management’s report - veresen...50 veresen 2014 financial report consolidated statement of cash...

46

Veresen 2014 Financial Report

To the Shareholders of Veresen Inc.

The consolidated financial statements of Veresen Inc. (“Veresen”) and all information contained in this annual report are the responsibility of management. The consolidated financial statements have been prepared by management in accordance with accounting principles generally accepted in the United States of America (US GAAP). If alternative accounting methods exist,managementhaschosenthoseitdeemsmostappropriateinthecircumstances.Financialstatementsarenotprecise since they include certain amounts based on estimates and judgements. Actual results may differ from these estimates and judgements. Management has ensured that these consolidated financial statements are presented fairly in all material respects.

Management maintains internal accounting and administrative controls designed to provide reasonable assurance that the financial information contained in this annual report is, in all material respects, relevant, reliable and accurate, and that assets are appropriately accounted for and adequately safeguarded.

The Board of Directors is responsible for reviewing and approving Veresen’s annual consolidated financial statements and, primarily through its Audit Committee, for ensuring that management fulfills its responsibilities for financial reporting and internal control.

The Audit Committee is comprised of four independent and financially literate board members that meet regularly during theyearwithmanagementandtheexternalauditorstosatisfyitselfthatmanagement’sresponsibilitiesarebeingdischarged; to review and approve the interim consolidated financial statements, Management’s Discussion and Analysis and other information contained in Veresen’s interim reports prior to their release; and to review the annual consolidated financial statements, Management’s Discussion and Analysis and other information contained in Veresen’s Annual Report, as well as its Annual Information Form prior to submitting them to the Board of Directors for approval.

Theindependentexternalauditors,PricewaterhouseCoopersLLP,havebeenappointedbytheshareholdersofVeresento expressanopinionastowhethertheconsolidatedfinancialstatementsofVeresenpresentfairly,inallmaterialrespects,itsfinancial position as at December 31, 2014 and 2013 and its results of operations and cash flows for the years then ended in accordance with US GAAP.

Donald L. Althoff Theresa JangPresident and Chief Executive Officer Senior Vice President, Finance and Chief Financial Officer

March 12, 2015

Management’s Report

47


Independent Auditor’s Report

To the Shareholders of Veresen Inc.

We have audited the accompanying consolidated financial statements of Veresen Inc., which comprise the consolidated statement of financial position as at December 31, 2014 and December 31, 2013, and the consolidated statements of income, comprehensive income, shareholders’ equity and cash flows for the years then ended, and the related notes, which comprise a summary of significantaccountingpoliciesandotherexplanatoryinformation.

Management’s responsibility for the consolidated financial statements

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

Auditor’s responsibility

Ourresponsibilityistoexpressanopinionontheseconsolidatedfinancialstatementsbasedonouraudits.Weconductedour audits in accordance with Canadian generally accepted auditing standards. Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the consolidated financial statements inordertodesignauditproceduresthatareappropriateinthecircumstances,butnotforthepurposeofexpressinganopinion on the effectiveness of the entity’s internal control. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

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

Opinion

In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of Veresen Inc. as at December 31, 2014 and December 31, 2013 and the results of its operations and its cash flows for the years then ended in accordance with accounting principles generally accepted in the United States of America.

Chartered AccountantsCalgary, Alberta, Canada

March 12, 2015

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Consolidated Statement of Financial Position

(Canadian $ Millions; number of shares in Millions) December 31, 2014 December 31, 2013

Assets

Current assets Cash and short-term investments 51.4 25.2 Restricted cash 4.9 3.7 Distributions receivable 45.6 46.2 Receivables 39.0 43.5 Accrued receivables 16.7 16.5 Other(note8) 12.6 9.0 Assets held for sale (note 5) 38.9 57.3

209.1 201.4Investments in jointly-controlled businesses (note 6) 885.2 857.7Investments held at cost (note 4) 1,660.2 –Rate-regulated asset (note 7) 24.1 34.7Pipeline, plant and other capital assets (note 9) 1,503.8 1,399.9Intangible assets (note 10) 392.7 418.2Due from jointly-controlled businesses (note 20) 44.0 46.6Other assets 18.4 14.9

4,737.5 2,973.4

Liabilities

Current liabilities Payables 30.9 12.2 Interest payable 6.0 12.5 Accrued payables 33.8 25.4 Deferred revenue 2.3 1.6 Dividends payable 8.0 13.2 Current portion of long-term senior debt (note 11) 11.5 212.4 Liabilities associated with assets held for sale (note 5) 3.6 3.3

96.1 280.6Long-term senior debt (note 11) 1,799.9 975.1Subordinated convertible debentures (note 12) – 86.2Deferredtaxliabilities(note14) 256.0 277.3Other long-term liabilities (note 13) 52.8 48.5

2,204.8 1,667.7

Shareholders’ Equity

Share capital (note 15) Preferred shares 341.4 341.4 Commonshares(285.0and201.5outstandingatDecember31,2014 and December 31, 2013, respectively) 3,185.5 1,848.6Additional paid-in capital 4.3 4.3Cumulative other comprehensive loss (64.6) (134.0)Accumulated deficit (933.9) (754.6)

2,532.7 1,305.7

4,737.5 2,973.4

Commitments and Contingencies (note 16)

See accompanying Notes to the Consolidated Financial Statements

Approved by the Board of Directors of Veresen Inc.

Don Althoff Bertrand A. ValdmanDirector Director

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Consolidated Statement of Income

Year ended December 31

(Canadian $ Millions, except per Common Share amounts (note 15)) 2014 2013

Equity income (note 6) 146.3 163.3

Dividend income (note 4) 15.6 –

Operating revenues 302.1 291.7

Operations and maintenance (141.0) (133.6)

General and administrative (49.2) (54.3)

Project development (78.8) (30.9)

Depreciation and amortization (83.3) (82.4)

Interest and other finance (58.7) (61.9)

Foreignexchangeandother 41.2 2.1

Gain on sale of assets, net of impairment loss (note 5, 9) 9.3 –

Netincomebeforetax 103.5 94.0

Currenttax(note14) (29.6) (19.0)

Deferredtax(note14) 4.6 (13.9)

Net income from continuing operations 78.5 61.1

Discontinued operations (note 5)

Netincome(loss)fromdiscontinuedoperationsbeforetax (16.0) 3.8

Incometaxondiscontinuedoperations 6.2 (1.4)

Discontinued operations income (loss) (9.8) 2.4

Net income 68.7 63.5

Preferred Share dividends (16.3) (10.3)

Net income attributable to Common Shares 52.4 53.2

Net income per Common Share

Continuing operations 0.28 0.26

Discontinued operations (0.04) 0.01

Basic and diluted 0.24 0.27

Consolidated Statement of Comprehensive Income


(Canadian $ Millions) 2014 2013


Other comprehensive income

Cumulative translation adjustment

Unrealizedforeignexchangegainontranslation 69.4 30.8

Other comprehensive income 69.4 30.8

Comprehensive income 138.1 94.3


Comprehensive income attributable to Common Shares 121.8 84.0


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Consolidated Statement of Cash Flows



Operating


Net loss (income) from discontinued operations 9.8 (2.4)

Equity income (note 6) (146.3) (163.3)

Distributions from jointly-controlled businesses 225.2 204.7

Depreciation and amortization 83.3 82.4

Foreignexchangeandothernon-cashitems 8.5 3.3

Deferredtax (4.6) 13.9

Gain on sale of assets, net of impairment loss (note 4) (9.3) –

Foreignexchangegainoninvestmentactivities (38.7) –

Changes in non-cash working capital (note 19) 6.1 0.4

Cash provided by continuing operations 202.7 202.5

Cash provided by discontinued operations (note 5) 11.9 14.9

214.6 217.4

Investing

Acquisitions (1,635.2) –

Foreignexchangegainoninvestmentactivities 38.7 –

Proceeds from sale of assets (note 5) 18.7 –

Investments in jointly-controlled businesses (74.5) (68.8)

Return of capital from jointly-controlled businesses 11.2 –

Pipeline, plant and other capital assets (147.8) (46.4)

Other (1.5) (1.8)

Cash provided by continuing operations (1,790.4) (117.0)

Cash used in discontinued operations (note 5) (3.8) (3.6)

(1,794.2) (120.6)

Financing

Long-term debt issued, net of issue costs 920.4 –

Long-term debt repaid (261.8) (11.8)

Net change in credit facilities (40.7) (60.0)

Common Shares issued, net of issue costs 1,156.9 –

Preferred Shares issued, net of issue costs – 144.8

Common Share dividends paid (155.8) (155.1)

Preferred Share dividends paid (16.3) (10.3)

Other 3.6 5.1

1,606.3 (87.3)

Increase in cash and short-term investments 26.7 9.5

Effectofforeignexchangeratechangesoncashandshort-terminvestments (0.5) 0.4

Cash and short-term investments at the beginning of the year 25.2 15.3

Cash and short-term investments at the end of the year 51.4 25.2

Supplemental disclosure of cash flow information

Interest paid 64.3 62.3

Taxespaid,netofrefundsreceived 14.0 24.0


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Consolidated Statement of Shareholders’ Equity



Preferred Shares

January 1 341.4 195.2

Series C Preferred Shares issued, net of issue costs (note 15) – 146.2

Balance at the end of the year 341.4 341.4

Common Shares

January 1 1,848.6 1,804.3

Convertible debentures converted into Common Shares, net of issue costs (note 15) 86.2 –

Common Shares issued under Premium Dividend and Dividend Reinvestment Plan (“DRIP”) 65.5 40.7

Common Shares issued, net of issue costs 1,169.5 –

December 31 3,169.8 1,845.0

Common Shares to be issued under DRIP 15.7 3.6

Balance at the end of the year 3,185.5 1,848.6

Additional paid-in capital

Balance at the beginning and end of the year 4.3 4.3

Cumulative other comprehensive loss

January 1 (134.0) (164.8)

Other comprehensive income 69.4 30.8

Balance at the end of the year (64.6) (134.0)

Accumulated deficit

January 1 (754.6) (608.1)



Common Share dividends (231.7) (199.7)

Balance at the end of the year (933.9) (754.6)

Shareholders’ Equity 2,532.7 1,305.7


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Notes to the Consolidated Financial StatementsYears ended December 31, 2014 and 2013 (Canadian $ Millions, except where noted)

1. DESCRIPTION OF BUSINESS

Veresen Inc. (“Veresen” or the “Company”) is a publicly-traded energy infrastructure company based in Calgary, Alberta, Canada.

