) (38) (37) (17) 2 -
Commodity contracts - crude oil (millions of barrels)
- (18) (18) (9) - -
Commodity contracts - NGL (millions of barrels)
(12) (9) - - - -
Commodity contracts - power (megawatt hours
(MWH))
22 40 40 30 31 (23)
15
December 31, 2014 2015 2016 2017 2018 2019 Thereafter
Foreign exchange contracts - United States dollar
forwards - purchase (millions of United States
dollars)
240 25 413 2 2 2
Foreign exchange contracts - United States dollar
forwards - sell (millions of United States dollars) 3,203 2,470 2,832 3,100 2,441 2,901
Foreign exchange contracts - Euro forwards -
purchase (millions of Euros) 15 - - - - -
Interest rate contracts - short-term borrowings
(millions of Canadian dollars)
5,767 5,486 4,851 3,529 222 469
Interest rate contracts - long-term debt (millions of
Canadian dollars)
3,528 1,762 2,470 1,176 - -
Equity contracts (millions of Canadian dollars)
41 51 - - - -
Commodity contracts - natural gas (billions of cubic
feet)
(62) (10) (25) (1) - -
Commodity contracts - crude oil (millions of barrels) 3 (18) (18) (9) - -
Commodity contracts - NGL (millions of barrels) (5) - - - - -
Commodity contracts - power (MWH) 25 40 40 30 31 -
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
The following table presents the effect of cash flow hedges and net investment hedges on the Company’s
consolidated earnings and consolidated comprehensive income, before the effect of income taxes.
Three months ended
March 31,
2015
2014
(millions of Canadian dollars)
Amount of unrealized gains/(loss) recognized in OCI
Cash flow hedges
Foreign exchange contracts
45
29
Interest rate contracts
(664)
(242)
Commodity contracts
19
(7)
Other contracts
(8)
5
Net investment hedges
Foreign exchange contracts
(123)
(48)
(731)
(263)
Amount of gains/(loss) reclassified from AOCI to earnings
(effective portion)
Foreign exchange contracts
1
-
(1)
Interest rate contracts
2
10
21
Commodity contracts
3
(20)
7
Other contracts
4
5
(4)
(5)
23
Amount of gains/(loss) reclassified from AOCI to earnings
(ineffective portion
and amount excluded from effectiveness testing)
Interest rate contracts
2
(23)
25
Commodity contracts
3
5
1
(18)
26
1 Reported within Transportation and other services revenues in the Consolidated Statements of Earnings.
2 Reported as an increase/(decrease)within Interest expense in the Consolidated Statements of Earnings.
3 Reported within Commodity costs in the Consolidated Statements of Earnings.
4 Reported within Operating and administrative expense in the Consolidated Statements of Earnings.
The Company estimates that $102 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 45 months as at March 31, 2015.
16
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.
Three months ended
March 31,
2015
2014
(millions of Canadian dollars)
Foreign exchange contracts
1
(1,293)
(420)
Interest rate contracts
2
-
1
Commodity contracts
3
(192)
173
Other contracts
4
2
5
Total unrealized derivative fair value loss
(1,483)
(241)
1 Reported within Transportation and other services revenues (2015 - $795 million loss; 2014 - $231 million loss) and Other
expense (2015 - $498 million loss; 2014 - $189 million loss) in the Consolidated Statements of Earnings.
2 Reported as an increase/(decrease) within Interest expense in the Consolidated Statements of Earnings.
3 Reported within Transportation and other services revenues (2015 - $18 million loss; 2014 - $134 million gain), Commodity
costs (2015 - $143 million loss; 2014 - $40 million gain) and Operating and administrative expense (2015 - $31 million loss;
2014 - $1 million loss) in the Consolidated Statements of Earnings.
4 Reported within Operating and administrative expense in the Consolidated Statements of Earnings.
LIQUIDITY RISK
Liquidity risk is the risk 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. The Company, through committed credit
facilities with a diversified group of banks and institutions, targets to maintain sufficient liquidity to enable
it to fund all anticipated requirements for approximately 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
March 31, 2015. 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. In order to mitigate this risk,
the Company enters into risk management transactions primarily with institutions that possess investment
grade credit ratings. Credit risk relating to derivative counterparties is mitigated by credit exposure limits
and contractual requirements, frequent assessment of counterparty credit ratings and netting
arrangements.
