2012 veresen inc. · net income attributable to common shares 38.9 5 3.1 132.7 per common share ($)...

03 04 05 06 07 08 09 10 11 2 0 1 2 V E R E S E N I N C . F I F T E E N Y E A R S

Financial Report

bVeresen

TablEofCoNTENTS

1 financialandoperatingHighlights

2 accountingStandardsandbasisofPresentation

2 forward-lookingandNon-GaaPInformation

3 businessoverview 3 Key Accomplishments and Developments in 2012 3 Pipeline Business 4 Midstream Business 5 Power Business 5 Development Projects

6 overallfinancialPerformance 6 Net Income Attributable to Common Shares 7 Distributable Cash 8 Cash from Operating Activities

8 Resultsofoperations–bybusinessSegment 8 Pipeline Business 11 Midstream Business 15 Power Business 17 Veresen – Corporate

18 liquidityandCapitalResources 18 Cash from Operating Activities 19 Investing Activities 19 Financing Activities

20 CreditRatings

20 Dividends

22 DistributableCash

24 ContractualobligationsandCommitments

24 Risks 24 Market Pricing Risks 28 Common Business Risks 30 Business-Specific Risks

32 CriticalaccountingPolicies

33 CriticalaccountingEstimates

34 NewaccountingStandards

34 Non-GaaPfinancialMeasures

36 SelectedQuarterlyfinancialInformation

37 DisclosureControlsandProcedures

37 InternalControlsoverfinancialReporting

38 Management’sReport

39 Independentauditor’sReport

40 ConsolidatedfinancialStatements

44 NotestotheConsolidatedfinancialStatements

65 CorporateInformation

1

financialandoperatingHighlights

($ Millions, except where noted) 2012 2011 2010

oPERaTINGHIGHlIGHTS(100%) Pipeline Alliance – billion cubic feet per day 1.553 1.564 1.600

AEGS – thousand barrels per day(1) 284.4 286.9 283.9

Midstream Hythe/Steeprock – million cubic feet per day(2) 393.1 n/a n/a Aux Sable – thousand barrels per day 72.2 77.0 74.1

Power – gigawatt hours (net) 925.9 871.1 665.7

fINaNCIalRESulTS Equity income 135.8 155.1 168.8

Operating revenues 264.2 174.2 121.0

Net income attributable to Common Shares 38.9 53.1 132.7

Per Common Share ($) – basic 0.20 0.33 0.92

– diluted 0.20 0.33 0.90

Cash from operating activities 179.9 191.4 165.6

Distributable cash(3, 4) 211.4 193.0 180.6

Per Common Share ($) – basic and diluted 1.09 1.18 1.24

Dividends paid/payable(5) 193.5 163.0 145.2

Per Common Share ($) 1.00 1.00 1.00

Capital expenditures(6) 91.5 18.5 6.3

Acquisitions, net of cash acquired 890.5 144.6 93.3

fINaNCIalPoSITIoN Cash and short-term investments 16.1 21.9 22.6

Total assets 3,144.0 2,558.1 1,960.7

Senior debt 1,259.3 765.6 572.1

Subordinated convertible debentures 86.2 86.2 86.3

Shareholders’ equity 1,359.8 938.8 921.0

CoMMoNSHaRES Outstanding – as at December 31(7) 197,804,153 166,602,055 158,152,406

Average daily volume 378,758 305,042 334,773

Price per Common Share – close ($) 11.83 15.30 11.88

(1) Average daily volume for AEGS is based on toll volumes.(2) Average daily volume for Hythe/Steeprock is based on fee volumes.(3) This item is not a standard measure under US GAAP and may not be comparable to similar measures presented by other entities. See section entitled “Non-GAAP

Financial Measures” in this MD&A.(4) We have provided a reconciliation of distributable cash to cash from operating activities in the “Non-GAAP Financial Measures” section of this MD&A.(5) Includes $79.2 million of dividends satisfied through the issuance of Common Shares under our Premium DividendTM and Dividend Reinvestment Plan

(trademark of Canaccord Genuity Corp.) for the year ended December 31, 2012 (2011 – $111.4 million).(6) Capital expenditures for wholly-owned and majority-controlled businesses, as presented on the consolidated statement of cash flows.(7) As at the close of markets on February 25, 2013 we had 198,407,806 Common Shares outstanding.

This MD&A, dated March 6, 2013, provides a review of the significant events and transactions that affected our performance during the year ended December 31, 2012 relative to the year ended December 31, 2011. It should be read in conjunction with our consolidated financial statements and notes as at and for the year ended December 31, 2012, prepared in accordance with accounting principles generally accepted in the United States.

Management‘s Discussion and AnalysisYear ended December 31, 2012

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MANAGEMENT’S DISCUSSION AND ANALYSIS

accountingStandardsandbasisofPresentationOur consolidated financial statements as at and for the year ended December 31, 2012 have been prepared by management in accordance with accounting principles generally accepted

in the United States. Comparative figures, which were previously presented in accordance with Canadian generally accepted accounting principles as defined in Part V of the Canadian

Institute of Chartered Accountants Handbook, have been adjusted as necessary to be compliant with accounting policies under US GAAP, which we adopted effective January 1, 2012.

All financial information is in Canadian dollars unless otherwise noted and, as it relates to our financial results, has been derived from information used to prepare our US GAAP

consolidated financial statements. Capitalized terms used in this MD&A that have not been defined have the same meanings attributed to them in our 2012 consolidated financial

statements. Additional information concerning our business is available on SEDAR at www.sedar.com or on our website at www.vereseninc.com.

forward-lookingandNon-GaaPInformationSome of the information contained in this MD&A is forward-looking information under Canadian securities laws. All information that addresses activities, events or developments

which may or will occur in the future is forward-looking information. Forward-looking information typically contains statements with words such as may, estimate, anticipate, believe,

expect, plan, intend, target, project, forecast or similar words suggesting future outcomes or outlook. Forward-looking statements in this MD&A include statements about:

• the ability of Alliance to successfully realize its proposed new services framework and the timing thereof;

• the recovery of costs associated with the relocation of a portion of the Alliance pipeline;

• the projected in-service date of the Tioga Lateral Project;

• the timing and duration of the Hythe plant turnaround;

• Aux Sable’s ability to realize upon the extraction agreements;

• the projected in-service date of NRGreen’s Whitecourt Recovered Energy Project;

• the projected in-service date and capital cost of the Dasque-Middle run-of-river facility;

• the sufficiency of our liquidity;

• the sufficiency of our available committed credit facilities to fund working capital, dividends and capital expenditures;

• the ability of each of our businesses to generate distributable cash and the timing under which distributable cash will be generated; and

• our ability to pay dividends.

The risks and uncertainties that may affect our operations, performance, development and the results of our businesses include, but are not limited to, the following factors:

• our ability to successfully implement our strategic initiatives and achieve expected benefits;

• levels of oil and gas exploration and development activity;

• status, credit risk and continued existence of contracted customers;

• availability and price of capital;

• availability and price of energy commodities;

• availability of construction services and materials;

• fluctuations in foreign exchange and interest rates;

• our ability to successfully obtain regulatory approvals;

• changes in tax, regulatory, environmental, and other laws and regulations;

• competitive factors in the pipeline, midstream and power industries;

• operational breakdowns, failures, or other disruptions; and

• prevailing economic conditions in North America.

Additional information on these and other risks, uncertainties and factors that could affect our operations or financial results are included in our filings with the securities commissions

or similar authorities in each of the provinces of Canada, as may be updated from time to time. We caution readers that the foregoing list of factors and risks is not exhaustive. The

impact of any one risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as these factors are independent and management’s future

course of action would depend on its assessment of all information at that time. Although we believe the expectations conveyed by the forward-looking information are reasonable

based on information available to us on the date of preparation, we can give no assurances as to future results, levels of activity and achievements. Readers should not place undue

reliance on the information contained in this MD&A, as actual results achieved will vary from the information provided herein and the variations may be material. We make no

representation that actual results achieved will be the same in whole or in part as those set out in the forward-looking information. Furthermore, the forward-looking statements

contained herein are made as of the date hereof, and, except as required by law, we do not undertake any obligation to update publicly or to revise any forward-looking information,

whether as a result of new information, future events or otherwise. We expressly qualify any forward-looking information contained in this MD&A by this cautionary statement.

