UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C.  20549

 

FORM 6-K

 

Report of Foreign Issuer

Pursuant to Rule 13a-16 or 15d-16 of

the Securities Exchange Act of 1934

 

Dated  November 5, 2015

Commission file number 001-15254

 

 

 

ENBRIDGE INC.

(Exact name of Registrant as specified in its charter)

 

Canada

(State or other jurisdiction

of incorporation or organization)

 

None

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

 

3000, 425 – 1st Street S.W.

Calgary, Alberta, Canada  T2P 3L8

(Address of principal executive offices and postal code)

 

(403) 231-3900

(Registrants telephone number, including area code)

 

 

 

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

 

Form 20-F

 

 

Form 40-F

P

 

 

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

 

Yes

 

 

No

P

 

 

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

 

Yes

 

 

No

P

 

 



 

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

 

Yes

 

 

No

P

 

 

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

 

N/A

 

THIS REPORT ON FORM 6-K SHALL BE DEEMED TO BE INCORPORATED BY REFERENCE IN THE REGISTRATION STATEMENTS ON FORM S-8 (FILE NO. 333-145236, 333-127265, 333-13456, 333-97305 AND 333-6436), FORM F-3 (FILE NO. 333-185591 AND 33-77022) AND FORM F-10 (FILE NO.  333-198566) OF ENBRIDGE INC. AND TO BE PART THEREOF FROM THE DATE ON WHICH THIS REPORT IS FURNISHED, TO THE EXTENT NOT SUPERSEDED BY DOCUMENTS OR REPORTS SUBSEQUENTLY FILED OR FURNISHED.

 

The following documents are being submitted herewith:

 

·                 Interim Report to Shareholders for the nine months ended September 30, 2015.

 

 

SIGNATURES

 

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

 

 

 

 

 

ENBRIDGE INC.

 

 

 

 

(Registrant)

 

 

 

 

 

 

 

 

 

 

Date:

November 5, 2015

 

By:

/s/“Tyler W. Robinson”

 

 

 

 

Tyler W. Robinson
Vice President & Corporate Secretary

 

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ENBRIDGE INC.

 

MANAGEMENT’S DISCUSSION AND ANALYSIS

 

September 30, 2015

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 



 

MANAGEMENT’S DISCUSSION AND ANALYSIS

FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2015

 

This Management’s Discussion and Analysis (MD&A) dated November 4, 2015 should be read in conjunction with the unaudited interim consolidated financial statements and notes thereto of Enbridge Inc. (Enbridge or the Company) as at and for the three and nine months ended September 30, 2015, prepared in accordance with accounting principles generally accepted in the United States of America (U.S. GAAP). It should also be read in conjunction with the audited consolidated financial statements and MD&A contained in the Company’s Annual Report for the year ended December 31, 2014. 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.

 

CONSOLIDATED EARNINGS

 

 

 

Three months ended

 

Nine months ended

 

 

September 30,

 

September 30,

 

 

2015

 

2014

 

2015

 

2014

 

(millions of Canadian dollars, except per share amounts)

 

 

 

 

 

 

 

 

 

Liquids Pipelines1

 

(247)

 

(31)

 

(260)

 

444

 

Gas Distribution

 

(2)

 

(11)

 

176

 

144

 

Gas Pipelines, Processing and Energy Services1

 

104

 

88

 

174

 

386

 

Sponsored Investments1

 

87

 

108

 

182

 

279

 

Corporate

 

(551)

 

(234)

 

(687)

 

(233)

 

Earnings/(loss) attributable to common shareholders from continuing operations

 

(609)

 

(80)

 

(415)

 

1,020

 

Discontinued operations - Gas Pipelines, Processing and Energy Services

 

-

 

-

 

-

 

46

 

Earnings/(loss) attributable to common shareholders

 

(609)

 

(80)

 

(415)

 

1,066

 

Earnings/(loss) per common share

 

(0.72)

 

(0.10)

 

(0.49)

 

1.29

 

Diluted earnings/(loss) per common share

 

(0.72)

 

(0.10)

 

(0.49)

 

1.27

 

1                 Effective September 1, 2015, Enbridge transferred its Canadian Liquids Pipelines business and certain Canadian renewable energy assets to the Fund Group (described below under Adjusted Earnings) within the Sponsored Investments segment as described under the Canadian Restructuring Plan, see Recent Developments – Sponsored Investments – The Fund Group – Canadian Restructuring Plan. Losses from the Canadian Liquids Pipelines assets prior to the date of transfer of $350 million and $403 million in the three and nine month periods ended September 30, 2015, respectively, (2014 - loss of $59 million and earnings of $349 million, respectively) and earnings from the Canadian renewable energy assets within the Gas Pipelines, Processing and Energy Services segment prior to the date of transfer of $1 million and $1 million in the three and nine month periods ended September 30, 2015, respectively, (2014 - loss of $3 million and $8 million, respectively) have not been reclassified into the Sponsored Investments segment for presentation purposes.

 

Loss attributable to common shareholders was $609 million for the three months ended September 30, 2015, or a loss of $0.72 per common share, compared with a loss of $80 million, or a loss of $0.10 per common share, for the three months ended September 30, 2014. The Company delivered strong quarter-over-quarter earnings growth as discussed in Adjusted Earnings; however, the visibility and the comparability of the Company’s operating results are impacted by a number of unusual, non-recurring or non-operating factors, the most significant of which is changes in unrealized derivative fair value gains and losses. The Company has a comprehensive long-term economic hedging program to mitigate 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 the reliable cash flows and dividend growth upon which the Company’s investor value proposition is based. The comparability of the Company’s quarter-over-quarter loss was also impacted by the transfer of assets between entities under common control of Enbridge in connection with the Canadian Restructuring Plan which generated a number of one-time charges in the quarter including a $247 million loss on the de-designation of interest rate hedges, an $88 million write-off of a regulatory asset in respect of taxes and $16 million of transaction costs in the third quarter of 2015.

 

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Partially offsetting these charges was a $44 million after-tax gain recognized in the third quarter of 2015 on the disposal of non-core assets within the Liquids Pipelines segment.

 

Loss attributable to common shareholders was $415 million for the nine months ended September 30, 2015, or a loss of $0.49 per common share, compared with earnings of $1,066 million, or $1.29 per common share, for the nine months ended September 30, 2014. In addition to the trends experienced in the three-month period discussed above, the comparability of the nine-month period-over-period was also impacted by a goodwill impairment charge of $440 million ($167 million after-tax attributable to Enbridge) recognized in the second quarter of 2015 related to Enbridge Energy Partners, L.P.’s (EEP) natural gas and natural gas liquids (NGL) businesses. Due to a prolonged decline in commodity prices, a reduction in producers’ expected drilling programs has negatively impacted expected volumes on EEP’s natural gas and NGL pipelines and processing systems, which EEP holds directly and indirectly through its partially-owned subsidiary, Midcoast Energy Partners, L.P. (MEP). Earnings were also negatively impacted by a tax effect of the transfer of assets between entities under common control of Enbridge in the second quarter of 2015. The intercompany gain realized as a result of the transfer has been eliminated for accounting purposes. However, as the transaction involved the sale of partnership units, all tax consequences have remained in consolidated earnings and resulted in a charge of $39 million. The loss for the nine months ended September 30, 2015 also included an out-of-period adjustment of $71 million recognized in the first quarter of 2015 in respect of an overstatement of deferred income tax expense in 2013 and 2014.

 

FORWARD-LOOKING INFORMATION

Forward-looking information, or forward-looking statements, have been included in this MD&A to provide information about the Company and its subsidiaries and affiliates, including management’s assessment of Enbridge and its subsidiaries’ future plans and operations. This information may not be appropriate for other purposes. Forward-looking statements are typically identified by words such as ‘‘anticipate’’, ‘‘expect’’, ‘‘project’’, ‘‘estimate’’, ‘‘forecast’’, ‘‘plan’’, ‘‘intend’’, ‘‘target’’, ‘‘believe’’, “likely” and similar words suggesting future outcomes or statements regarding an outlook. Forward-looking information or statements included or incorporated by reference in this document include, but are not limited to, statements with respect to the following: expected earnings/(loss) or adjusted earnings/(loss); expected earnings/(loss) or adjusted earnings/(loss) per share; expected available cash flow from operations (ACFFO); 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; expected costs related to leak remediation and potential insurance recoveries; expectations regarding the impact of the Canadian Restructuring Plan (or the Transaction); dividend payout policy and dividend payout expectation.

 

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

 

2



 

effects of inflation and foreign exchange rates on labour and material costs; the effects of interest rates on borrowing costs; the impact of weather; and customer and regulatory approvals on construction and in-service schedules.

 

Enbridge’s forward-looking statements are subject to risks and uncertainties pertaining to the Transaction, revised dividend policy, operating performance, regulatory parameters, project approval and support, weather, economic and competitive conditions, changes in tax law and tax rate increases, exchange rates, interest rates, commodity prices and supply of and demand for commodities, including but not limited to those risks and uncertainties discussed in this MD&A and in the Company’s other filings with Canadian and United States securities regulators. The impact of any one risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as these are interdependent and Enbridge’s future course of action depends on management’s assessment of all information available at the relevant time. Except to the extent required by applicable law, Enbridge assumes no obligation to publicly update or revise any forward-looking statements made in this MD&A or otherwise, whether as a result of new information, future events or otherwise. All subsequent forward-looking statements, whether written or oral, attributable to Enbridge or persons acting on the Company’s behalf, are expressly qualified in their entirety by these cautionary statements.

 

NON-GAAP MEASURES

 

This MD&A contains references to adjusted earnings/(loss) and available cash flow from operations (ACFFO). Adjusted earnings/(loss) represents 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. Adjusting items referred to as changes in unrealized derivative fair value gains and losses are presented net of amounts realized on the settlement of derivative contracts during the applicable period.

 

ACFFO is defined as cash flow provided by operating activities before changes in operating assets and liabilities (including changes in regulatory assets and liabilities and environmental liabilities) less distributions to noncontrolling interests and redeemable noncontrolling interests, preference share dividends and maintenance capital expenditures, and further adjusted for unusual, non-recurring or non-operating factors.

 

Management believes the presentation of adjusted earnings/(loss) and ACFFO provide useful information to investors and shareholders as they provide increased transparency and insight into the performance of the Company. Management uses adjusted earnings/(loss) to set targets and to assess the performance of the Company. Management also uses ACFFO to assess the performance of the Company and to set its dividend payout target. Adjusted earnings/(loss), adjusted earnings/(loss) for each segment and ACFFO are not measures that have standardized meaning prescribed by U.S. GAAP and are not U.S. GAAP measures. Therefore, these measures may not be comparable with similar measures presented by other issuers. The tables in this section summarize the reconciliation of the GAAP and non-GAAP measures.

 

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NON-GAAP RECONCILIATIONS

 

 

 

Three months ended

 

Nine months ended

 

 

September 30,

 

September 30,

 

 

2015

 

2014

 

2015

 

2014

 

(millions of Canadian dollars)

 

 

 

 

 

 

 

 

 

Earnings/(loss) attributable to common shareholders

 

(609)

 

(80)

 

(415)

 

1,066

 

Adjusting items1:

 

 

 

 

 

 

 

 

 

Changes in unrealized derivative fair value (gains)/loss2

 

654

 

396

 

1,335

 

156

 

Canadian Restructuring Plan

 

351

 

-

 

351

 

-

 

Goodwill impairment loss

 

-

 

-

 

167

 

-

 

Make-up rights adjustments

 

8

 

6

 

-

 

6

 

Leak remediation costs, net of leak insurance recoveries

 

(1)

 

16

 

(4)

 

17

 

Warmer/(colder) than normal weather

 

-

 

2

 

(27)

 

(35)

 

Gains on sale of non-core assets and investment, net of losses

 

(37)

 

-

 

(46)

 

(57)

 

Valuation allowance on deferred income tax assets

 

32

 

-

 

32

 

-

 

Project development and transaction costs

 

2

 

3

 

14

 

6

 

Tax on intercompany gains on sale of partnership units

 

-

 

-

 

39

 

-

 

Out-of-period adjustment

 

-

 

-

 

(71)

 

-

 

Other

 

(1)

 

2

 

(3)

 

6

 

Adjusted earnings

 

399

 

345

 

1,372

 

1,165

 

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

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

 

ADJUSTED EARNINGS

 

 

 

Three months ended

 

Nine months ended

 

 

September 30,

 

September 30,

 

 

2015

 

2014

 

2015

 

2014

 

(millions of Canadian dollars, except per share amounts)

 

 

 

 

 

 

 

 

 

Liquids Pipelines1

 

195

 

221

 

627

 

659

 

Gas Distribution

 

1

 

(9)

 

152

 

109

 

Gas Pipelines, Processing and Energy Services1

 

(21)

 

20

 

94

 

106

 

Sponsored Investments1

 

224

 

126

 

490

 

306

 

Corporate

 

-

 

(13)

 

9

 

(15)

 

Adjusted earnings

 

399

 

345

 

1,372

 

1,165

 

Adjusted earnings per common share

 

0.47

 

0.41

 

1.62

 

1.41

 

1                  Effective September 1, 2015, Enbridge completed the Transaction described under the Canadian Restructuring Plan, see Recent Developments – Sponsored Investments – The Fund Group – Canadian Restructuring Plan. Adjusted earnings from the Canadian Liquids Pipelines assets prior to the date of transfer of $128 million and $508 million in the three and nine month periods ended September 30, 2015, respectively, (2014 - $175 million and $542 million, respectively) and adjusted earnings from the Canadian renewable energy assets within the Gas Pipelines, Processing and Energy Services segment prior to the date of transfer of $2 million and $6 million in the three and nine month periods ended September 30, 2015, respectively, (2014 - loss of $2 million and $4 million, respectively) have not been reclassified into the Sponsored Investments segment for presentation purposes.

 

Adjusted earnings were $399 million, or $0.47 per common share, for the three months ended September 30, 2015 compared with $345 million, or $0.41 per common share, for the three months ended September 30, 2014. Adjusted earnings were $1,372 million, or $1.62 per common share, for the nine months ended September 30, 2015 compared with $1,165 million, or $1.41 per common share, for the nine months ended September 30, 2014.

 

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The following factors impacted adjusted earnings:

·

Within Liquids Pipelines, adjusted earnings for the three and nine months ended September 30, 2015 are impacted by the effect of the Canadian Restructuring Plan. Following the close of the Canadian Restructuring Plan on September 1, 2015, adjusted earnings from Canadian Mainline and Regional Oil Sands System business are no longer reported in the Liquids Pipelines segment, but are captured in the results of the Fund Group (comprising Enbridge Income Fund (the Fund), Enbridge Commercial Trust (ECT), Enbridge Income Partners LP (EIPLP) and the subsidiaries of EIPLP) which are reported within the Sponsored Investments segment. Prior to the closing of the Canadian Restructuring Plan on September 1, 2015, period-over-period adjusted earnings from the Canadian Mainline increased reflecting positive effects of higher throughput, partly attributed to the expansion of the Company’s mainline system completed in July 2015, higher terminalling revenues and a favourable United States/Canada foreign exchange rate. Partially offsetting these positive factors was a lower average Canadian Mainline International Joint Tariff (IJT) Residual Benchmark Toll, although this impact lessened commencing the second quarter of 2015 as effective April 1, 2015, this toll increased by US$0.10 per barrel to US$1.63 per barrel. Other factors negatively impacting adjusting earnings were higher power costs associated with higher throughput, higher depreciation expense due to an increased asset base and higher interest expense to support increased business activities. Partially mitigating the impact of a lower Canadian Mainline IJT Residual Benchmark Toll were new surcharges related to system expansions, including a surcharge for the Edmonton to Hardisty Expansion pipeline completed in April 2015. These trends continued into the month of September 2015, with Canadian Mainline adjusted earnings for the month of September 2015 now being reflected in the Fund Group, whereas, the adjusted earnings for the September 2014 period were reflected in Liquids Pipelines.

·

Within Liquids Pipelines, adjusted earnings from the Seaway and Flanagan South Pipeline increased reflecting the partial alleviation of upstream apportionment through the expansion of the Company’s mainline system completed in July 2015.

·

Also within Liquids Pipelines, adjusted earnings continued to reflect lower earnings from Southern Lights Pipeline. The majority of the economic benefit derived from Southern Lights Pipeline is now reflected in earnings of the Fund Group following the Fund Group’s November 2014 subscription and purchase of Class A units of certain Enbridge subsidiaries, which provide the Fund Group with a defined cash flow stream from Southern Lights Pipeline. Under the Canadian Restructuring Plan, the Fund Group also acquired full ownership interest in the Canadian segment of the Southern Lights Pipeline.

·

Within Gas Distribution, Enbridge Gas Distribution Inc. (EGD) adjusted earnings increased reflecting customer growth, as well as higher distribution charges due to increased assets base. Also positively impacting adjusted earnings within Gas Distribution was the absence of a loss that Enbridge Gas New Brunswick Inc. (EGNB) incurred in 2014 under a contract to sell natural gas to the province of New Brunswick. Due to an abnormally cold winter in the first quarter of 2014, costs associated with the fulfilment of the contract were higher than the revenues received.

·

Within Gas Pipelines, Processing and Energy Services, adjusted loss in the third quarter of 2015 included a loss from Energy Services. After a very strong first half, the performance of Energy Services weakened in the third quarter as a result of less favourable conditions in certain markets accessed by committed transportation capacity, combined with an erosion of the favourable tank management opportunities experienced in the first half of 2015 due to a reduction in refinery demand for blended crude oil feedstock in the Gulf Coast.

·

Also within Gas Pipelines, Processing and Energy Services, adjusted earnings/(loss) continued to reflect the absence of earnings from Alliance Pipeline US, which was transferred to the Fund Group in November 2014, as well as lower earnings from Aux Sable due to lower fractionation margins.

·

Within Sponsored Investments, the increase in adjusted earnings from the Fund Group reflected one month of earnings from the Canadian liquids pipelines business and Canadian renewable energy assets as discussed above as well as Enbridge’s overall 91.9% economic interest in the Fund Group, see Recent Developments – Sponsored Investments – The Fund Group – Canadian Restructuring Plan. Higher adjusted earnings also continued to reflect the impact of the transfer of natural gas and diluent pipeline interests from Enbridge in 2014, partially offset by higher financing costs associated with the debt issued to partially finance that transfer and higher income taxes.

 

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·

Also within Sponsored Investments, adjusted earnings from EEP reflected higher throughput and tolls on EEP’s major liquids pipelines, as well as contributions from new assets placed into service in 2014 and 2015, the most prominent being the replacement and expansion of Line 6B in 2014 and the expansion of the Company’s mainline system completed in July 2015. EEP adjusted earnings also reflected incremental earnings from the January 2, 2015 transfer of the remaining 66.7% interest in Alberta Clipper previously held by Enbridge. Higher contribution from EEP for the nine months ended September 30, 2015 also reflected distributions from Class D units and Incentive Distribution Units (IDU) which were issued to Enbridge in July 2014 under an equity restructuring transaction and from Class E units which were issued by EEP in January 2015 in connection with the transfer of Alberta Clipper. However, overall contributions from EEP for the three months ended September 30, 2015 were comparable with the corresponding period in 2014 as the period-over-period adjusted earnings were impacted by the absence of incremental distributions from Class D units and IDU.

·

Within the Corporate segment, Noverco Inc. (Noverco) adjusted earnings for the nine months ended September 30, 2015 increased compared with the corresponding 2014 period, reflecting stronger operating earnings due to a favourable United States/Canada foreign exchange rate and incremental earnings from new assets, partially offset by lower preferred share dividend income based on a lower yield of 10-year Government of Canada bonds, to which the dividend rate is linked.

·

Also within the Corporate segment, Other Corporate adjusted loss for the nine months ended September 30, 2015 decreased compared with the corresponding period in 2014 reflecting lower net Corporate segment finance costs, lower income taxes and the positive effects of foreign exchange rates on certain foreign currency balances, partially offset by higher preference share dividends reflecting additional preference shares issued in 2014 to fund the Company’s growth capital program.

 

AVAILABLE CASH FLOW FROM OPERATIONS

 

 

Three months ended

 

Nine months ended

 

 

 

September 30,

 

September 30,

 

 

 

2015 

 

2014 

 

2015 

 

2014 

 

(millions of Canadian dollars)

 

 

 

 

 

 

 

 

 

Cash provided by operating activities - continuing operations

 

905 

 

746 

 

3,765 

 

1,872 

 

Adjusted for changes in operating assets and liabilities1

 

444 

 

310 

 

214 

 

1,307 

 

 

 

1,349 

 

1,056 

 

3,979 

 

3,179 

 

Distributions to noncontrolling interests

 

(177)

 

(135)

 

(501)

 

(395)

 

Distributions to redeemable noncontrolling interests

 

(27)

 

(18)

 

(80)

 

(55)

 

Preference share dividends

 

(72)

 

(63)

 

(214)

 

(174)

 

Maintenance capital expenditures2

 

(204)

 

(259)

 

(520)

 

(658)

 

Significant adjusting items3

 

(201)

 

28 

 

(386)

 

(1)

 

Available cash flow from operations (ACFFO)

 

668 

 

609 

 

2,278 

 

1,896 

 

 

1

Changes in operating assets and liabilities include changes in regulatory assets and liabilities and environmental liabilities, net of recoveries.

2

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

3

Included in significant adjusting items for the three months ended September 30, 2015 were weather normalization of nil (2014 - $2 million), project development and transaction costs of $35 million (2014 - $1 million), hydrostatic testing of $49 million (2014 - nil) and other items of ($28) million (2014 - $25 million). Included in significant adjusting items for the nine months ended September 30, 2015 were weather normalization of ($27) million (2014 - ($35) million), project development and transaction costs of $42 million (2014 - $4 million), hydrostatic testing of $49 million (2014 - nil), and other items of ($28) million (2014 - $30 million). Also included in significant adjusting items for the three and nine months ended September 30, 2015 were ($257) million (2014 - nil) and ($422) million (2014 - nil) in respect of losses on sale of previously written down inventory for which there is an approximate offsetting realized derivative gain in ACFFO.

 

ACFFO was $668 million for the three months ended September 30, 2015 compared with $609 million for the three months ended September 30, 2014. ACFFO was $2,278 million for the nine months ended September 30, 2015 compared with $1,896 million for the nine months ended September 30, 2014.

 

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The Company experienced strong quarter-over-quarter and nine-month growth in ACFFO which was driven by the same factors as those impacting adjusted earnings across the Company’s various businesses, as discussed in Non-GAAP Measures Adjusted Earnings. In addition, the significant growth capital program undertaken by the Company over recent years is also positioning the Company for future growth and new opportunities, and contributing to the ACFFO growth.

 

Also contributing to the period-over-period increase in ACFFO were lower maintenance capital expenditures in 2015 compared with the corresponding 2014 periods. Over the last few years, under its maintenance capital program, the Company has made a significant investment on the ongoing support and maintenance of the existing pipeline system and on maintaining the service capability of the existing assets. The period-over-period decrease in maintenance capital expenditures is due to the completion of certain maintenance programs in 2014. The Company plans to continue to invest in its maintenance capital program to support the safety and reliability of its operations.

 

The period-over-period increase in ACFFO was partially offset by distributions to noncontrolling interests in EEP and Enbridge Energy Management, L.L.C. and to redeemable noncontrolling interest in the Fund. Distributions were higher for each of the three and nine-month periods in 2015 compared with the corresponding 2014 periods. Also, the Company’s payment of preference share dividends increased period-over-period due to preference shares issued in 2014 to fund the Company’s growth capital program. Finally, the ACFFO was also adjusted for the cash effect of certain unusual, non-recurring or non-operating factors as discussed in Non-GAAP Measures Non-GAAP Reconciliations.

 

RECENT DEVELOPMENTS

 

LIQUIDS PIPELINES

United States Restructuring

A review of a potential transfer of Enbridge’s United States liquids pipelines assets to EEP determined that conditions in the master limited partnership market do not support a large scale drop down at this time. The longer-term outlook for EEP remains strong, with over US$6 billion of secured growth projects coming into service through 2019 and options to increase its economic interest in projects that are jointly funded by Enbridge and EEP. EEP remains important to Enbridge’s overall strategy and Enbridge continues to support EEP during this time of significant organic growth. Enbridge has a large inventory of United States liquids pipelines assets which are well suited to EEP and continues to evaluate opportunities to generate value through selective drop downs of ownership interests or assets of approximately $500 million annually to EEP depending on market conditions.