The Company had group credit concentrations and maximum credit exposure, with respect to derivative
instruments, in the following counterparty segments:
March 31,
2015
December 31,
2014
(millions of Canadian dollars)
Canadian financial institutions
60
58
United States financial institutions
257
240
European financial institutions
60
73
Other
1
160
310
537
681
1 Other is comprised of commodity clearing house and physical natural gas and crude oil counterparties.
As at March 31, 2015, the Company had provided letters of credit totalling $456 million in lieu of providing
cash collateral to its counterparties pursuant to the terms of the relevant ISDA agreements. The Company
17
held $28 million of cash collateral on derivative asset exposures as at March 31, 2015 and $33 million of
cash collateral as at December 31, 2014.
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.
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’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 are 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 FINANCIAL INSTRUMENTS
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.
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
18
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, basis swaps, commodity swaps, power and energy swaps, as well as options. The
Company does not have any other financial instruments categorized in Level 3.
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 price) 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:
March 31, 2015
Level 1 Level 2 Level 3
Total Gross
Derivative
Instruments
(millions of Canadian dollars)
Financial assets
Current derivative assets
Foreign exchange contracts
- 10 - 10
Interest rate contracts
- 3 - 3
Commodity contracts
28 126 256 410
Other contracts
- 12 - 12
28 151 256 435
Long-term derivative assets
Foreign exchange contracts
- 85 - 85
Interest rate contracts
- - - -
Commodity contracts
- 18 126 144
Other contracts
- 7 - 7
- 110 126 236
Financial liabilities
Current derivative liabilities
Foreign exchange contracts
- (522) - (522)
Interest rate contracts
- (684) - (684)
Commodity contracts
(19) (117) (162) (298)
(19) (1,323) (162) (1,504)
Long-term derivative liabilities
Foreign exchange contracts
- (2,377) - (2,377)
Interest rate contracts
- (974) - (974)
Commodity contracts
- (139) (227) (366)
- (3,490) (227) (3,717)
Total net financial asset/(liability)
Foreign exchange contracts
- (2,804) - (2,804)
Interest rate contracts
- (1,655) - (1,655)
Commodity contracts
9 (112) (7) (110)
Other contracts
- 19 - 19
9 (4,552) (7) (4,550)
19
December 31, 2014 Level 1 Level 2 Level 3
Total Gross
Derivative
Instruments
(millions of Canadian dollars)
Financial assets
Current derivative assets
Foreign exchange contracts
- 13 - 13
Interest rate contracts
- 8 - 8
Commodity contracts
62 140 333 535
Other contracts
- 12 - 12
62 173 333 568
Long-term derivative assets
Foreign exchange contracts - 51 - 51
Interest rate contracts - 5 - 5
Commodity contracts - 22 113 135
Other contracts - 8 - 8
- 86 113 199
Financial liabilities
Current derivative liabilities
Foreign exchange contracts - (301) - (301)
Interest rate contracts - (438) - (438)
Commodity contracts (28) (137) (116) (281)
(28) (876) (116) (1,020)
Long-term derivative liabilities
Foreign exchange contracts - (1,196) - (1,196)
Interest rate contracts - (576) - (576)
Commodity contracts - (125) (181) (306)
- (1,897) (181) (2,078)
Total net financial asset/(liability)
Foreign exchange contracts - (1,433) - (1,433)
Interest rate contracts - (1,001) - (1,001)
Commodity contracts 34 (100) 149 83
Other contracts - 20 - 20
34 (2,514) 149 (2,331)
The significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
were as follows:
March 31, 2015
Fair Value
Unobservable
Input
Minimum
Price
Maximum
Price
Weighted
Average Price
(fair value in millions of Canadian dollars)
Commodity contracts - financial
1
Natural gas (2) Forward gas price 2.83 4.52 3.58 $/mmbtu
3
NGL 35 Forward NGL price 0.23 1.45 1.11 $/gallon
Power (166) Forward power price 30.75 71.50 48.76 $/MWH
Commodity contracts - physical
1
Natural gas (43) Forward gas price 1.28 5.37 3.34 $/mmbtu
3
Crude 40 Forward crude price 34.77 116.05 62.04 $/barrel
NGL 3 Forward NGL price 0.11 1.78 0.85 $/gallon
Commodity options
2
Crude 42 Option volatility 20% 34% 25%
NGL 84 Option volatility 18% 112% 36%
(7)
1 Financial and physical forward commodity contracts are valued using a market approach valuation technique.
2 Commodity options contracts are valued using an option model valuation technique.
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 could result in significantly different
fair values for the Company’s Level 3 derivatives. Changes in price volatility would change the value of
20
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:
Three months ended
March 31,
2015
2014
(millions of Canadian dollars)
Level 3 net derivative asset/(liability) at beginning of period
149
(164)
Total gains/(loss)
Included in earnings
1
(7)
12
Included in OCI
2
5
Settlements
(151)
14
Level 3 net derivative liability at end of period
(7)
(133)
1 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 March 31, 2015 or 2014.