Certain financial information contained in this MD&A may not be standard measures under GAAP in the United States and may not be comparable to similar measures presented

by other entities. These measures are considered to be important measures used by the investment community and should be used to supplement other performance measures prepared

in accordance with GAAP in the United States. For further information on non-GAAP financial measures used by us see the section entitled “Non-GAAP Financial Measures” contained

in this MD&A.

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businessoverview

We are a Canadian corporation committed to actively managing and growing our pipeline transportation, midstream services, and power generation businesses. We focus on high-quality, long-life infrastructure assets in North America with diversity in asset type and geography, and which contribute toward stable cash flow generation. Our businesses are underpinned by a prudent capital structure and investment-grade credit ratings.

KEyaCCoMPlISHMENTSaNDDEVEloPMENTSIN2012

In 2012, we established an independent midstream business through the $915.5 million acquisition of the Hythe/Steeprock gas gathering and processing complex:

• Closed the acquisition on February 9, 2012;

• Completed the financing of the acquisition through a $200 million preferred share issuance in February 2012 and a $350 million term debt issuance in March 2012 ($348.6 million subscription receipt offering completed in December 2011);

• Developed and invested in systems and processes in connection with our assumption of operatorship of the facilities on June 1, 2012; and

• Successfully completed the integration of all facets of the Hythe/Steeprock business on schedule and under budget.

We advanced the following initiatives in our Power business:

• Completed construction and placed into service in March 2012 the first two phases of our inaugural wind power project, Grand Valley I and II, capable of producing an aggregate 20 megawatts;

• Completed construction and placed into service in May 2012 the 400-MW York Energy Centre gas-fired generation facility;

• Advanced the construction of Dasque-Middle, two run-of-river hydro power facilities capable of producing an aggregate 20 MW;

• Advanced, through NRGreen, the construction of the Whitecourt Recovery Energy Project, a waste heat power facility capable of producing 13 MW; and

• Continued to progress a portfolio of renewable power projects through late stage development.

Alliance announced in October 2012 a proposed new services framework that will build on Alliance’s liquids-rich gas advantage and underpin the recontracting of the pipeline beyond December 2015. Alliance initiated consultation with existing and prospective shippers regarding the proposed new services in the fourth quarter of 2012.

We took measures to strengthen our liquidity by extending the term of our Revolving Credit Facility by one year, such that it now matures in December 2016.

On October 24, 2012, our Board of Directors announced that Stephen White, President and Chief Executive Officer, had decided to retire. On November 8, 2012, Don Althoff became our new President and Chief Executive Officer.

PIPElINEbuSINESS

Our pipeline business represented 45%8 of our total asset base as at December 31, 2012 and is comprised of:

• Alliance Pipeline (50% ownership); and

• Alberta Ethane Gathering System (wholly-owned).

Each of Alliance and AEGS are stable cash flow generators that are supported by long-term, take-or-pay transportation agreements.

8 As determined on a proportionately consolidated basis. This is a non-GAAP measure. We have provided a reconciliation to total assets as determined under US GAAP in the “Non-GAAP Financial Measures” section of this MD&A.

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alliance

Alliance owns and manages an integrated, high-pressure natural gas and natural gas liquids pipeline that extends approximately 3,000 kilometres across North America. The system is capable of transporting 1.325 billion cubic feet per day of liquids-rich natural gas on a firm-service basis. With an extensive gathering system, Alliance delivers natural gas from the gas-rich regions of northeastern British Columbia and northwestern Alberta to delivery points near Chicago, Illinois, a major natural gas market hub. At its terminus, the Alliance pipeline connects with five interstate natural gas pipelines and two local natural gas distribution systems with an aggregate receipt capacity of over 6 billion cubic feet per day. These connected pipelines and local distribution systems serve major natural gas consuming areas in the midwestern United States and Ontario. The Alliance pipeline also connects at its terminus with Aux Sable’s natural gas liquids, or “NGL” extraction facility, in which we hold a 42.7% ownership interest.

The Alliance pipeline is strategically located in close proximity to the Montney gas formation in northeastern British Columbia and the Bakken oil formation in Saskatchewan and North Dakota. The Montney and Bakken offer new, incremental sources of liquids-rich natural gas for delivery to downstream markets.

aEGS

AEGS is an integrated pipeline system that transports purity ethane from various Alberta ethane extraction plants to major petrochemical complexes located near Joffre and Fort Saskatchewan, Alberta. The system also transports ethane to and from third-party underground storage in Fort Saskatchewan. Expansion projects commissioned in 2012 near Fort Saskatchewan increased the overall length of AEGS to 1,330 km. These projects included additional pipeline and metering to directly connect AEGS to the major petrochemical complex in Fort Saskatchewan, and the installation of a new pipeline leg for the receipt of ethane from Aux Sable’s Heartland Off-gas facility.

MIDSTREaMbuSINESS

Prior to 2012, our midstream business was comprised of our ownership interests Aux Sable, through various jointly-controlled entities. The composition of our midstream business changed significantly as a result of our acquisition of the Hythe/Steeprock complex in February 2012. As at December 31, 2012, our midstream business represented 29%9 of our total asset base.

Hythe/SteeprockComplex

On February 9, 2012, we acquired the Hythe/Steeprock gas gathering and processing complex for $915.5 million. The Hythe/Steeprock complex is located in the Cutbank Ridge region of northwest Alberta and northeast British Columbia. Natural gas and NGLs in the region are produced from the prolific Montney, Cadomin and other geological formations. The Hythe/Steeprock complex is comprised of two natural gas processing plants with combined functional capacity of 516 mmcf/d, as well as approximately 40,000 horsepower of compression and 370 km of gas gathering lines. The Hythe plant processes both sour and sweet natural gas, while the Steeprock plant is a sour gas processing facility.

With the Hythe/Steeprock acquisition we established an independent natural gas midstream business. The acquisition is consistent with our strategy of growing our business through the selective development and acquisition of contracted, high-quality, long-life infrastructure assets which generate stable cash flows.

auxSable

Aux Sable is comprised of:

• Aux Sable Liquid Products (42.7% ownership), which owns the Channahon Facility, a world-scale NGL extraction and fractionation facility near the terminus of the Alliance pipeline, capable of recovering up to 80,000 barrels per day of ethane, propane, normal butane, iso-butane and natural gasoline;

• Aux Sable Midstream (42.7% ownership), which owns the following assets located in the Bakken region of North Dakota

– the Palermo Conditioning Plant, with a processing capacity to 80 mmcf/d, which removes the heavier hydrocarbon compounds from the rich gas delivered into the Prairie Rose Pipeline, while leaving the majority of the natural gas liquids;

– the Prairie Rose Pipeline, a 12-inch diameter, 134-km pipeline with an estimated capacity of 110 mmcf/d, which gathers liquids-rich gas from the Palermo Plant and other sources for delivery into the Alliance pipeline system; and

– storage facilities, downstream NGL pipelines and loading facilities adjacent to the Channahon Facility;


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• Aux Sable Canada (50% ownership), which owns

– NGL injection facilities on the Alliance pipeline in Alberta and B.C.;

– the Septimus Gas Plant, a natural gas processing plant, with a processing capacity of 60 mmcf/d, located in the liquids-rich Montney region of British Columbia;

– the Septimus Pipeline, a 20-km pipeline that is capable of delivering 400 mmcf/d of natural gas from the Septimus Gas Plant to the Alliance pipeline; and

– the Heartland Off-gas Facility, an off-gas processing facility located in Fort Saskatchewan, Alberta;

• Alliance Canada Marketing (42.7% ownership), which holds long-term firm natural gas transportation capacity on the Alliance pipeline; and

• Sable NGL Services (50% ownership), which, from time to time, holds short-term firm natural gas transportation capacity on the Alliance pipeline.