 

Seaway Pipeline Regulatory Matter

Seaway Crude Pipeline System (Seaway Pipeline) filed an application for market-based rates in December 2011. In relation to the original market-based rate application, the United States Federal Energy Regulatory Commission (FERC) issued its decision rejecting Seaway Pipeline’s application for market-based rates in February 2014 and announced a new methodology for determining whether a pipeline has market power and invited Seaway Pipeline to refile its market-based rate application consistent with the new policy. In December 2014, Seaway Pipeline filed a new market-based rate application. The FERC noticed the application in the Federal Register and in response several parties filed comments in opposition alleging that the application should be denied because Seaway Pipeline has market power in both its receipt and destination markets. On September 17, 2015, the FERC issued its decision setting the application for hearing. The case has been assigned to an Administrative Law Judge (ALJ), who held a scheduling conference on October 1, 2015. The scheduling order calls for evidence to be filed on December 3, 2015, a hearing to start on July 7, 2016 and an initial decision of the ALJ on December 1, 2016.

 

Since the FERC had not issued a ruling on the market-based rate application, Seaway Pipeline filed for initial rates in order to have rates in effect by the in-service date. The uncommitted rate on Seaway Pipeline was challenged by several shippers. In September 2013, a decision from an ALJ was released finding that the committed and uncommitted rates on Seaway Pipeline should be reduced to reflect the ALJ’s findings on the various cost of service inputs. Seaway Pipeline filed a brief with the FERC on

 

7



 

October 15, 2013, challenging the ALJ’s decision and asking for expedited ruling by the FERC on the committed rates. In February 2014, the FERC issued its decision upholding its policy to honour contracts and ordered the ALJ to revise her decision accordingly. On May 9, 2014, the ALJ issued an initial decision on remand reiterating her previous findings and did not change her decision. Briefings have concluded and the full record was sent to the FERC for its final decision, which is still pending.

 

GAS PIPELINES, PROCESSING AND ENERGY SERVICES

Aux Sable Environmental Protection Agency Matter

In September 2014, Aux Sable received a Notice and Finding of Violation (NFOV) from the United States Environmental Protection Agency (EPA) for alleged violations of the Clean Air Act related to the Leak Detection and Repair program, and related provisions of the Clean Air Act permit for Aux Sable’s Channahon, Illinois facility. As part of the ongoing process of responding to the September 2014 NFOV, Aux Sable discovered what it believes to be an exceedance of currently permitted limits for Volatile Organic Material. Aux Sable received a second NFOV from the EPA in April 2015 in connection with this potential exceedance. Aux Sable is engaged in discussions with the EPA to evaluate the potential impact and ultimate resolution of these issues. At this time, the Company is unable to reasonably estimate the financial impact.

 

SPONSORED INVESTMENTS – THE FUND GROUP

Canadian Restructuring Plan

On September 1, 2015, Enbridge announced it had closed the transfer of its Canadian Liquids Pipelines business, held through Enbridge Pipelines Inc. (EPI) and Enbridge Pipelines Athabasca Inc. (EPAI), and certain Canadian renewable energy assets to EIPLP, in which the Fund has an indirect interest, for aggregate consideration of $30.4 billion plus incentive distribution and performance rights (the Canadian Restructuring Plan or the Transaction).

 

The Transaction is a key component of Enbridge’s Financial Optimization Strategy introduced in December 2014, which included an increase in the Company’s targeted dividend payout. It advances the Company’s sponsored vehicle strategy and supports Enbridge’s previously announced 33% dividend increase effective March 1, 2015. The Transaction is expected to provide Enbridge with an alternate source of funding for its enterprise wide growth initiatives and enhance its competitiveness for new organic growth opportunities and asset acquisitions.

 

In conjunction with the execution of the Transaction, Enbridge adopted a supplemental cash flow metric, ACFFO, which was introduced in the second quarter of 2015 and is now a part of the Company’s normal course quarterly reporting of financial performance and guidance provision. ACFFO is used to assess the performance of the Company’s base business and expected growth program. The Company also started expressing its dividend payout range as a percentage of ACFFO rather than adjusted earnings. The target dividend payout policy range is 40% to 50% of ACFFO, which translates to approximately the previous payout range of 75% to 85% of adjusted earnings.

 

Consideration

Upon closing of the Transaction, Enbridge received $18.7 billion of units in the Fund Group, comprised of approximately $3 billion of units of the Fund and $15.7 billion of equity units of EIPLP, which at the time of the Transaction was an indirect subsidiary of the Fund. The Fund Group also assumed debt of EPI and EPAI of approximately $11.7 billion. In addition, a portion of the consideration to be received by Enbridge over time will be in the form of units which carry Temporary Performance Distribution Rights (TPDR). The TPDR are designed to allow Enbridge to capture increasing value from the secured growth embedded within the transferred businesses; however, the cash flows derived from this incentive mechanism will be deferred (until such time as the units become convertible to a class of cash paying units in the fourth year after issuance).

 

Enbridge will continue to earn a base incentive fee from the Fund Group through management and incentive fees and Incentive Distribution Rights, which entitle it to receive 25% of the pre-incentive distributable cash flow above a base distribution threshold of $1.295 per unit, adjusted for a tax factor and paid out of ECT. Distributions over $1.890 per unit will be paid out of EIPLP. In addition, Enbridge received the TPDR, a distribution equivalent to 33% of pre-incentive distributable cash flow above the

 

8



 

base distribution of $1.295 per unit. The TPDR will be paid in the form of Class D units of EIPLP and will be issued each month until the later of the end of 2020 or 12 months after the Canadian portion of the Line 3 Replacement Program (Canadian L3R Program) enters service. The Class D unitholders will receive a distribution each month equal to the per unit amount paid on Class C units of EIPLP, but to be paid in kind in additional Class D units. Each Class D unit is convertible into a cash paying Class C unit of EIPLP in the fourth year after its issuance.

 

The Fund units, Class A units of EIPLP and the EIPLP Class C units will pay a per unit cash distribution equivalent to the per unit cash distribution that the Fund pays on its units held by Enbridge Income Fund Holdings Inc. (ENF). The Fund units, EIPLP’s Class C units and existing units of ECT also include an exchange right whereby they may be converted into common shares of ENF on a one-for-one basis.

 

Financing Plan

To acquire an increasing ownership interest in the Fund Group, the financing plan contemplates the issuance by ENF of $600 million to $800 million of public equity per year in one or more tranches through 2018 to fund an increasing investment in the Canadian Liquids Pipelines business. Enbridge has agreed to backstop the equity funding required by ENF to undertake the growth program embedded in the assets it acquired in the Transaction. The amount of public equity issued by ENF will be adjusted as necessary to match its capacity to raise equity funding on favourable terms. On October 13, 2015 ENF announced that it had entered into an agreement to issue approximately 21.5 million common shares for gross proceeds of approximately $700 million on a bought deal basis to a syndicate of underwriters. The offering is expected to close on or about November 6, 2015. This common share offering also includes an over-allotment option, exercisable within 30 days following the closing of the offering, for up to approximately an additional three million common shares that would provide additional gross proceeds of up to approximately $100 million. Enbridge has agreed to concurrently subscribe for approximately 5.3 million common shares (up to approximately six million common shares if the over-allotment option is exercised in full) on a private placement basis to maintain its 19.9% ownership interest in ENF.

 

Development Opportunities

The Canadian Liquids Pipelines business is expected to have future organic growth opportunities beyond the current inventory of secured projects. The Fund Group has a first right to execute any such projects that fall within the footprint of the Canadian Liquids Pipelines business. Should the Fund Group choose not to proceed with a specific growth opportunity, Enbridge may pursue such opportunity.

 

Economic Interest

Upon closing of the Transaction, Enbridge’s overall economic interest in the Fund Group, including all of its direct and indirect interests in the Fund Group, was 91.9%. Upon completion of the $700 million common share issuance discussed above, Enbridge’s economic interest is expected to decrease to 89.2%. As ENF executes on its financing plan and increases its ownership in the Fund Group over time, Enbridge’s economic interest is expected to decline to approximately 80% by the end of 2018.

 

Fund Governance

Enbridge will continue to act as the manager of the Fund Group and operator and commercial developer of the Canadian Liquids Pipelines business. This will ensure continuity of management and operational expertise, with an ongoing commitment to the safe and reliable operation of the system. As a result of its significant ownership interest, Enbridge has the right to appoint a majority of the Trustees of the Board of ECT for as long as the Company holds a majority economic interest in the Fund Group. A standing conflicts committee has been established to review certain material transactions and arrangements where the interests of Enbridge, or its affiliates, and the relevant entity in the Fund Group, or its affiliates, come into conflict.

 

9



 

Alliance Pipeline Recontracting

During 2013, Alliance Pipeline announced a New Services Framework and the related tolls and tariff provisions required to implement the new services (collectively, New Services Framework) in which customers could express interest through a precedent agreement process. On June 30, 2015 and July 9, 2015, Alliance Pipeline received regulatory approval from the FERC and the National Energy Board (NEB), for the United States and Canadian segments of the pipeline, respectively, for this New Services Framework. Shipments under the New Services Framework will begin in December 2015. As part of its acceptance of Alliance Pipeline US’ New Services, the FERC set all issues related to the proposed elimination of Authorized Overrun Service and Interruptible Transportation revenue crediting, and the maintenance of Alliance Pipeline US’ existing recourse rates, for hearing. The negotiated reservation rates contained in the Precedent Agreements will be converted into negotiated rate transportation contracts as part of the New Services Offering and will not be part of this hearing. Alliance Pipeline has successfully re-contracted its firm capacity through 2018, and approximately 90% of receipt capacity in 2019 and 2020, with an average contract length of approximately five years.

 

Pursuant to the New Services Framework, Alliance Pipeline will retain exposure to potential variability in certain future costs and throughput volumes. As such, the majority of Alliance Pipeline’s operations no longer meet all of the criteria required for the continued application of rate-regulated accounting treatment and a derecognition of regulatory balances as at June 30, 2015 was required. The Fund Group recorded an after-tax write-down of approximately $10 million ($3 million after-tax attributable to Enbridge) during the second quarter of 2015.

 

SPONSORED INVESTMENTS – ENBRIDGE ENERGY PARTNERS, L.P.

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 EPA (the Order) which required additional containment and active recovery of submerged oil relating to the Line 6B crude oil release. In February 2015, the EPA acknowledged the completion of the Order. In November of 2014, regulatory authority was transferred from the EPA to the Michigan Department of Environmental Quality (MDEQ). The MDEQ 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.

 

In May 2015, EEP reached a settlement with the MDEQ and the Michigan Attorney General’s offices regarding the Line 6B crude oil release. As stipulated in the settlement, EEP agreed to: (1) provide at least 300 acres of wetland through restoration, creation or banked wetland credits to remain as wetland in perpetuity; (2) pay US$5 million as mitigation for impacts to the banks, bottomlands and flow of Talmadge Creek and the Kalamazoo River for the purpose of enhancing the Kalamazoo River watershed and restoring stream flows in the river; (3) continue to reimburse the State of Michigan for costs arising from oversight of EEP activities since the release; and (4) continue monitoring, restoration and invasive species control within state-regulated wetlands affected by the release and associated response activities. The timing of these activities is based upon the work plans approved by the State of Michigan.

 

As at September 30, 2015, EEP’s cumulative cost estimate for the Line 6B crude oil release remains at US$1.2 billion ($193 million after-tax attributable to Enbridge).

 

10



 

Expected losses associated with the Line 6B crude oil release included those costs that were considered probable and that could be reasonably estimated at September 30, 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

On September 9, 2010, a crude oil release occurred on Line 6A in Romeoville, Illinois, caused by a third party water pipeline failure which damaged EEP’s pipeline. 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

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 renewed 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 September 30, 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 September 30, 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 which is not scheduled to occur until the fourth quarter of 2016. While the Company believes that those costs are eligible for recovery, there can be no assurance that it will prevail in the arbitration.

 

Enbridge renewed its comprehensive property and liability insurance programs under which the Company is insured 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 five 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. Based

 

11



 

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 September 30, 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. EEP has entered into a tolling agreement with the applicable governmental agencies and discussions with these governmental agencies regarding fines, penalties and injunctive relief are ongoing.

 

In June 2015, EEP reached a separate agreement with the United States of America (Federal Natural Resources Damages Trustees), State of Michigan (State Natural Resources Damages Trustees), Match-E-Be-Nash-She-Wish Band of the Potawatomi Indians and the Nottawaseppi Huron Band of the Potawatomi Indians to pay approximately US$3.9 million that EEP had accrued to cover a variety of projects, including the restoration of 175 acres of oak savanna in Fort Custer State Recreation Area and wild rice beds along the Kalamazoo River.

 

EEP Common Unit Issuance

In March 2015, EEP completed the issuance of eight million Class A Common Units for gross proceeds of approximately US$294 million before underwriting discounts and commissions and offering expenses. Enbridge did not participate in the issuance; however, the Company made a capital contribution of US$6 million to maintain its 2% general partner interest in EEP. EEP expects to use the proceeds from the offering to fund a portion of its capital expansion projects, for general partnership purposes or any combination of such purposes.

 

GROWTH PROJECTS – COMMERCIALLY SECURED PROJECTS

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

 

 

 

Estimated
Capital Cost
1

Expenditures
to Date
2

Expected
In-Service
Date

Status

 

 

(Canadian dollars, unless stated otherwise)

 

 

 

 

 

LIQUIDS PIPELINES

 

 

 

1.

Southern Access Extension

US$0.6 billion

US$0.4 billion

2015

Under
construction

GAS DISTRIBUTION

 

 

 

 

2.

Greater Toronto Area Project

$0.9 billion

$0.6 billion

2015-2016
(in phases)

Under
construction

GAS PIPELINES, PROCESSING AND ENERGY SERVICES

 

 

3.

Keechi Wind Project

 

US$0.2 billion

US$0.2 billion

2015

Complete

4.

Walker Ridge Gas Gathering System

US$0.4 billion

US$0.3 billion

2014-TBD
(in phases)

Substantially
complete

5.

Big Foot Oil Pipeline

US$0.2 billion

US$0.2 billion

TBD

Substantially
complete

6.

Aux Sable Extraction Plant Expansion

US$0.1 billion

No significant
expenditures to date

2016

Under
construction

 

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Estimated
Capital Cost
1

Expenditures
to Date
2

Expected
In-Service
Date

Status

7.

Heidelberg Oil Pipeline

US$0.1 billion

US$0.1 billion

2016

Under
construction

8.

Stampede Oil Pipeline

US$0.2 billion

No significant expenditures to date

2018

Pre-
construction

SPONSORED INVESTMENTS

 

 

 

9.

The Fund Group - Eastern Access Line 9 Reversal and Expansion

$0.8 billion

$0.7 billion

2013-2015
(in phases)

Substantially
complete

10.

The Fund Group - Canadian Mainline Expansion

$0.7 billion

$0.7 billion

2015

Complete

11.

The Fund Group - Surmont Phase 2 Expansion

$0.3 billion

$0.3 billion

2014-2015
(in phases)

Complete

12.

The Fund Group - Canadian Mainline System Terminal Flexibility and Connectivity

$0.7 billion

$0.7 billion

2013-2015
(in phases)

Complete

13.

The Fund Group - Woodland Pipeline Extension

$0.7 billion

$0.7 billion

2015

Complete

14.

The Fund Group - Sunday Creek Terminal Expansion

$0.2 billion

$0.2 billion

2015

Complete

15.

The Fund Group - Edmonton to Hardisty Expansion

$1.8 billion

$1.4 billion

2015
(in phases)

Under
construction

16.

The Fund Group - AOC Hangingstone Lateral

$0.2 billion

$0.1 billion

2015

Under
construction

17.

The Fund Group - JACOS Hangingstone Project

$0.2 billion

$0.1 billion

2016

Under
construction

18.

The Fund Group - Regional Oil Sands Optimization Project

$2.6 billion

$1.5 billion

2017

Under
construction

19.

The Fund Group - Norlite Pipeline System3

$1.3 billion

$0.1 billion

2017

Under
construction

20.

The Fund Group - Canadian Line 3 Replacement Program

$4.9 billion

$0.7 billion

2017

Pre-
construction

21.

EEP - Eastern Access4

US$2.7 billion

US$2.3 billion

2013-2016
 (in phases)

Under
construction

22.

EEP - Lakehead System Mainline Expansion4

US$2.3 billion

US$1.9 billion

2014-2017
(in phases)

Under
construction

23.

EEP - Beckville Cryogenic Processing Facility

US$0.2 billion

US$0.2 billion

2015

Complete

24.

EEP - Eaglebine Gathering

US$0.2 billion

US$0.1 billion

2015-2016
(in phases)

Under
construction

25.

EEP - Sandpiper Project5

US$2.6 billion

US$0.7 billion

2017

Pre-
construction

26.

EEP - U.S. Line 3 Replacement Program

US$2.6 billion

US$0.3 billion

2017

Pre-
construction

 

1

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

2

Expenditures to date reflect total cumulative expenditures incurred from inception of the project up to September 30, 2015.

3

The Company will construct and operate the Norlite Pipeline System. Keyera Corp. will fund 30% of the project.

4

The Eastern Access and Lakehead System Mainline Expansion projects are funded 75% by Enbridge and 25% by EEP.

5

The Company will construct and operate the Sandpiper Project. Marathon Petroleum Corporation will fund 37.5% of the project.

 

LIQUIDS PIPELINES

Southern Access Extension

The Southern Access Extension joint venture involves the construction of a new 265-kilometre (165-mile), 24-inch diameter crude oil pipeline from Flanagan, Illinois to Patoka, Illinois, for an initial capacity of approximately 300,000 barrels per day (bpd), as well as additional tankage and two new pump stations. The project is expected to be placed into service in the fourth quarter of 2015. The Company’s share of

 

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the estimated capital cost is expected to be approximately US$0.6 billion, with expenditures to date of approximately US$0.4 billion.

 

GAS DISTRIBUTION

Greater Toronto Area Project

EGD is undertaking the expansion of its natural gas distribution system in the Greater Toronto Area (GTA) to meet the demands of growth and to continue the safe and reliable delivery of natural gas to current and future customers. The GTA project involves the construction of two new segments of pipeline, a 27-kilometre (17-mile), 42-inch diameter pipeline (Western segment) that is expected to enter service in the first quarter of 2016 and a 23-kilometre (14-mile), 36-inch diameter pipeline (Eastern segment) that is expected to enter service in December of 2015 as well as related facilities to upgrade the existing distribution system in Toronto, Ontario, that delivers natural gas to several municipalities in Ontario. Construction began in January 2015. The project is now expected to cost approximately $0.9 billion due to greater complexity in the construction and requirements from government and permitting agencies. Expenditures incurred to date were approximately $0.6 billion.

 

GAS PIPELINES, PROCESSING AND ENERGY SERVICES

Keechi Wind Project

In 2014, Enbridge announced it had entered into an agreement with Renewable Energy Systems Americas Inc. (RES Americas) to own and operate the 110-megawatt Keechi Wind Project (Keechi), located in Jack County, Texas. The project was constructed by RES Americas under a fixed price, engineering, procurement and construction agreement at a total cost of approximately US$0.2 billion, and it entered service in January 2015. The electricity generated by Keechi is delivered into the Electric Reliability Council of Texas, Inc. market under a 20-year power purchase agreement with Microsoft Corporation.

 

Walker Ridge Gas Gathering System

The Company has agreements 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, the Company is constructing and will own and operate the Walker Ridge Gas Gathering System (WRGGS) to provide natural gas gathering services to the Chevron operated 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 metres (7,000 feet), with capacity of 100 million cubic feet per day (mmcf/d). The Jack St. Malo portion of the WRGGS was placed into service in December 2014. The Big Foot portion of the WRGGS start-up has been delayed due to platform installation issues experienced by Chevron. Chevron is currently investigating the extent of the damage and the delay. The Big Foot gas portion of the WRGGS has met its completion requirements under the terms of the agreements and the Company expects to begin collecting take or pay toll revenue in the fourth quarter of 2015. The total WRGGS project is expected to cost approximately US$0.4 billion, with expenditures to date of approximately US$0.3 billion.

 

Big Foot Oil Pipeline

Under agreements with Chevron, Statoil Gulf of Mexico LLC and Marubeni Oil & Gas (USA) Inc., the Company is constructing a 64-kilometre (40-mile), 20-inch oil pipeline with a capacity of 100,000 bpd from Chevron’s Big Foot ultra-deep water development in the Gulf of Mexico. This crude oil pipeline project is complementary to the Company’s undertaking of the WRGGS construction, discussed above. Upon completion of the project, the Company will operate the Big Foot Oil Pipeline, located approximately 274 kilometres (170 miles) south of the coast of Louisiana. As noted above, although the Big Foot ultra-deep water development has been delayed, the Big Foot Oil Pipeline has met its completion requirements under the terms of the agreements and the Company expects to begin collecting take or pay revenue in the fourth quarter of 2015. The estimated capital cost of the project is approximately US$0.2 billion, with expenditures to date of approximately US$0.2 billion.

 

Aux Sable Extraction Plant Expansion

In 2014, the Company approved the expansion of fractionation capacity and related facilities at the Aux Sable Extraction Plant located in Channahon, Illinois. The expansion will facilitate the growing NGL-rich

 

14



 

gas stream on the Alliance Pipeline, allow for effective management of Alliance Pipeline’s downstream natural gas heat content and support additional production and sale of NGL products. The expansion is expected to be placed into service in the second quarter of 2016, with the Company’s share of the project cost being approximately US$0.1 billion.

 

Heidelberg Oil Pipeline

The Company will construct, own and operate a crude oil pipeline in the Gulf of Mexico to connect the proposed Heidelberg development, operated by Anadarko Petroleum Corporation, to an existing third party system. Heidelberg Oil Pipeline (Heidelberg Pipeline), a 58-kilometre (36-mile), 20-inch diameter pipeline with capacity of 100,000 bpd, 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. Heidelberg Pipeline is expected to be operational in the second quarter of 2016 at an approximate cost of US$0.1 billion, with expenditures to date of approximately US$0.1 billion.

 

Stampede Oil Pipeline

In January 2015, Enbridge announced that it will build, own and operate a crude oil pipeline in the Gulf of Mexico to connect the planned Stampede development, which is operated by Hess Corporation, to an existing third party pipeline system. The Stampede Oil Pipeline (Stampede Pipeline), a 26-kilometre (16-mile), 18-inch diameter pipeline with capacity of approximately 100,000 bpd, will originate in Green Canyon Block 468, approximately 350 kilometres (220 miles) southwest of New Orleans, Louisiana, at an estimated depth of 1,200 metres (3,900 feet). Stampede Pipeline is expected to be completed at an approximate cost of US$0.2 billion and is expected to be placed into service in 2018.

 

SPONSORED INVESTMENTS

As part of the Canadian Restructuring Plan, the commercially secured growth programs embedded within EPI and EPAI were transferred to the Fund Group and are now presented in Sponsored Investments. Enbridge continues to oversee the execution of the growth program, as well as manage the operations and future development opportunities of these assets. Reference to “the Company” in this Sponsored Investments section includes activities performed by the Fund Group, or on its behalf by Enbridge, following the completion of the Canadian Restructuring Plan.

 

The Fund Group

Eastern Access

The Eastern Access initiative includes a series of Enbridge and EEP crude oil pipeline projects to provide increased access to refineries in the upper midwest United States and eastern Canada. Projects being undertaken by the Company include a reversal of Line 9A and expansion of the Toledo Pipeline, both completed in 2013, as well as the reversal of Line 9B and expansion of Line 9 (together, Line 9). For discussion on EEP’s portion of Eastern Access, refer to Growth Projects – Commercially Secured Projects – Sponsored Investments – Enbridge Energy Partners, L.P. – Eastern Access.

 

The Company is undertaking a reversal of its 240,000 bpd Line 9B from Westover, Ontario to Montreal, Quebec to serve refineries in that province. The Line 9B reversal was initially 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 additional delivery capacity into Ontario and Quebec, resulting in the Line 9 capacity expansion project. The Line 9 capacity expansion will increase the annual capacity of Line 9 from 240,000 bpd to 300,000 bpd at an estimated cost of approximately $0.1 billion.