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 totalled $102 million as at March 31, 2015 (December 31, 2014 - $99
million).
The Company has a held to maturity preferred share investment carried at its amortized cost of $352
million as at March 31, 2015 (December 31, 2014 - $323 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%. As at March 31, 2015, the fair value of this preferred
share investment approximates its face value of $580 million (December 31, 2014 - $580 million).
As at March 31, 2015, the Company’s long-term debt had a carrying value of $36,445 million (December
31, 2014 - $34,427 million) and a fair value of $39,489 million (December 31, 2014 - $36,637 million).
NET INVESTMENT HEDGES
The Company has designated a portion of its United States dollar denominated debt, as well as a
portfolio of foreign exchange forward contracts, as a hedge of its net investment in United States dollar
denominated investments and subsidiaries.
During the three months ended March 31, 2015, the Company recognized an unrealized foreign
exchange loss on the translation of United States dollar denominated debt of $331 million (2014 -
unrealized loss of $57 million) and an unrealized loss on the change in fair value of its outstanding foreign
exchange forward contracts of $124 million (2014 - unrealized loss of $49 million) in OCI. The Company
also recognized a realized loss of $2 million (2014 - realized gain of $3 million) in OCI associated with the
settlement of foreign exchange forward contracts that had matured during the period. There was no
ineffectiveness during the three months ended March 31, 2015 (2014 - nil).
21
11. INCOME TAXES
The effective income tax rate for the three months ended March 31, 2015 was a recovery of 56.3% (2014
- 20.7% expense). The period-over-period change in the effective tax rate is primarily attributable to the
rate-regulated tax benefit and other permanent items relative to the loss in the first three months of
2015. The effective income tax rate for the three months ended March 31, 2015 was further impacted by
an out-of-period adjustment (Note 3).
12. RETIREMENT AND POSTRETIREMENT BENEFITS
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 provide Company funded defined benefit pension and/or defined contribution
benefits to Canadian employees of Enbridge. The Enbridge United States pension 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. The Company also provides OPEB, which primarily include supplemental health and dental,
health spending account and life insurance coverage, for qualifying retired employees.
NET BENEFIT COSTS RECOGNIZED
Three months ended
March 31,
2015
2014
(millions of Canadian dollars)
Benefits earned during the period
44
30
Interest cost on projected benefit
obligations
27
26
Expected return on plan assets
(36)
(32)
Amortization of prior service costs
-
-
Amortization of actuarial loss
12
7
Net benefit costs on an accrual basis
1,2
47
31
1 Included in net benefit costs for the three months ended March 31, 2015 are costs related to OPEB of $3 million (2014 - $4
million).
2 For the three months ended March 31, 2015, offsetting regulatory asset of nil (2014 - $2 million regulatory liability) has been
recorded to the extent pension and OPEB costs are expected to be refunded to or collected from customers in future rates.
13. CONTINGENCIES
ENBRIDGE ENERGY PARTNERS, L.P.
Enbridge holds an approximate 35.9% combined direct and indirect economic interest in EEP, which is
consolidated with noncontrolling interests within the Sponsored Investments segment.
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.
EEP continues to perform necessary remediation, restoration and monitoring of the areas affected by the
Line 6B crude oil release. All 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 March 14, 2013, EEP received an order from the Environmental Protection Agency (EPA)
(the Order) which required additional containment and active recovery of submerged oil relating to the
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Line 6B crude oil release. On February 12, 2015, the EPA approved the Submerged Oil Recovery and
Assessment (SORA) work plan with modifications and acknowledged that EEP had completed the
dredging requirements of the Order. At this time, EEP has completed all of the SORA.
Regulatory authority was transferred from the EPA to the Michigan Department of Environmental Quality
(MDEQ). EEP is now working with the MDEQ who has oversight over the submerged oil reassessment,
sheen management and sediment trap monitoring and maintenance activities through a Kalamazoo River
Residual Oil Monitoring and Maintenance Work Plan.
As at March 31, 2015, EEP’s total cost estimate for the Line 6B crude oil release remains at US$1.2
billion ($193 million after-tax attributable to Enbridge).