PowERbuSINESS

We have grown our power business through greenfield development and acquisitions into a diverse portfolio of power generation facilities capable of generating in excess of 780 MW. A significant portion of our power facilities are underpinned with long-term capacity payment-based energy contracts that provide stable cash flows not significantly influenced by commodity prices or volumes of electricity generated. Our power assets represented 25%10 of our total asset base as at December 31, 2012 and are comprised of (wholly-owned except where stated otherwise):

• Gas-fired generation and district energy facilities

– York Energy Centre generation facility in Ontario (400 MW; 50% ownership);

– East Windsor cogeneration facility in Ontario (86 MW);

– London cogeneration and district energy facility in Ontario (17 MW);

– Brush II power generation facility in Colorado (70 MW);

– Ripon and San Gabriel cogeneration facilities in California (49 MW and 44 MW, respectively);

– P.E.I. Energy Systems, a district energy facility in Charlottetown, P.E.I.;

• Waste heat facilities

– two EnPower facilities in B.C. (10 MW);

– four NRGreen facilities in Saskatchewan (20 MW; 50% ownership) and one facility currently under construction in Alberta (13 MW; 50% ownership);

• Run-of-river hydro facilities

– Glen Park in New York (33 MW);

– Furry Creek in B.C. (11 MW; 99% ownership);

– Upper and Lower Clowhom in B.C. (22 MW);

– Dasque-Middle, currently under construction in B.C. (20 MW); and

• Wind power facilities

– Grand Valley phases I and II in Ontario (9 MW and 11 MW, respectively; 75% ownership).

DEVEloPMENTPRojECTS

In 2012, we advanced engineering and permitting activities through the United States regulatory approval process in respect of the Jordan Cove Energy Project, which proposes to export liquefied natural gas from Coos Bay, Oregon. Jordan Cove and Pacific Connector Gas Pipeline each initiated the Federal Energy Regulatory Commission’s pre-filing process under the National Environmental Policy Act, which will lead to completion and submission of formal FERC applications in 2013. Jordan Cove also submitted an application to the U.S. Department of Energy for authorization to export natural gas to non-Free Trade Agreement countries, having earlier received DOE export approval to U.S. Free Trade Agreement countries. In 2012, we also acquired the remaining land in the Coos Bay area to site the LNG terminal project. From a commercial perspective, discussions continue with potential strategic partners to secure long-term arrangements to produce LNG for international customers.

We are also in the late stages of developing several renewable power projects representing an additional aggregate 88 MW of capacity.


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overallfinancialPerformance

NETINCoMEaTTRIbuTablEToCoMMoNSHaRES

Three months ended December 31, Year ended December 31,

($ Millions, except per Common Share amounts) 2012 2011 2012 2011

Net income (loss) before tax and non-controlling interest Pipeline 22.5 23.1 88.7 92.6

Midstream 20.3 32.7 76.7 90.2

Power 0.7 (9.2) (1.0) (24.0)

Veresen – Corporate (22.4) (16.3) (88.9) (62.4)

21.1 30.3 75.5 96.4

Tax expense (6.9) (15.8) (28.8) (43.2)

Net income attributable to non-controlling interest – (0.1) (0.1) (0.1)

Netincome 14.2 14.4 46.6 53.1

PreferredSharedividends (2.2) – (7.7) –

NetincomeattributabletoCommonShares 12.0 14.4 38.9 53.1

PerCommonShare($) 0.06 0.09 0.20 0.33

For the three months ended December 31, 2012, we generated net income attributable to Common Shares of $12.0 million or $0.06 per Common Share compared to $14.4 million or $0.09 per Common Share for the same period last year. Excluding the effect of unrealized fair value gains and losses related to a 20-year interest rate hedge for the York Energy Centre, net income attributable to Common Shares for the three months ended December 31, 2012 was $10.6 million or $0.05 per Common Share compared to $17.9 million or $0.11 per Common Share for the same period in 2011.

For the year ended December 31, 2012, we generated net income attributable to Common Shares of $38.9 million or $0.20 per Common Share compared to $53.1 million or $0.33 per Common Share for 2011. Excluding the effect of unrealized fair value gains and losses related to the York Energy Centre hedge, net income attributable to Common Shares for the year ended December 31, 2012 was $38.7 million or $0.20 per Common Share compared to $69.4 million or $0.43 per Common Share for 2011.

The decrease in earnings primarily reflects reduced NGL fractionation margins realized from our Aux Sable midstream business. The newly acquired Hythe/Steeprock complex, which generates the majority of its earnings from minimum fee commitments, made a substantial contribution towards offsetting the reduced Aux Sable earnings. Earnings were also impacted by higher corporate costs, incurred to support our growth activities, including the Hythe/Steeprock acquisition and the advancement of our LNG project. The decrease in per Common Share earnings further reflects the impact of additional Common Shares issued, primarily to fund the Hythe/Steeprock acquisition.

For the three and 12 months ended December 31, 2012, equity income from Aux Sable was $16.0 million and $53.4 million, respectively, compared to $32.7 million and $90.2 million for the same periods last year. Earnings before interest, taxes, depreciation and amortization, included in Aux Sable equity income, was $19.0 million and $64.6 million respectively, compared to $35.3 million and $98.9 million for the same periods last year. Aux Sable’s earnings were negatively impacted through the majority of 2012 by unfavourable NGL market conditions, driven by the continued oversupply of ethane in Aux Sable’s market region and high levels of propane inventory. These factors drove lower fractionation margins relative to the record-level margins realized in 2011, resulting in Aux Sable reinjecting ethane for extended periods in the second half of 2012 when economics did not support production. Lower earnings from Aux Sable’s margin-based activities were partially offset by new fixed fee earnings generated by its Bakken region assets in North Dakota, acquired in July 2011.

The Hythe/Steeprock complex generated $4.3 million and $23.3 million of net income before finance costs, classified in Veresen - Corporate, and tax for the three months ended December 31, 2012 and the period February 9 to December 31, 2012, respectively. EBITDA for the same periods was $13.7 million and $57.4 million, consistent with our expectations. Earnings reflect the deferral of $2.8 million in fee commitment revenues, a cumulative amount for the period February 9 to December 31, 2012, which was recorded in the fourth quarter upon the finalization of our revenue recognition policy for Hythe/Steeprock. (Further information on Hythe/Steeprock deferred revenue can be found in the “Results of Operations – By Business Segment – Midstream Business – Hythe/Steeprock” section of this MD&A.)

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Earnings also reflect increased corporate costs, which amounted to $22.4 million and $88.9 million for the three and 12 months ended December 31, 2012, respectively, compared to $16.3 million and $62.4 million for the same periods last year. The increase results from higher interest expense related to debt issued to finance the Hythe/Steeprock acquisition and non-recurring costs incurred to integrate Hythe/Steeprock operations. The increase in corporate costs also reflects increased project development expenditures related to the Jordan Cove LNG export terminal project.

Excluding the effect of the unrealized fair value gains and losses related to the York Energy Centre hedge, our Power business generated a net loss before tax and non-controlling interest of $1.2 million for each of the three and 12 months ended December 31, 2012, compared to net losses of $4.5 million and $2.3 million for the same periods last year. Power EBITDA, as determined on a proportionately consolidated basis11, was $17.6 million and $65.5 million for the three and 12 months ended December 31, 2012, respectively, compared to $8.1 million and $48.3 million for the same periods last year. The increase in EBITDA was primarily driven by contributions from our newly commissioned power facilities, York Energy Centre and Grand Valley I and II, and a $3.0 million completion bonus related to York Energy Centre recorded in the second quarter. Offsetting EBITDA was higher depreciation and interest expense associated with our new facilities, and increased power project development expenditures incurred to advance several late-stage development projects.

Our Pipeline business generated $22.5 million and $88.7 million of net income before tax for the three and 12 months ended December 31, 2012, respectively, compared to $23.1 million and $92.6 million for the same periods last year. The decrease reflects the continued reduction in returns on Alliance’s declining investment base, partially offset by slightly higher earnings from AEGS.

DISTRIbuTablECaSH


($ Millions, except per Common Share amounts) 2012 2011 2012 2011

Pipeline 37.2 37.4 147.5 151.0

Midstream 36.3 34.6 124.3 94.2

Power 4.0 1.4 27.1 25.8


Taxes (3.2) (8.3) (15.4) (28.6)

Preferred Share dividends (2.2) – (7.7) –

DistributableCash (1) 56.5 53.2 211.4 193.0

PerCommonShare($) 0.29 0.32 1.09 1.18

(1) See the reconciliation of distributable cash to cash from operating activities in the “Non-GAAP Financial Measures” section of this MD&A.

For the three months ended December 31, 2012, we generated distributable cash of $56.5 million or $0.29 per Common Share compared to $53.2 million or $0.32 per Common Share for the same period last year.

For the year ended December 31, 2012, we generated distributable cash of $211.4 million or $1.09 per Common Share compared to $193.0 million or $1.18 per Common Share for 2011.