Veresen operates in three business segments, Pipelines, Midstream, and Power. At December 31, 2014 the Company’s businesses were comprised of the following:

Entity(1) Business DescriptionOwnership

Interest (%)

CONTROLLED

Pipeline Business

•AlbertaEthaneGathering System L.P. (“AEGS”)

AEGS owns a 1,330-kilometre pipeline system that transports purity ethane fromvariousAlbertaethaneextractionplantstoAlberta’smajorpetrochemicalcomplexeslocatednearJoffreandFortSaskatchewan,Alberta.

100

Midstream Business

•Hythe/Steeprock TheHythe/Steeprockcomplexiscomprisedoftwonaturalgasprocessing plantswithcombinedfunctionalcapacityof516mmcf/d,aswellasapproximately 40,000 horsepower of compression and 370 km of gas gathering lines and is located in the Cutbank Ridge region of Alberta and British Columbia. The Hythe plant processes both sour and sweet natural gas, while the Steeprock plant is a sour gas processing facility.

100 (note 21)

Power Business

•Gas-FiredGeneration

– East Windsor Cogeneration L.P. (“East Windsor Cogeneration”)

– London Cogeneration

•an86-MWcogenerationfacilitylocatedinWindsor,Ontario

• a 17-MW cogeneration facility located in London, Ontario

100

100

•DistrictEnergy

– London District Energy

– PEI District Energy

• a district energy system that produces and distributes steam and chilled water fueled primarily by natural gas, located in London, Ontario

• a district energy system that produces and distributes steam, hot water and electricity fueled primarily by biomass and waste fuel, located in Charlottetown, P.E.I.

100

100

•Run-of-RiverHydro

– Northbrook New York, LLC (“Northbrook”)

– Swift Power L.P. (“Swift”)

– Furry Creek Power Ltd. (“Furry Creek”)

– Clowhom Power L.P. (“Clowhom”)

• a 33-MW run-of-river hydroelectric power facility (“Glen Park”) located on the Black River near Watertown, New York

• a 20-MW run-of-river hydroelectric power facility (“Dasque-Middle”) located near Terrace, B.C.

• an 11-MW run-of-river power facility located 30 km north of Vancouver, B.C.

• two 11-MW run-of-river power facilities located 65 km northwest of Vancouver, B.C.

100

100

99

100

•WasteHeat

– EnPower Green Energy Generation Limited Partnership (“EnPower”)

• two 5-MW waste-heat power generation facilities located at Spectra pipeline’s 150 Mile House and Savona, B.C. compressor stations

100

•WindPower

– St. Columban Energy L.P. (“St. Columban”)

• a 33-MW wind project under construction in the County of Huron, Ontario 90

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Entity(1) Business DescriptionOwnership

Interest (%)

INVESTMENTS HELD AT COST

Pipeline Business

•RubyPipelineHolding Company L.L.C.

TheRubyPipelinesystemisa680-mile,42-inchpipelinesystemthattransportsnatural gas between the Opal hub in Wyoming and the Malin hub in Oregon.

50(2)

(note 4)

JOINTLY-CONTROLLED

Pipeline Business

•AlliancePipelineLimited Partnership (“Alliance Canada”)

•AlliancePipelineL.P. (“Alliance U.S.”)

•(Collectively“Alliance” or “Alliance Pipeline”)

Alliance owns a 3,000-kilometre natural gas pipeline comprised of a mainline andvariousconnectinglateralpipelines.TheAlliancepipelineextendsfromnortheastern B.C. to points near Chicago, Illinois.

50

Midstream Business (Collectively “Aux Sable”)

•AuxSableCanadaL.P.

•SableNGLCanadaL.P.

•(Collectively“AuxSableCanada”)

Aux Sable Canada owns:

•NGLinjectionfacilitiesontheAlliancepipelineinAlbertaandB.C.,

•anoff-gasprocessingfacilityinFortSaskatchewan,Alberta,

•anaturalgasprocessingplantinnortheasternB.C.,and

•anaturalgaspipelinetoconnectitsgasprocessingplanttothe Alliance pipeline

50

•AuxSableLiquid Products L.P. (“ASLP”)

•AuxSableMidstreamLLC(“ASM”)

•AllianceCanadaMarketingL.P.(“ACM”)

•SableNGLServicesL.P. (“Sable NGL Services”)

•(Collectively“AuxSableU.S.”)

Aux Sable U.S. owns:

•anaturalgasliquids(“NGL”)extractionandfractionationfacilitynear the terminus of the Alliance pipeline,

• a natural gas processing plant in the Bakken region of North Dakota,

• a natural gas pipeline which connects the gas processing plant to the Alliance pipeline,

• storage facilities, downstream NGL pipelines and loading facilities adjacenttotheNGLextractionandfractionationfacility,and

• short-term and long-term natural gas transportation capacity on the Alliance pipeline

42.7

•VeresenMidstreamLP • will be comprised of natural gas processing, gathering, and compression assets, located in northeastern British Columbia and northwestern Alberta

50 (note 21)

Power Business

•Gas-FiredGeneration

– York Energy Centre L.P. (“York Energy Centre”)

• a 400-MW simple cycle gas turbine peaking generation facility in the York region, Ontario

50

•WasteHeat

– NRGreen Power Limited Partnership (“NRGreen”)

• four 5-MW waste heat power generation facilities located at Alliance’s Saskatchewan compressor stations and,

• a 13-MW waste heat power generation facility located at Alliance’s Windfall compressor station in Alberta

50

•WindPower

– Grand Valley I and II Limited Partnership (“Grand Valley”)

• two wind power facilities, 9-MW and 11-MW, respectively, near Grand Valley, Ontario

•sixteenturbinewindfarmfacility,40-MW,nearGrandValley,Ontario

75

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As at December 31, 2014 the Company’s development projects consisted of the following:

Entity(1) Development Project DescriptionOwnership

Interest (%)

CONTROLLED

•JordanCoveEnergyProjectL.P. The Jordan Cove LNG terminal is a development project that is proposed toexportliquefiednaturalgasfromCoosBay,Oregon.

100

JOINTLY-CONTROLLED

•PacificConnectorGasPipelineL.P. The Pacific Connector Gas Pipeline, a proposed 232-mile pipeline, is a development project that is proposed to connect the Jordan Cove LNG terminal to a natural gas hub at Malin, Oregon.

50

(1) Where applicable, defined entities include the respective managing general partner.

(2) Ownership percentage represents convertible preferred interest in Ruby Pipeline Holding Company, L.L.C., a parent of Ruby Pipeline L.L.C., holder of the Ruby pipeline system (note 4).

2. BASIS OF PRESENTATION

These consolidated financial statements have been prepared by management in accordance with accounting principles generally accepted in the United States of America (“US GAAP”).

Alliance Pipeline is regulated by the National Energy Board (“NEB”) in Canada and by the Federal Energy Regulatory Commission (“FERC”) in the United States. The Company has adopted accounting and reporting requirements applicable to rate-regulated entitiesinconnectionwithAlliance.TherequirementsprovideforcertainrevenuesandexpensesbeingrecognizeddifferentlythanotherwiseexpectedunderUSGAAPapplicabletonon-regulatedbusinesses.RubyPipeline,aninvestmentheldatcost, is also a rate-regulated entity and adopted the relevant accounting standards for rate-regulated operations. The Tupper Pipeline, part of the Hythe/Steeprock gathering lines, is regulated by the NEB. None of Veresen’s other businesses are rate-regulated entities.

Amounts are stated in millions of Canadian dollars unless otherwise indicated.

The preparation of financial statements in accordance with US GAAP requires management to make estimates and assumptions thataffectthereportedamountsofassets,liabilities,revenues,expenses,financialinstrumentsandtaxes.Actualamountscoulddiffer from these estimates. Significant estimates used in the preparation of these consolidated financial statements relate to the determination of any impairment in the carrying value of long-term assets, the estimated useful lives over which certain assets are depreciated or amortized, the measurement of asset retirement obligations, and contingencies.

These consolidated financial statements include the accounts of the Company and its subsidiaries. The Company consolidates itsinterestinentitiesoverwhichitisabletoexercisecontrol.Totheextentthereareinterestsownedbyotherparties,theotherparties’ interests are included in Non-Controlling Interest. Veresen accounts for its jointly-controlled businesses using the equity method, and its investment in Ruby using the cost method.

Reporting in Accordance with US GAAP

In February 2014 the Alberta Securities Commission (“ASC”) and Ontario Securities Commission (“OSC”) issued a relief order which permits the Company to continue to prepare its financial statements in accordance with US GAAP until the earliest of: (i) January 1, 2019; (ii) the first day of the financial year that commences after the Company ceases to have activities subject to rate regulation; or (iii) the effective date prescribed by the International Accounting Standards Board for the mandatory application of a standard within International Financial Reporting Standards specific to entities with activities subject to rate regulation.ThisASC/OSCreliefordereffectivelyreplacedandextendedthepreviousrelieforder,whichwasduetoexpire effective January 1, 2015.

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3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

New Accounting Pronouncements

The following new Accounting Standards Updates (“ASU”) have been issued, as of December 31, 2014.

Effective January 1, 2014, the Company adopted Accounting Standards Update (“ASU”) 2013-04 “Obligations Resulting from Joint and Several Liability Arrangements”.ThisASUprovidesguidanceondisclosureandmeasurementforobligationswithfixedamounts at a reporting date resulting from joint and several liability arrangements. This guidance was applied retrospectively and did not have a material impact to the Company.

Effective January 1, 2014, the Company adopted ASU 2013-05 “Foreign Currency Matters: Parent’s Accounting for the Cumulative Translation Adjustment upon Derecognition of Certain Subsidiaries or Groups of Assets within a Foreign Entity or of an Investment in a Foreign Entity”. This ASU provides guidance for transactions that require the entire amount of a cumulative translation adjustment related to an entity’s investment in a foreign entity to be released. This guidance was applied retrospectively and did not have a material impact to the Company.