 

The Line 9B Reversal and Line 9 Capacity Expansion projects were approved by the NEB in March 2014 subject to 30 conditions. In October 2014, the NEB requested additional information regarding one of the conditions imposed on the Line 9B Reversal and Line 9 Capacity Expansion Project. On October 23, 2014, the Company responded to the NEB describing the Company’s rigorous approach to risk management and isolation valve placement. On February 6, 2015, the NEB approved Conditions 16 and 18, the two conditions in the NEB’s order requiring approval, and the Company filed for a Leave to Open (LTO), which is a prerequisite to allowing the operation of the project. In its February approval, the NEB also imposed additional obligations on the Company that directed the Company to take a “life-cycle”

 

15



 

approach to water crossings and valves, requiring it to perform ongoing analysis to ensure optimal protection of the area’s water resources. On June 18, 2015, the NEB approved the LTO application and issued a separate order imposing further conditions requiring the Company to perform hydrostatic tests of selected segments of the pipeline. The Company filed its hydrostatic test plan with the NEB on July 23, 2015, which was approved on July 27, 2015. Hydrostatic testing was completed and the Company submitted the test results to the NEB in September 2015. On September 30, 2015 the NEB confirmed that the hydrostatic tests successfully met their criteria. Line-fill commenced in late October 2015 and the pipeline is expected to be placed into service in December 2015.

 

Cost estimates related to conditions imposed by the NEB, including valve placement and hydrostatic testing, are expected to increase the total project cost to $0.8 billion, inclusive of costs related to the previously mentioned Line 9A reversal. Pursuant to various agreements with shippers, the Company expects to recover from shippers the full costs of compliance with NEB imposed hydrostatic testing. Total expenditures to date on the Line 9A and Line 9B projects are approximately $0.7 billion.

 

On July 31, 2014, the Company filed an application for tolls on Line 9. After complaints from shippers on Line 9 were filed with the NEB with respect to the inclusion of mainline surcharges in the Line 9 toll, the NEB approved the tolls on an interim basis to allow for time to engage shippers in further discussions to attempt to resolve the outstanding issues. On January 30, 2015, the NEB convened a hearing to consider the matter. In response to a request from the Company that was supported by the shippers, the hearing was suspended to allow the Company and shippers to engage in further discussions to resolve the outstanding issues. In the third quarter of 2015, the Company and the shippers came to an agreement to recover mainline surcharges in the Line 9 toll.

 

Canadian Mainline Expansion

The Company undertook an expansion of the Alberta Clipper line between Hardisty, Alberta and the Canada/United States border near Gretna, Manitoba. The scope of the project consisted of two phases that involved the addition of pumping horsepower to raise the capacity of the Alberta Clipper line from 450,000 bpd to 800,000 bpd. The initial phase to increase capacity from 450,000 bpd to 570,000 bpd was completed in the third quarter of 2014 at an estimated capital cost of approximately $0.2 billion. The second phase to increase capacity from 570,000 bpd to 800,000 bpd was completed in July 2015 at an expected cost of approximately $0.5 billion. The total cost of the entire expansion was approximately $0.7 billion. Receipt of the final regulatory approval on EEP’s portion of the mainline system expansion has been delayed. EEP continues to work with regulatory authorities; however, the timing of the federal regulatory approval cannot be determined at this time. A number of temporary system optimization actions have been undertaken to substantially mitigate any impact on throughput associated with this delay. See Growth Projects – Commercially Secured Projects – Sponsored Investments – Enbridge Energy Partners, L.P. – Lakehead System Mainline Expansion.

 

Surmont Phase 2 Expansion

In 2013, the Company entered into a terminal services agreement with ConocoPhillips Canada Resources Corp. (ConocoPhillips) and Total E&P Canada Ltd. (together, the ConocoPhillips Partnership) to expand the Cheecham Terminal to accommodate incremental bitumen production from Surmont’s Phase 2 expansion. The Company constructed two new 450,000 barrel blend tanks and converted an existing tank from blend to diluent service. The expansion occurred in two phases with the blended product system placed into service in November 2014 and the diluent system placed into service in March 2015 at a total cost of approximately $0.3 billion.

 

Canadian Mainline System Terminal Flexibility and Connectivity

As part of the Light Oil Market Access Program initiative, the Company undertook 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 modifications comprised of upgrading existing booster pumps, installing additional booster pumps and adding new tank line connections. These projects had varying completion dates from 2013 through the second quarter of 2015. The total cost of the project was approximately $0.7 billion.

 

16



 

Woodland Pipeline Extension

The joint venture Woodland Pipeline Extension Project extends the Woodland Pipeline south from the Company’s Cheecham Terminal to its Edmonton Terminal. The extension is a 388-kilometre (241-mile), 36-inch diameter pipeline with an initial capacity of 400,000 bpd, expandable to 800,000 bpd. The project was completed and placed into service in July 2015. The Company’s share of the project costs is approximately $0.7 billion.

 

Sunday Creek Terminal Expansion

In 2014, the Company announced the construction of additional facilities at its existing Sunday Creek Terminal, located in the Christina Lake area of northern Alberta, to support production growth from the Christina Lake oil sands project operated by Cenovus Energy Inc. and jointly owned with ConocoPhillips. The expansion included development of a new site adjacent to the existing terminal, construction of a new 350,000 barrel tank with associated piping, pumps and measurement equipment, as well as civil construction work for a future tank. The project was placed into service in August 2015 at an approximate cost of $0.2 billion.

 

Edmonton to Hardisty Expansion

The Company is undertaking an expansion of the Canadian Mainline system between Edmonton, Alberta and Hardisty, Alberta. The expansion project includes 181 kilometres (112 miles) of new 36-inch diameter pipeline and will provide an initial capacity of approximately 570,000 bpd, expandable to 800,000 bpd. The new line generally follows the same route as the Company’s existing Line 4 pipeline. Also included in the project scope are connections into existing infrastructure at the Hardisty Terminal and new terminal facilities in Edmonton, Alberta which include five new 500,000 barrel tanks. The new pipeline was placed into service in April 2015, with additional tankage requirements expected to be completed by the fourth quarter of 2015. The total cost of the project is expected to be approximately $1.8 billion, with expenditures to date of approximately $1.4 billion.

 

AOC Hangingstone Lateral

In 2013, the Company entered into an agreement with Athabasca Oil Corporation (AOC) to provide pipeline and terminalling services to the proposed AOC Hangingstone Oil Sands Project (AOC Hangingstone) in Alberta. Phase I of the project will involve the construction of a new 49-kilometre (31-mile), 16-inch diameter pipeline from the AOC Hangingstone project site to the Company’s existing Cheecham Terminal and related facility modifications at Cheecham, Alberta. This phase of the project will provide an initial capacity of 16,000 bpd and is expected to be placed into service in the fourth quarter of 2015 at an estimated cost of approximately $0.2 billion. Expenditures to date on the project are approximately $0.1 billion. Phase 2 of the project, which is subject to commercial approval, would provide up to an additional 60,000 bpd for a total capacity of 76,000 bpd.

 

JACOS Hangingstone Project

The Company will undertake the construction of facilities and provide transportation services to the Japan Canada Oil Sands Limited (JACOS) Hangingstone Oil Sands Project (JACOS Hangingstone). JACOS and Nexen Energy ULC, a wholly-owned subsidiary of China National Offshore Oil Corporation Limited, are partners in the project which is operated by JACOS. The Company plans to construct a new 53-kilometre (33-mile), 12-inch lateral pipeline to connect the JACOS Hangingstone project site to the Company’s existing Cheecham Terminal. The project, which will provide capacity of 40,000 bpd, is expected to enter service in 2016. The estimated cost is approximately $0.2 billion, with expenditures to date of approximately $0.1 billion.

 

Regional Oil Sands Optimization Project

In March 2015, the Company announced a plan to optimize previously announced expansions of its Regional Oil Sands System currently in execution. The Company previously announced the Wood Buffalo Extension, which includes the construction of a 30-inch pipeline, from the Company’s Cheecham Terminal to its Battle River Terminal at Hardisty, Alberta and associated terminal upgrades, and the Athabasca Pipeline Twin, which consists of the twinning of the southern section of the Athabasca Pipeline with a 36-inch diameter pipeline from Kirby Lake, Alberta to its Hardisty crude oil hub.

 

17



 

The optimization plan, which has been agreed to with the affected shippers, including Suncor Energy Inc., Total E&P Canada Ltd. and Teck Resources Limited (the Fort Hills Partners), will enable deferral of the southern segment of the Wood Buffalo Extension by connecting it to the Athabasca Pipeline Twin. The optimization involves the upsize of a 100-kilometre (60-mile) segment of the Wood Buffalo Extension between Cheecham, Alberta and Kirby Lake, Alberta from a 30-inch diameter pipeline to a 36-inch diameter pipeline, which will now connect to the origin of the Athabasca Pipeline Twin at Kirby Lake, Alberta. The capacity of the Athabasca Pipeline Twin will be expanded from 450,000 bpd to 800,000 bpd through additional horsepower.

 

The definitive cost estimate of the Wood Buffalo Extension was finalized at approximately $1.8 billion before optimization. As a result of the optimization, the cost estimate to complete the integrated Wood Buffalo Extension and Athabasca Pipeline Twin projects is expected to decrease from approximately $3.0 billion to approximately $2.6 billion. Expenditures on the joint projects to date are approximately $1.5 billion.

 

The integrated Wood Buffalo Extension and Athabasca Pipeline Twin will transport diluted bitumen from the proposed Fort Hills Partners’ oil sands project (Fort Hills Project) in northeastern Alberta, as well as from oil sands production from Suncor Energy Oil Sands Limited Partnership (Suncor Partnership) in the Athabasca region. The Wood Buffalo Extension and the Athabasca Pipeline Twin will ship blended bitumen from the Fort Hills Project and have an expected 2017 in-service date. The Athabasca Pipeline Twin will also ship blended bitumen from the Cenovus Christina Lake Steam Assisted Gravity Drainage project near the origin of the Athabasca Pipeline Twin.

 

Norlite Pipeline System

The Company is undertaking the development of Norlite, a new industry diluent pipeline originating from Edmonton, Alberta to meet the needs of multiple producers in the Athabasca oil sands region. The scope of the project was increased to a 24-inch diameter pipeline, which will provide an initial capacity of approximately 224,000 bpd of diluent, with the potential to be further expanded to approximately 400,000 bpd of capacity with the addition of pump stations. Norlite will be anchored by throughput commitments from the Fort Hills Partners for production from the proposed Fort Hills Project and from Suncor Partnership’s proprietary oil sands production. Norlite will involve the construction of a new 449-kilometre (278-mile) pipeline from the Company’s Stonefell Terminal to its Cheecham Terminal with an extension to Suncor Partnership’s East Tank Farm, which is adjacent to the Company’s existing Athabasca Terminal. Under an agreement with Keyera Corp. (Keyera), Norlite has the right to access certain existing capacity on Keyera’s pipelines between Edmonton, Alberta and Stonefell, Alberta and, in exchange, Keyera has elected to participate in the new pipeline infrastructure project as a 30% non-operating owner. Subject to regulatory and other approvals, Norlite is expected to be completed in 2017 at an estimated cost of approximately $1.3 billion, with expenditures to date of approximately $0.1 billion.

 

Canadian Line 3 Replacement Program

In 2014, Enbridge and EEP jointly announced that shipper support was received for investment in the Line 3 Replacement Program (L3R Program). The Canadian L3R Program will complement existing integrity programs by replacing approximately 1,084 kilometres (673 miles) of the remaining line segments of the existing Line 3 pipeline between Hardisty, Alberta and Gretna, Manitoba. While the L3R Program will not provide an increase in the overall capacity of the mainline system, it will support the safety and operational reliability of the overall system, enhance flexibility and allow the Company to optimize throughput on the mainline system’s overall western Canada export capacity. The L3R Program is expected to achieve capacity of approximately 760,000 bpd.

 

Subject to regulatory and other approvals, the Canadian L3R Program is targeted to be completed in late 2017. The NEB deemed the Canadian Line 3R Program application complete and issued a hearing order in which it confirmed that it had until May 2016 to issue a decision. The Company has reached a settlement agreement with landowner associations representing Line 3 landowners in Canada and as a result these parties have withdrawn from the hearing process.

 

18



 

The estimated capital cost of the Canadian L3R Program is approximately $4.9 billion, with expenditures to date of approximately $0.7 billion. Costs of the Canadian L3R Program will be recovered through a 15-year toll surcharge mechanism under the Competitive Toll Settlement (CTS). For discussion on EEP’s portion of the L3R Program, refer to Growth Projects – Commercially Secured Projects – Sponsored Investments – Enbridge Energy Partners, L.P. – United States Line 3 Replacement Program.

 

Enbridge Energy Partners, L.P.

Eastern Access

The Eastern Access initiative includes a series of Enbridge and EEP crude oil pipeline projects to provide increased access to refineries in the upper midwest United States and eastern Canada. Projects undertaken by EEP include an expansion of Line 5 and of the United States mainline involving the Spearhead North Pipeline (Line 62), both completed in 2013, and replacement of additional segments of Line 6B, completed in 2014. The cost of these projects is approximately US$2.4 billion. For discussion on the Company’s portion of Eastern Access, refer to Growth Projects – Commercially Secured Projects –Sponsored Investments – The Fund Group – Eastern Access.

 

Additionally, the Eastern Access initiative also includes a further upsizing of EEP’s Line 6B. The Line 6B capacity expansion from Griffith, Indiana to Stockbridge, Michigan will increase capacity from 500,000 bpd to 570,000 bpd and will include pump station modifications at the Griffith, Niles and Mendon stations, additional modifications at the Griffith and Stockbridge terminals and breakout tankage at Stockbridge. The Line 6B capacity expansion is now expected to be placed into service in mid-2016 at an estimated cost of approximately US$0.3 billion.

 

The total estimated cost of the projects being undertaken by EEP as part of the Eastern Access initiative, including the Line 6B capacity expansion project, is approximately US$2.7 billion, with expenditures to date of approximately US$2.3 billion. The Eastern Access projects undertaken by EEP are being funded 75% by Enbridge and 25% by EEP. 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 an additional 15%. On July 30, 2015, Enbridge and EEP reached an agreement to forego distributions to Enbridge Energy, Limited Partnership (EELP) for its interests in the Eastern Access projects until the second quarter of 2016. EELP holds partnership interest in assets that are jointly funded by Enbridge and EEP, including the Eastern Access projects. In return, Enbridge’s capital funding contribution requirements to the Eastern Access projects will be netted against its foregone cash distribution during this period.

 

Lakehead System Mainline Expansion

The Lakehead System Mainline Expansion includes 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. These projects are in addition to expansions of the Lakehead System mainline being undertaken as part of the Eastern Access initiative and include the expansion of Alberta Clipper (Line 67) and Southern Access (Line 61) and the construction of the Spearhead North Twin (Line 78).

 

The current scope of the Alberta Clipper expansion between the border and Superior, Wisconsin consists of two phases. The initial phase increased capacity from 450,000 bpd to 570,000 bpd at an estimated capital cost of approximately US$0.2 billion. The second phase increased capacity from 570,000 bpd to 800,000 bpd at an estimated capital cost of approximately US$0.2 billion. The initial phase was completed in the third quarter of 2014 and the second phase was completed in July 2015. Both phases of the Alberta Clipper expansion required only the addition of pumping horsepower with no pipeline construction and are subject to regulatory 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. EEP continues to work with regulatory authorities; however, the timing of receipt of the amendment to the Presidential border crossing permit to allow for increased flow on Alberta Clipper across the border cannot be determined at this time. A number of temporary system optimization actions have been undertaken to substantially mitigate any impact on throughput associated with any delays in obtaining this amendment.

 

19



 

In November 2014, several environmental and Native American groups filed a complaint in the United States District Court in Minnesota against the United States Department of State (DOS). The Complaint alleges, among other things, that the DOS is in violation of the United States’ National Environmental Policy Act by acquiescing in the Company’s use of permitted cross border capacity on other pipelines to achieve the transportation of amounts in excess of Alberta Clipper’s current permitted capacity while the review and approval of the Company’s application to the DOS to increase Alberta Clipper’s permitted cross border capacity is still pending. The Company has intervened in the case and a decision at the trial level is not expected before the fourth quarter of 2015.

 

The scope of the Southern Access expansion between Superior, Wisconsin and Flanagan, Illinois also consists of phases that require only the addition of pumping horsepower with no pipeline construction. The initial phase to increase the capacity from 400,000 bpd to 560,000 bpd was completed in August 2014 at an estimated capital cost of approximately US$0.2 billion. EEP further expanded the pipeline capacity to 800,000 bpd in May 2015 at an estimated capital cost of approximately US$0.4 billion. Additional tankage is expected to cost approximately US$0.4 billion and will be completed on various dates beginning in the third quarter of 2015 through the third quarter of 2016. In the first quarter of 2015, the Company, in conjunction with shippers, decided to delay the in-service date of a further expansion tranche to increase the pipeline capacity to 1,200,000 bpd at an estimated capital cost of approximately US$0.4 billion, to align more closely with the currently anticipated in-service date for the Sandpiper Project (Sandpiper). In October 2015, a portion of this tranche was put into service early to address capacity constraints, increasing the pipeline capacity to 950,000 bpd. The remaining capacity is expected to be in service in late 2017.

 

As part of the Light Oil Market Access Program, EEP also plans to expand the capacity of the Lakehead System between Flanagan, Illinois and Griffith, Indiana. This section of the Lakehead System will be expanded by constructing a 127-kilometre (79-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 the fourth quarter of 2015.

 

The projects collectively referred to as the Lakehead System Mainline Expansion are expected to cost approximately US$2.3 billion, with expenditures incurred to date of approximately US$1.9 billion. EEP will operate the project on a cost-of-service basis. The Lakehead System Mainline Expansion is funded 75% by Enbridge and 25% by EEP. 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 an additional 15%. On July 30, 2015, Enbridge and EEP reached an agreement to forego distributions to EELP for its interests in the Lakehead System Mainline Expansion until the second quarter of 2016. EELP holds partnership interests in assets that are jointly funded by Enbridge and EEP, including the Lakehead System Mainline Expansion. In return, Enbridge’s capital funding contribution requirements to the Lakehead System Mainline Expansion will be netted against its foregone cash distribution during this period.

 

Beckville Cryogenic Processing Facility

EEP and its partially-owned subsidiary, MEP, have constructed a cryogenic natural gas processing plant near Beckville (the Beckville Plant) in Panola County, Texas. The Beckville Plant offers incremental processing capacity for existing and future customers in the 10-county Cotton Valley shale region, where the East Texas system is located. The Beckville Plant has a natural gas processing capability of 150 mmcf/d and is expected to produce 8,500 bpd of NGL. The Beckville Plant was placed into service in May 2015 at a cost of approximately US$0.2 billion.

 

Eaglebine Gathering

In February 2015, EEP and MEP announced they are entering into the emerging Eaglebine shale play in East Texas through two transactions totalling approximately US$0.2 billion. EEP and MEP have commenced construction of the Ghost Chili pipeline project, which consists of a lateral and associated facilities that will create gathering capacity of over 50 mmcf/d for rich natural gas to be delivered from Eaglebine production areas to their complex of cryogenic processing facilities in East Texas. The initial facilities were placed into service in October 2015. EEP also expects to construct the Ghost Chili

 

20



 

Extension Lateral by late 2016 to fully utilize the gathering capacity with the rest of EEP’s processing assets. MEP also acquired New Gulf Resources, LLC’s midstream business in Leon, Madison and Grimes Counties, Texas. The acquisition consists of a natural gas gathering system that is currently in operation. Expenditures incurred to date are approximately US$0.1 billion.

 

Sandpiper Project

As part of the Light Oil Market Access Program initiative, EEP plans to undertake Sandpiper, 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. The proposed expansion will involve construction of a 965-kilometre (600-mile) line from Beaver Lodge Station near Tioga, North Dakota to the Superior, Wisconsin mainline system terminal. The new line will twin the existing 210,000 bpd North Dakota System mainline, which now terminates at Clearbrook Terminal in Minnesota, by adding 250,000 bpd of capacity between Tioga and Berthold, North Dakota and 225,000 bpd of capacity between Berthold and Clearbrook, both with new 24-inch diameter pipelines, as well as adding 375,000 bpd of capacity between Clearbrook and Superior with a new 30-inch diameter pipeline. Sandpiper is expected to cost approximately US$2.6 billion, with expenditures incurred to date of approximately US$0.7 billion.

 

EEP is in the process of obtaining the appropriate permits for constructing Sandpiper in Minnesota. The project requires both a Certificate of Need and Route Permit from the Minnesota Public Utilities Commission (MNPUC). On August 3, 2015, the MNPUC issued an order granting a Certificate of Need and a separate order restarting the Route Permit proceedings. On September 14, 2015 the Minnesota Court of Appeals reversed the MNPUC’s Certificate of Need order stating that an Environmental Impact Statement must be prepared prior to reaching a final decision in cases where proceedings have been separated and handled sequentially. As of October 7, 2015 the MNPUC stayed its August 3, 2015 order and reopened the Certificate of Need proceeding. Both the MNPUC and EEP have appealed the Minnesota Court of Appeals decision to the State Supreme Court. Activity continues in the Route Permit proceeding according to MNPUC expectations. Subject to regulatory and other approvals, the expected in-service date for Sandpiper is late 2017.

 

Marathon Petroleum Corporation (MPC) has been secured as an anchor shipper for Sandpiper. As part of the arrangement, EEP, through its subsidiary, North Dakota Pipeline Company LLC (NDPC) (formerly known as Enbridge Pipelines (North Dakota) LLC), and Williston Basin Pipeline LLC (Williston), an affiliate of MPC, entered into an agreement to, among other things, admit Williston as a member of NDPC. Williston will fund 37.5% of Sandpiper construction and will have the option to participate in other growth projects within NDPC, unless specifically excluded by the agreement; this investment is not to exceed US$1.2 billion in aggregate. In return for funding part of Sandpiper’s construction, Williston will obtain an approximate 27% equity interest in NDPC at the in-service date of Sandpiper.

 

United States Line 3 Replacement Program

In 2014, Enbridge and EEP jointly announced that shipper support was received for investment in the L3R Program. EEP will undertake the United States portion of the Line 3 Replacement Program (U.S. L3R Program) which will complement existing integrity programs by replacing approximately 576 kilometres (358 miles) of the remaining line segments of the existing Line 3 pipeline between Neche, North Dakota and Superior, Wisconsin. While the L3R Program will not provide an increase in the overall capacity of the mainline system, it will support the safety and operational reliability of the overall system, enhance flexibility and allow the Company to optimize throughput on the mainline system’s overall western Canada export capacity. The L3R Program is expected to achieve capacity of approximately 760,000 bpd.

 

Subject to regulatory and other approvals, the U.S. L3R Program is targeted to be completed in late 2017. The MNPUC found both the Certificate of Need and Route Permit applications for the U.S. L3R Program through Minnesota to be complete. The MNPUC has sent the Certificate of Need application to the ALJ for a pre-hearing meeting to establish a schedule. With respect to the Route Permit, the Minnesota Department of Commerce held public scoping meetings in August 2015. As a result of the Court of Appeals decision in the Sandpiper docket, the ALJ has requested direction on how to proceed with the

 

21



 

Certificate of Need process for Line 3. The Company filed a motion to join the Certificate of Need and Route Permit dockets which would enable the MNPUC to rely on the Comparative Environmental Analysis in reaching its decision on both the Certificate of Need and Route Permit applications.

 

The estimated capital cost of the U.S. L3R Program is approximately US$2.6 billion, with expenditures to date of approximately US$0.3 billion. The U.S. L3R Program will be jointly funded by Enbridge and EEP at participation levels that are subject to finalization. EEP will recover the costs based on its existing Facilities Surcharge Mechanism with the initial term of the agreement being 15 years. For the purpose of the toll surcharge, the agreement specifies a 30-year recovery of the capital based on a cost of service methodology.