Distributable cash reflects a $16.5 million and $60.3 million contribution from Hythe/Steeprock, for the three months ended December 31, 2012 and for the period February 9 to December 31, 2012, respectively, and an aggregate $2.7 million and $7.5 million contribution from the recently commissioned York Energy Centre and Grand Valley power facilities for the three and 12 months ended December 31, 2012, respectively. These increases were partially offset by a $14.8 million and $30.2 million decrease in distributions from Aux Sable, driven by lower fractionation margins; higher costs associated with our growth initiatives, mainly corporate administrative and interest costs; and dividends on our Preferred Shares issued in February 2012. Taxes were lower than the comparative periods due to lower U.S.-based earnings from our Midstream business. Distributable cash for the year from our Pipeline business decreased relative to 2011, as first quarter 2011 distributions from Alliance U.S. included an additional amount resulting from a realignment of its capital position, which occurs from time to time.

Distributable cash on a per Common Share basis, decreased by $0.03 and $0.09 compared to the same periods last year. In addition to the variances described above, distributable cash per Common Share decreased as a result of Common Shares issued over the past year through our Premium DividendTM and Dividend Reinvestment Program (trademark of Canaccord Genuity Corp.) and the conversion of 24.7 million subscription receipts to Common Shares in February 2012 upon our acquisition of the Hythe/Steeprock complex.

11 This is a non-GAAP measure. We have provided a reconciliation to Power net loss before tax and non-controlling interest as determined under US GAAP in the “Non-GAAP Financial Measures” section of this MD&A.

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CaSHfRoMoPERaTINGaCTIVITIES


($ Millions) 2012 2011 2012 2011

Pipeline 35.6 32.9 148.1 157.9

Midstream 32.8 32.4 103.3 88.2

Power 6.9 4.6 14.5 13.8


65.1 59.9 179.9 191.4

For the three months ended December 31, 2012, we generated $65.1 million of cash from operating activities, compared to $59.9 million for the same period last year. The increase reflects operating cash flows from Hythe/Steeprock and distributions from York Energy Centre, partially offset by lower distributions from Aux Sable.

For the year ended December 31, 2012, we generated $179.9 million of cash from operating activities, compared to $191.4 million for 2011. The decrease reflects lower distributions from Aux Sable and Alliance, and higher corporate costs, partially offset by increased cash flows from Hythe/Steeprock and distributions from York Energy Centre.

Resultsofoperations–bybusinessSegment

PIPElINEbuSINESS

Three months ended December 31, 2012 Three months ended December 31, 2011

($ Millions, except where noted) Total Alliance (1) AEGS Total Alliance (1) AEGS

Earningsbeforeinterest,taxesdepreciationandamortization(“EbITDa”) (2) 6.8 63.2 6.8 6.0 64.1 6.0

Depreciation & amortization (3.4) (26.9) (3.4) (3.2) (25.1) (3.2)

Interest (1.3) (15.9) (1.3) (1.4) (17.3) (1.4)

Equity income 20.4 20.4 – 21.7 21.7 –

Netincomebeforetax 22.5 20.4 2.1 23.1 21.7 1.4

Volumes(100%) 1.561 291.1 1.562 277.8

bcf/d mbbls/d (3) bcf/d mbbls/d (3)

Year ended December 31, 2012 Year ended December 31, 2011

($ Millions, except where noted) Total Alliance (1) AEGS Total Alliance (1) AEGS

EbITDa (2) 25.0 249.8 25.0 23.9 256.0 23.9

Depreciation & amortization (13.3) (102.1) (13.3) (12.9) (99.4) (12.9)

Interest (5.2) (65.5) (5.2) (5.4) (69.6) (5.4)

Equity income 82.2 82.2 – 87.0 87.0 –

Netincomebeforetax 88.7 82.2 6.5 92.6 87.0 5.6

Volumes(100%) 1.553 284.4 1.564 286.9

bcf/d mbbls/d(3) bcf/d mbbls/d (3)

(1) Amounts in the shaded area represent our 50% share in each of the line items of Alliance Pipeline’s income statement, including consolidation adjustments, and are provided for the reader’s information. Net income before tax equals our share of equity income, as determined in accordance with US GAAP.

(2) This item is not a standard measure under US GAAP and may not be comparable to similar measures presented by other entities. See section entitled “Non-GAAP Financial Measures” in this MD&A.

(3) Average daily volumes for AEGS are based on toll volumes.

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alliancePipeline

Alliance has firm-service transportation service contracts with primary terms extending to December 1, 2015 with a group of 27 shippers. Alliance U.S. has one additional shipper with a firm-transportation contract that extends to February 2020. Under the transportation service contracts, each shipper is obligated to pay monthly demand charges based on their contracted firm volume, regardless of volumes actually transported. These transportation contracts provide toll revenues sufficient to recover the costs of providing transportation service to shippers, including depreciation, debt financing costs and an allowed return on equity.

operationalHighlights

Transportation deliveries for the three and 12 months ended December 31, 2012 averaged 1.561 bcf/d and 1.553 bcf/d, respectively, compared to 1.562 bcf/d and 1.564 bcf/d for the same periods last year. The Authorized Overrun Service volumes shipped on the Alliance pipeline were lower for the three and 12-month periods in 2012 due to routine maintenance work. AOS levels were further impacted by Alliance’s fall system outage, discussed below. The lower AOS volumes did not impact firm transportation service or earnings.

Fall System Outage

On October 1, 2012, the Alliance system had a planned shut down to accommodate the relocation of a short section of the mainline in northwestern Alberta. This action was taken in response to a safety-related National Energy Board order, driven by recent commercial development close to the pipeline.

The duration of the outage was approximately four days while the new segment of pipeline was successfully connected, tested and put into operation. Firm service on the pipeline was impacted during this period and AOS was impacted in the days leading up to and after the outage. Alliance expects to recover through its 2013 tolls all costs associated with the NEB order. Total project costs included in the 2013 tolls were forecasted at $7.5 million (100% – $15.0 million).

Tioga Lateral Pipeline

In 2011, Alliance filed project plans with the FERC to construct a new lateral pipeline, the Tioga Lateral, to transport liquids-rich natural gas. The 127-km (79-mile) lateral pipeline, underpinned with a long-term shipper contract, will connect new natural gas supply from the Bakken region of North Dakota to the Alliance system, for onward shipment to the Chicago market hub. The lateral has an initial design capacity of 126 mmcf/d and can be expanded based on shipper demand. This new infrastructure will enable producers to economically move natural gas and natural gas liquids produced in association with oil production to market.

The FERC approved construction of the Tioga Lateral on September 20, 2012. Construction of the Tioga Lateral is progressing on plan and commercial in-service is expected in the third quarter of 2013.

Appointment of President and Chief Executive Officer

Mr. Terrance Kutryk was appointed President and Chief Executive Officer of Alliance effective October 1, 2012, replacing Mr. Murray Birch who retired on July 31, 2012.

financialHighlights

Equity income for the three months ended December 31, 2012 was $20.4 million, down marginally from $21.7 million for the same period last year.

Equity income for the year ended December 31, 2012 was $82.2 million compared to $87.0 million for the prior year. The decrease results from lower returns as a result of a declining investment base and lower income tax recoveries.

opportunitiesandDevelopments

Alliance’s key business objective for the period post-2015 is to transition to a multi-service business model, providing shippers with competitively priced infrastructure and energy transportation services to deliver natural gas to major markets in North America.

Alliance is in close proximity to significant natural gas production areas in northeastern British Columbia and northwestern Alberta. In this region, approximately 5.5 bcf/d of natural gas production is within a 40-km distance to the pipeline system. The Alliance system is also ideally positioned relative to unconventional liquids-rich shale developments in the Montney and Bakken regions.

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Alliance has implemented a number of pipeline system optimization projects in response to shipper demand for increased receipt capacity from northeastern British Columbia. Alliance has also increased its receipt capacity from the Montney and Bakken regions. In 2010, the Septimus pipeline, owned by Aux Sable and located in the Montney region, was connected to the Alliance system and is flowing liquids-rich natural gas. Also in 2010, the Prairie Rose Pipeline, acquired by Aux Sable in 2011 and located in the Bakken region, was connected to the Alliance system. In 2011, contract capacity from the Prairie Rose pipeline was doubled to 80 mmcf/d. An executed firm transportation agreement with an anchor shipper enabled Alliance to add additional contract capacity of 62 mmcf/d onto the Tioga Lateral, currently under construction with a design capacity of 126 mmcf/d. These lateral pipelines and their associated facilities are designed to be expandable with in-fill compression to accommodate future growth beyond current design capacities.