InApril2014,theFinancialAccountingStandardsBoard(“FASB”)issuedASU2014-08,“Presentation of Financial Statements and Property, Plant, and Equipment: Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity”. This ASU provides guidance for changes in criteria and enhanced disclosures for reporting discontinued operations. This guidance is effective for annual and interim periods beginning after December 15, 2014, and is to be applied prospectively. It is anticipated that in general, the revised criteria will result in fewer transactions being categorized as discontinued operations.

In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers”. This ASU provides guidance for changes in criteria for revenue recognition from contracts with customers. This guidance is effective for annual and interim periods beginning after December 15, 2016, and is to be applied retrospectively. The Company is currently evaluating the impact of the standard.

In June 2014, the FASB issued ASU 2014-10, “Development Stage Entities: Elimination of Certain Financial Reporting Requirements, Including an Amendment to Variable Interest Entities Guidance in Topic 810, Consolidation”. This ASU eliminates the concept of a development-stage entity from US GAAP along with the associated presentation and disclosure requirements for development-stage entities. This guidance is effective for annual and interim periods beginning after December 15, 2014, is to be applied prospectively, and will not have a material impact on the Company.

In November 2014, the FASB issued ASU 2014-16, “Derivatives and Hedging.” This ASU provides guidance to clarify the criteria in evaluating the economic characteristics and risks of a host contract in a hybrid financial instrument that is issued in the form of a share. This guidance is effective for annual and interim periods beginning after December 15, 2015, and is to be applied prospectively. The Company is currently evaluating the impact of the standard.

In February 2015, the FASB issued ASU 2015-02, “Consolidation: Amendments to the Consolidation Analysis”. This ASU amends the current consolidation guidance, specifically the guidance in determining whether or not an entity is a variable interest entity. This guidance is effective for annual and interim periods beginning after December 15, 2015, and is to be applied prospectively. The Company is currently evaluating the impact of the standard.

Cash and Short-Term Investments

Cash and short-term investments comprise cash and highly liquid investments with original maturities of 90 days or less andcarryingvalueswhichapproximatemarketvalue.Aportionoftheseshort-terminvestmentsareheldintrustaccounts, themajorityofwhicharepermittedtobeusedforoperating,capitalexpenditureandworkingcapitalpurposes.

56


Investments in Jointly-Controlled Businesses

InvestmentsoverwhichtheCompanyexercisessignificantinfluence,butdoesnothavecontrollingfinancialinterests,areaccounted for using the equity method. Equity investments are initially measured at cost and are adjusted for the Company’s proportionate share of undistributed equity earnings or loss. Equity investments are increased for contributions made to and decreased for distributions received from the investees.

Pipeline, Plant and Other Capital Assets

Fixed asset category Measurement Depreciation policy and rates (per annum)

Pipeline Cost Straight-line basis with a rate of 4%

Plant Cost Straight-line basis over the life of the asset with rates ranging from 3% to 33%

Power facilities Cost Straight-line basis over the life of the asset with rates ranging from 3% to 33%

Administrative Cost Straight-line basis over the life of the asset or the term of the lease, where applicable, with rates ranging from 20% to 33%

Capital spares Lower of average cost or net realizable value Not depreciated

Land Cost Not depreciated

Expendituresthatincreaseorprolongtheservicelifeorcapacityofanassetarecapitalized.Maintenanceandrepaircostsareexpensedasincurred.Constructionworkinprogress,whichincludescapitalizedinterest,willbereclassifiedtopipeline,plant and power facilities and depreciated over the estimated useful life upon commencement of operations.

Intangible Assets

Intangible assets predominantly consist of an acquired customer relationship and service agreement, ethane transportation agreements (“ETAs”), power purchase agreements and water licenses. Intangible assets are amortized on a straight-line basis over their respective useful lives ranging from 11 to 40 years.

Impairment of Long-Lived Assets

The Company evaluates, at least annually, the long-lived assets, such as pipeline, plant and other capital assets and intangible assets for impairment when events or changes in circumstances indicate, in management’s judgment, that the carrying value of such assets may not be recoverable. When such a determination is made, management’s estimate of the sum of undiscounted future cash flows attributable to the assets is compared to the carrying value of the assets to determine whether the recoverability ofthecarryingvaluehasbeenimpaired.Ifthecarryingvalueexceedsthesumofundiscountedcashflows,thecarryingvalueoftheassetsisdeemedtobeimpaired.Theamountbywhichthecarryingvalueexceedstheestimatedfairvalueisrecognizedasan impairment loss.

Judgments and assumptions are inherent in management’s estimate of the undiscounted future cash flows used to determine recoverability of an asset and the estimate of an asset’s fair value used to calculate the amount of any impairment.

Asset Retirement Obligations

The estimated fair value of asset retirement obligations associated with tangible long-lived assets are recognized in the period in which they are incurred if a reasonable estimate of a fair value can be determined. The asset retirement obligation is capitalized as part of the cost of the related long-lived assets and is amortized over the remaining life of the assets.

For some of the Company’s assets, including those held by our jointly-controlled businesses, it is not possible to make a reasonable estimate of ARO due to the indeterminate timing and scope of the asset retirements.

57


Revenue Recognition

Power revenue derived from the sale of energy in the form of electricity, steam, hot water and chilled water, is recognized on the accrual basis upon delivery at rates pursuant to the relevant agreements. In addition, the Company’s gas-fired generation power facilitiesreceivefixedcapacitypaymentsthatarenotdependentupontheamountofenergydeliveredtocustomers.Thisrevenueis recognized as earned on a monthly basis.

AEGS transportation revenue is based on toll charges and operating cost recoveries, including maintenance capital, as provided for under the ETAs. Revenue is recognized at each receipt point and is subject to minimum take-or-pay arrangements.

Hythe/Steeprock revenue is based on providing minimum volume capacity over an agreed upon period, and is recognized at the later of when committed volume capacity is provided under the agreement or when the counterparty’s ability to apply deficiency volumecredithasexpired.

Rate-Regulated Accounting

The Company has rate-regulated businesses, including Alliance which uses rate-regulated accounting as described in note 7. If rate-regulated accounting was not used in respect of Alliance, the rate-regulated asset and a corresponding amount of deferred taxliabilitywouldnotberecognizedintheseconsolidatedfinancialstatements.

Project Development Costs

TheCompanyexpensesprojectdevelopmentcostsasincurred.Projectdevelopmentcostsareonlycapitalizedwhen,inmanagement’s judgment, certain commercial and regulatory criteria have been met, which make it probable that such costs will be recoverable from a project’s future revenues. Capitalized project development costs are amortized on a systematic basis over the applicable project’s useful life.

Capitalized Interest

The Company capitalizes interest costs which are directly attributable to the acquisition or construction of qualifying assets.

Foreign Currency Translation

The functional currency of the Company and its Canadian subsidiaries is the Canadian dollar. The Company’s foreign operations are self-sustaining and are translated using the current rate method. Under this method all assets and liabilities are translated into Canadiandollarsusingtheexchangerateineffectatthebalancesheetdate,andallrevenuesandexpensesaretranslatedintoCanadiandollarsataverageexchangeratesduringtheyear.Theresultingnetcumulativetranslationgainorlossisdeferredandreported as a separate component of other comprehensive income. A portion of such deferred translation gain or loss is recognized in net income when such a foreign subsidiary is disposed of or liquidated.

Long-term Incentive Compensation

The Company has a long-term employee incentive plan (“LTIP”) and a deferred share unit plan (“DSU”). Under each plan, notional common shares are granted to eligible employees. The notional shares are payable in cash at the date of vesting when certain conditions are met, including the employee’s continued employment during a specified period. Amounts payable under theLTIParefurtherdependentupontheachievementofspecifiedperformancetargets.ExpensesrelatedtothevariousLTIPsand DSU plan are accounted for on an accrual basis.

Financial Instruments

Financial assets and financial liabilities are classified as held-for-trading, available-for-sale or at amortized cost. Financial instruments are initially recorded at fair value on the balance sheet. Subsequent measurement of each financial instrument is based on its classification. At December 31, 2014 and 2013, the Company did not have held-to-maturity instruments or instruments in qualifying hedging relationships.

Financial assets and liabilities classified as held-for-trading are measured at fair value with changes in fair value recognized in earnings.

Available-for-sale financial assets are measured at fair value with changes in fair value recognized in other comprehensive income.

The investment in Ruby is recorded at cost.

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Income Tax

TheCompanyusestheliabilitymethodofaccountingforincometaxes.Underthismethod,currentincometaxesarerecognizedfortheestimatedincometaxespayableinrespectofthecurrentyear,whichincludesanaccrualforinterestandpenalties,ifany.Deferredtaxassetsandliabilitiesarerecognizedfortemporarydifferencesbetweenthetaxandaccountingassetandliabilitybasesusingenactedtaxratesandlawsexpectedtoapplywhentheliabilitiesaresettledandtheassetsrealized.Deferredtaxassetsarerecognizedincircumstanceswhereitisconsideredmorelikelythannottherelatedincometaxbenefitswillberealized.

Whenappropriate,theCompanyrecordsavaluationallowanceagainstdeferredtaxassetstoreflectthatthesetaxassetsmaynotbe realized. In determining whether a valuation allowance is appropriate, the Company considers whether it is more likely than not thatallorsomeportionofitsdeferredtaxassetswillnotberealized,basedonmanagement’sjudgmentsusingavailableevidenceabout future events.

Attimes,theCompanymayclaimtaxbenefitsthatmaybechallengedbyataxauthority.TheCompanyrecognizestaxbenefitsonlyfortaxpositionsthataremorelikelythannottobesustaineduponexaminationbytaxauthorities.Theamountrecognized is measured as the largest amount of benefit that has a greater than 50% likelihood to be realized upon settlement. A liability for“unrecognizedtaxbenefits”isrecordedforanytaxbenefitsclaimedintheCompany’staxreturnsthatdonotmeettheserecognition and measurement standards.

Share Issuance Costs

Costs directly attributable to the raising of equity are charged against the related share capital.

4. ACQUISITIONS

Acquisition of a 50% Interest in Ruby Pipeline

On November 6, 2014, the Company acquired, through a wholly-owned subsidiary, two entities which hold an aggregate 50% convertible preferred interest in Ruby Pipeline Holding Company, LLC, which owns the Ruby pipeline system (“Ruby”), for cash considerationofUS$1.425billion.TheacquisitionwasfundedwithproceedsfromtheOctober1,2014subscriptionreceiptoffering and from a new unsecured non-revolving term loan (“Acquisition Credit Facility”).