 

OTHER ANNOUNCED PROJECTS UNDER DEVELOPMENT

 

The following projects have been announced by the Company, but have not yet met the Company’s criteria to be classified as commercially secured. The Company also has significant additional attractive projects under development that have not yet progressed to the point of public announcement. In its long-term funding plans, the Company makes full provision for all commercially secured projects and makes provision for projects under development based on an assessment of the aggregate securement success anticipated. Actual securement success achieved could exceed or fall short of the anticipated level.

 

LIQUIDS PIPELINES

Northern Gateway Project

The Northern Gateway Project (Northern Gateway) involves constructing a twin 1,178-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 transport imported condensate from Kitimat to the Edmonton area and is proposed to be a 20-inch diameter line with an initial capacity of 193,000 bpd.

 

In June 2014, the Governor in Council approved Northern Gateway, subject to 209 conditions following a recommendation from the Joint Review Panel (JRP). The Company continues to work closely with its customers in advancing this project to open West Coast market access and is making progress in fulfilling the conditions and building relationships and trust with communities and Aboriginal groups along the proposed route.

 

Nine applications to the Federal Court of Appeal (Federal Court) for leave for judicial review of the Order in Council have been filed pursuant to section 55 of the NEB Act. The applicants make two basic arguments in seeking leave. First, they argue that the JRP report and the Order in Council contain evidentiary gaps or gaps in reasoning. Second, they allege that the Crown has failed to discharge its constitutional duty to consult and, if appropriate, accommodate the Aboriginal applicants.

 

On September 26, 2014, the Federal Court granted leave to all nine applications and on December 17, 2014, the Federal Court issued a decision accepting the request by all parties to consolidate the nine applications into a single proceeding (the Application) and stated that delays in the hearing of the Application should be minimized. The filing of the Appellants’ Memoranda of Fact and Law occurred in May 2015 and the Respondents’ Memoranda were filed in June 2015. The hearing of the Application commenced in Vancouver on October 1, 2015 and concluded on October 8, 2015. Depending on the outcome of these proceedings, which is anticipated for 2016, an application for Leave to Appeal to the Supreme Court of Canada is a possibility.

 

The Company reviewed an updated cost estimate of Northern Gateway based on full engineering analysis of the pipeline route and terminal location. Based on this comprehensive review, the Company expects that the final cost of the project will be substantially higher than the preliminary cost figures included in the Northern Gateway filing with the JRP, which reflected a preliminary estimate prepared in 2004 and escalated to 2010. The drivers behind this substantial increase include the significant costs associated with escalation of labour and construction costs, satisfying the 209 conditions imposed in the

 

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Governor in Council approval, a larger portion of high cost pipeline terrain, more extensive terminal site rock excavations and a delayed anticipated in-service date. The updated cost estimate is currently being assessed and refined by Northern Gateway and the potential shippers. Expenditures to date, which relate primarily to the regulatory process, are approximately $0.5 billion, of which approximately half is being funded by potential shippers on Northern Gateway.

 

The in service date of the project will be dependent upon the timing and outcome of judicial reviews, continued commercial support, receipt of regulatory and other approvals and adequately addressing landowner and local community concerns (including those of Aboriginal communities). Of the 48 Aboriginal groups eligible to participate as equity owners, 28 have signed up to do so.

 

Given the many uncertainties surrounding 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 Northern Gateway also maintains a website at www.northerngateway.ca where the full regulatory application submitted to the NEB, the 2010 Enbridge Northern Gateway Community Social Responsibility Report and the December 19, 2013 Report of the JRP on the Northern Gateway Application are available. Unless otherwise specifically stated, none of the information contained on, or connected to, the JRP website or the Northern Gateway website is incorporated by reference in, or otherwise part, of this MD&A.

 

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FINANCIAL RESULTS

 

LIQUIDS PIPELINES

 

 

 

Three months ended

 

Nine months ended

 

 

 

September 30,

 

September 30,

 

 

 

2015 

 

2014 

 

2015 

 

2014 

 

(millions of Canadian dollars)

 

 

 

 

 

 

 

 

 

Canadian Mainline

 

109 

 

128 

 

395 

 

400 

 

Regional Oil Sands System

 

17 

 

44 

 

108 

 

134 

 

Seaway and Flanagan South Pipeline

 

41 

 

16 

 

63 

 

39 

 

Spearhead Pipeline

 

10 

 

 

24 

 

27 

 

Southern Lights Pipeline

 

 

13 

 

 

37 

 

Feeder Pipelines and Other

 

13 

 

11 

 

28 

 

22 

 

Adjusted earnings

 

195 

 

221 

 

627 

 

659 

 

Canadian Mainline - changes in unrealized derivative fair value loss

 

(398)

 

(231)

 

(819)

 

(192)

 

Canadian Mainline - Line 9B costs incurred during reversal

 

(1)

 

(2)

 

(5)

 

(6)

 

Canadian Mainline - write-off of regulatory asset in respect of taxes

 

(88)

 

 

(88)

 

 

Canadian Mainline - impact of tax rate changes

 

 

 

 

 

Regional Oil Sands System - make-up rights adjustment

 

(2)

 

 

 

 

Regional Oil Sands System - leak insurance recoveries

 

 

 

 

 

Regional Oil Sands System - leak remediation and long-term pipeline stabilization costs

 

 

(4)

 

(5)

 

(4)

 

Regional Oil Sands System - impact of tax rate changes

 

 

 

(31)

 

 

Regional Oil Sands System - loss on disposal of non-core assets

 

(7)

 

 

(7)

 

 

Regional Oil Sands System - prior period adjustment

 

16 

 

 

16 

 

 

Seaway and Flanagan South Pipeline - make-up rights adjustment

 

(4)

 

(11)

 

(8)

 

(11)

 

Spearhead Pipeline - make-up rights adjustment

 

 

 

 

(1)

 

Spearhead Pipeline - changes in unrealized fair value loss

 

(1)

 

 

(1)

 

 

Southern Lights Pipeline - changes in unrealized derivative fair value loss

 

 

(9)

 

 

(9)

 

Feeder Pipelines and Other - gain on sale of non-core assets

 

44 

 

 

44 

 

 

Feeder Pipelines and Other - make-up rights adjustment

 

(1)

 

 

(4)

 

 

Feeder Pipelines and Other - project development costs

 

(2)

 

(1)

 

(5)

 

(4)

 

Feeder Pipelines and Other - impact of tax rate changes

 

 

 

(4)

 

 

Earnings/(loss) attributable to common shareholders

 

(247)

 

(31)

 

(260)

 

444 

 

 

Additional details on items impacting Liquids Pipelines earnings/(loss) include:

 

·

Canadian Mainline loss for each period reflected changes in unrealized fair value 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 loss for each period included depreciation and interest expenses charged to Line 9B while it is idled and undergoing a reversal as part of the Company’s Eastern Access initiative.

·

Canadian Mainline loss for 2015 included a write-off of a regulatory asset in respect of taxes resulting from the transfer of assets between entities under common control of Enbridge in support of the Canadian Restructuring Plan.

·

Regional Oil Sands System earnings for 2015 and 2014 included charges, as well as related insurance recoveries, associated with the Line 37 crude oil release, which occurred in June 2013.

 

24



 

·

Earnings/(loss) for Canadian Mainline, Regional Oil Sands System and Feeder Pipelines and Other included the impact of a corporate tax rate change in the province of Alberta on opening deferred income tax balances.

·

Feeder Pipelines and Other earnings for each period included certain business development costs related to Northern Gateway that are anticipated to be recovered over the life of the project.

 

Canadian Mainline

Canadian Mainline adjusted earnings for the three and nine months ended September 30, 2015 are impacted by the effect of the Canadian Restructuring Plan. Prior to September 1, 2015, the closing date of the Canadian Restructuring Plan, Canadian Mainline results were reflected in Liquids Pipelines. Following the close of the Canadian Restructuring Plan on September 1, 2015, the results of Canadian Mainline are no longer reported in the Liquids Pipelines segment, but are captured in the results of the Fund Group which are reported within Sponsored Investments, see Financial Results – Sponsored Investments – The Fund Group. For further details on the Canadian Restructuring Plan refer to Recent Developments – Sponsored Investments – The Fund Group – Canadian Restructuring Plan.

 

Prior to the closing of the Canadian Restructuring Plan on September 1, 2015, Canadian Mainline adjusted earnings increased compared with the corresponding 2014 periods. The period-over-period increase reflected higher throughput from strong oil sands production combined with strong refinery demand in the midwest market partly due to a start-up of a midwest refinery’s conversion to heavy oil processing in the second quarter of 2014. Higher throughput in the third quarter of 2015 was also achieved from the expansion of the Company’s mainline system completed in July 2015 and through continued efforts by the Company to optimize capacity utilization and to enhance scheduling efficiency with shippers. Although throughput increased relative to the comparative periods in 2014, further throughput growth in 2015 was hindered by upstream plant maintenance in Alberta during the second and third quarters which impacted light volumes, and an unplanned shutdown of a midwest refinery that impacted the takeaway of heavy volumes in the third quarter. Other factors contributing to an increase in adjusted earnings were higher terminalling revenues and the impact of a stronger United States dollar as the IJT Benchmark Toll and its components are set in United States dollars. The majority of the Company’s foreign exchange risk on Canadian Mainline earnings is hedged; however, the average foreign exchange rate at which these revenues were hedged was higher during the nine months ended September 30, 2015 compared with the same period in 2014. These trends continued into the month of September 2015, with Canadian Mainline adjusted earnings for the month of September 2015 now being reflected in the Fund Group, whereas the comparative September 2014 period was reflected in Liquids Pipelines.

 

Partially offsetting the positive factors noted above for the eight month period ended August 31, 2015 was a lower average Canadian Mainline IJT Residual Benchmark Toll, although this impact lessened commencing the second quarter of 2015 as effective April 1, 2015, this toll increased by US$0.10 per barrel to US$1.63 per barrel. Changes in the Canadian Mainline IJT Residual Benchmark Toll are inversely related to the Lakehead System Toll, which was higher due to the recovery of incremental costs associated with EEP’s growth projects. Also mitigating the impact of a lower Canadian Mainline IJT Residual Benchmark Toll were new surcharges related to system expansions, including a surcharge for the Edmonton to Hardisty Expansion pipeline completed in April 2015. Other factors which negatively impacted adjusted earnings were higher power costs associated with higher throughput, higher depreciation expense due to an increased asset base and higher interest expense resulting from higher outstanding debt to support increased business activities.

 

Supplemental information on Canadian Mainline adjusted earnings for the three and nine months ended September 30, 2015 and 2014 is provided below.

 

25



 

 

 

Three months ended

 

Nine months ended

 

 

 

September 30,1

 

September 30,1

 

 

 

2015

 

2014

 

2015

 

2014

 

(millions of Canadian dollars)

 

 

 

 

 

 

 

 

 

Revenues6

 

495

 

366

 

1,313

 

1,121

 

Expenses

 

 

 

 

 

 

 

 

 

Operating and administrative6

 

94

 

99

 

296

 

282

 

Power

 

62

 

41

 

158

 

117

 

Depreciation and amortization

 

82

 

67

 

224

 

198

 

 

 

238

 

207

 

678

 

597

 

 

 

257

 

159

 

635

 

524

 

Other income/(expense)

 

(11)

 

6

 

(8)

 

4

 

Interest expense

 

(51)

 

(40)

 

(149)

 

(118

)

 

 

195

 

125

 

478

 

410

 

Income taxes recovery/(expense)

 

(16)

 

3

 

(13)

 

(10

)

 

 

179

 

128

 

465

 

400

 

Amounts attributable to the Fund Group within Sponsored Investments1

 

(70)

 

-

 

(70)

 

-

 

Adjusted earnings - Liquids Pipelines1

 

109

 

128

 

395

 

400

 

 

 

 

 

 

 

 

 

 

 

Effective United States to Canadian dollar exchange rate2

 

1.113

 

1.016

 

1.097

 

1.019

 

 

As at September 30,

 

2015

 

2014

(United States dollars per barrel)

 

 

 

 

IJT Benchmark Toll3

 

$4.07

 

$4.02

Lakehead System Local Toll4

 

$2.44

 

$2.49

Canadian Mainline IJT Residual Benchmark Toll5

 

$1.63

 

$1.53

1                  Effective September 1, 2015, the results of Canadian Mainline are reflected in adjusted earnings from the Fund Group within the Sponsored Investments segment, whereas results prior to September 1, 2015, are reflected in Liquids Pipelines adjusted earnings.

2                  Inclusive of realized gains and losses on foreign exchange derivative financial instruments.

3                  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, 2014, the IJT Benchmark Toll increased from US$3.98 to US$4.02 and increased to US$4.07 effective July 1, 2015.

4                  The Lakehead System Local Toll is per barrel of heavy crude oil transported from Neche, North Dakota to Chicago, Illinois. In 2014, EEP delayed its annual April 1 tariff filing for its Lakehead System as it was in negotiations with the Canadian Association of Petroleum Producers concerning certain components of the tariff rate structure. The toll application was filed with the FERC on June 27, 2014, and effective August 1, 2014, the Lakehead System Local Toll increased from US$2.17 to US$2.49. Effective April 1, 2015, the Lakehead System Local Toll decreased from US$2.49 to US$2.39. Effective July 1, 2015, this toll increased to US$2.44.

5                  The Canadian Mainline IJT Residual Benchmark Toll is per barrel of heavy crude oil transported from Hardisty, Alberta to Gretna, Manitoba. For any shipment, this toll is the difference between the IJT Benchmark Toll and the Lakehead System Local Toll. Effective July 1, 2014, this toll increased from US$1.81 to US$1.85 and subsequently decreased to US$1.53 effective August 1, 2014, coinciding with the revised Lakehead System Local Toll. Effective April 1, 2015, the Canadian Mainline IJT Residual Benchmark Toll increased to US$1.63.

6                  In 2015, the Company commenced collecting, in its tolls, NEB mandated future abandonment costs from shippers. Approximately $10 million and $27 million in revenues were recorded for the three and nine months ended September 30, 2015, respectively, but these amounts were offset by a regulatory expense within operating and administrative expense. For further details, refer to Critical Accounting Estimates.

 

 

 

Three months ended

 

Nine months ended

 

 

 

September 30,

 

September 30,

 

 

 

2015

 

2014

 

2015

 

2014

 

Throughput1 (thousand barrels per day (kbpd))

 

2,212

 

2,039

 

2,165

 

1,970

 

1                  Throughput volume, presented in kbpd, represents mainline deliveries ex-Gretna, Manitoba which is made up of United States and eastern Canada deliveries originating from western Canada. The results of Canadian Mainline are reflected in Liquids Pipeline from January 1, 2015 to August 31, 2015. Effective September 1, 2015, the results of Canadian Mainline are reflected in the Fund Group.

 

26



 

Regional Oil Sands System

Regional Oil Sands System adjusted earnings for the three and nine months ended September 30, 2015 decreased compared with the corresponding 2014 periods. The decrease in adjusted earnings was primarily due to the transfer of the Regional Oil Sands System to the Fund Group, within the Sponsored Investments segment. Following the close of the Canadian Restructuring Plan on September 1, 2015, the results of Regional Oil Sands System are no longer reported in the Liquids Pipelines segment, but are captured in the results of the Fund Group within Sponsored Investments, see Financial Results — Sponsored Investments — The Fund Group. For further details on the Canadian Restructuring Plan refer to Recent Developments — Sponsored Investments — The Fund Group — Canadian Restructuring Plan.

 

Prior to the closing of the Canadian Restructuring Plan on September 1, 2015, Regional Oil Sands System adjusted earnings were lower compared with the corresponding 2014 period and reflected a reduction in contracted volumes on the Athabasca Mainline, although mitigated in part by higher uncommitted volumes on this pipeline. Higher depreciation expense from a larger asset base and higher interest expense also contributed to a decrease in period-over-period adjusted earnings. These negative effects were partially offset by higher earnings from assets placed into service in 2014 and 2015, including the Norealis Pipeline completed in April 2014. This trend continued into the month of September 2015, with Regional Oil Sands System adjusted earnings for the month of September 2015 now being reflected in the Fund Group, whereas the adjusted earnings for the September 2014 period was reflected in Liquids Pipelines.

 

Seaway and Flanagan South Pipelines

Seaway and Flanagan South Pipelines adjusted earnings for the three and nine months ended September 30, 2015 increased relative to the corresponding 2014 periods and reflected the effects of Flanagan South Pipeline and Seaway Pipeline Twin commencing operations in late 2014. During the first half of 2015, as a result of Canadian Mainline apportionment, throughput on Seaway and Flanagan South Pipelines was lower than the throughput committed on these pipelines. However, this upstream apportionment was partially alleviated in the third quarter of 2015 through the expansion of the Company’s mainline system completed in July 2015. When committed shippers on Flanagan South are unable to fulfill their volume commitments due to apportionment, they are provided with temporary relief to make up those volumes during the course of their contracts or the apportioned volumes are added on to the end of the contract term.

 

Spearhead Pipeline

Spearhead Pipeline adjusted earnings decreased for the nine months ended September 30, 2015 compared with the same 2014 period. Lower throughput due to upstream apportionment, refinery maintenance and unscheduled shutdown, as well as power outages, drove lower adjusted earnings for the nine months ended September 30, 2015. These negative effects were partially offset by a decrease in power cost associated with the lower throughput.

 

Southern Lights Pipeline

Southern Lights Pipeline adjusted earnings for the three and nine months ended September 30, 2015 decreased relative to the corresponding 2014 periods. The majority of the economic benefit derived from Southern Lights Pipeline was reflected in earnings from the Fund Group following the Fund Group’s November 2014 subscription and purchase of Class A units of certain Enbridge subsidiaries that indirectly own the Canadian and United States segments of the Southern Lights Pipeline. The Class A units provide a defined cash flow stream from Southern Lights Pipeline. In addition, as part of the Canadian Restructuring Plan, effective September 1, 2015, Enbridge transferred all Class B units of Southern Lights Canada to the Fund Group. Following the closing of the Transaction, the Fund Group holds all the ownership, economic interests and voting rights, direct and indirect, in Southern Lights Canada. Enbridge continues to indirectly own all of the Class B Units of Southern Lights US.

 

Feeder Pipelines and Other

Feeder Pipelines and Other adjusted earnings for the three and nine months ended September 30, 2015 increased compared with the corresponding 2014 periods. The increase in adjusted earnings was attributable to higher earnings from Eddystone Rail Project completed in April 2014, incremental earnings

 

27



 

from certain storage agreements and higher tolls and throughput on Toledo Pipeline. Partially offsetting the increase in adjusted earnings were higher business development costs not eligible for capitalization in the first quarter of 2015, lower average tolls on Olympic Pipeline and higher property taxes relating to Toledo Pipeline mainly in the third quarter of 2015.

 

GAS DISTRIBUTION

 

 

 

Three months ended

 

Nine months ended

 

 

 

September 30,

 

September 30,

 

 

 

2015

 

2014

 

2015

 

2014

 

(millions of Canadian dollars)

 

 

 

 

 

 

 

 

 

Enbridge Gas Distribution Inc. (EGD)

 

4

 

(3)

 

131

 

100

 

Other Gas Distribution and Storage

 

(3)

 

(6)

 

21

 

9

 

Adjusted earnings/(loss)

 

1

 

(9)

 

152

 

109

 

EGD - (warmer)/colder than normal weather

 

-

 

(2)

 

27

 

35

 

EGD - changes in unrealized derivative fair value loss

 

(3)

 

-

 

(3)

 

-

 

Earnings/(loss) attributable to common shareholders

 

(2)

 

(11)

 

176

 

144

 

 

EGD adjusted earnings increased for the three and nine months ended September 30, 2015 compared with the corresponding 2014 periods. While both periods reflected rates as established under EGD’s Customized Incentive Rate Plan, the higher adjusted earnings in 2015 were primarily attributable to higher distribution charges due to increased assets base, as well as customer growth in 2015.

 

Other Gas Distribution and Storage earnings increased for the nine months ended September 30, 2015 compared with the corresponding 2014 period. The increase in earnings reflected the absence of a loss that EGNB incurred in 2014 under a contract to sell natural gas to the province of New Brunswick. Due to an abnormally cold winter in the first quarter of 2014, costs associated with the fulfilment of the contract were higher than the revenues received. Excluding the impact of the above noted contract which expired in October 2014, EGNB adjusted earnings for the nine months ended September 30, 2015 increased slightly due to higher distribution revenues.

 

Other Gas Distribution and Storage loss for the third quarter of 2015 decreased compared with the corresponding 2014 three-month period, reflecting similar trends as the year-to-date results noted above.

 

28



 

GAS PIPELINES, PROCESSING AND ENERGY SERVICES

 

 

 

Three months ended

 

Nine months ended

 

 

 

September 30,

 

September 30,

 

 

 

2015

 

2014

 

2015

 

2014

 

(millions of Canadian dollars)

 

 

 

 

 

 

 

 

 

Aux Sable

 

(6)

 

9

 

(2)

 

20

 

Energy Services

 

(19)

 

(3)

 

53

 

27

 

Alliance Pipeline US

 

-

 

12

 

-

 

36

 

Vector Pipeline

 

2

 

3

 

11

 

12

 

Canadian Midstream

 

6

 

6

 

29

 

17

 

Enbridge Offshore Pipelines (Offshore)

 

1

 

(3)

 

(1)

 

(3

)

Other

 

(5)

 

(4)

 

4

 

(3

)

Adjusted earnings/(loss)

 

(21)

 

20

 

94

 

106

 

Aux Sable - accrual for commercial arrangements

 

-

 

-

 

(10)

 

-

 

Energy Services - changes in unrealized derivative fair value gains

 

126

 

71

 

92

 

288

 

Canadian Midstream - impact of tax rate changes

 

(2)

 

-

 

(3)

 

-

 

Offshore - changes in unrealized derivative fair value loss

 

-

 

(2)

 

-

 

(2

)

Offshore - gain on sale of non-core assets

 

-

 

-

 

4

 

43

 

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

 

1

 

(1)

 

1

 

(3

)

Other - impact of tax rate changes

 

-

 

-

 

(4)

 

-

 

Earnings attributable to common shareholders

 

104

 

88

 

174

 

432

 

 

Additional details on items impacting Gas Pipelines, Processing and Energy Services earnings include:

·                  Energy Services earnings for each period reflected changes in unrealized fair value gains related to the revaluation of financial derivatives used to manage the profitability of transportation and storage transactions and the revaluation of inventory. Energy Services adjusted earnings for 2014 excluded a realized loss of $71 million incurred during the second quarter of 2014 to close out certain forward derivative financial contracts intended to hedge the value of committed physical transportation capacity in certain markets accessed by Energy Services, but determined to be no longer effective in doing so.

·                  Other earnings/(loss) for each period reflected changes in unrealized fair value gains and losses on the long-term power price derivative contracts acquired to hedge expected revenues and cash flows from the Blackspring Ridge Wind Project.

·                  Other earnings for 2015 included the impact of a corporate tax rate change in the province of Alberta on opening deferred income tax balances.

 

Aux Sable reported adjusted losses for the three and nine month periods ended September 30, 2015, compared with adjusted earnings reported in the corresponding 2014 periods. Lower fractionation margins resulting from a weaker commodity price environment, absence of contributions from the upside sharing mechanism and the loss of a producer processing contract at the Palermo Conditioning Plant were the main drivers behind the period-over-period decreases in adjusted earnings.

 

Energy Services operates a physical commodity marketing business which captures 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. Energy Services adjusted earnings for the nine months ended September 30, 2015 increased compared with the corresponding 2014 period. Higher earnings reflected strong refinery demand for blended crude oil feedstock leading to more favourable tank management opportunities during the first half of 2015. Also favourably impacting period-over-period adjusted earnings was the absence of losses realized in the first quarter of 2014 on certain financial contracts intended to hedge the value of committed transportation capacity, but which were not effective in doing so. During the second quarter of 2014, the Company closed out a forward component of these derivative contracts which had been determined to be no longer effective.

 

29



 

An adjusted loss in the third quarter of 2015 resulted from less favourable conditions in certain markets accessed by committed transportation capacity involving unrecovered demand charges, combined with an erosion of the favourable tank management opportunities experienced in the first half of 2015 due to a reduction in refinery demand for blended crude oil feedstock in the Gulf Coast. Adjusted earnings from Energy Services are dependent on market conditions and results achieved in one period may not be indicative of results to be achieved in future periods.