The liquidity of the Chicago market, the associated takeaway capacity, and the diversity of pipeline connections enabled Alliance to launch the Alliance Chicago Exchange Hub, a new suite of services that leverage Alliance’s interconnections to other pipelines and downstream markets. As a step forward in Alliance’s development of new services, the ACE Hub enables market participants to be more competitive and access greater commercial liquidity and delivery flexibility in their transactions.

Proposed Service Offerings

On October 10, 2012, Alliance announced a proposed new services framework that will underpin the recontracting of the pipeline beyond December 2015, when the initial 15-year term of the original transportation contracts end. The proposed new services build on Alliance’s advantage in providing low cost, predictable transportation for high energy natural gas.

Prospective shippers have been offered increased optionality through the introduction of a segmented service structure in Canada with two receipt zones, the creation of a new Canadian trading pool that will allow shippers to sell their natural gas out of the receipt zones, and a transmission zone to the U.S. border. Alliance further proposes to offer shippers fixed tolls or tolls that vary with the Chicago-AECO market basis, and varying contract lengths. Alliance also intends to continue to offer a full path service from Canadian receipt points to Chicago.

Alliance is consulting with existing and prospective shippers regarding the new services framework with the goal of entering into precedent agreements in the fall of 2013, after which one or more open seasons will be held to determine additional shipper interest.

2013 Toll/Rate Filings

On October 31, 2012 and November 30, 2012, Alliance filed amended tolls and rates with the NEB and the FERC for the Canadian and U.S. portions of the pipeline, respectively. Effective January 1, 2013, the aggregate 2013 firm transportation rate increased by US$0.051 or 3.3% from US$1.537/mcf to US$1.588/mcf. The increase is due primarily to higher negotiated shipper depreciation rates, higher current income tax recoveries, and increased expenditures for operational pipeline system applications and system optimization activities, pipeline integrity and compliance projects. These increases are partially offset by a decrease in interest expense on senior debt, a reduction in maintenance expenditures and a lower return on equity due to a declining investment base.

The 2013 tolls filed with the NEB were made interim, pending settlement of an intervention filed with the NEB by two shippers. This intervention relates to indirect costs of approximately $2.5 million (100% - $5.0 million) included in the 2013 toll filing. The costs in question were incurred during the 2012 fall system outage, which was conducted to comply with an NEB safety order. On February 28, 2013, the NEB issued a letter decision that Alliance’s 2013 final tolls should not include these costs. The NEB ordered Alliance to recalculate its 2013 tolls in accordance with the decision and submit these tolls in a compliance filing to the Board by March 28, 2013.

The FERC accepted and suspended the amended 2013 rates, subject to refund and conditions, set forth by a FERC order issued December 28, 2012 after interventions were filed by two shippers. The interventions relate to Alliance’s inclusion of Tioga Lateral costs in the 2013 rates and Alliance’s reservation charge credit tariff provisions. Alliance was directed by the FERC to submit revised rates by January 28, 2013, removing any costs associated with the Tioga Lateral from the mainline rates recoverable from Alliance’s negotiated rate shippers. On January 23, 2013, Alliance provided a reply submission to the FERC along with a request that the FERC set aside the December 28, 2012 order and issue an order on rehearing which accepts the negotiated rates filed by Alliance on November 30, 2012, to become effective January 1, 2013, without condition or refund obligation. Alliance also requested within its reply submission that the FERC grant rehearing of the December 28, 2012 order for changes to reservation charge credit tariff provisions and find that any need to show cause as to why these tariff provisions should remain effective be deemed satisfied.

Land Matters Consultation Initiative

Alliance is responsible for compliance with all laws and regulations concerning the abandonment of the pipeline and related facilities at the end of their respective lives. In the fall of 2007, the NEB established a Land Matters Consultation Initiative as part of its examination of key issues. The LMCI is a result of a desire to improve understanding and dialogue between pipeline companies and landowners.

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On May 26, 2009, the NEB adopted a report on the financial issues of pipeline abandonment that will require NEB-regulated pipeline companies to set aside funds to cover future abandonment costs. The issuance of this report followed a public hearing held in January 2009 into the financial matters of pipeline abandonment.

As a result of the mandated framework and action plan, Alliance filed preliminary abandonment cost estimates, largely based on NEB assumptions, for the Canadian segment of its pipeline with the NEB on November 30, 2011.

The NEB held Pipeline Abandonment hearings in November 2012 to consider the reasonableness of each company’s submitted cost estimates, including abandonment methods, environmental considerations, the scope and rationale of each abandonment activity considered for estimating the costs, and the approach to the estimation of the contingency and provision for post-abandonment. On February 14, 2013, the NEB issued its decision on Alliance’s abandonment cost estimates. The NEB has directed Alliance to submit revised cost estimates based on a higher pipeline removal percentage and to increase the post-abandonment monitoring and remediation requirements. The revised cost estimates are to be filed by April 16, 2013.

On February 28, 2013, affected companies including Alliance filed a joint application for a process and mechanism to set aside the funds for pipeline abandonment costs. A second filing detailing affected companies’ proposed collection mechanism is required by May 2013. Under the NEB’s current directive, affected companies will have to start collecting such funds no later than the 2015 toll year.

aEGS

AEGS’ revenues and earnings are based on long-term, take-or-pay ethane transportation agreements, referred to as “ETAs”, which extend to December 31, 2018. The ETAs provide for a minimum revenue stream based on specified committed volumes and the recovery of all operating costs.


Toll volumes for the three months ended December 31, 2012 were 291.1 mbbls/d compared to 277.8 mbbls/d for the same period last year, reflecting higher natural gas exports. Toll volumes for the year ended December 31, 2012 averaged 284.4 mbbls/d compared to 286.9 mbbls/d for the same period last year. Planned turnarounds performed at two major petrochemical plants served by AEGS in the second quarter of 2012 resulted in lower annual ethane deliveries.

financialHighlights

For the three and 12 months ended December 31, 2012, AEGS generated $6.8 million and $25.0 million in EBITDA, respectively, a $0.8 million and $1.1 million increase compared to $6.0 million and $23.9 million for the same periods last year. The increase reflects higher transportation revenues, and higher operating cost recoveries.

Net income before tax for the three and 12 months ended December 31, 2012 was $2.1 million and $6.5 million, respectively, a $0.7 million and $0.9 million increase compared to $1.4 million and $5.6 million for the same periods last year. The increase in net income before tax primarily resulted from higher EBITDA.

MIDSTREaMbuSINESS


Hythe/ Hythe/($ Millions, except where noted) Total Steeprock Aux Sable (1) Total Steeprock Aux Sable (1)

EbITDa 13.7 13.7 19.0 – – 35.3

Depreciation & amortization (9.4) (9.4) (3.0) – – (2.3)

Interest – – – – – (0.3)

Equity income 16.0 – 16.0 32.7 – 32.7

Netincomebeforetax 20.3 4.3 16.0 32.7 – 32.7

Volumes(100%) Fee Volumes (3) 392.3 – mmcf/d Ethane 22.3 47.5

Propane plus 49.8 39.7

72.1 87.2

mbbls/d mbbls/d

(continued on page 12)

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Hythe/ Hythe/($ Millions, except where noted) Total Steeprock (2) Aux Sable (1) Total Steeprock Aux Sable (1)

EbITDa 57.4 57.4 64.6 – – 98.9

Depreciation & amortization (34.1) (34.1) (10.4) – – (7.0)

Interest – – (0.8) – – (1.7)

Equity income 53.4 – 53.4 90.2 – 90.2

Netincomebeforetax 76.7 23.3 53.4 90.2 – 90.2

Volumes(100%) Fee Volumes (3) 393.1 – mmcf/d Ethane 34.3 43.2

Propane plus 37.9 33.8

72.2 77.0

mbbls/d mbbls/d

(1) Amounts in the shaded area represent our 42.7% and 50% share, respectively, in each of the line items of Aux Sable U.S. and Aux Sable Canada’s income statements, including consolidation adjustments, and are provided for the reader’s information. Net income before tax equals our share of equity income, as determined in accordance with US GAAP.