Ruby is a natural gas transmission system delivering U.S. Rockies natural gas production to markets in the western United States. The680-mile,42-inchpipelinehasacurrentcapacityofapproximately1.5billioncubicfeetperday(“bcf/d”).Rubyoriginates attheOpalhubinWyomingandextendstotheMalinhubinOregon.

Theacquisitionisaccountedforasaninvestmentusingthecostmethod.Transactioncostsofapproximately$6.9millionhavebeen classified with the investment in Ruby on the balance sheet in accordance with the cost method of accounting.

The purchase price has been allocated as follows:

Consideration

Cashconsiderationpaid 1,628.3

Allocation of Consideration

InvestmentinconvertiblepreferredunitsinRubyPipelineHoldingCompany,LLC 1,628.3

Transaction costs 6.9

Investment in Ruby Pipeline 1,635.2

FortheperiodNovember6,2014toDecember31,2014,theCompanyrecordeddividendincomeof$15.6millionrelatedtotheacquired business.

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5. DISPOSALS AND ASSETS HELD FOR SALE

Assets Held for Sale

On November 7, 2014, the Company reached an agreement with an unrelated third party to dispose of its power facilities located inCaliforniaandColoradointheUnitedStateswithanunrelatedthirdpartyforproceedsofapproximatelyUS$27.4millionplusworking capital. As a result, the assets and liabilities of the facilities have been classified as held for sale on the consolidated statement of financial position as at December 31, 2014 and the results of operations have been presented as discontinued operations on the consolidated statement of income, with comparatives. The assets and liabilities held for sale were remeasured toreflectourassessmentoffairvalueasaresultofthesale,whichresultedinanimpairmentchargeof$12.2million.TheCompanycompletedthesaleonJanuary8,2015.

The table below details the assets and liabilities held for sale:

2014 2013

Assets

Cash 2.5 1.4

Receivables 3.2 2.9

Other(note8) 1.6 2.3

Property, plant and equipment (note 9) 24.3 38.2

Intangible assets (note 10) 7.3 12.5

Assets held for sale 38.9 57.3

Liabilities

Payables 0.4 0.6

Accrued payables 3.2 2.7

Liabilities associated with assets held for sale 3.6 3.3

The table below provides details on the results of the discontinued operations:

2014 2013

Operating revenues 36.2 33.0

Operations and maintenance (23.6) (20.3)

General and administrative (1.2) (1.0)

Depreciation and amortization (15.1) (7.9)

Interest and other finance (0.1) –

Asset impairment loss (12.2) –

Netincome(loss)fromdiscontinuedoperationsbeforetax (16.0) 3.8

Incometaxfromdiscontinuedoperations 6.2 (1.4)

Discontinued operations income (loss) (9.8) 2.4

Sale of Alton natural gas storage project (“Alton”)

On February 20, 2014 the Company closed the sale of its 50% interest in Alton, a proposed underground storage facility inNovaScotia,foranagreeduponsalepriceof$8.3million,resultinginanafter-taxgainofapproximately$7.5million. ThecarryingvalueofnetassetssoldasatFebruary20,2014was$0.3million.

Sale of Culliton Creek run-of-river hydro project (“Culliton”)

OnJanuary31,2014,theCompanyclosedthesaleofCullitonforanagreeduponsalepriceof$10.4million,resultingin anafter-taxgainofapproximately$5.2million.ThecarryingvalueofnetassetssoldasatJanuary31,2014was$4.2million,including$3.9millionofintangibleassets.

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6. INVESTMENTS IN JOINTLY-CONTROLLED BUSINESSES

Condensed financial information (100%) for the Company’s jointly-controlled businesses:

As at Year ended Year ended December 31, December 31, As at December 31, 2014 December 31, 2014 2014 2014

Non- Non- Net Income Equity Current Current Current Current Senior (Loss) Ownership Equity Income100% Assets Assets Liabilities(1) Liabilities(1) Debt Revenues Expenses beforeTax (%) Investment (Loss)

Alliance Canada(2) 147.5 1,283.5 76.6 10.9 1,037.0 486.4 368.1 118.3 50 186.8 52.0Alliance U.S.(3)(6) 105.4 1,158.1 86.2 18.8 601.7 376.1 246.1 130.0 50 242.9 60.1AuxSableCanada 58.3 107.6 52.2 9.2 – 733.9 714.7 19.2 50 50.8 9.5ASLP(4)(6) 41.0 477.6 45.1 9.7 21.2 188.8 150.0 38.8 42.7 151.2 18.4ASM(6) 28.9 258.9 19.4 1.2 – 490.4 454.6 35.8 42.7 112.2 15.3ACM 12.2 – 9.5 – – 253.1 253.7 (0.6) 42.7 1.2 2.1Sable NGL Services 0.6 – 0.2 – – 0.1 (5.9) 6.0 50 0.2 2.9York Energy Centre(5) 19.2 275.4 6.8 45.4 286.5 73.4 78.0 (4.6) 50 33.2 (4.8)NRGreen 12.7 141.6 38.4 6.1 0.5 11.7 8.8 2.9 50 54.5 1.4Grand Valley 4.7 50.2 2.4 43.6 – 7.9 6.4 1.5 75 27.0 1.1Veresen Midstream LP – 50.0 – – – – – – 50 25.0 –Other(6) 10.1 20.3 2.1 – – – 23.0 (23.0) 50 0.2 (11.7)

885.2 146.3

As at Year ended Year ended December 31, December 31, As at December 31, 2013 December 31, 2013 2013 2013

Non- Non- Net Income Equity Current Current Current Current Senior (Loss) Ownership Equity Income100% Assets Assets Liabilities(1) Liabilities(1) Debt Revenues Expenses beforeTax (%) Investment (Loss)

Alliance Canada(2) 135.4 1,393.3 62.8 16.4 1,120.3 460.0 347.2 112.8 50 203.9 49.6Alliance U.S.(3)(6) 109.2 1,162.8 83.9 12.3 645.2 336.9 230.7 106.2 50 236.2 50.0AuxSableCanada 50.2 131.2 45.5 7.8 – 245.7 228.6 17.1 50 62.1 8.4ASLP(4)(6) 61.1 436.9 46.7 8.2 19.0 194.4 123.1 71.3 42.7 140.8 32.0ASM(6) 41.2 234.4 33.0 0.5 – 499.1 451.6 47.5 42.7 101.2 20.3ACM 1.1 – 1.5 – – 163.2 184.5 (21.3) 42.7 0.3 (6.6)SableNGLServices 0.5 – 0.1 – – 7.2 10.8 (3.6) 50 0.2 (1.8)York Energy Centre(5) 17.8 289.6 6.4 20.7 260.2 62.6 25.5 37.1 50 54.3 16.1NRGreen 22.4 135.2 10.6 5.5 39.8 11.4 8.3 3.1 50 50.9 1.5GrandValley 3.9 52.8 3.8 43.5 – 7.4 6.4 1.0 75 7.1 0.7Other(6) 2.4 0.8 1.6 – – – 13.1 (13.1) 50-75 0.7 (6.9)

857.7 163.3

Upon acquisition of investments accounted for under the equity method, the Company prepared purchase price allocations of the purchase price to the assets and liabilities of the underlying investee and adjusts equity method earnings for the amortization of purchase price adjustments allocated to depreciable assets.

(1) Current liabilities and non-current liabilities exclude senior debt.

(2) At December 31, 2014, the Company had a $54.2 million (December 31, 2013 – $60.7 million) increase in the carrying value of Alliance Canada compared to the underlying equity in the net assets primarily resulting from the purchase price discrepancy as part of the acquisitions in 1997, 2002, and 2003 resulting in 50% ownership.

(3) At December 31, 2014, the Company had a US$ 11.7 million (December 31, 2013 – US$ 8.7 million) decrease in the carrying value of Alliance U.S. compared to the underlying equity in the net assets primarily resulting from the purchase price discrepancy as part of the acquisitions in 1997, 2002, and 2003 resulting in 50% ownership.

(4) At December 31, 2014, the Company had a US$ 29.4 million (December 31, 2013 – US$ 31.2 million) decrease in the carrying value of ASLP compared to the underlying equity in the net assets primarily resulting from the purchase price discrepancy as part of the acquisitions in 1997, 2002, and 2003 resulting in 42.7% ownership.

(5) At December 31, 2014, the Company had a $43.3 million (December 31, 2013 – $45.8 million) increase in the carrying value of York Energy Centre compared to the underlying equity in the net assets primarily resulting from the purchase price discrepancy as part of the acquisition in 2010 resulting in 50% ownership. Expenses include unrealized gains or losses on the interest rate hedge (note 16).

(6) Assets and liabilities of these investments have been translated into Canadian dollars using the exchange rate in effect at the balance sheet date and revenues and expenses have been translated into Canadian dollars at average exchange rates during the period.

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7. RATE-REGULATED ACCOUNTING

Alliance Pipeline is regulated by the NEB in Canada and the FERC in the United States. Transportation contracts are designed to provide toll revenues sufficient to recover the costs of providing transportation service to shippers, including operating, maintenance andadministrativecosts,allowancesfordepreciation,allowancesfortaxes,costsofindebtedness,andanallowedreturnonequity.

The period in which Alliance Pipeline’s transportation costs are recovered from toll receipts may differ from the period these costs are included in equity income recorded in these consolidated financial statements. Alliance Pipeline’s revenue includes amountsrelatedtoaccruedexpensesthatareexpectedtoberecoveredfromshippersinfuturetolls.Similarly,norevenueisrecognizedbyAlliancePipelineinagivenperiodfortollsreceivedthatdonotrelatetocurrentperiodexpensesaccruedinthatperiod. Differences between Alliance Pipeline’s recorded transportation revenue and actual toll receipts are included in Alliance Pipeline’s assets or liabilities and settled through future tolls and are included in the Company’s investment in Alliance.