 

The absence of Alliance Pipeline US earnings for the three and nine months ended September 30, 2015 reflected the transfer of Alliance Pipeline US to the Fund Group in November 2014.

 

Canadian Midstream earnings increased for the nine months ended September 30, 2015 compared with the corresponding 2014 period. Higher earnings reflected an increase in take-or-pay fees on the Company’s investment in Cabin Gas Plant and the Pipestone and Sexsmith Sour Gas Gathering and Compression Facilities, as well as higher volumes at Pipestone. These positive impacts were partially offset by the timing of operating expenses which were higher in the third quarter of 2015 than in the prior two quarters.

 

Adjusted loss for Offshore pipelines for the nine months ended September 30, 2015 was slightly lower than the loss in the corresponding 2014 period. Higher earnings from the Jack St. Malo portion of WRGGS were offset by losses from equity investments in certain joint venture pipelines and the absence of earnings from non-core assets sold in March 2014. The third quarter of 2015 reflected similar year-to-date trends; however, the absence of earnings from disposals of non-core assets did not have a quarter-over-quarter impact.

 

Adjusted earnings from Other are impacted by the effects of the Canadian Restructuring Plan. Prior to September 1, 2015, the closing date of the Canadian Restructuring Plan, Other included results from Lac Alfred, Massif du Sud, Blackspring Ridge and Saint Robert Bellarmin wind projects. Following the close of the Canadian Restructuring Plan on September 1, 2015, the results of these wind projects are no longer reported in the Gas Pipelines, Processing and Energy Services segment, but are captured in the results of the Fund Group within Sponsored Investments, see Financial Results — Sponsored Investments — The Fund Group. For further details on the Canadian Restructuring Plan refer to Recent Developments — Sponsored Investments — The Fund Group — Canadian Restructuring Plan.

 

Prior to September 1, 2015, adjusted earnings from Other increased compared with the corresponding 2014 periods. The period-over-period increase reflected contributions from new wind farms including the Wildcat and Magic Valley wind farms acquired at the end of 2014 and incremental earnings associated with the purchase of additional interests in the Lac Alfred and Massif du Sud wind projects, which closed in the fourth quarter of 2014, partially offset by higher business development costs not eligible for capitalization within Other. This trend continued into the month of September 2015; however, adjusted earnings for the month of September 2015 from the wind projects noted above, as part of the Canadian Restructuring Plan, were reflected in the Fund Group, whereas adjusted earnings for the September 2014 period were reflected in Gas Pipelines, Processing and Energy Services.

 

30



 

SPONSORED INVESTMENTS

 

 

 

 

Three months ended

 

Nine months ended

 

 

 

September 30,

 

September 30,

 

 

 

2015

 

 

2014

 

 

 

2015

 

 

2014

 

(millions of Canadian dollars)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

The Fund Group

 

 

132

 

 

26

 

 

 

222

 

 

91

 

Enbridge Energy Partners, L.P. (EEP)

 

 

60

 

 

62

 

 

 

186

 

 

157

 

Enbridge Energy, Limited Partnership (EELP)

 

 

32

 

 

38

 

 

 

82

 

 

58

 

Adjusted earnings

 

 

224

 

 

126

 

 

 

490

 

 

306

 

The Fund Group - make-up rights adjustment

 

 

(2

)

 

(1

)

 

 

(1

)

 

(1

)

The Fund Group - changes in unrealized derivative fair value gains/(loss)

 

 

(99

)

 

3

 

 

 

(107

)

 

3

 

The Fund Group - unrealized intercompany foreign exchange gains

 

 

17

 

 

-

 

 

 

29

 

 

-

 

The Fund Group - drop down transaction costs

 

 

-

 

 

(2

)

 

 

(3

)

 

(2

)

The Fund Group - gain on sale

 

 

-

 

 

-

 

 

 

5

 

 

-

 

The Fund Group - impact of tax rate changes

 

 

-

 

 

-

 

 

 

(6

)

 

-

 

The Fund Group - write-down of regulatory balances

 

 

-

 

 

-

 

 

 

(3

)

 

-

 

The Fund Group - prior period adjustment

 

 

(13

)

 

-

 

 

 

(13

)

 

-

 

EEP - changes in unrealized derivative fair value loss

 

 

(1

)

 

(6

)

 

 

(4

)

 

(9

)

EEP - make-up rights adjustment

 

 

-

 

 

-

 

 

 

1

 

 

(1

)

EEP - valuation allowance on deferred income tax assets

 

 

(32

)

 

-

 

 

 

(32

)

 

-

 

EEP - goodwill impairment loss

 

 

-

 

 

-

 

 

 

(167

)

 

-

 

EEP - leak remediation costs

 

 

-

 

 

(12

)

 

 

-

 

 

(17

)

EEP - transfer of contracts

 

 

(1

)

 

-

 

 

 

(1

)

 

-

 

EEP - hydrostatic testing

 

 

(6

)

 

-

 

 

 

(6

)

 

-

 

Earnings attributable to common shareholders

 

 

87

 

 

108

 

 

 

182

 

 

279

 

 

Additional details on items impacting Sponsored Investments earnings/(loss) include:

·                  The Fund Group earnings for 2015 reflected changes in unrealized fair value 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.

·                  The Fund Group earnings for 2015 included the impact of a corporate tax rate change in the province of Alberta on opening deferred income tax balances.

·                  EEP earnings for 2015 included a goodwill impairment charge related to EEP’s natural gas and NGL businesses due to a prolonged decline in commodity prices which has reduced producers’ expected drilling programs and negatively impacted volumes on EEP’s natural gas and NGL systems.

·                  EEP earnings for 2014 included charges related to estimated costs, before insurance recoveries, associated with the Line 6B crude oil release. See Recent Developments – Sponsored Investments – Enbridge Energy Partners, L.P. Lakehead System Lines 6A and 6B Crude Oil Releases.

 

The Fund Group

Adjusted earnings from the Fund Group for the three and nine months ended September 30, 2015 increased compared with the 2014 comparative periods. The significant increase in adjusted earnings is largely attributable to the transfer of the Canadian liquids business and certain Canadian renewable energy assets from Enbridge as well as Enbridge’s overall 91.9% economic interest in the Fund Group, effective September 1, 2015, the closing date of the Canadian Restructuring Plan. For further discussion on the Canadian Restructuring Plan refer to Recent Developments – Sponsored Investments – The Fund Group – Canadian Restructuring Plan. Adjusted earnings from assets transferred under the Canadian Restructuring Plan were impacted by the reasons discussed in the Financial Performance section of Liquids Pipelines and Gas Pipelines, Processing and Energy Services segments.

 

Also positively impacting adjusted earnings from the Fund Group were incremental earnings from natural gas and diluent pipeline interests transferred by Enbridge to the Fund Group in November 2014. Partially

 

31



 

offsetting the increase in adjusted earnings were higher financing costs associated with debt raised to acquire the natural gas and diluent pipeline interests and higher income taxes.

 

Enbridge Energy Partners, L.P.

EEP adjusted earnings increased for the nine months ended September 30, 2015 compared with the corresponding 2014 period. The adjusted earnings increase reflected higher throughput and tolls in EEP’s liquids business, as well as contributions from new assets placed into service in 2014 and 2015, the most prominent being the replacement and expansion of Line 6B completed in 2014 and the expansion of the Company’s mainline system completed in July 2015. In addition, EEP adjusted earnings reflected incremental earnings from the transfer on January 2, 2015 of the remaining 66.7% interest in Alberta Clipper previously held by Enbridge through EELP. Partially offsetting the increase in adjusted earnings in EEP’s liquids business were higher operating and administrative costs, incremental power costs associated with higher throughput and higher depreciation expense from an increased asset base. Also contributing to higher earnings for the nine month period ended September 30, 2015 were distributions from Class D units and IDU which were issued to Enbridge in July 2014 under an equity restructuring transaction and from Class E units which were issued in January 2015 in connection with the transfer of Alberta Clipper. Finally, the 2015 year-to-date results reflected lower volumes within EEP’s natural gas and NGL businesses primarily as a result of reduced drilling programs by producers. EEP holds its natural gas and NGL businesses directly and indirectly through its partially-owned subsidiary, MEP.

 

EEP adjusted earnings for the three months ended September 30, 2015 were comparable with the adjusted earnings for the corresponding period in 2014. The trends noted above for the nine-month period were also applicable to the third quarter of 2015; however, the period-over-period change in the adjusted earnings was impacted by the absence of incremental distributions from Class D units and IDU in the third quarter of 2015 as those units were issued in July 2014.

 

On July 30, 2015, Enbridge and EEP reached an agreement to extend the deferral of quarterly cash distribution on Series 1 preferred units issued by EEP to Enbridge in May 2013. The first quarterly cash distribution will now occur in the third quarter of 2018 and the deferred distribution will now be payable in equal amounts over a 12-quarter period beginning the first quarter of 2019.

 

Enbridge Energy, Limited Partnership

EELP earnings reflect Enbridge’s interests in both the Eastern Access and Lakehead System Mainline expansion projects. Adjusted earnings from EELP increased for the nine-month period ended September 30, 2015 compared with the corresponding nine-month period in 2014 due to contributions from assets recently placed into service, most notably the expansion of Line 6B completed in phases during 2014 as part of the Company’s Eastern Access Program and the expansion of the Company’s mainline system completed in July 2015. Partially offsetting the increase in the nine months of earnings was the absence of earnings from EELP’s interest in Alberta Clipper which was transferred to EEP on January 2, 2015.

 

For the three months ended September 30, 2015, the positive effects of Eastern Access and Lakehead System Mainline expansion projects noted above were more than offset by the absence of earnings from EELP’s interest in Alberta Clipper, which had a strong third quarter of 2014.

 

32



 

CORPORATE

 

 

 

 

Three months ended

 

Nine months ended

 

 

 

September 30,

 

September 30,

 

 

 

2015

 

 

2014

 

 

 

2015

 

 

2014

 

(millions of Canadian dollars)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Noverco

 

 

(4

)

 

(3

)

 

 

28

 

 

22

 

Other Corporate

 

 

4

 

 

(10

)

 

 

(19

)

 

(37

)

Adjusted earnings/(loss)

 

 

-

 

 

(13

)

 

 

9

 

 

(15

)

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

 

 

3

 

 

-

 

 

 

(7

)

 

(5

)

Other Corporate - changes in unrealized derivative fair value loss

 

 

(282

)

 

(221

)

 

 

(487

)

 

(227

)

Other Corporate - loss on de-designation of interest rate hedges in connection with the Canadian Restructuring Plan

 

 

(247

)

 

-

 

 

 

(247

)

 

-

 

Other Corporate - transaction costs relating to the Canadian Restructuring Plan

 

 

(16

)

 

-

 

 

 

(16

)

 

-

 

Other Corporate - deferred income tax out-of-period adjustments

 

 

-

 

 

-

 

 

 

71

 

 

-

 

Other Corporate - impact of tax rate changes

 

 

-

 

 

-

 

 

 

44

 

 

-

 

Other Corporate - drop down transaction costs

 

 

-

 

 

-

 

 

 

(6

)

 

-

 

Other Corporate - tax on intercompany gains on sale of partnership units

 

 

-

 

 

-

 

 

 

(39

)

 

-

 

Other Corporate - gain on sale of investment

 

 

-

 

 

-

 

 

 

-

 

 

14

 

Other Corporate - prior period adjustment

 

 

(9

)

 

-

 

 

 

(9

)

 

-

 

Loss attributable to common shareholders

 

 

(551

)

 

(234

)

 

 

(687

)

 

(233

)

 

Additional details on items impacting Corporate earnings/loss include:

·                  Other Corporate loss for each period included changes in the unrealized fair value losses on derivative financial instruments related to forward foreign exchange risk management positions.

·                  Other Corporate loss for 2015 included an out-of-period adjustment to reduce deferred income tax expense related to intercompany preferred dividends.

·                  Other Corporate loss for 2015 included the impact of a corporate tax rate change in the province of Alberta on opening deferred income tax balances.

 

Noverco adjusted earnings for the nine months ended September 30, 2015 increased compared with the corresponding 2014 period. Noverco adjusted earnings include returns on the Company’s preferred share investments, as well as its equity earnings from Noverco’s underlying gas and power distribution investments through Gaz Metro Limited Partnership (Gaz Metro). The increase in adjusted earnings for the nine months ended September 30, 2015 reflected stronger operating earnings from Gaz Metro due to a favourable United States/Canada foreign exchange rate on Gaz Metro’s United States based business and incremental earnings from new assets. Partially offsetting the higher adjusted earnings were lower preferred share dividend income based on lower yield of 10-year Government of Canada bonds to which the dividend rate is linked as compared with the prior year.

 

Noverco adjusted loss for the three months ended September 30, 2015 increased slightly compared with the corresponding 2014 three month period. Excluding the timing of a positive equity earnings adjustment related to the second quarter of 2014, which was recognized in the third quarter of 2014, Noverco adjusted loss decreased in the three months ended September 30, 2015 compared with the corresponding 2014 period and reflected the year-to-date trends noted above.

 

Other Corporate adjusted loss decreased for the nine months ended September 30, 2015 compared with the corresponding 2014 period and reflected lower net Corporate segment finance costs in the first half of 2015 and lower income taxes, partially offset by higher operating and administrative expenses and preference share dividends on additional preference shares issued in 2014 to fund the Company’s growth

 

33



 

capital program. In the third quarter of 2015, Other Corporate also benefitted from the positive effects of foreign exchange rates on certain foreign currency balances.

 

LIQUIDITY AND CAPITAL RESOURCES

 

The maintenance of financial strength and flexibility is fundamental to Enbridge’s growth strategy, particularly in light of the record level of capital projects currently secured or under development. Access to timely funding from capital markets could be limited by factors outside Enbridge’s control, including but not limited to financial market volatility resulting from economic and political events both inside and outside North America. To mitigate such risks, the Company actively manages financial plans and strategies to ensure it maintains sufficient liquidity to meet routine operating and future capital requirements. In the near term, the Company generally expects to utilize cash from operations and 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. Furthermore, Enbridge targets to maintain sufficient standby liquidity to bridge fund through protracted capital markets disruptions. The Company targets to maintain sufficient liquidity through committed credit facilities with a diversified group of banks and institutions to enable it to fund all anticipated requirements for approximately one year without accessing the capital markets.

 

The Company’s financing plan is regularly updated to reflect evolving capital requirements and financial market conditions and identifies a variety of potential sources of debt and equity funding alternatives, including utilization of its sponsored vehicles through which it can monetize assets, with the objective of diversifying funding sources and maintaining access to low cost capital.

 

Following the Company’s announcement of the execution of the definitive agreement in connection with the Canadian Restructuring Plan and ENF receiving shareholder approval thereof, as applicable, certain credit ratings of the Company were revised or affirmed.

 

·                  DBRS Limited downgraded the Company’s issuer rating and medium-term notes and unsecured debentures rating from A (low) to BBB (high), downgraded the Company’s commercial paper rating from R-1 (low) to R-2 (high) and downgraded the Company’s preference share rating from Pfd-2 (low) to Pfd-3 (high), all with stable trends.

·                  Moody’s Investor Services, Inc. downgraded the Company’s issuer rating and medium-term notes and unsecured debt rating from Baa1 to Baa2 and updated this rating outlook to stable and downgraded the Company’s preference share credit rating from Baa3 to Ba1 and updated this rating outlook to stable.

·                  Standard & Poor’s Ratings Services (S&P) downgraded the Company’s corporate credit rating and unsecured debt rating from A- to BBB+ and removed these ratings from credit watch and downgraded the Company’s preference share credit rating from P-2 to P-2 (low) and removed this rating from credit watch. S&P also affirmed the Company’s Canadian commercial paper credit rating of A-1 (low), removed this rating from credit watch and maintained an overall A-2 short-term rating and removed this rating from credit watch.

 

All ratings now have a stable outlook and the Company believes that it continues to have appropriate access to financial markets both in Canada and the United States.

 

In accordance with its funding plan, the Company has completed the following public issuances to date in 2015:

 

Segment

 

Entity

 

Type of Issuance

 

Amount ($millions)

 

Gas Distribution

 

EGD

 

Medium-term notes

 

$570

 

Sponsored Investments

 

EPI
(via the Fund Group)

 

Medium-term notes

 

$1,000

 

Sponsored Investments

 

EEP

 

Class A common units

 

US$294

 

Sponsored Investments

 

EEP

 

Senior notes

 

US$1,600

 

 

34



 

In addition, ENF announced on October 13, 2015 that it had entered into an agreement to issue $700 million of common equity on a bought deal basis to a syndicate of underwriters. The transaction is expected to close on or about November 6, 2015, see Recent Developments – Sponsored Investments – The Fund Group – Canadian Restructuring Plan – Financing Plan.

 

To ensure ongoing liquidity and to mitigate the risk of capital market disruption, Enbridge maintains ready access to funds through committed bank credit facilities. In addition to ensuring adequate liquidity, the Company actively manages its bank funding sources to optimize pricing and other terms. The following table provides a summary of the Company’s committed credit facilities as at September 30, 2015 and December 31, 2014.

 

 

 

 

 

September 30, 2015

 

 

December 31,
2014

 

 

 

Maturity
Dates

 

 

Total
Facilities

 

Draws

1

Available

 

 

 

Total
Facilities

 

(millions of Canadian dollars)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Liquids Pipelines

 

2017

 

 

3,027

 

1,180

 

1,847

 

 

 

300

 

Gas Distribution

 

2017-2019

 

 

1,009

 

543

 

466

 

 

 

1,008

 

Sponsored Investments

 

2017-2019

 

 

5,072

 

3,796

 

1,276

 

 

 

4,531

 

Corporate

 

2016-2020

 

 

12,390

 

7,409

 

4,981

 

 

 

12,772

 

Total committed credit facilities

 

 

 

 

21,498

 

12,928

 

8,570

 

 

 

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 $401 million (December 31, 2014 - $361 million) of uncommitted demand credit facilities, of which $50 million (December 31, 2014 - $80 million) were unutilized as at September 30, 2015.

 

The Company’s net available liquidity of $9,225 million as at September 30, 2015 was inclusive of $1,024 million of unrestricted cash and cash equivalents and net of bank indebtedness of $369 million as reported on the Consolidated Statements of Financial Position.

 

The Company’s credit facility agreements include standard events of default and covenant provisions whereby accelerated repayment may be required if the Company were to default on payment or violate certain covenants. As at September 30, 2015, the Company was in compliance with all debt covenants and expects to continue to comply with such covenants.

 

There are no material restrictions on the Company’s cash with the exception of cash in trust of $68 million related to cash collateral and for specific shipper commitments. Cash and cash equivalents held by EEP and the Fund Group are generally not readily accessible by Enbridge until distributions are declared and paid by these entities, which occurs quarterly for EEP and monthly for the Fund Group. Further, cash and cash equivalents held by certain foreign subsidiaries may not be readily accessible for alternative uses by Enbridge.

 

OPERATING ACTIVITIES

Cash generated from operating activities for the three and nine months ended September 30, 2015 was $905 million and $3,765 million, respectively, compared with $746 million and $1,891 million for the three and nine months ended September 30, 2014.

 

Cash from operating activities increased by approximately $159 million and $1,874 million for the three and nine months ended September 30, 2015, respectively, relative to the comparable periods in 2014. This cash growth delivered by operations is a reflection of the positive factors discussed in Financial Results, which include higher throughput on Canadian Mainline, higher volumes and tolls on EEP’s liquids business, contributions from new liquids pipeline assets placed into service in recent years and strong refinery demand for crude oil feedstock leading to more favourable tank management opportunities for Energy Services.

 

35



 

Another contributor to the increase in cash from operating activities for the nine months ended September 30, 2015 was a positive period-over-period change in operating assets and liabilities of approximately $1,039 million derived primarily from a negative impact in early 2014 related to significantly higher natural gas prices combined with colder weather within the Company’s gas distribution business, which resulted in the Company accumulating a significant regulatory receivable, fluctuations in crude oil prices within Sponsored Investments during 2015 and other normal course factors including timing of cash receipts and payments. The increase in cash from operating activities for the three months ended September 30, 2015 was partially offset by a negative period-over-period change in operating assets and liabilities of approximately $155 million mainly attributable to an increase in inventory balances due to higher volumes in EGD, as a result of seasonal patterns, and in Energy Services, as a result of increased activity derived from the completion of the Seaway and Flanagan South projects in late 2014.

 

At September 30, 2015, the Company had a negative working capital position. Despite this negative working capital, the Company continues to have significant liquidity available through committed credit facilities, which allow for the funding of liabilities as they become due. As discussed above, as at September 30, 2015, the Company’s net available liquidity totalled $9,225 million (December 31, 2014 - $9,291 million). In addition, it is anticipated that any current maturities of long-term debt will be refinanced upon maturity.

 

INVESTING ACTIVITIES

Cash used in investing activities for the three and nine months ended September 30, 2015 was $1,746 million and $5,637 million, respectively, compared with $2,525 million and $8,154 million for the three and nine months ended September 30, 2014.The Company continues with the execution of its growth projects, which are discussed in Growth Projects – Commercially Secured Projects. The timing of project approval, construction and in-service dates impact the timing of cash requirements. Cash used in investing activities has decreased period-over-period primarily due to the successful completion in 2014 of growth projects including the Flanagan South Pipeline, components of Eastern Access and the Seaway Pipeline Twinning/Extension which required significant investments during the first nine months of 2014, partially offset by higher capital spending on the GTA project and Southern Access Extension during the first nine months of 2015.

 

FINANCING ACTIVITIES

Cash generated from financing activities for the three and nine months ended September 30, 2015 was $605 million and $1,516 million, respectively, compared with $1,594 million and $6,549 million for the three and nine months ended September 30, 2014. The reduction of the cash generated from financing activities relative to the comparable period in 2014 reflects lower capital requirements.

 

During the first nine months of 2015, the Company increased its overall debt by $2,361 million. The most significant contributors were an increase in credit facilities and commercial paper draws of $2,444 million and the issuance of medium-term notes, net of repayments, of $556 million, partially offset by repayments of short-term borrowings of $639 million. For the comparative period in 2014, the Company increased its overall debt by $5,740 million. The most significant contributors were the issuance of medium-term notes, net of repayments, of $3,509 million, credit facilities and commercial paper draws, net of repayments, of $1,596 million and increased short-term borrowings, net of repayments, of $635 million.

 

Furthermore, during the first nine months of 2014, the Company raised net proceeds of $1,365 million in preference shares (2015 - nil) and $470 million in common shares primarily through public offerings (2015 - $47 million through routine exercises of stock options). Additional preference and common shares outstanding in 2015 together with a 33% increase in the common share dividend rate effective in the first quarter of 2015, gave rise to an increase in dividends paid during the first nine months of 2015 compared with the same period in 2014.

 

Financing activities also included transactions between the Company’s Sponsored Investments and their public unitholders, also referred to as noncontrolling interests. During the first nine months of 2015, sponsored vehicles received contributions, net of distributions, of $31 million, primarily as a result of their

 

36



 

equity issuances to the public. During the comparative period in 2014, these sponsored vehicles made distributions, net of contributions, of $287 million.

 

Dividend Reinvestment and Share Purchase Plan

Participants in the Company’s Dividend Reinvestment and Share Purchase Plan receive a 2% discount on the purchase of common shares with reinvested dividends. For the three months ended September 30, 2015, dividends declared were $400 million (2014 - $296 million), of which $230 million (2014 - $193 million) were paid in cash and reflected in financing activities. The remaining $170 million (2014 - $103 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 nine months ended September 30, 2015, dividends declared were $1,195 million (2014 - $880 million), of which $709 million (2014 - $565 million) were paid in cash and reflected in financing activities. The remaining $486 million (2014 - $315 million) of dividends declared were reinvested pursuant to the plan and resulted in the issuance of common shares rather than a cash payment. For the three and nine months ended September 30, 2015, 42.5% (2014 - 34.8%) and 40.7% (2014 - 35.8%) of total dividends declared were reinvested.

 

On November 4, 2015, the Enbridge Board of Directors declared the following quarterly dividends. All dividends are payable on December 1, 2015 to shareholders of record on November 16, 2015.