(2) Hythe/Steeprock year-to-date results are for the period February 9 to December 31, 2012.(3) Hythe/Steeprock fee volumes represent (i) either the minimum commitment volumes for which we earned processing fees or actual volumes processed if in excess

of the minimum threshold in respect of the Midstream Services Agreement with our primary customer, and (ii) fees for volumes processed for other producers.

Hythe/Steeprock

Hythe/Steeprock earnings are primarily generated from a long-term midstream services agreement, referred to as the “MSA”, with our primary customer, a major natural gas producer. The MSA provides for minimum monthly fees based on specific committed volumes and unit fees, as well as the recovery of operating and maintenance costs. Volume commitments and unit fees are adjusted annually based on a pre-determined schedule to reflect anticipated production profiles and moderate fee escalation. Total committed volumes, as measured by total Hythe plant throughput, were approximately 374 mmcf/d in 2012 and will average 370 mmcf/d, or 72% of total functional capacity, over the term of the MSA.

Actual monthly volumes delivered by our primary customer can and do vary relative to the minimum volume commitments set out in the MSA. The MSA provides a mechanism whereby limited excess or deficiency volumes can be carried forward for a rolling 12-month period and credited towards any changes resulting from deliveries in deficiency or excess for the minimum volume commitment. Cumulative excess volumes from the previous 12-month period can be used towards the current month’s fees to the extent our primary customer is using less than the committed volumes in the current month. Conversely, cumulative deficiency volumes from the previous 12-month period can be used to offset the current month’s excess volumes. The credits that can be carried forward are subject to financial limits. No carry-forward scenarios will result in Veresen receiving less than the minimum committed fee stream. Under US GAAP, we are required to defer the recognition of revenues earned from processing excess volumes until the 12-month carry forward period has expired and retention is certain. In the case of volume deficiencies, we are required to defer the recognition of revenue from the portion of committed fees equal to the maximum amount of future excess fees we could be required to forgo until the 12-month carry forward period has expired.


We assumed operatorship of both Hythe and Steeprock on June 1, 2012 without incident, while retaining substantially all operational employees at both processing plants. Our primary customer is the contract operator of the compression and gas gathering system we acquired.

On September 1, 2012, we assumed the production accounting function for each of the Hythe and Steeprock facilities, representing the last business transition. Transition and integration activities were executed as planned, resulting in a smooth and orderly transfer of all aspects of operatorship.

During the three months ended December 31, 2012 and the period February 9 to December 31, 2012, fee volumes at Hythe/Steeprock averaged 392.3 mmcf/d and 393.1 mmcf/d, respectively, which is comprised of the minimum volume commitment under the MSA and 18 mmcf/d and 19 mmcf/d of natural gas from third party producers.

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financialHighlights

Hythe/Steeprock generated $13.7 million and $57.4 million in EBITDA for the three months ended December 31, 2012 and the period February 9 to December 31, 2012, respectively. These amounts are primarily comprised of the fee commitments under the MSA. At December 31, 2012, our primary customer had a cumulative volume deficiency relative to its commitments that could result in a maximum $2.8 million of foregone processing value in excess of the committed fee stream in the next 12 months. We have received the funds associated with these volumes and deferred the recognition of $2.8 million of revenues until the customer either applies these deficiency volumes against future excess volumes or the 12-month carry forward period expires, whichever occurs first. The $2.8 million deferred revenue represents a cumulative amount for the period February 9 to December 31, 2012, and was recorded in the fourth quarter upon the finalization of our revenue recognition policy for Hythe/Steeprock. No carry-forward scenario will result in our receiving fees below the minimum committed fee stream.

Net Income before tax for the three months ended December 31, 2012 and the period February 9 to December 31, 2012 was $4.3 million and $23.3 million, respectively, before corporate financing costs, which are classified in the corporate segment of our business. Depreciation and accretion expense for the fourth quarter was $9.4 million which is in line with the third quarter.


Major Turnaround

In late May 2013, the Hythe plant is scheduled to have a major turnaround wherein we will inspect and perform maintenance on equipment. Portions of the facility are expected be out of service for up to 16 days. Planning the turnaround began shortly after we assumed operatorship of the facilities. Our objective is to plan and execute the turnaround in a manner that ensures safety of all stakeholders and mitigates risks and additional costs associated with extended facility down-time. To manage these risks, we have retained many of the staff who have participated in previous turnarounds at Hythe and Steeprock. The majority of the costs associated with the turnaround will be recoverable from our primary customer under the MSA.

Facility Debottleneck and Optimization

As operator of Hythe and Steeprock, we have identified a number of potential opportunities to increase production through the facilities. We continue to develop these projects and solicit interest from producers in the area, including current customers. We will be implementing key tie-ins for a Hythe debottleneck during the 2013 plant turnaround, which will eliminate the need for facility down-time if and when expansion projects are undertaken.

auxSable

Pursuant to a long-term NGL Sales Agreement with BP Products North America Inc., Aux Sable sells all production from its Channahon Facility to BP. In return, BP pays Aux Sable a fixed annual fee and a percentage share of net margins in excess of the fixed fee. The percentage share of net margins varies and depends upon specified thresholds being reached. In addition, BP compensates Aux Sable for all associated operating and maintenance costs, as well as growth and maintenance capital expenditures costs related to the Channahon Facility, subject to certain limits in the case of capitalized costs.

In late 2009 and in 2010, Aux Sable advanced its strategy of attracting new sources of liquids-rich natural gas for the Channahon Facility by acquiring the newly constructed Septimus Gas Plant, located in the Montney region of British Columbia, by constructing the Septimus Pipeline, and by acquiring an expansion to the Septimus Gas Plant that more than doubled its initial capacity to 60 mmcf/d. Aux Sable receives take-or-pay fees for both the plant and the pipeline under long-term contracts.

In addition to the Septimus projects, Aux Sable continues to focus on a number of initiatives to ensure the optimal level of rich gas is delivered into the Alliance pipeline for recovery of NGLs at the Channahon Facility. These activities have largely been focused on the Montney region in northwest Alberta and northeast British Columbia, and in the Bakken region in North Dakota and Saskatchewan. In July 2011, Aux Sable acquired the Palermo Conditioning Plant and the Prairie Rose Pipeline in the Bakken region of North Dakota. Aux Sable earns processing and pipeline transportation fees from these assets, and retains a margin on the NGLs recovered. The acquisition represented a significant step forward in Aux Sable’s pursuit of its strategic growth objectives in the Bakken, which include owning key infrastructure assets that will lead to increased deliveries of liquids-rich natural gas to the Channahon Facility. Aux Sable is also expanding its rail off-load capacity at the Channahon Facility in order to provide fractionation services for U.S. shale gas producers.

Aux Sable has also entered the off-gas processing business. In 2010, Aux Sable entered into a long-term off-gas processing agreement with a third party to secure a feedstock source for its Heartland off-gas facility, located in Fort Saskatchewan, Alberta. Heartland commenced commercial operations in September 2011 and is capable of processing up to 20 mmcf/d of off-gas, producing hydrogen, ethane and a propane-plus mix. All of the products from the facility are sold to the contract counterparty under the long-term agreement.

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NGlMarketoverview

Although the NGL market environment was strong in the first quarter of 2012, conditions turned downward in the second quarter and remained weak for the remainder of the year.

Average WTI crude oil prices decreased by US$5.57 per barrel to US$88.18 per bbl in the fourth quarter, a 6% decrease relative to the same period last year, while the annual average of US$94.25 per bbl increased by 1% relative to last year. Natural gas prices in the US Gulf Coast increased by US$0.08 per thousand British thermal units to US$3.39 for the fourth quarter, and annual prices decreased by US$1.24 per mmbtu to US$2.75 per mmbtu, a 2% increase and 31% decrease, respectively, from the same periods last year.

In spite of the significant year-over-year decline in natural gas prices and the resultant increase in the crude oil to natural gas ratio, realized fractionation margins for the fourth quarter and year were significantly lower than the record levels achieved during the same periods last year. US Gulf Coast ethane margins decreased to US$0.06 per gallon and US$0.21 per gallon for the fourth quarter and year, respectively, a 91% and 58% decrease compared to the same periods last year. Ethane prices at Conway, where a significant portion of Aux Sable’s ethane sales are benchmarked, were lower than at Mt. Belvieu due to continued oversupply of ethane in the region. These economic conditions resulted in Aux Sable reinjecting ethane for a significant period in 2012.