Pipeline, plant and other capital assets recorded by Alliance Pipeline (and included in Alliance Pipeline’s non-current assets) include an allowance for funds used during construction (“AFUDC”) of the Alliance pipeline which have been capitalized based ontherateofreturnonratebaseapprovedbyregulatorsandareexpectedtoberecoveredinfuturetolls.Accordingly,thesecosts are being amortized to earnings on a basis consistent with the underlying assets.

Alliance’sCanadianrate-regulatedoperationsrecovertaxexpenseusingthetaxespayablemethod,asprescribedbytheNEB for ratemaking purposes. The Company has recorded a rate-regulated asset on its statement of financial position which offsets thedeferredtaxliabilityrecorded.

8. OTHER CURRENT ASSETS 2014 2013

Prepaidexpensesandother 7.9 4.6

Inventory 4.7 5.2

Due from jointly-controlled businesses (note 20) 1.6 1.5

Reclassified to assets held for sale (note 5) (1.6) (2.3)

12.6 9.0

9. PIPELINE, PLANT, AND OTHER CAPITAL ASSETS

2014 2013

Accumulated Net book Accumulated Net book Cost depreciation value Cost depreciation value

Pipeline 470.0 (133.6) 336.4 469.9 (116.9) 353.0

Plant 516.0 (58.6) 457.4 504.2 (38.0) 466.2

Power facilities 625.7 (172.5) 453.2 610.5 (135.5) 475.0

Administrative 9.7 (6.1) 3.6 10.2 (7.2) 3.0

Capital spares 1.3 – 1.3 0.6 – 0.6

Land 46.8 (5.0) 41.8 49.3 – 49.3

Construction work in progress 234.4 – 234.4 91.0 – 91.0

Reclassified to assets held for sale (note 5) (114.6) 90.3 (24.3) (109.7) 71.5 (38.2)

1,789.3 (285.5) 1,503.8 1,626.0 (226.1) 1,399.9

The cost and accumulated depreciation of pipeline, plant and other capital assets deemed to be under operating leases at December31,2014was$106.1millionand$81.9million,respectively(2013–cost:$102.1million,accumulateddepreciation:$63.8million)whichincludesassetsheldforsale.FortheyearendedDecember31,2014,theseassetsgenerated$36.2millioninoperatingleaserevenues(2013–$32.7million).

Asset Impairment Loss

In2014,theCompanyrecognizeda$5.0millionimpairmentlossonlandheldinOntario,Canada.ThisresultedfromtheCompany engaging an unrelated third party to complete a market valuation assessment of the land.

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10. INTANGIBLE ASSETS 2014 2013

Accumulated Net book Accumulated Net book Cost amortization value Cost amortization value

Midstream customer relationship and service agreement 283.5 (41.3) 242.2 283.5 (26.9) 256.6

Power agreements and licenses 267.7 (114.4) 153.3 264.1 (95.6) 168.5

Ethane transportation agreements (“ETAs”) 15.6 (11.1) 4.5 15.6 (10.0) 5.6

Reclassified to assets held for sale (note 5) (93.2) 85.9 (7.3) (88.1) 75.6 (12.5)

473.6 (80.9) 392.7 475.1 (56.9) 418.2

The Midstream customer relationship and service agreement represents the value attributed to intangible assets upon acquisition of Hythe/Steeprock in February 2012. The gas gathering and processing services are provided to Encana Corporation (“Encana”), a major natural gas producer, under a 20-year agreement for minimum monthly fees based on specific committed volumes and unit fees, plus operating and maintenance cost recoveries.

Power purchase agreements and water licenses represent the value attributed to intangible assets upon various acquisitions related to the Company’s power business. Each of the Company’s gas-fired generation facilities hold long-term power purchase agreements, which provide for capacity payments and the sale of electricity to their respective markets or customers, as applicable. Northbrook holds a long-term FERC license under which it operates and maintains the Glen Park facility. Swift holds a long-term electricity purchase agreement, awarded by BC Hydro, which provides for the sale of power produced from the Dasque-Middle run-of-river facility upon commencement of commercial operations. The Furry Creek and Clowhom run-of-river facilities, acquired on February 14, 2011, each hold 40-year water licenses attached to the land for the use of water at their respective sites.

ETAs represent value attributed to AEGS’ intangible assets upon Veresen’s acquisition in December 2004. Under the ETAs, whichexpireonDecember31,2018,shippersarecommittedtopayaminimumfirmtollbasedon90%oftotalcommittedvolume, and to reimburse AEGS for all operating costs, including maintenance capital.

Theintangibleassetsareamortizedonastraight-linebasis.FortheyearendedDecember31,2014,totalamortizationexpenseforintangibleassetswas$27.5million(2013–$27.1million).Annualamortizationexpenseforeachofthenext5yearsisexpectedtobeapproximately$24.1million.

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11. LONG-TERM SENIOR DEBT 2014 2013

VeresenRevolving credit facility 121.6 162.0

5.6% Senior notes due 2014 – 200.0

3.95% Medium term notes due 2017 300.0 300.0

4.0%Mediumtermnotesdue2018 150.0 150.0

3.06% Medium term notes due 2019 200.0 –

5.05% Medium term notes due 2022 50.0 50.0

Acquisition credit facility due 2016 726.0 –

1,547.6 862.0

Less: current portion – (200.0)

1,547.6 662.0

AEGS5.565% Senior notes due 2020 84.4 87.8

Less: current portion (3.5) (3.4)

80.9 84.4

East Windsor Cogeneration6.283%Seniorbondsdue2029 149.5 155.5


143.1 149.5

Clowhom and Furry CreekTerm loan due 2016 – 50.9

7.2947% Term loan due 2024 9.7 10.3


9.0 59.0

EnPower6.65%Termloandue2018 20.2 21.0


19.3 20.2

1,799.9 975.1

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Veresen

Revolving Credit Facilities

AsatDecember31,2014,theCompanyhad$29.0millionlettersofcreditoutstanding,leaving$444.4millionavailableunder thefacilities(asatDecember31,2013,theRevolvingCreditFacilitieshad$31.8millionlettersofcreditoutstanding,leaving$401.2millionavailableunderthisfacility).

Medium Term Notes

OnJune10,2014,theCompanyissued$200millionofseniorunsecuredmediumtermnotesmaturingonJune13,2019,bearing interest at 3.06% per annum, payable semi-annually in arrears on June 13 and December 13 of each year, commencing on December 13, 2014. The net proceeds of the offering were used by the Company on July 10, 2014 to redeem all of its outstanding$200millionaggregateprincipalof5.60%seniornoteswhichwerescheduledtomatureonJuly28,2014.

Veresen Acquisition Credit Facility

The Acquisition Credit Facility is a new unsecured non-revolving term loan used to fund the Ruby acquisition. It ranks pari passuwiththeCompany’sseniorunsecuredobligations,includingtheexistingRevolvingCreditFacility.Thefacilityhasa two-year term maturing November 6, 2016, bearing interest at a quoted floating rate plus a margin. Prepayments are permitted at the Company’s option at any time and upon the occurrence of certain events, in each case without premium or penalty.

Clowhom

OnMay30,2014theCompanyextinguishedtheremainingoutstandingbalanceof$50.4millionoftheClowhomtermloan,which was scheduled to mature on February 21, 2016.

Compliance with Debt Covenants

Each of Veresen and its businesses were in compliance with their respective debt covenants as at December 31, 2014 and 2013.

Scheduled Principal Repayments of Long-Term Senior Debt

Scheduled principal repayments of long-term senior debt, including the current portion thereof, are as follows:

For the years ending December 31

2015 11.5

2016 860.0

2017 313.1

2018 180.1

2019 213.6

Thereafter 233.1

1,811.4

12. SUBORDINATED CONVERTIBLE DEBENTURES 2014 2013

5.75% Series C Subordinated convertible debentures due 2017 – 86.2

Less: current portion – –

– 86.2

Early Redemption of Series C Debentures

On October 20, 2014, the Company redeemed the remaining issued and outstanding 5.75% Convertible Unsecured Subordinated Debentures, Series C due July 17, 2017 (the “Series C Debentures”). The accrued and unpaid interest ontheSeriesCDebenturesissuedandoutstandingasoftheRedemptionDatewas$12.76per$1,000principalamount of Series C Debentures.

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13. OTHER LONG-TERM LIABILITIES 2014 2013

Asset retirement obligations 38.5 36.3

Other 16.3 14.6

54.8 50.9


52.8 48.5

Asset Retirement Obligations

AtDecember31,2014,$22.7millionoftheconsolidatedassetretirementobligation(“ARO”)relatestoAEGS(2013– $21.4million).Thisrepresentsmanagement’sestimateofthecosttoabandontheethanetransportationpipelineandthetimingof the costs to be incurred. Estimated cash flows were discounted at AEGS’ weighted average credit-adjusted risk free rate of return of 6.3% (2013 – 6.3%) and an inflation rate of 2.3% (2013 – 2.3%). The total undiscounted amount of future cash flows requiredtosettletheobligationisestimatedtobe$110.9million(2013–$110.9million).TheestimatedAROcostsreflectsuchactivities as dismantling, demolition and disposal of a portion of the pipeline as well as remediation and restoration of the surface land.Paymentstosettletheobligationarenotexpectedtooccurpriorto2040.

AtDecember31,2014,$13.5millionoftheconsolidatedAROrelatestoHythe/Steeprock(2013–$12.8million).Thisrepresentsmanagement’s estimate of the cost to abandon the gathering and processing facilities, pipelines and storage facilities, and the timing of the costs to be incurred. Estimated cash flows were discounted at Hythe/Steeprock’s weighted average credit-adjusted risk free rate of return of 6.2% (2013 – 6.2%) and an inflation rate of 2.0% (2013 – 2.0%). The total undiscounted amount of futurecashflowsrequiredtosettletheobligationisestimatedtobe$99.9million(2013–$99.9million).Expenditurestosettletheobligationarenotexpectedtooccurpriorto2044.

2014 2013

Asset retirement obligations, January 1 36.3 34.1

Accretionexpense 2.2 2.2

Asset retirement obligations, December 31 38.5 36.3

Other

Otherlong-termliabilitiesprimarilyrepresent$14.2millionofaccrualsforLTIPandDSU(2013–$10.2million).PaymentsmadeundertheLTIPandDSUin2014were$4.6million(2013–$3.3million).