 

Common Shares

 

$0.46500

Preference Shares, Series A

 

$0.34375

Preference Shares, Series B

 

$0.25000

Preference Shares, Series D

 

$0.25000

Preference Shares, Series F

 

$0.25000

Preference Shares, Series H

 

$0.25000

Preference Shares, Series J

 

US$0.25000

Preference Shares, Series L

 

US$0.25000

Preference Shares, Series N

 

$0.25000

Preference Shares, Series P

 

$0.25000

Preference Shares, Series R

 

$0.25000

Preference Shares, Series 1

 

US$0.25000

Preference Shares, Series 3

 

$0.25000

Preference Shares, Series 5

 

US$0.27500

Preference Shares, Series 7

 

$0.27500

Preference Shares, Series 9

 

$0.27500

Preference Shares, Series 11

 

$0.27500

Preference Shares, Series 13

 

$0.27500

Preference Shares, Series 15

 

$0.27500

 

CAPITAL EXPENDITURE COMMITMENTS

The Company has signed contracts for the purchase of services, pipe and other materials totalling $2,796 million which are expected to be paid over the next five years.

 

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.

 

37



 

Foreign Exchange Risk

The Company generates certain revenues, incurs expense 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 expense, 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 2.0%.

 

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 3.8%.

 

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

 

Commodity Price Risk

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

 

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.

 

38



 

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.

 

 

 

Three months ended

September 30,

 

Nine months ended

September 30,

 

 

 

2015

 

 

2014

 

 

 

2015

 

 

2014

 

(millions of Canadian dollars)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Amount of unrealized gains/(loss) recognized in OCI

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash flow hedges

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Foreign exchange contracts

 

 

36

 

 

22

 

 

 

66

 

 

(9

)

Interest rate contracts

 

 

(390

)

 

(173

)

 

 

(662

)

 

(694

)

Commodity contracts

 

 

18

 

 

9

 

 

 

8

 

 

(8

)

Other contracts

 

 

(26

)

 

7

 

 

 

(40

)

 

15

 

Net investment hedges

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Foreign exchange contracts

 

 

(105

)

 

(63

)

 

 

(206

)

 

(66

)

 

 

 

(467

)

 

(198

)

 

 

(834

)

 

(762

)

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Foreign exchange contracts1

 

 

-

 

 

(5

)

 

 

6

 

 

10

 

Interest rate contracts2

 

 

20

 

 

30

 

 

 

53

 

 

74

 

Commodity contracts

 

 

(13

)

 

2

 

 

 

(35

)

 

14

 

Other contracts4

 

 

16

 

 

(5

)

 

 

22

 

 

(12

)

 

 

 

23

 

 

22

 

 

 

46

 

 

86

 

De-designation of qualifying hedges in connection with the Canadian Restructuring Plan (Note 2)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest rate contracts2

 

 

338

 

 

-

 

 

 

338

 

 

-

 

 

 

 

338

 

 

-

 

 

 

338

 

 

-

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest rate contracts2

 

 

25

 

 

130

 

 

 

(10

)

 

158

 

Commodity contracts

 

 

-

 

 

-

 

 

 

5

 

 

3

 

 

 

 

25

 

 

130

 

 

 

(5

)

 

161

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Foreign exchange contracts1

 

 

(1,087

)

 

(568

)

 

 

(1,992

)

 

(510

)

Interest rate contracts2,5

 

 

(380

)

 

1

 

 

 

(380

)

 

3

 

Commodity contracts3

 

 

204

 

 

146

 

 

 

(23

)

 

447

 

Other contracts4

 

 

(16

)

 

5

 

 

 

(15

)

 

12

 

 

 

 

(1,279

)

 

(416

)

 

 

(2,410

)

 

(48

)

 

 

1

Reported within Transportation and other services revenues and Other expense in the Consolidated Statements of Earnings.

2

Reported within Interest expense in the Consolidated Statements of Earnings.

3

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

4

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

5

The amounts above include $338 million in the three and nine months ended September 30, 2015 relating to the de-designation of qualifying hedges in connection with the Canadian Restructuring Plan.

 

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. However, leading up to the closure of the

 

39



 

Canadian Restructuring Plan, the Company did not access the public markets in recent quarters as regularly as it had in previous years. However, once the Canadian Restructuring Plan was closed, Enbridge again began to access the public debt and equity markets in normal course. The Company is in compliance with all the terms and conditions of its committed credit facilities as at September 30, 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 generally has a policy of entering into individual International Swaps and Derivatives Association, Inc. agreements, or other similar derivative agreements, with the majority of its derivative counterparties. These agreements provide for the net settlement of derivative instruments outstanding with specific counterparties in the event of bankruptcy or other significant credit event, and would reduce the Company’s credit risk exposure on derivative asset positions outstanding with the counterparties in these particular circumstances.

 

Credit risk also arises from trade and other long-term receivables, and is mitigated through credit exposure limits and contractual requirements, assessment of credit ratings and netting arrangements. Within 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 rates, foreign exchange rates, commodity prices and share prices, as applicable) 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.

 

CRITICAL ACCOUNTING ESTIMATES

 

ASSET RETIREMENT OBLIGATIONS

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.

 

40



 

In 2009, the NEB issued a decision related to the Land Matters Consultation Initiative (LMCI), which required holders of an authorization to operate a pipeline under the NEB Act to file a proposed process and mechanism to set aside funds to pay for future abandonment costs in respect of the sites in Canada used for the operation of a pipeline. The NEB’s decision stated that while pipeline companies are ultimately responsible for the full costs of abandoning pipelines, abandonment costs are a legitimate cost of providing service and are recoverable from the users of the pipeline upon approval by the NEB.

 

Following the NEB’s final approval of the collection mechanism and the set-aside mechanism for LMCI, the Company began collecting and setting aside funds to cover future abandonment costs effective January 1, 2015. The funds collected are held in trusts in accordance with the NEB decision. The funds collected from shippers are reported within Transportation and other services revenues and Long-term investments. Concurrently, the Company reflects the future abandonment cost as an increase to Operating and administrative expense and Other long-term liabilities.

 

Currently, for the majority 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 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

 

ADOPTION OF NEW STANDARDS

Principles of Consolidation and Noncontrolling Interests

As a result of the Canadian Restructuring Plan, ECT, a subsidiary of the Company, determines its equity investment earnings from EIPLP using the Hypothetical Liquidation at Book Value (HLBV) method. ECT applies the HLBV method to its equity method investments where cash distributions, including both preference and residual distributions, are not based on the investor’s ownership percentages. Under the HLBV method, a calculation is prepared at each balance sheet date to determine the amount that ECT would receive if EIPLP were to liquidate all of its assets, as valued in accordance with U.S. GAAP, and distribute that cash to the investors. The difference between the calculated liquidation distribution amounts at the beginning and the end of the reporting period, after adjusting for capital contributions and distributions, is ECT’s share of the earnings or losses from the equity investment for the period.

 

While ECT and EIPLP are both consolidated in the financial statements of Enbridge, the use of the HLBV method by ECT impacts the earnings attributable to redeemable noncontrolling interests reported on Enbridge’s Consolidated Statements of Earnings. The Company continues to recognize Redeemable noncontrolling interests on the Consolidated Statements of Financial Position at the maximum redemption value of the trust units held by third parties, which references the market price of ENF common shares.

 

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.

 

Extraordinary and Unusual Items

Effective January 1, 2015, the Company retrospectively adopted ASU 2015-01 which eliminates the concept of extraordinary items from U.S. GAAP. Entities will no longer be required to separately classify and present extraordinary items in the Consolidated Statements of Earnings. There was no material impact to the Company’s 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

 

41



 

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. Further, ASU 2015-15 was issued in August 2015 to clarify the presentation and subsequent measurement of debt issuance costs associated with line-of-credit arrangements, whereby an entity may defer debt issuance costs as an asset and subsequently amortize them over the term of the line-of-credit. The accounting updates are 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.

 

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. In July 2015, the effective date of the new standard was delayed by one year and the new standard is now effective for annual and interim periods beginning on or after December 15, 2017 and may be applied on either a full or modified retrospective basis.

 

Simplifying the Accounting for Measurement-Period Adjustments in Business Combinations

ASU 2015-16, was issued in September 2015 with the intent to simplify the accounting for measurement-period adjustments in business combinations. The new standard requires that an acquirer must recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. The accounting update is effective for fiscal years beginning after December 15, 2015, including interim periods within those fiscal years 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.

 

42



 

QUARTERLY FINANCIAL INFORMATION1

 

 

 

2015

 

2014

 

 

2013

 

 

 

 

Q3

 

 

Q2

 

Q1

 

 

 

Q4

 

Q3

 

Q2

 

Q1

 

 

 

Q4

 

(millions of Canadian dollars,

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

except per share amounts)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues

 

 

8,320

 

 

8,631

 

7,929

 

 

 

8,797

 

8,297

 

10,026

 

10,521

 

 

 

8,293

 

Earnings/(loss) attributable to common shareholders

 

 

(609

)

 

577

 

(383

)

 

 

88

 

(80

)

756

 

390

 

 

 

(267

)

Earnings/(loss) per common share

 

 

(0.72

)

 

0.68

 

(0.46

)

 

 

0.11

 

(0.10

)

0.92

 

0.48

 

 

 

(0.33

)

Diluted earnings/(loss) per common share

 

 

(0.72

)

 

0.67

 

(0.46

)

 

 

0.10

 

(0.10

)

0.91

 

0.47

 

 

 

(0.33

)

Dividends per common share

 

 

0.465

 

 

0.465

 

0.465

 

 

 

0.350

 

0.350

 

0.350

 

0.350

 

 

 

0.315

 

EGD - warmer/(colder) than normal weather

 

 

-

 

 

6

 

(33

)

 

 

(1

)

2

 

(4

)

(33

)

 

 

(13

)

Changes in unrealized derivative fair value (gains)/loss

 

 

654

 

 

(296

)

977

 

 

 

164

 

396

 

(430

)

190

 

 

 

613

 

 

1                  Quarterly financial information has been extracted from financial statements prepared in accordance with U.S. GAAP.

 

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.

 

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

 

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 flow-through nature of these costs.

 

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

 

In addition to the impacts of weather in EGD’s franchise area and changes in unrealized gains and losses outlined above, significant items impacting the consolidated quarterly earnings included:

·                  Included in the third quarter of 2015 were impacts from the transfer of assets between entities under common control of Enbridge in connection with the Canadian Restructuring Plan, resulting in a $247 million loss on the de-designation of interest rate hedges, an $88 million write-off of a regulatory asset in respect of taxes and $16 million of transaction costs.

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

·                  Included in the second quarter of 2015 was a goodwill impairment charge of $440 million ($167 million after-tax attributable to Enbridge) related to EEP’s natural gas and NGL businesses due to a prolonged decline in commodity prices which reduced producers’ expected drilling programs and negatively impacted volumes on EEP’s natural gas and NGL systems.

 

43



 

·                  Included in the second quarter of 2015 and fourth quarter of 2014 were the tax impact of asset transfers, respectively, between entities under common control of Enbridge. The intercompany gains realized by the selling entities have been eliminated from the Company’s consolidated financial statements. However, as the transaction involved sale of partnership units, the tax consequences have remained in consolidated earnings and resulted in a charge of $39 million and $157 million, respectively.

·                  Included in earnings are after-tax gains on the disposal of non-core Offshore assets. The Company recognized gains of $4 million in the second quarter of 2015 and $43 million and $14 million in first and fourth quarters of 2014. Earnings in the first quarter of 2014 also included a $14 million after-tax gain on the sale of an Alternative and Emerging Technologies investment within the Corporate segment.

·                  Included in earnings is the Company’s share of after-tax leak remediation costs associated with the Line 6B crude oil release. Remediation costs of $5 million and $12 million were recognized in the second and third quarters of 2014, and $9 million was recognized in the fourth quarter of 2013. In the fourth quarter of 2014, the Company recognized an out-of-period adjustment of $5 million to reduce Enbridge’s share of leak remediation costs recognized in the third quarter of 2014.

·                  Included in earnings are after-tax costs of $6 million in the second quarter of 2015, $4 million in the third quarter of 2014 as well as $3 million incurred in the fourth quarter of 2013, in connection with the Line 37 crude oil release which occurred in June 2013. Earnings also reflected insurance recoveries associated with the Line 37 crude oil release of $9 million recognized in the first quarter of 2015 and $4 million recognized in each of the second quarter and fourth quarter of 2014, respectively.

 

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

 

OUTSTANDING SHARE DATA1

 

PREFERENCE SHARES

 

 

 

Number

 

Redemption and Conversion
Option Date

2,3

Right to
Convert
Into

3

Preference Shares, Series A

 

5,000,000

 

-

 

-

 

Preference Shares, Series B

 

20,000,000

 

June 1, 2017

 

Series C

 

Preference Shares, Series D

 

18,000,000

 

March 1, 2018

 

Series E

 

Preference Shares, Series F

 

20,000,000

 

June 1, 2018

 

Series G

 

Preference Shares, Series H

 

14,000,000

 

September 1, 2018

 

Series I

 

Preference Shares, Series J

 

8,000,000

 

June 1, 2017

 

Series K

 

Preference Shares, Series L

 

16,000,000

 

September 1, 2017

 

Series M

 

Preference Shares, Series N

 

18,000,000

 

December 1, 2018

 

Series O

 

Preference Shares, Series P

 

16,000,000

 

March 1, 2019

 

Series Q

 

Preference Shares, Series R

 

16,000,000

 

June 1, 2019

 

Series S

 

Preference Shares, Series 1

 

16,000,000

 

June 1, 2018

 

Series 2

 

Preference Shares, Series 3

 

24,000,000

 

September 1, 2019

 

Series 4

 

Preference Shares, Series 5

 

8,000,000

 

March 1, 2019

 

Series 6

 

Preference Shares, Series 7

 

10,000,000

 

March 1, 2019

 

Series 8

 

Preference Shares, Series 9

 

11,000,000

 

December 1, 2019

 

Series 10

 

Preference Shares, Series 11

 

20,000,000

 

March 1, 2020

 

Series 12

 

Preference Shares, Series 13

 

14,000,000

 

June 1, 2020

 

Series 14

 

Preference Shares, Series 15

 

11,000,000

 

September 1, 2020

 

Series 16

 

 

44



 

COMMON SHARES

 

 

 

Number

 

Common Shares - issued and outstanding (voting equity shares)

 

863,652,599

 

Stock Options - issued and outstanding (21,199,766 vested)

 

36,628,111

 

 

1                  Outstanding share data information is provided as at October 23, 2015.

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

 

45



 

 

 

 

 

 

 

 

 

 

 

ENBRIDGE INC.

 

CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

 

September 30, 2015

 



 

 

CONSOLIDATED STATEMENTS OF EARNINGS

 

 

 

Three months ended

 

Nine months ended

 

 

September 30,

 

September 30,

 

 

2015 

 

2014 

 

2015 

 

2014 

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

 

 

 

 

 

 

 

 

Revenues

 

 

 

 

 

 

 

 

Commodity sales

 

6,562 

 

6,599 

 

17,768 

 

22,089 

Gas distribution sales

 

305 

 

309 

 

2,424 

 

2,018 

Transportation and other services

 

1,453 

 

1,389 

 

4,688 

 

4,737 

 

 

8,320 

 

8,297 

 

24,880 

 

28,844 

Expenses

 

 

 

 

 

 

 

 

Commodity costs

 

6,230 

 

6,459 

 

17,071 

 

21,578 

Gas distribution costs

 

143 

 

149 

 

1,807 

 

1,332 

Operating and administrative

 

1,097 

 

805 

 

3,016 

 

2,364 

Depreciation and amortization

 

524 

 

392 

 

1,483 

 

1,151 

Environmental costs, net of recoveries

 

 

62 

 

(2)

 

103 

Goodwill impairment (Note 7)

 

 

 

440 

 

 

 

7,996 

 

7,867 

 

23,815 

 

26,528 

 

 

324 

 

430 

 

1,065 

 

2,316 

Income from equity investments

 

117 

 

72 

 

359 

 

251 

Other expense

 

(331)

 

(220)

 

(630)

 

(143)

Interest expense

 

(718)

 

(347)

 

(1,253)

 

(816)

 

 

(608)

 

(65)

 

(459)

 

1,608 

Income taxes recovery/(expense) (Note 13)

 

(129)

 

31 

 

(76)

 

(362)

Earnings/(loss) from continuing operations

 

(737)

 

(34)

 

(535)

 

1,246 

Discontinued operations (Note 5)

 

 

 

 

 

 

 

 

Earnings from discontinued operations before income taxes

 

 

 

 

73 

Income taxes from discontinued operations

 

 

 

 

(27)

Earnings from discontinued operations

 

 

 

 

46 

Earnings/(loss)

 

(737)

 

(34)

 

(535)

 

1,292 

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

 

200 

 

20 

 

334 

 

(46)

Earnings/(loss) attributable to Enbridge Inc.

 

(537)

 

(14)

 

(201)

 

1,246

Preference share dividends

 

(72)

 

(66)

 

(214)

 

(180)

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

 

(609)

 

(80)

 

(415)

 

1,066 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

Earnings/(loss) from continuing operations

 

(609)

 

(80)

 

(415)

 

1,020 

Earnings from discontinued operations, net of tax

 

 

 

 

46 

 

 

(609)

 

(80)

 

(415)

 

1,066 

 

 

 

 

 

 

 

 

 

Earnings/(loss) per common share attributable to Enbridge Inc. common shareholders (Note 9)

 

 

 

 

 

 

 

 

Continuing operations

 

(0.72)

 

(0.10)

 

(0.49)

 

1.23 

Discontinued operations

 

 

 

 

0.06 

 

 

(0.72)

 

(0.10)

 

(0.49)

 

1.29 

 

 

 

 

 

 

 

 

 

Diluted earnings/(loss) per common share attributable to Enbridge Inc. common shareholders (Note 9)

 

 

 

 

 

 

 

 

Continuing operations

 

(0.72)

 

(0.10)

 

(0.49)

 

1.21 

Discontinued operations

 

 

 

 

0.06 

 

 

(0.72)

 

(0.10)

 

(0.49)

 

1.27 

 

See accompanying notes to the unaudited interim consolidated financial statements.

 

1



 

 

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

 

 

 

Three months ended
September 30,

 

Nine months ended
September 30,

 

 

2015

 

2014

 

2015

 

2014

(unaudited; millions of Canadian dollars)

 

 

 

 

 

 

 

 

Earnings/(loss)

 

(737)

 

(34)

 

(535)

 

1,292

Other comprehensive income/(loss), net of tax

 

 

 

 

 

 

 

 

Change in unrealized gains/(loss) on cash flow hedges

 

91

 

(96)

 

(129)

 

(610)

Change in unrealized loss on net investment hedges

 

(374)

 

(143)

 

(720)

 

(134)

Other comprehensive income/(loss) from equity investees

 

(5)

 

(3)

 

17

 

4

Reclassification to earnings of realized cash flow hedges

 

14

 

(13)

 

24

 

62

Reclassification to earnings of unrealized cash flow hedges

 

(17)

 

100

 

(53)

 

124

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

 

9

 

3

 

22

 

6

Change in foreign currency translation adjustment

 

1,392

 

671

 

2,685

 

687

Reclassification to earnings of derecognized cash flow hedges (Note 12)

 

(247)

 

-

 

(247)

 

-

Other comprehensive income

 

863

 

519

 

1,599

 

139

Comprehensive income

 

126

 

485

 

1,064

 

1,431

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

 

229

 

(94)

 

275

 

(67)

Comprehensive income attributable to Enbridge Inc.

 

355

 

391

 

1,339

 

1,364

Preference share dividends

 

(72)

 

(66)

 

(214)

 

(180)

Comprehensive income attributable to Enbridge Inc. common shareholders

 

283

 

325

 

1,125

 

1,184

 

See accompanying notes to the unaudited interim consolidated financial statements.

 

2



 

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

 

 

 

Nine months ended
September 30,

 

 

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

 

-

 

1,374

Balance at end of period

 

6,515

 

6,515

Common shares

 

 

 

 

Balance at beginning of period

 

6,669

 

5,744

Shares issued

 

-

 

446

Dividend reinvestment and share purchase plan

 

486

 

315

Shares issued on exercise of stock options

 

64

 

40

Balance at end of period

 

7,219

 

6,545

Additional paid-in capital

 

 

 

 

Balance at beginning of period

 

2,549

 

746

Drop down of interest to Enbridge Energy Partners, L.P. (Note 11)

 

218

 

-

Stock-based compensation

 

30

 

25

Options exercised

 

(16)

 

(11)

Issuance of treasury stock

 

-

 

22

Enbridge Energy Partners, L.P. equity restructuring

 

-

 

1,584

Drop down of interest to Midcoast Energy Partners, L.P.

 

-

 

(18)

Dilution gains and other

 

35

 

5

Balance at end of period

 

2,816

 

2,353

Retained earnings

 

 

 

 

Balance at beginning of period

 

1,571

 

2,550

Earnings/(loss) attributable to Enbridge Inc.

 

(201)

 

1,246

Preference share dividends

 

(214)

 

(180)

Common share dividends declared

 

(1,195)

 

(880)

Dividends paid to reciprocal shareholder

 

17

 

13

Redemption value adjustment attributable to redeemable noncontrolling interests

 

440

 

(364)

Balance at end of period

 

418

 

2,385

Accumulated other comprehensive income/(loss) (Note 10)

 

 

 

 

Balance at beginning of period

 

(435)

 

(599)

Other comprehensive income attributable to Enbridge Inc. common shareholders

 

1,540

 

118

Balance at end of period

 

1,105

 

(481)

Reciprocal shareholding

 

 

 

 

Balance at beginning of period

 

(83)

 

(86)

Issuance of treasury stock

 

-

 

3

Balance at end of period

 

(83)

 

(83)

Total Enbridge Inc. shareholders’ equity

 

17,990

 

17,234

Noncontrolling interests

 

 

 

 

Balance at beginning of period

 

2,015

 

4,014

Earnings/(loss) attributable to noncontrolling interests

 

(339)

 

46

Other comprehensive income/(loss) attributable to noncontrolling interests, net of tax

 

 

 

 

Change in unrealized loss on cash flow hedges

 

(149)

 

(144)

Change in foreign currency translation adjustment

 

240

 

95

Reclassification to earnings of realized cash flow hedges

 

(10)

 

21

Reclassification to earnings of unrealized cash flow hedges

 

(17)

 

58

 

 

64

 

30

Comprehensive income attributable to noncontrolling interests

 

(275)

 

76

Distributions

 

(501)

 

(395)

Contributions

 

612

 

163

Drop down of interest to Enbridge Energy Partners, L.P. (Note 11)

 

(304)

 

-

Dilution loss

 

(53)

 

-

Enbridge Energy Partners, L.P. equity restructuring

 

-

 

(2,330)

Drop down of interest to Midcoast Energy Partners, L.P.

 

-

 

39

Disposition of Frontier Pipeline Company (Note 5)

 

(7)

 

-

Other

 

(1)

 

2

Balance at end of period

 

1,486

 

1,569

Total equity

 

19,476

 

18,803

 

 

 

 

 

Dividends paid per common share

 

1.395

 

1.050

 

See accompanying notes to the unaudited interim consolidated financial statements.