US Gulf Coast propane plus margins were US$0.90 per gallon and US$1.03 per gallon, respectively, a 34% and 20% decrease compared to the same periods last year. Continued high inventory levels of propane, driven by unseasonably warm weather this past winter, led to a decrease in propane values in the fourth quarter and year compared to the same periods last year.


During the year ended December 31, 2012, Aux Sable processed 97% of the natural gas delivered by Alliance, a slight decrease compared to 98% for the previous year.

Receipts into the Prairie Rose Pipeline in North Dakota averaged 102.1 mmcf/d and 84.8 mmcf/d during the fourth quarter and year, respectively, compared to 57.7 mmcf/d and 50.7 mmcf/d, respectively, for the same periods last year. The average heat content of the natural gas delivered to the Alliance interconnection at Bantry, North Dakota for 2012 is approximately 1,353 btu/ft3, indicative of the high heat content of the liquids-rich natural gas stream being delivered out of the Bakken. In comparison, the heat content of the western Canada natural gas delivered on the Alliance system averages approximately 1,102 btu/ft3.

Aux Sable sold 72.1 mbbls/d and 72.2 mbbls/d of NGLs during the fourth quarter and year, respectively, compared to 87.2 mbbls/d and 77.0 mbbls/d for the same periods last year. Average ethane volumes decreased to 22.3 mbbls/d and 34.3 mbbls/d, respectively, from 47.5 mbbls/d and 43.2 mbbls/d for the fourth quarter and year, respectively. The decreased ethane sales volumes are attributable to reinjection due to uneconomic margins in 2012.

Propane plus sales volumes were 49.8 mbbls/d and 37.9 mbbls/d for the fourth quarter and year, respectively, up compared to 39.7 mbbls/d and 33.8 mbbls/d for the same periods last year due to increased production and heat content from the Bakken area in North Dakota and from western Canada.

financialHighlights

For the three and 12 months ended December 31, 2012, we recorded $16.0 million and $53.4 million of equity income from Aux Sable, respectively, a $16.7 million and $36.8 million decrease compared to the same periods last year.

For the three and 12 months ended December 31, 2012, EBITDA, included in Aux Sable equity income, was $19.0 million and $64.6 million respectively, a $16.3 million and $34.3 million decrease compared to the same periods last year. EBITDA is comprised of (i) fixed fees from activities that are not subject to long-term volume or commodity risk, (ii) operating margins from margin-based activities that are subject to long-term volume or commodity risk, and is reduced by (iii) non-recoverable operations, maintenance and administrative costs. For the three and 12 months ended December 31, 2012, fixed fees increased by $0.5 million and $13.4 million, respectively, to $8.8 million and $34.0 million, primarily due to arrangements with minimum volume thresholds at the Palermo Conditioning Plant and Prairie Rose Pipeline. Increased fixed fees were more than offset by a $17.4 million and $39.8 million decrease in operating margins from Aux Sable’s margin-based activities, which amounted to $14.4 million and $49.3 million, driven by the weak margin environment described above. Non-recoverable costs for the three-month period approximated amounts incurred last year, but increased by $7.9 million to $18.7 million for the 12-month period, reflecting a full year of North Dakota operations and administration.

For the three and 12 months ended December 31, 2012, Aux Sable generated $9.8 million and $40.7 million of margin-based lease revenues, respectively. Including amounts generated but not recognized in the first nine months of 2012, Aux Sable recognized $11.7 million and $40.7 million in EBITDA for the three and 12 months, respectively. In comparison, Aux Sable generated and recognized record levels of margin-based lease revenues in the same periods last year, amounting to $30.6 million and $92.6 million, respectively.

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Aux Sable continues to successfully advance its rich gas inducement strategy by entering into multi-year extraction rights agreements, which offer competitive NGL recovery options to producers who utilize the Alliance pipeline for delivery of liquids-rich natural gas to Aux Sable’s Channahon facility.

In July 2012, Aux Sable entered into a ten-year extraction rights agreement with a producer in northwestern Alberta. The rich gas stream is expected to originate from the producer’s Duvernay and Montney development areas, and to be delivered to Aux Sable’s Channahon Facility for processing via the Alliance pipeline commencing in the second quarter of 2013. In February 2013, Aux Sable announced it had entered into additional extraction rights agreements with Canadian producers.

In February 2013, Aux Sable announced it had entered into additional extraction rights agreements with Canadian producers. We expect these agreements to result in the transportation of approximately 450 mmcf/d of natural gas on the Alliance pipeline beyond 2015.

PowERbuSINESS


Gas-Fired/ Gas-Fired/ District Power- District Power-($ Millions, except where noted) Total Energy Renewables Corporate Total Energy (2) Renewables (3) Corporate

ProportionatelyConsolidated (1) EbITDa 17.6 17.1 4.9 (4.4) 8.1 8.4 3.4 (3.7)

Depreciation & amortization (11.7) (8.5) (3.1) (0.1) (9.0) (6.1) (2.7) (0.2)

Interest, net (7.2) (5.5) (1.7) – (3.6) (2.7) (1.3) 0.4

Fair value gain (loss) 1.9 1.9 – – (4.7) (4.7) – –Foreign exchange and other 0.1 – 0.1 – – – – –

Netincome(loss)beforetaxesandnon-controllinginterest 0.7 5.0 0.2 (4.5) (9.2) (5.1) (0.6) (3.5)

Volumes(Gwh) Gross 221.9 100.7 121.2 – 255.8 138.6 117.2 –Net 192.0 93.0 99.0 – 216.5 122.6 93.9 –


Gas-Fired/ Gas-Fired/ District Power- District Power-($ Millions, except where noted) Total Energy Renewables Corporate Total Energy (2) Renewables (3) Corporate

ProportionatelyConsolidated (1) EbITDa 65.5 60.6 18.4 (13.5) 48.3 43.1 18.1 (12.9)

Depreciation & amortization (43.3) (30.5) (12.3) (0.5) (35.3) (24.3) (10.3) (0.7)

Interest, net (23.4) (17.5) (6.7) 0.8 (15.2) (10.6) (5.0) 0.4

Fair value gain (loss) 0.2 0.2 – – (21.7) (21.7) – –Foreign exchange and other – – – – (0.1) – – (0.1)

Netincome(loss)beforetaxesandnon-controllinginterest (1.0) 12.8 (0.6) (13.2) (24.0) (13.5) 2.8 (13.3)

Volumes(Gwh) Gross 1,041.9 563.4 478.5 – 1,015.7 526.5 489.2 –Net 925.9 528.9 397.0 – 871.1 466.3 404.8 –

(1) Our jointly-controlled power businesses (York Energy Centre, NRGreen, and Grand Valley) are presented in the above results on a proportionately consolidated basis, which does not conform to US GAAP. A reconciliation to US GAAP is provided in the “Non-GAAP Financial Measures” section of this MD&A.

(2) Includes 100 percent of East Windsor Cogeneration; the offsetting 25 percent, related to the portion not owned by us in 2011, is reflected in non-controlling interest.(3) Includes 100 percent of EnPower; the offsetting 25 percent, related to the portion not owned by us in 2011, is reflected in non-controlling interest.

Our power business is comprised of gas-fired generation, renewable power generation, and district energy facilities in North America. Consistent with our overall corporate strategy, we focus on assets that have long-term sales contracts, capacity-based cash flows, limited volume risk and commodity exposure, and creditworthy counterparties. This focus provides for predictable, stable cash flows based primarily on the availability of the facilities rather than short-term electricity demand and prices.

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Gas-firedandDistrictEnergyfacilities

Each of our gas-fired generation facilities in Ontario, Colorado and California sells capacity and electricity pursuant to long-term power purchase agreements with investment-grade counterparties. The power purchase agreements are structured to pay the facilities contracted rates for having capacity available and for the recovery of fuel costs. As a result, earnings and cash flows from the gas-fired facilities are realized primarily by capacity payments and are not significantly impacted by the volume of electricity produced or by commodity price fluctuations. In addition to capacity payments, the majority of these facilities have the opportunity to earn energy margins.

Our district energy systems in Ontario and Prince Edward Island consist of central production plants which convert fuel (such as natural gas, municipal waste, biomass and fuel oil) into steam, hot water and/or chilled water. These products are distributed through underground pipes to customers’ buildings to provide heating, air conditioning and some industrial process uses.