14. TAXES

Components of Taxes

ThefollowingisasummaryofthesignificantcomponentsoftheCompany’staxexpense:

2014 2013(1)

Currenttaxexpense 29.6 19.0

Deferredtaxexpense(recovery)

Origination and reversal of temporary differences (6.3) 30.7

Benefit of loss carry-forwards (2.1) (18.1)

Change in valuation allowance 3.8 1.3

Totaldeferredtaxexpense (4.6) 13.9

Totaltaxexpense 25.0 32.9

(1) Certain comparative figures for the year ended December 31, 2013 have been reclassified (note 5).

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Geographical Components

Netincomebeforetaxanddiscontinuedoperationsfortheyearsended2014and2013areasfollows:

2014 2013(1)

Netincomebeforetaxanddiscontinuedoperations

Canada 91.5 38.1

United States 12.0 55.9

Netincomebeforetaxanddiscontinuedoperations 103.5 94.0


Taxexpensefortheyearsended2014and2013areasfollows:

2014 2013(1)

Currenttaxexpense

Canada 9.7 4.2

United States 19.9 14.8

Totalcurrenttaxexpense 29.6 19.0

Deferredtaxexpense(recovery)

Canada 20.3 15.4

United States (24.9) (1.5)

Totaldeferredtaxexpense(recovery) (4.6) 13.9

Totaltaxexpense 25.0 32.9


Components of Deferred Taxes

Theprovisionfordeferredtaxesarisesfromtemporarydifferencesinthecarryingvaluesofassetsandliabilitiesforfinancialstatementandincometaxpurposesandtheeffectoflosscarryforwards.Theitemscomprisingthedeferredtaxassetsandliabilities are as follows:

2014 2013(1)

Deferredtaxliabilities(assets)

Investments in jointly-controlled businesses 263.0 232.3

Regulatory assets 24.1 34.7

Pipeline, plant and other capital assets 81.6 110.2

Non-capital losses (85.7) (83.6)

Asset retirement obligations (9.9) (9.3)

Deferred revenue and costs (17.1) (7.1)

Totalnetdeferredtaxliabilities 256.0 277.2


TheabovedeferredtaxbalancesatDecember31,2014and2013arenetofvaluationallowancesof$9.0millionand$6.1million,respectively.

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Tax Reconciliation

TheprovisionfortaxesdiffersfromtheresultthatwouldbeobtainedbyapplyingthecombinedCanadianfederalandprovincialstatutoryincometaxratetonetincomebeforetaxandnon-controllinginterest.Thedifferenceresultsfromanumberoffactorssummarized in the following reconciliation: 2014 2013(1)

Netincomebeforetaxanddiscontinuedoperations 103.5 94.0

Canadianstatutoryincometaxrate 25.0% 25.0%

Incometaxatstatutoryrate 25.9 23.5

Increase (decrease) resulting from:

DeferredtaxesrelatedtoCanadianregulatedoperations 7.9 8.2

Higherincometaxratesinotherjurisdictions 2.8 6.0

Deductibleintercompanyinterestexpense (7.1) (6.0)

Change in valuation allowance 3.8 1.3

Adjustment in respect of prior periods (3.4) (0.6)

Taxablecapitalgainsgreater(less)thanaccountinggains (5.5) 0.7

Other 0.6 (0.2)

Taxexpense 25.0 32.9

Net income before discontinued operations 78.5 61.1

Effectivetaxrate 24.2% 35.0%


TheCompanyhasCanadianandU.S.non-capitallossesof$287.4million(2013–$324.7million)and$32.2million(2013–$4.5million),respectively.Canadianlossesexpirebeginningin2024.U.S.losseswillexpireinvaryingamountsfrom2027 to 2032.

TheCompanyhasnounrecognizedtaxbenefitsastherecognitionandmeasurementcriterionhasbeenmet.Itismorelikely thannotthattheCompanywillrealizeitstaxpositions.

TheCompanyissubjecttoCanadianfederalandprovincialincometax,U.S.federalandstateincometax,andotherforeignfederaltaxes.AllCanadianfederalandprovincialincometaxreturnsaresubjecttoexaminationbythetaxationauthorities.AllU.S.federalincometaxreturnsandgenerallyallU.S.stateincometaxreturnsfor2010andsubsequentyearscontinuetoremainsubjecttoexaminationbythetaxationauthorities,inadditiontoyearsrelatingtonon-operatinglossesaresubjecttoexamination.

15. SHARE CAPITAL

Authorized

The authorized capital of the Company consists of (i) an unlimited number of Common Shares and (ii) Preferred Shares, issuable in series, to be limited in number to an amount equal to not more than one-half of the Common Shares issued and outstanding at the time of issuance of such Preferred Shares.

Common Shares 2014 2013

Common Shares Number Value Number Value

January 1 Opening balance (1) 201,736,655 1,848.6 198,112,906 1,804.3

Convertible Debentures converted into Common Shares, net of issue costs (2013: nil) 5,887,565 86.2 – –

Common Shares issued under Premium Dividend and Dividend Reinvestment Plan (“DRIP”)(2) 4,034,816 65.5 3,363,338 40.7

Common Shares issued, net of issue costs (2013: nil) 73,370,000 1,169.5 – –

December 31 285,029,036 3,169.8 201,476,244 1,845.0

Common Shares to be issued under DRIP(2) 1,023,761 15.7 260,411 3.6

286,052,797 3,185.5 201,736,655 1,848.6

(1) Includes 260,411 Common Shares valued at $3.6 million (2013 – 308,753 Common Shares; $3.6 million) subsequently issued under DRIP.

(2) Represents Common Shares issued to satisfy a portion of the Company’s dividends.

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OnApril3,2014,theCompanyissued17.3millionCommonSharesatapriceof$16.50pershareforaggregategrossproceedsofapproximately$284.6million.

OnOctober1,2014,theCompanyissued56.1millionsubscriptionreceiptsatapriceof$16.40persubscriptionreceiptfor grossproceedsof$920million.Thegrossproceedsfromthesaleofthesubscriptionreceiptswereheldbyanescrowagentpending fulfillment or waiver of certain conditions. On November 6, 2014, each outstanding subscription receipt of Veresen wasautomaticallyexchangedforoneCommonShareofVeresenandadividendequivalentpaymentof$0.0833persubscriptionreceipt in respect of the dividend declared by the Company on October 22, 2014 to shareholders of record at the close of business on October 31, 2014.

The weighted average number of Common Shares outstanding used to determine net income per Common Share on a basic anddilutedbasisfortheyearendedDecember31,2014was225,724,157(2013–199,558,454).TherewerenoconvertibledebenturesoutstandingonDecember31,2014(2013–5,906,508).FortheyearendedDecember31,2013,thesewereexcludedfromthedilutedearningsperCommonSharecalculationastheeffectwasanti-dilutive.

Dividends

For the year ended December 31, 2014, the Company declared and paid dividends to common shareholders in the amount of$227.2millionor$1.00perCommonShare(2013–$199.7millionor$1.00perCommonShare).

Premium Dividend and Dividend Reinvestment Plan

The Company’s Premium Dividend and Dividend Reinvestment Plan (“DRIP”) allows eligible shareholders to elect to reinvest the eligible portion of the dividend declared by the Company in additional Common Shares at a 5% discount to the average market price or to receive the dividend in cash plus a 2% premium cash payment based on the eligible portion of the dividend. The Company reserves the right to determine, for each dividend declared, how much new equity would be issued under the DRIP.

Preferred Shares

Series C Preferred Shares

On October 21, 2013, the Company issued 6 million Cumulative Redeemable Preferred Shares, Series C (“Series C Preferred Shares”)atapriceof$25perSeriesCPreferredShare.TheholdersofSeriesCPreferredSharesareentitledtoreceivefixedcumulativepreferentialcashdividendsatanannualrateof5.00%,payablequarterlyforaninitialperioduptobutexcludingMarch 31, 2019, if and when declared by the Board of Directors. The dividend rate will reset on March 31, 2019 and every five years thereafter at a rate equal to the sum of the then five-year Government of Canada bond yield plus 3.01%. The Series C Preferred Shares are redeemable by the Company, at the Company’s option, on March 31, 2019 and on March 31 of every fifth year thereafter.

Holders of Series C Preferred Shares have the right to convert all or any part of their shares into Cumulative Redeemable Preferred Shares, Series D (“Series D Preferred Shares”) subject to certain conditions, on March 31, 2019 and on March 31 of every fifth year thereafter. The holders of Series D Preferred Shares are entitled to receive quarterly floating rate cumulative dividends at a rate equal to the sum of the then 90-day Government of Canada treasury bill rate plus 3.01%.

Series A Preferred Shares

OnFebruary14,2012,theCompanyissued8millionCumulativeRedeemablePreferredShares,SeriesA(“SeriesAPreferredShares”)atapriceof$25perSeriesAPreferredShare.TheholdersofSeriesAPreferredSharesareentitledtoreceivefixedcumulativepreferentialcashdividendsatanannualrateof4.40%,payablequarterlyforaninitialperioduptobutexcludingSeptember 30, 2017 if and when declared by the Board of Directors. The dividend rate will reset on September 30, 2017 and every five years thereafter at a rate equal to the sum of the then five-year Government of Canada bond yield plus 2.92%. The Series A Preferred Shares are redeemable by the Company, at the Company’s option, on September 30, 2017 and on September 30 of every fifth year thereafter.

Holders of Series A Preferred Shares have the right to convert all or any part of their shares into Cumulative Redeemable Preferred Shares, Series B (“Series B Preferred Shares”) subject to certain conditions, on September 30, 2017 and on September 30 of every fifth year thereafter. The holders of Series B Preferred Shares are entitled to receive quarterly floating rate cumulative dividends at a rate equal to the sum of the then 90-day Government of Canada treasury bill rate plus 2.92%.

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Dividends

In2014,theCompanymadecashdividendpaymentsof$8.8millionor$1.10pershareinrespectoftheSeriesAPreferredShares(2013–$8.8millionor$1.10pershare),and$7.5millionor$1.25pershareinrespectoftheSeriesCPreferredShares(2013–$1.5millionor$0.24pershare).