 

3



 

CONSOLIDATED STATEMENTS OF CASH FLOWS

 

 

 

Three months ended
September 30,

 

Nine months ended
September 30,

 

 

2015 

 

2014

 

2015 

 

2014 

(unaudited; millions of Canadian dollars)

 

 

 

 

 

 

 

 

Operating activities

 

 

 

 

 

 

 

 

Earnings/(loss)

 

(737)

 

(34)

 

(535)

 

1,292 

Earnings from discontinued operations

 

 

 

 

(46)

Depreciation and amortization

 

524 

 

392 

 

1,483 

 

1,151 

Deferred income taxes (recovery)/expense

 

98 

 

(14)

 

(41)

 

332 

Changes in unrealized (gains)/loss on derivative instruments, net

 

1,279 

 

419 

 

2,410 

 

56 

Cash distributions in excess of equity earnings

 

54 

 

90 

 

180 

 

139 

Impairment (Note 7)

 

 

 

456 

 

-

Gain on disposition

 

(60)

 

 

(94)

 

(16)

Hedge ineffectiveness

 

(21)

 

130 

 

(51)

 

161 

Inventory revaluation allowance

 

216

 

 

261

 

Other

 

(4)

 

71 

 

(90)

 

106 

Changes in regulatory assets and liabilities

 

21 

 

(4)

 

53 

 

11 

Changes in environmental liabilities, net of recoveries

 

(15)

 

(11)

 

(35)

 

(47)

Changes in operating assets and liabilities

 

(450)

 

(295)

 

(232)

 

(1,271)

Cash provided by continuing operations

 

905 

 

746 

 

3,765 

 

1,872 

Cash provided by discontinued operations (Note 5)

 

 

 

 

19 

 

 

905 

 

746 

 

3,765 

 

1,891 

Investing activities

 

 

 

 

 

 

 

 

Additions to property, plant and equipment

 

(1,747)

 

(2,354)

 

(5,310)

 

(7,397)

Long-term investments

 

(132)

 

(168)

 

(311)

 

(693)

Additions to intangible assets

 

(27)

 

(42)

 

(89)

 

(153)

Acquisition

 

 

 

(106)

 

Proceeds from disposition

 

112 

 

62 

 

146 

 

81 

Affiliate loans, net

 

48 

 

 

54 

 

Changes in restricted cash

 

 

(26)

 

(21)

 

(5)

Cash used in continuing operations

 

(1,746)

 

(2,525)

 

(5,637)

 

(8,158)

Cash provided by discontinued operations (Note 5)

 

 

 

 

 

 

(1,746)

 

(2,525)

 

(5,637)

 

(8,154)

Financing activities

 

 

 

 

 

 

 

 

Net change in bank indebtedness and short-term borrowings

 

(88)

 

191 

 

(639)

 

635 

Net change in commercial paper and credit facility draws

 

208 

 

381 

 

2,444 

 

1,596 

Debenture and term note issues

 

1,554 

 

878 

 

1,554 

 

4,334 

Debenture and term note repayments

 

(603)

 

(200)

 

(998)

 

(825)

Southern Lights credit facility repayments

 

 

(1,507)

 

 

(1,507)

Debenture and term note issues - Southern Lights

 

 

1,507 

 

 

1,507 

Contributions from noncontrolling interests

 

33 

 

82 

 

612 

 

163 

Distributions to noncontrolling interests

 

(177)

 

(135)

 

(501)

 

(395)

Distributions to redeemable noncontrolling interests

 

(27)

 

(18)

 

(80)

 

(55)

Preference shares issued

 

 

607 

 

 

1,365 

Common shares issued

 

 

64 

 

47 

 

470 

Preference share dividends

 

(72)

 

(63)

 

(214)

 

(174)

Common share dividends

 

(230)

 

(193)

 

(709)

 

(565)

 

 

605 

 

1,594 

 

1,516 

 

6,549 

Effect of translation of foreign denominated cash and cash equivalents

 

51 

 

25 

 

119 

 

26 

Increase/(decrease) in cash and cash equivalents

 

(185)

 

(160)

 

(237)

 

312 

Cash and cash equivalents at beginning of period - discontinued operations

 

 

 

 

20 

Cash and cash equivalents at beginning of period - continuing operations

 

1,209 

 

1,248 

 

1,261 

 

756 

Cash and cash equivalents at end of period

 

1,024 

 

1,088 

 

1,024 

 

1,088 

 

See accompanying notes to the unaudited interim consolidated financial statements.

 

4



 

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

 

 

 

September 30,
2015

 

December 31,
2014

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

 

 

 

 

Assets

 

 

 

 

Current assets

 

 

 

 

Cash and cash equivalents

 

1,024

 

1,261

Restricted cash

 

68

 

47

Accounts receivable and other (Note 6)

 

5,043

 

5,504

Accounts receivable from affiliates

 

5

 

241

Inventory

 

1,491

 

1,148

 

 

7,631

 

8,201

Property, plant and equipment, net

 

61,995

 

53,830

Long-term investments

 

6,520

 

5,408

Deferred amounts and other assets

 

3,198

 

3,208

Intangible assets, net

 

1,296

 

1,166

Goodwill (Note 7)

 

78

 

483

Deferred income taxes

 

852

 

561

 

 

81,570

 

72,857

Liabilities and equity

 

 

 

 

Current liabilities

 

 

 

 

Bank indebtedness

 

369

 

507

Short-term borrowings

 

540

 

1,041

Accounts payable and other

 

7,242

 

6,444

Accounts payable to affiliates

 

57

 

80

Interest payable

 

334

 

264

Environmental liabilities

 

146

 

161

Current maturities of long-term debt (Note 8)

 

767

 

1,004

 

 

9,455

 

9,501

Long-term debt (Note 8)

 

38,927

 

33,423

Other long-term liabilities

 

6,369

 

4,041

Deferred income taxes

 

5,615

 

4,842

 

 

60,366

 

51,807

Contingencies (Note 15)

 

 

 

 

Redeemable noncontrolling interests

 

1,728

 

2,249

Equity

 

 

 

 

Share capital

 

 

 

 

Preference shares

 

6,515

 

6,515

Common shares (864 and 852 outstanding at September 30, 2015 and December 31, 2014, respectively)

 

7,219

 

6,669

Additional paid-in capital

 

2,816

 

2,549

Retained earnings

 

418

 

1,571

Accumulated other comprehensive income/(loss) (Note 10)

 

1,105

 

(435)

Reciprocal shareholding

 

(83)

 

(83)

Total Enbridge Inc. shareholders’ equity

 

17,990

 

16,786

Noncontrolling interests

 

1,486

 

2,015

 

 

19,476

 

18,801

 

 

81,570

 

72,857

 

See accompanying notes to the unaudited interim consolidated financial statements.

 

5



 

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 certain out-of-period adjustments further described in Note 4, Segmented Information, which management considers necessary to present fairly the Company’s financial position as at September 30, 2015 and results of operations and cash flows for the three and nine months ended September 30, 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 3). 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.          CANADIAN RESTRUCTURING PLAN

 

Effective September 1, 2015, under an agreement with Enbridge Income Fund (the Fund) and Enbridge Income Fund Holdings Inc. (ENF), Enbridge transferred its Canadian Liquids Pipelines business, held by Enbridge Pipelines Inc. (EPI) and Enbridge Pipelines Athabasca Inc. (EPAI), and certain Canadian renewable energy assets to the Fund Group (comprising the Fund, Enbridge Commercial Trust (ECT), Enbridge Income Partners LP (EIPLP) and the subsidiaries of EIPLP) for consideration valued at $30.4 billion plus incentive distribution and performance rights. The consideration that Enbridge received included $18.7 billion of units in the Fund Group, comprised of $3 billion of Fund units and $15.7 billion of equity units of EIPLP, in which the Fund has an interest. The Fund Group also assumed debt of EPI and EPAI of approximately $11.7 billion. Upon closing of the transaction, Enbridge’s overall economic interest in the Fund Group increased to 91.9%. Also effective September 1, 2015, the transferred businesses and assets noted above are reported under the Sponsored Investments segment as further described below.

 

LIQUIDS PIPELINES

Until August 31, 2015, Liquids Pipelines consisted 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, Seaway Crude Pipeline System, Flanagan South Pipeline, Southern Lights Pipeline, Spearhead Pipeline and Feeder Pipelines and Other. Effective September 1, 2015, under the agreement described above, Enbridge transferred to the Fund Group the Canadian Mainline, Regional Oil Sands System, the Canadian portion of the Southern Lights Pipeline and certain residual rights and/or obligations relating to certain terminal and storage assets. These transferred assets are reported under the Sponsored Investments segment from the date of transfer.

 

GAS PIPELINES, PROCESSING AND ENERGY SERVICES

Gas Pipelines, Processing and Energy Services continues to consist of investments in natural gas pipelines, gathering and processing facilities and the Company’s energy services businesses, along with renewable energy and transmission facilities. Effective September 1, 2015, under the agreement described above, Enbridge transferred to the Fund Group certain Canadian renewable energy assets which are reported under the Sponsored Investments segment from the date of transfer.

 

6



 

SPONSORED INVESTMENTS

Sponsored Investments includes the Company’s 33.7% economic interest in Enbridge Energy Partners, L.P. (EEP) and Enbridge’s interests in both the Eastern Access and Lakehead System Mainline Expansion projects held through Enbridge Energy, Limited Partnership. Also within Sponsored Investments is the Company’s overall 91.9% economic interest in the Fund Group. Enbridge, through its subsidiaries, manages the day-to-day operations of and develops and assesses opportunities for each of these investments, including both organic growth and acquisition opportunities.

 

As a result of the Canadian Restructuring Plan, as discussed above, effective September 1, 2015, the Fund Group’s primary operations include its liquids pipelines business, which includes the Canadian Mainline and Regional Oil Sands System, its renewable power generation assets and a natural gas transmission business through its 50% interest in Alliance Pipeline.

 

3.          SIGNIFICANT ACCOUNTING POLICIES

 

ADOPTION OF NEW STANDARDS

Principles of Consolidation and Noncontrolling Interests

As a result of the Canadian Restructuring plan, ECT, a subsidiary of the Company, determines its equity investment earnings from EIPLP using the Hypothetical Liquidation at Book Value (HLBV) method. ECT applies the HLBV method to its equity method investments where cash distributions, including both preference and residual distributions, are not based on the investor’s ownership percentages. Under the HLBV method, a calculation is prepared at each balance sheet date to determine the amount that ECT would receive if EIPLP were to liquidate all of its assets, as valued in accordance with U.S. GAAP, and distribute that cash to the investors. The difference between the calculated liquidation distribution amounts at the beginning and the end of the reporting period, after adjusting for capital contributions and distributions, is ECT’s share of the earnings or losses from the equity investment for the period.

 

While ECT and EIPLP are both consolidated in these financial statements, the use of the HLBV method by ECT impacts the earnings attributable to redeemable noncontrolling interests reported on Enbridge’s Consolidated Statements of Earnings. The Company continues to recognize Redeemable noncontrolling interests on the Consolidated Statements of Financial Position at the maximum redemption value of the trust units held by third parties, which references the market price of ENF common shares.

 

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.

 

Extraordinary and Unusual Items

Effective January 1, 2015, the Company retrospectively adopted ASU 2015-01 which eliminates the concept of extraordinary items from U.S. GAAP. Entities will no longer be required to separately classify and present extraordinary items in the Consolidated Statements of Earnings. There was no material impact to the Company’s 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.

 

7



 

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. Further, ASU 2015-15 was issued in August 2015 to clarify the presentation and subsequent measurement of debt issuance costs associated with line-of-credit arrangements, whereby an entity may defer debt issuance costs as an asset and subsequently amortize them over the term of the line-of-credit. The accounting updates are 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.

 

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. In July 2015, the effective date of the new standard was delayed by one year and the new standard is now effective for annual and interim periods beginning on or after December 15, 2017 and may be applied on either a full or modified retrospective basis.

 

Simplifying the Accounting for Measurement-Period Adjustments in Business Combinations

ASU 2015-16 was issued in September 2015 with the intent to simplify the accounting for measurement-period adjustments in business combinations. The new standard requires that an acquirer must recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. The accounting update is effective for fiscal years beginning after December 15, 2015, including interim periods within those fiscal years 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.

 

8



 

4.          SEGMENTED INFORMATION

 

Three months ended September 30, 2015

 

Liquids
Pipelines
2

 

Gas
Distribution

 

Gas Pipelines,
Processing
and Energy
Services
2

 

Sponsored
Investments
2

 

Corporate1

 

Consolidated

(millions of Canadian dollars)

 

 

 

 

 

 

 

 

 

 

 

 

Revenues

 

263

 

388

 

5,842

 

1,827

 

-

 

8,320

Commodity and gas distribution costs

 

(1)

 

(156)

 

(5,555)

 

(663)

 

2

 

(6,373)

Operating and administrative

 

(323)

 

(131)

 

(56)

 

(581)

 

(6)

 

(1,097)

Depreciation and amortization

 

(141)

 

(73)

 

(45)

 

(254)

 

(11)

 

(524)

Environmental costs, net of recoveries

 

-

 

-

 

-

 

(2)

 

-

 

(2)

Goodwill impairment

 

-

 

-

 

-

 

-

 

-

 

-

 

 

(202)

 

28

 

186

 

327

 

(15)

 

324

Income/(loss) from equity investments

 

83

 

-

 

(3)

 

51

 

(14)

 

117

Other income/(expense)

 

41

 

-

 

4

 

(27)

 

(349)

 

(331)

Interest expense

 

(140)

 

(44)

 

(27)

 

(175)

 

(332)

 

(718)

Income taxes recovery/(expense)

 

(28)

 

14

 

(65)

 

(270)

 

220

 

(129)

Earnings/(loss)

 

(246)

 

(2)

 

95

 

(94)

 

(490)

 

(737)

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

 

(1)

 

-

 

9

 

181

 

11

 

200

Preference share dividends

 

-

 

-

 

-

 

-

 

(72)

 

(72)

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

 

(247)

 

(2)

 

104

 

87

 

(551)

 

(609)

Additions to property, plant and equipment3

 

1,038

 

205

 

51

 

443

 

10

 

1,747

 

Three months ended September 30, 2014

 

Liquids
Pipelines
2

 

Gas
Distribution

 

Gas Pipelines,
Processing
and Energy
Services
2

 

Sponsored
Investments
2

 

Corporate1

 

Consolidated

 

(millions of Canadian dollars)

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues

 

382

 

354

 

5,355

 

2,206

 

-

 

8,297

 

Commodity and gas distribution costs

 

-

 

(150)

 

(5,122)

 

(1,336)

 

-

 

(6,608)

 

Operating and administrative

 

(270)

 

(129)

 

(52)

 

(351)

 

(3)

 

(805)

 

Depreciation and amortization

 

(123)

 

(53)

 

(47)

 

(164)

 

(5)

 

(392)

 

Environmental costs, net of recoveries

 

(7)

 

-

 

-

 

(55)

 

-

 

(62)

 

 

 

(18)

 

22

 

134

 

300

 

(8)

 

430

 

Income/(loss) from equity investments

 

35

 

-

 

33

 

20

 

(16)

 

72

 

Other income/(expense)

 

(9)

 

(5)

 

(1)

 

12

 

(217)

 

(220)

 

Interest expense

 

(86)

 

(43)

 

(29)

 

(176)

 

(13)

 

(347)

 

Income taxes recovery/(expense)

 

48

 

15

 

(49)

 

(69)

 

86

 

31

 

Earnings/(loss)

 

(30)

 

(11)

 

88

 

87

 

(168)

 

(34)

 

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

 

(1)

 

-

 

-

 

21

 

-

 

20

 

Preference share dividends

 

-

 

-

 

-

 

-

 

(66)

 

(66)

 

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

 

(31)

 

(11)

 

88

 

108

 

(234)

 

(80)

 

Additions to property, plant and equipment3

 

1,287

 

99

 

134

 

817

 

18

 

2,355

 

 

9



 

Nine months ended September 30, 2015

 

Liquids
Pipelines
2

 

Gas
Distribution

 

Gas Pipelines,
Processing
and Energy
Services
2

 

Sponsored
Investments2

 

Corporate1

 

Consolidated

 

(millions of Canadian dollars)

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues

 

1,422

 

2,806

 

15,246

 

5,406

 

-

 

24,880

 

Commodity and gas distribution costs

 

(5

)

(1,852

)

(14,600

)

(2,421

)

-

 

(18,878

)

Operating and administrative

 

(1,074

)

(399

)

(180

)

(1,354

)

(9

)

(3,016

)

Depreciation and amortization

 

(449

)

(230

)

(140

)

(642

)

(22

)

(1,483

)

Environmental costs, net of recoveries

 

4

 

-

 

-

 

(2

)

-

 

2

 

Goodwill impairment

 

-

 

-

 

-

 

(440

)

-

 

(440

)

 

 

(102

)

325

 

326

 

547

 

(31

)

1,065

 

Income/(loss) from equity investments

 

228

 

-

 

(1

)

150

 

(18

)

359

 

Other income/(expense)

 

29

 

(2

)

22

 

(31

)

(648

)

(630

)

Interest expense

 

(454

)

(126

)

(85

)

(384

)

(204

)

(1,253

)

Income taxes recovery/(expense)

 

41

 

(21

)

(103

)

(410

)

417

 

(76

)

Earnings/(loss)

 

(258

)

176

 

159

 

(128

)

(484

)

(535

)

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

 

(2

)

-

 

15

 

310

 

11

 

334

 

Preference share dividends

 

-

 

-

 

-

 

-

 

(214

)

(214

)

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

 

(260

)

176

 

174

 

182

 

(687

)

(415

)

Additions to property, plant and equipment3

 

2,871

 

540

 

163

 

1,701

 

36

 

5,311

 

 

Nine months ended September 30, 2014

 

Liquids
Pipelines
2

 

Gas
Distribution

 

Gas Pipelines,
Processing
and Energy
Services
2

 

Sponsored
Investments2

 

Corporate1

 

Consolidated

 

(millions of Canadian dollars)

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues

 

1,820

 

2,268

 

18,063

 

6,693

 

-

 

28,844

 

Commodity and gas distribution costs

 

-

 

(1,333

)

(17,291

)

(4,286

)

-

 

(22,910

)

Operating and administrative

 

(805

)

(399

)

(136

)

(1,015

)

(9

)

(2,364

)

Depreciation and amortization

 

(361

)

(225

)

(82

)

(469

)

(14

)

(1,151

)

Environmental costs, net of recoveries

 

-

 

-

 

-

 

(103

)

-

 

(103

)

 

 

654

 

311

 

554

 

820

 

(23

)

2,316

 

Income/(loss) from equity investments

 

110

 

-

 

111

 

55

 

(25

)

251

 

Other income/(expense)

 

(6

)

(3

)

8

 

10

 

(152

)

(143

)

Interest income/(expense)

 

(260

)

(123

)

(72

)

(397

)

36

 

(816

)

Income taxes recovery/(expense)

 

(51

)

(41

)

(215

)

(166

)

111

 

(362

)

Earnings/(loss) from continuing operations

 

447

 

144

 

386

 

322

 

(53

)

1,246

 

Discontinued operations

 

 

 

 

 

 

 

 

 

 

 

 

 

Earnings from discontinued operations before income tax

 

-

 

-

 

73

 

-

 

-

 

73

 

Income taxes from discontinued operations

 

-

 

-

 

(27

)

-

 

-

 

(27

)

Earnings from discontinued operations

 

-

 

-

 

46

 

-

 

-

 

46

 

Earnings/(loss)

 

447

 

144

 

432

 

322

 

(53

)

1,292

 

Earnings attributable to noncontrolling interests and redeemable noncontrolling interests

 

(3

)

-

 

-

 

(43

)

-

 

(46

)

Preference share dividends

 

-

 

-

 

-

 

-

 

(180

)

(180

)

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

 

444

 

144

 

432

 

279

 

(233

)

1,066

 

Additions to property, plant and equipment3

 

4,301

 

307

 

463

 

2,286

 

42

 

7,399

 

 

1                  Included within the Corporate segment was Interest income of $203 million and $625 million for the three and nine months ended September 30, 2015, respectively (2014 - $182 million and $498 million, respectively) charged to other operating segments.

2                  Effective September 1, 2015, Enbridge transferred its Canadian Liquids Pipelines businesses and certain Canadian renewable energy assets to the Fund Group within the Sponsored Investments segment as described under the Canadian Restructuring Plan (Note 2). Revenues of ($53) million and $603 million and loss of $350 million and $403 million in the three and nine month periods ended September 30, 2015, respectively (2014 - revenues of $237 million and $1,402 million and loss of $59 million and earnings of $349 million, respectively, in the three and nine month periods) which relate to Liquids Pipelines assets prior to the transfer have not been reclassified into the Sponsored Investments segment for presentation purposes. Revenues of $17 million and $83 million and earnings of $1 million and $1 million in the three and nine month periods ended September 30, 2015, respectively (2014 - revenues of $23 million and $61 million and loss of $3 million and $8 million, respectively, in the three and nine month periods) which relate to Gas Pipelines, Processing and Energy Services assets prior to the transfer have not been reclassified into the Sponsored Investments segment for presentation purposes.

 

10



 

3                  Includes allowance for equity funds used during construction.

 

OUT-OF-PERIOD ADJUSTMENTS

Earnings attributable to Enbridge Inc. common shareholders for the nine months ended September 30, 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.

 

For the three months ended September 30, 2014, Commodity sales revenues and Commodity costs were increased by a non-cash out-of-period adjustment of $174 million. The adjustment related to understatement of Commodity sales revenues and Commodity costs for the first half of 2014 and had no impact on earnings.

 

TOTAL ASSETS

 

 

 

September 30,
2015 

 

December 31,
2014

 

(millions of Canadian dollars)

 

 

 

 

 

Liquids Pipelines 1

 

12,052

 

27,657

 

Gas Distribution

 

9,227

 

9,320

 

Gas Pipelines, Processing and Energy Services 1

 

7,821

 

7,601

 

Sponsored Investments 1

 

48,226

 

23,515

 

Corporate

 

4,244

 

4,764

 

 

 

81,570

 

72,857

 

 

1                  Effective September 1, 2015, Enbridge transferred its Canadian Liquids Pipelines businesses and certain Canadian renewable energy assets to the Fund Group within the Sponsored Investments segment as described under the Canadian Restructuring Plan (Note 2). Liquids Pipelines assets as at December 31, 2014 of $17,782 million and Gas Pipelines, Processing and Energy Services assets as at December 31, 2014 of $1,123 million have not been reclassified into the Sponsored Investments segment for presentation purposes.

 

5.          ACQUISITION AND DISPOSITIONS

 

ACQUISITION

Magic Valley and Wildcat Wind Farms

Subsequent to the December 31, 2014 acquisition of an 80% controlling interest in Magic Valley and Wildcat wind farms, the Company completed the valuation of the acquired assets, resulting in no change to the purchase price allocation previously disclosed. The wind farms are included within the Gas Pipelines, Processing and Energy Services segment.

 

OTHER DISPOSITIONS

In August 2015, the Company sold its 77.8% controlling interest in the Frontier Pipeline Company, including certain non-core pipeline assets located in the midwest United States, to two unrelated parties for gross proceeds of $112 million (US$85 million). A gain of $70 million (US$53 million) was presented within Other expense on the Consolidated Statements of Earnings. These amounts are included within the Liquids Pipelines segment.

 

In May 2015, the Fund sold certain of its crude oil pipeline system assets to an unrelated party for gross proceeds of $26 million. A gain of $22 million was presented within Other expense on the Consolidated Statements of Earnings.

 

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 nine months ended September 30, 2014. The results of operations, including revenues of $4 million and related cash flows, have also been presented as discontinued operations for the nine months ended September 30, 2014. These amounts are included within the Gas Pipelines, Processing and Energy Services segment.

 

11



 

6.          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 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$341 million ($457 million) and US$378 million ($439 million) as at September 30, 2015 and December 31, 2014, respectively.

 

7.          GOODWILL

 

During the second quarter of 2015, the Company recorded an impairment charge of $440 million ($167 million after-tax attributable to Enbridge) related to EEP’s natural gas and NGL businesses, which EEP holds directly and indirectly through its partially-owned subsidiary, Midcoast Energy Partners, L.P. Due to a prolonged decline in commodity prices, reduction in producers’ expected drilling programs negatively impacted forecasted cash flows from EEP’s natural gas and NGL systems. This change in circumstance led to the completion of an impairment test, resulting in a full impairment of goodwill on EEP’s natural gas and NGL businesses.

 

In performing the impairment assessment, EEP measured the fair value of its reporting units primarily by using a discounted cash flow analysis and it also considered overall market capitalization of its business, cash flow measurement data and other factors. EEP’s estimate of fair value required it to use significant unobservable inputs representative of a Level 3 fair value measurement, including assumptions related to the future performance of its reporting units.

 

8.          DEBT

 

During the nine months ended September 30, 2015, the Company completed aggregate issuances of unsecured, medium-term notes of $1,570 million. These aggregate issuances carry interest rates ranging from approximately 3.3% to 4.5% and have maturities ranging from 10 to 30 years.

 

Subsequent to September 30, 2015, the Company completed aggregate issuances of senior unsecured notes of US$1,600 million. These aggregate issuances carry interest rates ranging from approximately 4.4% to 7.4% and have maturities ranging from five to 30 years.

 

CREDIT FACILITIES

The following table provides details of the Company’s committed credit facilities as at September 30, 2015 and December 31, 2014.