Expected losses associated with the Line 6B crude oil release included those costs that were considered
probable and that could be reasonably estimated at March 31, 2015. 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. 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 in connection
with this crude oil release. On February 20, 2015, Enbridge, EEP and their affiliates agreed to a consent
order releasing the parties from any claims, liability or penalties.
Insurance Recoveries
EEP is included in the comprehensive insurance program that is maintained by Enbridge for its
subsidiaries and affiliates which renews throughout the year. On May 1 of each year, the insurance
program is up for renewal and includes commercial liability insurance coverage that is consistent with
coverage considered customary for its industry and includes coverage for environmental incidents
excluding costs for fines and penalties.
A majority of the costs incurred in connection with 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 for Enbridge and its affiliates. Including EEP’s remediation
spending through March 31, 2015, costs related to Line 6B exceeded the limits of the coverage available
under this insurance policy. Additionally, fines and penalties would not be covered under the existing
insurance policy. As at March 31, 2015, EEP has recorded total insurance recoveries of US$547 million
($80 million after-tax attributable to Enbridge) for the Line 6B crude oil release out of the US$650 million
aggregate limit. EEP will record receivables for additional amounts it claims for recovery pursuant to its
insurance policies during the period it deems recovery to be probable.
In March 2013, EEP and Enbridge filed a lawsuit against the insurers of US$145 million of coverage, as
one particular insurer is disputing the recovery eligibility for costs related to EEP’s claim on the Line 6B
crude oil release and the other remaining insurers assert that their payment is predicated on the outcome
of the recovery from that insurer. EEP received a partial recovery of US$42 million from the other
remaining insurers and amended its lawsuit such that it included only one insurer.
Of the remaining US$103 million coverage limit, US$85 million was the subject matter of a lawsuit
Enbridge filed against one particular insurer. In March 2015, Enbridge reached an agreement with that
insurer to submit the US$85 million claim to binding arbitration. The recovery of the remaining US$18
million is awaiting resolution of that arbitration. While EEP believes that those costs are eligible for
recovery, there can be no assurance that EEP will prevail in the arbitration.
23
Enbridge has renewed its comprehensive property and liability insurance programs, which are effective
May 1, 2015 through April 30, 2016 with a liability program aggregate limit of US$860 million, which
includes sudden and accidental pollution liability. In the unlikely event that multiple insurable incidents
which in aggregate exceed coverage limits occur within the same insurance period, the total insurance
coverage will be allocated among Enbridge entities on an equitable basis based on an insurance
allocation agreement among Enbridge and its subsidiaries.
Legal and Regulatory Proceedings
A number of United States governmental agencies and regulators have initiated investigations into the
Line 6B crude oil release. Approximately six actions or claims are pending 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, the
Company does not expect the outcome of these actions to be material to the Company’s results of
operations or financial condition.
As at March 31, 2015, included in EEP’s estimated costs related to the Line 6B crude oil release is
US$48 million in fines and penalties. Of this amount, US$40 million related to civil penalties under the
Clean Water Act of the United States. While no final fine or penalty has been assessed or agreed to date,
EEP believes that, based on the best information available at this time, the US$40 million represents an
estimate of the minimum amount which may be assessed, excluding costs of injunctive relief that may be
agreed to with the relevant governmental agencies. Given the complexity of settlement negotiations,
which EEP expects will continue, and the limited information available to assess the matter, EEP is
unable to reasonably estimate the final penalty which might be incurred or to reasonably estimate a range
of outcomes at this time. Injunctive relief is likely to include further measures directed toward enhancing
spill prevention, leak detection and emergency response to environmental events. The cost of compliance
with such measures, when combined with any fine or penalty, could be material. Discussions with
governmental agencies regarding fines, penalties and injunctive relief are ongoing.
TAX MATTERS
Enbridge and its subsidiaries maintain tax liabilities related to uncertain tax positions. While fully
supportable in the Company’s view, these tax positions, if challenged by tax authorities, may not be fully
sustained on review.
OTHER LITIGATION
The Company and its subsidiaries are subject to various other legal and regulatory actions and
proceedings which arise in the normal course of business, including interventions in regulatory
proceedings and challenges to regulatory approvals and permits by special interest groups. While the
final outcome of such actions and proceedings cannot be predicted with certainty, Management believes
that the resolution of such actions and proceedings will not have a material impact on the Company's
consolidated financial position or results of operations.
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