16. COMMITMENTS AND CONTINGENCIES

Veresenhasoperatingleasesforofficepremisesandvehicles.Includedingeneralandadministrativeexpenseareleaseexpensesof$4.4million(2013–$4.6million).Expectedfutureminimumleasepaymentsundertheoperatingleasesareasfollows:

For the years ending December 31 Operating leases

2015 6.7

2016 6.2

2017 5.3

2018 4.9

2019 5.0

Thereafter 29.3

Total minimum lease payments(1) 57.4

(1) Total rental payments to be received in future periods under non-cancelable subleases are $1.5 million.

InSeptember2014,AuxSablereceivedaNoticeofViolation(“NOV”)fromtheUnitedStatesEnvironmentalProtectionAgency(“EPA”) for alleged violations of the Clean Air Act related to the Leak Detection and Repair program, and related provisions of theCleanAirActpermitforAuxSable’sChannahon,Illinoisfacility.AspartoftheongoingprocessofrespondingtotheNOV, AuxSablediscoveredwhatitbelievestobeadditionalexceedanceofcurrentlypermittedlimitsforVolatileOrganicMaterial. AuxSableisengagedindiscussionswiththeEPAtoevaluatethepotentialimpactandultimateresolutionoftheseissues. At this time, the Company is unable to reasonably estimate the financial impact, if any, which might result from discussions with the EPA.

The Company will be filing an appeal of the decision issued on February 26, 2015 by an Ontario court relating to an application commenced by Energy Fundamentals Group Inc. (“EFG”) for a declaration that, among other things, the option to acquire up to 20% of Veresen’s equity interest in the Jordan Cove LNG terminal and related assets in Coos Bay, Oregon, granted to EFG pursuanttoa2005letteragreementbetweentheparties,continuestoapplytoourproposedJordanCoveLNGexportterminal.Initsdecision,thecourtdeclaredthat,amongotherthings,theoptioncontinuestoapplytotheJordanCoveLNGexportproject.Notice of the appeal must be served within a prescribed period of 30 days following the decision.

OnMarch30,2012,aStatementofClaimwasfiledagainsttheCompany’sequity-accountedinvestees,AuxSableLiquidProducts,L.P.,AuxSableCanadaL.P.,AuxSableExtractionLPandAuxSableCanadaLtd.,relatingtodifferencesininterpretation of certain terms of the NGL Sales Agreement. The Company’s equity-accounted investees were served with thisStatementofClaimonMarch18,2013.TheCompany’sshareofthepotentialexposure,throughitsequityinvestments, isapproximatelyUS$13.0million(42.7%).FurtherpotentialdifferencesininterpretationofcertaintermsoftheNGLSalesAgreement have also been identified on additional years not currently the subject of any claims. The Company has recognized an estimated minimum amount within a range of possible amounts sufficient to potentially settle these claims. At this time, the Company is unable to predict the likely outcome of this matter. The Company will continue to assess the matter and the amount of loss accrued may change in the future.

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17. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

Financial Instruments

The following table summarizes the Company’s financial instrument carrying and fair values as at December 31, 2014:

Financial Financial assets at cost liabilities at or amortized amortized Non-financial cost cost instruments Total Fair value(1)

AssetsCash and short-term investments 51.4 51.4 51.4Restricted cash 4.9 4.9 4.9Distributions receivable 45.6 45.6 45.6Receivables and accrued receivables 55.7 55.7 55.7Due from jointly-controlled businesses 45.6 45.6 45.6Assets held for sale 5.7 33.2 38.9 5.7Investments held at cost 1,660.2 1,660.2 1,660.2Otherassets 1.6 16.8 18.4 1.6

LiabilitiesPayables,interestpayableandaccruedpayables 68.7 2.0 70.7 68.7Dividendspayable 8.0 8.0 8.0Liabilities associated with assets held for sale 3.6 3.6 3.6Seniordebt 1,811.4 1,811.4 1,864.3Otherlong-termliabilities 14.3 38.5 52.8 14.3

(1) Fair value excludes non-financial instruments.

The following table summarizes the Company’s financial instrument carrying and fair values as at December 31, 2013:

Financial Financial assets at cost liabilities at or amortized amortized Non-financial cost cost instruments Total Fair value(2)

AssetsCash and short-term investments 25.2 25.2 25.2Restricted cash 3.7 3.7 3.7Distributions receivable 46.2 46.2 46.2Receivables and accrued receivables 60.0 60.0 60.0Duefromjointly-controlledbusinesses 48.1 48.1 48.1Assets held for sale 4.3 53.0 57.3 4.3Other assets 1.6 13.3 14.9 1.6

LiabilitiesPayables, interest payable and accrued payables 47.7 2.4 50.1 47.7Dividends payable 13.2 13.2 13.2Liabilities associated with assets held for sale 3.3 3.3 3.3Seniordebt 1,187.5 1,187.5 1,226.3Subordinatedconvertibledebentures 86.2 86.2 91.6Otherlong-termliabilities 10.2 38.3 48.5 10.2

(2) Fair value excludes non-financial instruments.

For the years ended December 31, 2014 and 2013 the following amounts were recognized in income:

2014 2013

Totalinterestexpense,recordedwithrespecttootherfinancialliabilities,

calculated using the effective rate method 58.7 61.9

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Fair Values

Fair value is the amount of consideration that would be agreed upon in an arm’s length transaction between knowledgeable, willing parties who are under no compulsion to act.

The fair values of financial instruments included in cash and short-term investments, restricted cash, distributions receivable, receivables and accrued receivables, due from jointly-controlled businesses, other assets, payables, interest payable, accrued payables,dividendspayable,andotherlong-termliabilitiesapproximatetheircarryingamountsduetothenatureoftheitem and/ortheshorttimetomaturity.ThefairvalueoftheinvestmentinRubyapproximatesitscarryingvalueduetothecloseproximityoftheacquisitiondatetothebalancesheetdate.Thefairvaluesofseniordebtarecalculatedbydiscountingfuture cashflowsusingdiscountratesestimatedbasedongovernmentbondratesplusexpectedspreadsforsimilarly-ratedinstrumentswith comparable risk profiles. The fair values of subordinated convertible debentures are measured at quoted market prices.

US GAAP establishes a fair value hierarchy that distinguishes between fair values developed based on market data obtained from sources independent of the reporting entity, and fair values developed using the reporting entity’s own assumptions based on the best information available in the circumstances. The levels of the fair value hierarchy are:

Level 1: Inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities.

Level 2: Inputs are other than the quoted prices included in Level 1 that are observable for the asset or liability, either directly or indirectly.

Level 3: Inputs are not based on observable market data.

VeresenhascategorizedseniordebtasLevel2.AtDecember31,2014seniordebthadacarryingvalueof$1,811.4million(December31,2013–$1,187.5million)andfairvalueof$1,864.3million(December31,2013–$1,226.3million).

The carrying value of investments held at cost are accounted for under the cost method. As part of the Company’s impairment review, the Company performs a fair value assessment of the Company’s investments held at cost on an annual basis using the most currently available information. The fair value assessment was based on a number of factors, including the present value of anticipated distributable cash flows to be produced from the underlying operations of the Ruby investment. Assessing these cash flows required the use of assumptions related to the future demand for Ruby’s operations, forecasted commodity prices and interest rates, anticipated economic conditions, timing of conversion of the preferred interest into a common equity interest, and other inputs, many of which are not available as observable market data. As a result, the Company’s estimate of fair value was a Level 3 fair value measurement.

Financial instruments measured at fair value as of December 31, 2014 were:

Level 1 Level 2 Level 3 Total

Cash and short-term investments 51.4 51.4

Restricted cash 4.9 4.9

Investments held at cost 1,660.2 1,660.2

Maturity Analysis of Financial Liabilities

The tables below summarize the Company’s financial liabilities into relevant maturity groupings based on the remaining period at the balance sheet date to the contractual maturity date. The amounts disclosed in the table are the undiscounted cash flows.

The following table summarizes the maturity analysis of financial liabilities as of December 31, 2014:

<1 year 1 – 3 years 4 – 5 years Over 5 years

Payables,interestpayable,andaccruedpayables 68.7

Dividendspayable 8.0

Liabilities associated with assets held for sale 3.6

Senior debt 11.5 1,173.1 393.7 233.1

Other long-term liabilities 14.3

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The following table summarizes the maturity analysis of financial liabilities as of December 31, 2013:

<1 year 1 – 3 years 4 – 5 years Over 5 years

Payables, interest payable, and accrued payables 47.7

Dividends payable 13.2

Liabilities associated with assets held for sale 3.3

Senior debt 212.4 235.2 493.2 246.7

Subordinatedconvertibledebentures 86.2

Other long-term liabilities 10.2

Currency Risk

From time to time, the Company has utilized U.S.-denominated debt to hedge a portion of the net investment in its self-sustaining U.S.operations.Totheextentthesehedgesweredeemedtobeeffective,anysuchgainsorlosseswererecordedinothercomprehensive income. For the years ended December 31, 2014 and December 31, 2013, there were no net investment hedges.

OnDecember31,2014,approximately50%oftheCompany’stotalassetsweredenominatedinU.S.dollars(2013–39%).

Foreign Exchange Hedge

In2014,theCompanyenteredintoforwardforeignexchangecontractstomanagetheforeignexchangeexposurerelating totheRubyacquisition(note4).FortheyearendedDecember31,2014,theCompanyrecognizeda$38.7millionrealizedpre-taxgainassociatedwiththeforwardforeignexchangecontracts,includedwithinforeignexchangeandotherintheConsolidated Statement of Income, classified within the Corporate segment (December 31, 2013 – nil). As the term of the contractsexpiredinNovember2014,therearenounrealizedforeignexchangehedginggainsorlossesatDecember31,2014(December 31, 2013 – nil).

Interest Rate Risk

AtDecember31,2014,47%ofconsolidatedlong-termdebtwasfloating-ratedebt(2013–18%).

Veresen and its jointly-controlled businesses periodically enter into interest rate hedges (“hedges”) to manage interest rate exposures.AsatDecember31,2014andDecember31,2013,YorkEnergyCentre,ajointly-controlledbusiness,hadoneinterestrate hedge. Future changes in interest rates will affect the fair value of the hedge, impacting the amount of unrealized gains or losses included in equity income from jointly-controlled businesses recognized in the period.