 

 

 

 

 

September 30, 2015

 

 

December 31,
2014

 

 

 

Maturity
Dates

 

 

Total
Facilities

 

Draws

1

Available

 

 

 

Total
Facilities

 

(millions of Canadian dollars)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Liquids Pipelines

 

2017

 

 

3,027

 

1,180

 

1,847

 

 

 

300

 

Gas Distribution

 

2017-2019

 

 

1,009

 

543

 

466

 

 

 

1,008

 

Sponsored Investments

 

2017-2019

 

 

5,072

 

3,796

 

1,276

 

 

 

4,531

 

Corporate

 

2016-2020

 

 

12,390

 

7,409

 

4,981

 

 

 

12,772

 

Total committed credit facilities

 

 

 

 

21,498

 

12,928

 

8,570

 

 

 

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 $401 million (December 31, 2014 - $361 million) of uncommitted demand credit facilities, of which $50 million (December 31, 2014 - $80 million) was unutilized as at September 30, 2015.

 

12



 

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 2020.

 

Commercial paper and credit facility draws, net of short-term borrowings, of $12,084 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.

 

9.          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 and nine months ended September 30, 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
September 30,

 

Nine months ended
September 30,

 

 

 

2015

 

 

2014

 

 

 

2015

 

 

2014

 

(number of shares in millions)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Weighted average shares outstanding

 

 

849

 

 

835

 

 

 

845

 

 

826

 

Effect of dilutive options

 

 

10

 

 

12

 

 

 

12

 

 

11

 

Diluted weighted average shares outstanding

 

 

859

 

 

847

 

 

 

857

 

 

837

 

 

For the three and nine months ended September 30, 2015, 8,876,940 and 6,878,620 anti-dilutive stock options with a weighted average exercise price of $54.08 and $57.59, respectively (2014 - nil and 5,920,500 with a weighted average exercise price of nil and $48.78, respectively) were excluded from the diluted earnings per common share calculation.

 

13



 

10.       COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS)

 

Changes in Accumulated other comprehensive income/(loss) (AOCI) attributable to Enbridge common shareholders for the nine months ended September 30, 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

 

7

 

(759

)

2,427

 

35

 

-

 

1,710

 

Other comprehensive gains/(loss) reclassified to earnings

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest rate contracts1

 

(14

)

-

 

-

 

-

 

-

 

(14

)

Commodity contracts2

 

(10

)

-

 

-

 

-

 

-

 

(10

)

Foreign exchange contracts3

 

6

 

-

 

-

 

-

 

-

 

6

 

Other contracts4

 

22

 

-

 

-

 

-

 

-

 

22

 

Amortization of pension and OPEB actuarial loss and prior service cost5

 

-

 

-

 

-

 

-

 

26

 

26

 

Other comprehensive loss reclassified to earnings of derecognized cash flow hedges (Note 12)

 

(338

)

-

 

-

 

-

 

-

 

(338

)

 

 

(327

)

(759

)

2,427

 

35

 

26

 

1,402

 

Tax impact

 

 

 

 

 

 

 

 

 

 

 

 

 

Income tax on amounts retained in AOCI

 

20

 

39

 

-

 

(2

)

-

 

57

 

Income tax on amounts reclassified to earnings

 

(6

)

-

 

-

 

-

 

(4

)

(10

)

Income tax on amounts reclassified to earnings of derecognized cash flow hedges (Note 12)

 

91

 

-

 

-

 

-

 

-

 

91

 

 

 

105

 

39

 

-

 

(2

)

(4

)

138

 

Balance at September 30, 2015

 

(710

)

(612

)

2,736

 

28

 

(337

)

1,105

 

 

 

 

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

 

(628

)

(155

)

592

 

4

 

-

 

(187

)

Other comprehensive gains/(loss) reclassified to earnings

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest rate contracts1

 

150

 

-

 

-

 

-

 

-

 

150

 

Commodity contracts2

 

8

 

-

 

-

 

-

 

-

 

8

 

Foreign exchange contracts3

 

10

 

-

 

-

 

-

 

-

 

10

 

Other contracts4

 

(29

)

-

 

-

 

-

 

-

 

(29

)

Amortization of pension and OPEB actuarial loss and prior service cost5

 

-

 

-

 

-

 

-

 

10

 

10

 

 

 

(489

)

(155

)

592

 

4

 

10

 

(38

)

Tax impact

 

 

 

 

 

 

 

 

 

 

 

 

 

Income tax on amounts retained in AOCI

 

171

 

21

 

-

 

-

 

-

 

192

 

Income tax on amounts reclassified to earnings

 

(32

)

-

 

-

 

-

 

(4

)

(36

)

 

 

139

 

21

 

-

 

-

 

(4

)

156

 

Balance at September 30, 2014

 

(351

)

244

 

(186

)

(11

)

(177

)

(481

)

 

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

2                  Reported within Commodity sales and 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.

 

14



 

11. 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 million 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.

 

In addition to its economic interest, Enbridge also holds interest in the preferred units of EEP.

 

REDEEMABLE NONCONTROLLING INTERESTS

Redeemable noncontrolling interests in the Fund at September 30, 2015 represented 34.3% (December 31, 2014 - 70.6%; September 30, 2014 - 68.6%) of interests in the Fund’s trust units that are held by third parties. The decrease from 70.6% at December 31, 2014 to 34.3% at September 30, 2015 represented an increase in Enbridge’s unit holdings in the Fund resulting from the September 1, 2015 closing of the Canadian Restructuring Plan (Note 2).

 

15



 

12. RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

 

MARKET RISK

The Company’s earnings, cash flows and other comprehensive income/(loss) (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 2.0%.

 

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 3.8%.

 

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

 

Commodity Price Risk

The Company’s earnings and cash flows are exposed to changes in commodity prices as a result of its ownership 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 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

 

16



 

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 at September 30, 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.

 

September 30, 2015

 

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

 

(millions of Canadian dollars)

 

 

 

 

 

 

 

 

 

 

 

 

 

Accounts receivable and other

 

 

 

 

 

 

 

 

 

 

 

 

 

Foreign exchange contracts

 

5

 

3

 

2

 

10

 

(4

)

6

 

Interest rate contracts

 

-

 

-

 

-

 

-

 

-

 

-

 

Commodity contracts

 

10

 

-

 

579

 

589

 

(160

)

429

 

Other contracts

 

-

 

-

 

3

 

3

 

(2

)

1

 

 

 

15

 

3

 

584

 

602

 

(166

)

436

 

Deferred amounts and other assets

 

 

 

 

 

 

 

 

 

 

 

 

 

Foreign exchange contracts

 

101

 

6

 

-

 

107

 

(106

)

1

 

Interest rate contracts

 

1

 

-

 

-

 

1

 

-

 

1

 

Commodity contracts

 

14

 

-

 

166

 

180

 

(93

)

87

 

 

 

116

 

6

 

166

 

288

 

(199

)

89

 

Accounts payable and other

 

 

 

 

 

 

 

 

 

 

 

 

 

Foreign exchange contracts

 

(1

)

(75

)

(638

)

(714

)

4

 

(710

)

Interest rate contracts

 

(576

)

-

 

(83

)

(659

)

-

 

(659

)

Commodity contracts

 

-

 

-

 

(465

)

(465

)

138

 

(327

)

Other contracts

 

-

 

-

 

(2

)

(2

)

2

 

-

 

 

 

(577

)

(75

)

(1,188

)

(1,840

)

144

 

(1,696

)

Other long-term liabilities

 

 

 

 

 

 

 

 

 

 

 

 

 

Foreign exchange contracts

 

-

 

(244

)

(2,718

)

(2,962

)

106

 

(2,856

)

Interest rate contracts

 

(651

)

-

 

(341

)

(992

)

-

 

(992

)

Commodity contracts

 

-

 

-

 

(271

)

(271

)

93

 

(178

)

Other contracts

 

(9

)

-

 

(5

)

(14

)

-

 

(14

)

 

 

(660

)

(244

)

(3,335

)

(4,239

)

199

 

(4,040

)

Total net derivative asset/(liability)

 

 

 

 

 

 

 

 

 

 

 

 

 

Foreign exchange contracts

 

105

 

(310

)

(3,354

)

(3,559

)

-

 

(3,559

)

Interest rate contracts

 

(1,226

)

-

 

(424

)

(1,650

)

-

 

(1,650

)

Commodity contracts

 

24

 

-

 

9

 

33

 

(22

)1

11

 

Other contracts

 

(9

)

-

 

(4

)

(13

)

-

 

(13

)

 

 

(1,106

)

(310

)

(3,773

)

(5,189

)

(22

)

(5,211

)

 

1                   Amount available for offset includes $22 million of cash collateral.

 

17



 

December 31, 2014

 

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

 

(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.

 

September 30, 2015

 

2015

 

2016

 

2017

 

2018

 

2019

 

Thereafter

 

Foreign exchange contracts - United States dollar forwards - purchase (millions of United States dollars)

 

200

 

28

 

413

 

2

 

2

 

2

 

Foreign exchange contracts - United States dollar forwards - sell (millions of United States dollars)

 

1,139

 

3,002

 

3,104

 

3,150

 

2,645

 

3,105

 

Foreign exchange contracts - Euro forwards - purchase (millions of Euros)

 

-

 

-

 

-

 

-

 

-

 

-

 

Interest rate contracts - short-term borrowings (millions of Canadian dollars)

 

1,599

 

8,441

 

7,469

 

3,859

 

346

 

505

 

Interest rate contracts - long-term debt (millions of Canadian dollars)

 

2,861

 

2,572

 

2,560

 

1,239

 

767

 

-

 

Equity contracts (millions of Canadian dollars)

 

41

 

51

 

48

 

-

 

-

 

-

 

Commodity contracts - natural gas (billions of cubic feet)

 

(45

)

(174

)

(79

)

(18

)

3

 

1

 

Commodity contracts - crude oil (millions of barrels)

 

(4

)

(12

)

(18

)

(9

)

-

 

-

 

Commodity contracts - NGL (millions of barrels)

 

(5

)

(8

)

-

 

-

 

-

 

-

 

Commodity contracts - power (megawatt hours (MWH))

 

32

 

40

 

40

 

30

 

31

 

(23

)

 

18



 

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
September 30,

 

Nine months ended
September 30,

 

 

 

2015

 

 

2014

 

 

 

2015

 

 

2014

 

(millions of Canadian dollars)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Amount of unrealized gains/(loss) recognized in OCI

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash flow hedges

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Foreign exchange contracts

 

 

36

 

 

22

 

 

 

66

 

 

(9

)

Interest rate contracts

 

 

(390

)

 

(173

)

 

 

(662

)

 

(694

)

Commodity contracts

 

 

18

 

 

9

 

 

 

8

 

 

(8

)

Other contracts

 

 

(26

)

 

7

 

 

 

(40

)

 

15

 

Net investment hedges

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Foreign exchange contracts

 

 

(105

)

 

(63

)

 

 

(206

)

 

(66

)

 

 

 

(467

)

 

(198

)

 

 

(834

)

 

(762

)

Amount of gains/(loss) reclassified from AOCI to earnings (effective portion)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Foreign exchange contracts1

 

 

-

 

 

(5

)

 

 

6

 

 

10

 

Interest rate contracts2

 

 

20

 

 

30

 

 

 

53

 

 

74

 

Commodity contracts3

 

 

(13

)

 

2

 

 

 

(35

)

 

14

 

Other contracts4

 

 

16

 

 

(5

)

 

 

22

 

 

(12

)

 

 

 

23

 

 

22

 

 

 

46

 

 

86

 

De-designation of qualifying hedges in connection with the Canadian Restructuring Plan (Note 2)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest rate contracts2,5

 

 

338

 

 

-

 

 

 

338

 

 

-

 

 

 

 

338

 

 

-

 

 

 

338

 

 

-

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest rate contracts2

 

 

25

 

 

130

 

 

 

(10

)

 

158

 

Commodity contracts3

 

 

-

 

 

-

 

 

 

5

 

 

3

 

 

 

 

25

 

 

130

 

 

 

(5

)

 

161

 

 

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

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

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

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

5                  The amounts above include $338 million in the three and nine months ended September 30, 2015 relating to the de-designation of qualifying hedges in connection with the Canadian Restructuring Plan.

 

19



 

The Company estimates that $92 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 51 months at September 30, 2015.

 

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
September 30,

 

Nine months ended
September 30,

 

 

2015

 

 

2014

 

 

2015

 

 

2014

 

(millions of Canadian dollars)

 

 

 

 

 

 

 

 

 

 

 

 

Foreign exchange contracts1 

 

(1,087

)

 

(568

)

 

(1,992

)

 

(510

)

Interest rate contracts2,5

 

(380

)

 

1

 

 

(380

)

 

3

 

Commodity contracts

 

204

 

 

146

 

 

(23

)

 

447

 

Other contracts4

 

(16

)

 

5

 

 

(15

)

 

12

 

Total unrealized derivative fair value gains/(loss)

 

(1,279

)

 

(416

)

 

(2,410

)

 

(48

)

 

1

Reported within Transportation and other services revenues (2015 - $1,253 million loss; 2014 - $254 million loss) and Other expense (2015 - $739 million loss; 2014 - $256 million loss) in the Consolidated Statements of Earnings.

2

Reported as an (increase)/decrease to Interest expense in the Consolidated Statements of Earnings.

3

Reported within Transportation and other services revenues (2015 - $148 million gain; 2014 - $395 million gain), Commodity sales revenues (2015 - $326 million loss; 2014 - nil), Commodity costs (2015 - $162 million gain; 2014 - $57 million gain) and Operating and administrative expense (2015 - $7 million loss; 2014 - $5 million loss) in the Consolidated Statements of Earnings.

4

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

5

The amounts above include $338 million in the three and nine months ended September 30, 2015 relating to the de-designation of qualifying hedges in connection with the Canadian Restructuring Plan (Note 2).

 

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 September 30, 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.

 

20



 

The Company had group credit concentrations and maximum credit exposure, with respect to derivative instruments, in the following counterparty segments:

 

 

 

September 30,
2015 

 

 

December 31,
2014

 

(millions of Canadian dollars)

 

 

 

 

 

 

Canadian financial institutions

 

45

 

 

58

 

United States financial institutions

 

308

 

 

240

 

European financial institutions

 

29

 

 

73

 

Other1

 

331

 

 

310

 

 

 

713

 

 

681

 

1                  Other is comprised of commodity clearing house and physical natural gas and crude oil counterparties.

 

As at September 30, 2015, the Company had provided letters of credit totalling $559 million in lieu of providing cash collateral to its counterparties pursuant to the terms of the relevant ISDA agreements. The Company held $22 million of cash collateral on derivative asset exposures as at September 30, 2015 and $33 million of cash collateral 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.

 

21



 

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, 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.

 

22



 

The Company has categorized its derivative assets and liabilities measured at fair value as follows:

 

September 30, 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

 

Commodity contracts

 

14

 

110

 

465

 

589

 

Other contracts

 

-

 

3

 

-

 

3

 

 

 

14

 

123

 

465

 

602

 

Long-term derivative assets

 

 

 

 

 

 

 

 

 

Foreign exchange contracts

 

-

 

107

 

-

 

107

 

Interest rate contracts

 

-

 

1

 

-

 

1

 

Commodity contracts

 

-

 

35

 

145

 

180

 

 

 

-

 

143

 

145

 

288

 

Financial liabilities

 

 

 

 

 

 

 

 

 

Current derivative liabilities

 

 

 

 

 

 

 

 

 

Foreign exchange contracts

 

-

 

(714

)

-

 

(714

)

Interest rate contracts

 

-

 

(659

)

-

 

(659

)

Commodity contracts

 

(8

)

(97

)

(360

)

(465

)

Other contracts

 

-

 

(2

)

-

 

(2

)

 

 

(8

)

(1,472

)

(360

)

(1,840

)

Long-term derivative liabilities

 

 

 

 

 

 

 

 

 

Foreign exchange contracts

 

-

 

(2,962

)

-

 

(2,962

)

Interest rate contracts

 

-

 

(992

)

-

 

(992

)

Commodity contracts

 

-

 

(44

)

(227

)

(271

)

Other contracts

 

-

 

(14

)

-

 

(14

)

 

 

-

 

(4,012

)

(227

)

(4,239

)

Total net financial asset/(liability)

 

 

 

 

 

 

 

 

 

Foreign exchange contracts

 

-

 

(3,559

)

-

 

(3,559

)

Interest rate contracts

 

-

 

(1,650

)

-

 

(1,650

)

Commodity contracts

 

6

 

4

 

23

 

33

 

Other contracts

 

-

 

(13

)

-

 

(13

)

 

 

6

 

(5,218

)

23

 

(5,189

)

 

23



 

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:

 

September 30, 2015

 

Fair Value

 

Unobservable
Input

 

Minimum
Price

 

Maximum
Price

 

Weighted
Average Price

 

Unit of
Measurement

 

(fair value in millions of Canadian dollars)

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity contracts - financial1

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas

 

2

 

Forward gas price

 

3.20

 

4.43

 

3.76

 

$/mmbtu

3

Crude

 

(2

)

Forward crude price

 

41.87

 

62.75

 

59.35

 

$/barrel 

 

NGL

 

14

 

Forward NGL price

 

0.27

 

1.32

 

0.96

 

$/gallon 

 

Power

 

(153

)

Forward power price

 

34.00

 

75.22

 

53.12

 

$/MWH 

 

Commodity contracts - physical1

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas

 

(7

)

Forward gas price

 

2.75

 

4.72

 

3.48

 

$/mmbtu

3

Crude

 

32

 

Forward crude price

 

36.05

 

127.69

 

59.40

 

$/barrel 

 

NGL

 

12

 

Forward NGL price

 

0.22

 

1.86

 

0.79

 

$/gallon 

 

Commodity options2

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude

 

46

 

Option volatility

 

23%

 

36%

 

29%

 

 

 

NGL

 

79

 

Option volatility

 

19%

 

63%

 

46%

 

 

 

 

 

23

 

 

 

 

 

 

 

 

 

 

 

 

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

 

24



 

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:

 

 

 

Nine months ended
September 30,

 

 

2015

 

 

2014

 

(millions of Canadian dollars)

 

 

 

 

 

 

Level 3 net derivative asset/(liability) at beginning of period

 

149

 

 

(164

)

Total gains/(loss)

 

 

 

 

 

 

Included in earnings

 

43

 

 

29

 

Included in OCI

 

(17

)

 

4

 

Settlements

 

(152

)

 

11

 

Level 3 net derivative liability at end of period

 

23

 

 

(120

)

 

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 at the last day of the reporting period. There were no transfers between levels as at September 30, 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 $124 million at September 30, 2015 (December 31, 2014 - $99 million).

 

The Company has restricted investments held in trust totalling $34 million as at September 30, 2015 (December 31, 2014 - nil).

 

The Company has a held to maturity preferred share investment carried at its amortized cost of $335 million as at September 30, 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 September 30, 2015, the fair value of this preferred share investment approximates its face value of $580 million (December 31, 2014 - $580 million).

 

As at September 30, 2015, the Company’s long-term debt had a carrying value of $39,694 million (December 31, 2014 - $34,427 million) and a fair value of $40,602 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 nine months ended September 30, 2015, the Company recognized an unrealized foreign exchange loss on the translation of United States dollar denominated debt of $536 million (2014 - unrealized loss of $97 million) and an unrealized loss on the change in fair value of its outstanding foreign exchange forward contracts of $203 million (2014 - unrealized loss of $66 million) in OCI. The Company also recognized a realized loss of $20 million (2014 - realized gain of $8 million) in OCI associated with the settlement of foreign exchange forward contracts and designated debt that had matured during the period. There was no ineffectiveness during the nine months ended September 30, 2015 (2014 - nil).

 

25



 

13. INCOME TAXES

 

The effective income tax rates for the three and nine months ended September 30, 2015 were an expense of 21.2 % and 16.6%, respectively (2014 - 47.7% recovery and 22.5% expense, respectively). The period-over-period change in the effective tax rate is primarily attributable to the effects of rate-regulated accounting and other permanent items relative to the loss in the first nine months of 2015 as compared with the corresponding 2014 period, offset by a $39 million tax expense arising from an intercompany transfer of assets during the second quarter of 2015 and an $88 million write-off of a regulatory asset during the third quarter of 2015 as a result of a common control transaction. The effective income tax rate for the nine months ended September 30, 2015 was further impacted by an out-of-period adjustment recorded in the first quarter of 2015 (Note 4) and a $272 million valuation allowance on deferred tax assets on certain United States investments.

 

14. 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
September 30,

 

Nine months ended
September 30,

 

 

2015

 

 

2014

 

 

2015

 

 

2014

 

(millions of Canadian dollars)

 

 

 

 

 

 

 

 

 

 

 

 

Benefits earned during the period

 

43

 

 

29

 

 

131

 

 

88

 

Interest cost on projected benefit obligations

 

27

 

 

25

 

 

80

 

 

77

 

Expected return on plan assets

 

(36

)

 

(32

)

 

(109

)

 

(96

)

Amortization of prior service costs

 

-

 

 

-

 

 

1

 

 

1

 

Amortization of actuarial loss

 

12

 

 

7

 

 

36

 

 

21

 

Net benefit costs on an accrual basis1,2

 

46

 

 

29

 

 

139

 

 

91

 

 

1

Included in net benefit costs for the three and nine months ended September 30, 2015 are costs related to OPEB of $3 million and $10 million, respectively (2014 - $3 million and $11 million, respectively).

2

For the three and nine months ended September 30, 2015, offsetting regulatory liabilities of nil (2014 - $2 million and $5 million regulatory liabilities, respectively) have been recorded to the extent pension and OPEB costs are expected to be refunded to, or collected from, customers in future rates.

 

26



 

15. CONTINGENCIES

 

ENBRIDGE ENERGY PARTNERS, L.P.

Enbridge holds an approximate 35.8% 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 Line 6B crude oil release. In February 2015, the EPA acknowledged the completion of the Order. In November of 2014, regulatory authority was transferred from the EPA to the Michigan Department of Environmental Quality (MDEQ). The MDEQ 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.

 

In May 2015, EEP reached a settlement with the MDEQ and the Michigan Attorney General’s offices regarding the Line 6B crude oil release. As stipulated in the settlement, EEP agreed to: (1) provide at least 300 acres of wetland through restoration, creation, or banked wetland credits, to remain as wetland in perpetuity; (2) pay US$5 million as mitigation for impacts to the banks, bottomlands and flow of Talmadge Creek and the Kalamazoo River for the purpose of enhancing the Kalamazoo River watershed and restoring stream flows in the river; (3) continue to reimburse the State of Michigan for costs arising from oversight of EEP activities since the release; and (4) continue monitoring, restoration and invasive species control within state-regulated wetlands affected by the release and associated response activities. The timing of these activities is based upon the work plans approved by the State of Michigan.

 

As at September 30, 2015, EEP’s cumulative 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 September 30, 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

On September 9, 2010, a crude oil release occurred on Line 6A in Romeoville, Illinois, caused by a third party water pipeline failure which damaged EEP’s pipeline. 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

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 renewed and includes commercial liability insurance coverage that is consistent with coverage

 

27



 

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 September 30, 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 September 30, 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 insurer who is disputing recovery eligibility for Line 6B costs. In March 2015, Enbridge reached an agreement with that insurer to submit the claim to binding arbitration which is not scheduled to occur until the fourth quarter of 2016. While the Company believes that those costs are eligible for recovery, there can be no assurance that it will prevail in the arbitration.

 

Enbridge renewed its comprehensive property and liability insurance programs under which the Company is insured 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 five 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. 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 September 30, 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. EEP has entered into a tolling agreement with the applicable governmental agencies and discussions with these governmental agencies regarding fines, penalties and injunctive relief are ongoing.

 

In June 2015, EEP reached a separate agreement with the United States of America (Federal Natural Resources Damages Trustees), State of Michigan (State Natural Resources Damages Trustees), Match-E-Be-Nash-She-Wish Band of the Potawatomi Indians and the Nottawaseppi Huron Band of the

 

28



 

Potawatomi Indians to pay approximately US$3.9 million that EEP had accrued to cover a variety of projects, including the restoration of 175 acres of oak savanna in Fort Custer State Recreation Area and wild rice beds along the Kalamazoo River.

 

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.

 

29