The following is a summary of the interest rate hedge in place as at December 31, 2014:

VariableDebtInterestRate FixedRate NotionalAmount(50%) FairValue(50%) Term

CAD-BA-CDOR 4.36% $126.4 $(22.7) April 30, 2012 to June 30, 2032

The following is a summary of the interest rate hedge in place as at December 31, 2013:

VariableDebtInterestRate FixedRate NotionalAmount(50%) FairValue(50%) Term

CAD-BA-CDOR 4.24% $130.1 $(10.3) April30,2012toJune30,2032

ThefairvaluesapproximatetheamountthatYorkEnergyCentrewouldhaveeitherpaidorreceivedtosettlethecontract, and are included in the Company’s investment in York Energy Centre.

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Credit Risk

Veresenanditsjointly-controlledbusinessesareexposedtocreditriskasrevenuesaredependentupontheabilityofcustomersto fulfill their contractual obligations, the failure of which could adversely affect the ability of Veresen and its jointly-controlled businesses to recover operating and financing costs or make dividends or distributions, as applicable. Alliance and Ruby’s businesses are concentrated in the natural gas transportation industry and their revenue is dependent upon the ability of their shipperstopaytheirmonthlydemandcharges.Exposuretothiscreditriskismitigatedbyrequiringshipperstoprovideletters of credit or other suitable security unless the shippers maintain specified credit ratings or a suitable financial position. As at December31,2014,Allianceheld$55.0millioninlettersofcreditandcashdepositsassecurityfromitsshippers.

AEGS is primarily dependent upon two customers, both large petrochemical companies with world-scale petrochemical facilities located in Alberta. AEGS represents a critical component in securing ethane feedstock for these petrochemical facilities.

InthecaseoftheHythe/Steeprockcomplex,theCompanyisprimarilydependentonEncana,amajornaturalgasproducer, with investment-grade credit ratings.

AuxSable’searningsandcashflowsareprimarilydependentuponthelong-termNGLSalesAgreementwithalarge,integratedenergy company.

ThecounterpartyexposuresassociatedwiththeCompany’sPowerbusinessarediverseandarespreadacrossnumerousentities(including a number of government entities in the case of the Company’s district energy facilities) and individual counterparties.

None of the Company’s financial assets are past due or impaired, nor have any terms been renegotiated. The Company is satisfiedwiththecreditqualityofitsfinancialassets.Themaximumexposuretocreditriskrelatedtonon-derivativefinancialassets is their carrying value, as disclosed previously in the table “Financial Instruments”.

Liquidity Risk

Veresenanditsbusinessesmanagetheirliquidityrequirementsutilizingcashfromoperations,excesscashandundrawncommittedcreditfacilities.TheCompanybelievesthesesourcesoffundingaresufficienttomeetitsexpectedliquidityrequirements.

Allfinancialliabilitiesclassifiedascurrentonthebalancesheetareexpectedtobesettledwithinoneyear.

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18. SEGMENTED INFORMATION

Pipelines Midstream Power Corporate(1) Total

Year ended December 31 2014 2013 2014 2013 2014 2013 2014 2013 2014 2013

Equity income (loss) 112.1 99.6 48.2 52.3 (2.3) 18.3 (11.7) (6.9) 146.3 163.3

Dividend income 15.6 – – – – – – – 15.6 –

Operating revenues 61.3 58.1 132.9 142.3 107.9 91.3 – – 302.1 291.7

Operations and maintenance (31.5) (28.3) (55.0) (63.7) (54.5) (41.6) – – (141.0) (133.6)

General and administrative (2.4) (3.0) (4.7) (4.3) (13.4) (13.5) (28.7) (30.9) (49.2) (51.7)

Project development – – – – – – (78.8) (33.5) (78.8) (33.5)

Depreciation and amortization (14.0) (13.9) (39.7) (39.3) (27.2) (26.9) (2.4) (2.3) (83.3) (82.4)

Interest and other finance (4.8) (5.1) – – (12.6) (14.4) (41.3) (42.4) (58.7) (61.9)

Foreignexchangeandother – – – – 0.1 – 41.1 2.1 41.2 2.1

Gain on sale of assets, net of impairment loss – – – – – – 9.3 – 9.3 –

Netincome(loss)beforetaxfrom continuing operations 136.3 107.4 81.7 87.3 (2.0) 13.2 (112.5) (113.9) 103.5 94.0

Taxexpense(2) – – – – – – (25.0) (32.9) (25.0) (32.9)

Net income (loss) from continuing operations 136.3 107.4 81.7 87.3 (2.0) 13.2 (137.5) (146.8) 78.5 61.1

Discontinued operations

Netincome(loss)beforetaxfrom discontinued operations – – – – (16.0) 3.8 – – (16.0) 3.8

Taxexpense(recovery)from discontinued operations – – – – 6.2 (1.4) – – 6.2 (1.4)

Net income (loss) from discontinued operations – – – – (9.8) 2.4 – – (9.8) 2.4

Net income (loss) 136.3 107.4 81.7 87.3 (11.8) 15.6 (137.5) (146.8) 68.7 63.5

Preferred Share dividends – – – – – – (16.3) (10.3) (16.3) (10.3)

Net income (loss) attributable to Common Shares 136.3 107.4 81.7 87.3 (11.8) 15.6 (153.8) (157.1) 52.4 53.2

Total assets(3) 2,359.4 732.5 1,228.1 1,232.3 681.8 912.5 468.2 96.1 4,737.5 2,973.4

Capitalexpenditures(4) – 1.8 14.3 16.6 132.1 31.0 1.4 0.6 147.8 50.0

(1) Reflects unallocated amounts applicable to Veresen’s head office activities.

(2) The Company holds its ownership interests in multiple business lines through partnerships, which are consolidated into various corporate entities. Consequently, the tax provision is determined on a consolidated basis and, as such, the Company is not able to present income tax by segment.

(3) After giving effect to intersegment eliminations and allocations to businesses.

(4) Reflects capital expenditures related only to wholly-owned and majority-controlled businesses.

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2014

Canada U.S. Total

Dividend income – 15.6 15.6Operating revenues from continuing operations 294.7 7.4 302.1Equity income from jointly-controlled businesses 63.5 82.8 146.3

Investments held at cost – 1,660.2 1,660.2Investments in jointly-controlled businesses 378.0 507.2 885.2Pipeline, plant and other capital assets 1,432.0 71.8 1,503.8

2013

Canada U.S. Total

Operatingrevenuesfromcontinuingoperations 285.5 6.2 291.7

Equity income from jointly-controlled businesses 66.9 96.4 163.3

Investmentsinjointly-controlledbusinesses 379.0 478.7 857.7

Pipeline, plant and other capital assets 1,332.2 67.7 1,399.9

RevenuesearnedfromonecustomerwithintheCompany’sMidstreamsegmentrepresentapproximately39%(2013–43%) of the Company’s 2014 operating revenues. Within the Power segment, there were no revenues earned from one customer representing an amount greater than 10% of the Company’s 2014 operating revenues (2013 – 10%). No other customer represents over 10% of operating revenues in 2014 or 2013.

19. SUPPLEMENTAL CASH FLOW INFORMATION 2014 2013

Accounts receivable 10.7 6.2

Accrued receivables (7.5) 2.4

Other assets (5.6) (0.7)

Payables 11.3 (8.8)

Interest payable (6.6) –

Deferred revenue 0.6 (1.2)

Accrued payables 3.2 2.5

Changes in non-cash operating working capital from continuing operations 6.1 0.4

20. DUE FROM JOINTLY-CONTROLLED BUSINESS

OnMarch30,2012,theCompanyprovideda$47.0millionamortizingtermloantoGrandValley,ajointly-controlled business. Principal and interest are payable on a quarterly basis. The loan bears interest of 5.2% and the maturity dateisDecember31,2031.AtDecember31,2014,theoutstandingbalancewas$43.0million(2013–$44.5million).

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21. SUBSEQUENT EVENTS

Dividends

OnFebruary18,2015,theCompanydeclaredaquarterlydividendof$0.275persharefortheperiodendingMarch31,2015 in respect of the Series A Preferred Shares, payable on March 31, 2015 to shareholders of record on March 13, 2015.

OnFebruary18,2015,theCompanydeclaredaquarterlydividendof$0.3125persharefortheperiodendingMarch31,2015 in respect of the Series C Preferred Shares, payable on March 31, 2015 to shareholders of record on March 13, 2014.

OnJanuary21,2015andFebruary19,2015,theCompanydeclareddividendsof$0.0833perCommonShareforeachofJanuary and February 2015, respectively. These dividends are payable on February 23, 2015 to shareholders of record on January 30, 2015, and March 23, 2015 to shareholders of record on February 27, 2015, respectively.

Veresen Midstream

On December 22, 2014, the Company announced the formation of a new entity, Veresen Midstream Limited Partnership (“Veresen Midstream”), which will be jointly controlled by Veresen and affiliates of Kohlberg Kravis Roberts & Co. L.P. (“KKR”), a global investment firm. The Company will fund its interest in Veresen Midstream by contributing its Hythe/Steeprock gathering andprocessingassetsvaluedat$920million,andinexchangewillreceivefromVeresenMidstream$420millionincash,resultingina50%equitypositionvaluedat$500million.KKRwillfundits50%interestinVeresenMidstreambycontributing$500millionincash.Inadditiontocashonhand,acquisitionofthisinfrastructurewillalsobefundedfromnewVeresenMidstream credit facilities.

Veresen Midstream has entered into definitive agreements to acquire certain natural gas gathering and compression assets supporting Montney development in the Dawson area of northeastern British Columbia from Encana and the Cutbank Ridge Partnership (“CRP”). CRP is a partnership between Encana and Cutbank Dawson Gas Resources Ltd., a subsidiary of Mitsubishi Corporation. This infrastructure is located adjacent to the Hythe/Steeprock assets. Veresen Midstream has alsoagreedtoundertakeupto$5billionofnewmidstreamexpansionforEncanaandCRPintheMontneyregionunder a30-yearfee-for-servicearrangement.Thetransactionisexpectedtocloseattheendofthefirstquarterof2015.

Upon the formation of Veresen Midstream LP on December 22, 2014, the Company and KKR each provided a capital contributionof$25milliontothePartnership,constitutingadepositpaiddirectlytoanescrowagentinrespectofthe acquisition of the Encana assets.

management’s report - veresen...50 veresen 2014 financial report consolidated statement of cash...

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