Renewables

wasteHeatfacilities

Our waste heat facilities in Saskatchewan and British Columbia use Energy Recovery Generation (ERG®) technology and waste heat generated by Alliance and Spectra pipeline compressor stations, respectively. Electricity generated is sold to Saskatchewan Power Corporation and to BC Hydro under long-term power purchase agreements.

NRGreen, in which we hold a 50 percent ownership interest, is constructing a 13-MW waste heat power generation facility at Alliance’s Windfall compressor station in Alberta. NRGreen was awarded a $3.5 million (100 percent – $7 million) grant by the Climate Change and Emissions Management Corporation under the Alberta Energy Efficiency Projects grant program to assist in the construction of this project. Construction of the facility is progressing and is expected to be completed in the third quarter of 2013, when it will sell power under a long-term agreement.

Run-of-Riverfacilities

We own three run-of-river hydroelectric facilities in British Columbia with an aggregate 33 MW of generation capacity. These facilities sell electricity to BC Hydro under long-term electricity purchase agreements. We are paid for the volume of electricity actually delivered based on fixed, inflation-escalated prices.

Our portfolio of run-of-river facilities also includes the 33-MW Glen Park facility, located in upstate New York. Glen Park sells all of its output at prevailing market terms on a month-to-month basis.

We are constructing the Dasque-Middle run-of-river hydro facility, a 20-MW project located in northwest British Columbia. The project experienced delays in 2012 due to challenges in progressing the civil works. Dasque-Middle has contracted to sell its output to BC Hydro under a long-term electricity purchase agreement.

windPowerfacilities

In March 2012, we completed construction of the first two phases of the Ontario-based Grand Valley wind project, in which we hold a 75 percent ownership interest. Grand Valley sells its output to the Ontario Power Authority under long-term contracts.

Development Projects

We are continuing to advance the growth of our renewable power business through the development of three wind projects, Grand Valley Phase III (40 MW; 75% interest) and St. Columban I and II (18 MW and 15 MW, respectively; 90% interest), each of which were awarded contracts under the Ontario Feed-in Tariff program in 2011, and Culliton Creek, a 15-MW run-of-river development project in British Columbia that holds a long-term electricity power agreement with BC Hydro. Each project achieved development milestones, including completion of system impact assessment studies required for interconnection, in 2012. Upon receipt of the respective regulatory approvals, anticipated in 2013, we will make final investment decisions regarding each project.


On May 9, 2012, York Energy Centre, a 400-MW gas-fired generation facility in Ontario in which we hold a 50% ownership interest, was placed into commercial service. Construction of York Energy Centre, which started in September 2010 with an aggregate budgeted capital cost of $338 million (100%), was completed on schedule and within budget. York Energy Centre is a peaking generation facility with a 20-year power purchase contract with the OPA. Operations are running well, with 61,579 MWh of electricity having been generated from May 9 to December 31, 2012.

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Operational performance from our gas-fired and district energy systems during 2012 generally met our expectations. Our Ontario gas-fired facilities performed well in response to robust energy demand, particularly during the third quarter. Our San Gabriel gas-fired facility experienced a brief unplanned outage in late May, which resulted in increased maintenance expenditures.

With respect to our renewable power facilities, no significant operational issues were experienced during 2012. The first two phases of our Grand Valley wind farm successfully commenced operations on March 24, 2012. Power production from Glen Park and our waste heat facilities were negatively impacted by reduced water flows and host compressor unit maintenance, respectively.

financialHighlights

For the three and 12 months ended December 31, 2012, EBITDA from our Power business, as determined on a proportionately consolidated basis, was $17.6 million and $65.5 million, respectively, a $9.5 million and $17.2 million increase compared to the same periods last year. Our gas-fired and district energy systems generated $8.7 million and $17.5 million of the increase, respectively, due to a $6.0 million and $14.8 million contribution from York Energy Centre, higher energy margins earned by East Windsor due to strong market demand, particularly in the third quarter, and $2.0 million of insurance proceeds at San Gabriel recorded in the fourth quarter. EBITDA from our renewable power facilities increased by $1.5 million and $0.3 million for the three and 12-month periods, respectively, due to a $1.3 million and $3.1 million contribution from Grand Valley and higher water flows at our B.C. run-of-river facilities, partially offset by lower water flows and continued weak energy prices at Glen Park and maintenance at the host compressor units of our waste heat facilities. Power-Corporate costs for 2012 were partially offset by a $3.0 million completion bonus, which we received in the second quarter of 2012 due to the successful commissioning of York Energy Centre within schedule and under budget.

Net income (loss) before taxes and non-controlling interest was $0.7 million and ($1.0) million for the three and 12 months ended December 31, 2012, respectively, compared to a net loss of $9.2 million and $24.0 million for the same periods last year. Excluding the effect of fair value gains and losses related to York Energy Centre’s interest rate hedges, net loss before tax and non-controlling interest was $1.2 million for each of the three and 12 months ended December 31, 2012, respectively, a $3.3 million and $1.1 million decrease compared to the same periods last year. The increases in EBITDA, discussed above, were offset by higher depreciation and interest associated with York Energy Centre and Grand Valley.

VERESEN–CoRPoRaTE


($ Millions) 2012 2011 2012 2011

Equity loss 0.9 0.5 1.9 1.3

General & administrative Recurring 5.5 6.4 22.8 21.9

Non-recurring 0.5 0.2 4.8 1.7

Project development 5.0 2.9 17.0 8.3

Depreciation & amortization 0.5 0.5 2.2 2.1

Interest 10.2 5.7 39.3 25.6

Foreign exchange & other (0.2) 0.1 0.9 1.5

Netexpensesbeforetaxes 22.4 16.3 88.9 62.4

Current tax expense 6.0 8.3 18.2 28.1

Future tax expense 0.9 7.5 10.6 15.1

Netexpenses 29.3 32.1 117.7 105.6

For the three and 12 months ended December 31, 2012, we incurred $22.4 million and $88.9 million, respectively, of corporate net expenses before taxes, a $6.1 million and $26.5 million increase compared to the same periods last year. The increase reflects higher interest costs, primarily related to financing the Hythe/Steeprock acquisition; higher project development spending related to our Jordan Cove LNG project; and higher non-recurring general and administrative costs, primarily comprised of integration costs which, in 2012, relate to the Hythe/Steeprock acquisition, and, in 2011, relate to the Pristine acquisition. Fourth quarter recurring G&A costs decreased by $0.9 million primarily due to the downward revaluation of our long-term incentive plan, which is valued relative to our share price. For the 12-month period, this dynamic was partially offset by costs incurred to support our growing business, resulting in an overall $0.9 million increase in recurring G&A. Taxes have decreased for the three and 12 month periods relative to the same periods last year due to the decrease in earnings.

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liquidityandCapitalResources

Year ended December 31,

($ Millions, except where noted) 2012 2011

Cash flows Operating activities 179.9 191.4 Investing activities (1,080.7) (283.5) Financing activities 894.7 84.9

Cash and short-term investments 16.1 21.9

Capitalization Senior debt (1) 1,259.3 46% 765.6 42%

Subordinated convertible debentures 86.2 3% 86.2 5%

Other long-term liabilities 46.2 2% 35.0 2%

Shareholders’ equity 1,359.8 49% 938.8 51%

2,751.5 100% 1,825.6 100%

(1) Includes current portion.

Overall, there has not been any significant change in our financial condition or that of our businesses compared with the positions as at December 31, 2011. We expect to continue to utilize cash from operations, drawings on our Revolving Credit Facility, and cash raised through our DRIP to fund liabilities as they become due, finance capital expenditures, fund debt repayments and pay dividends. At December 31, 2012, we had $595 million of committed credit facilities of which $243 million was drawn, including $21 million in letters of credit. Inclusive of unrestricted cash and cash equivalents of $16.1 million, we had net available liquidity at December 31, 2012 of $368.1 million. We expect liquidity available in our credit facilities, together with cash from operations and anticipated future access to capital markets, to be sufficient to finance current capital projects and to provide flexibility for new investment opportunities.

On December 19, 2012, we amended the terms of our Revolving Credit Facility to extend the term by one year such that it now matures on December 13, 2016. The Revolving Credit Facility agreement includes standard default and covenant provisions whereby accelerated repayment may be required if we were to default on payment or violate certain covenants. As in prior years, we expect to continue to comply with these provisions and therefore not trigger any early repayments. As at December 31, 2012, we were in compliance with these covenants.

We continue to manage our debt to capitalization ratio to maintain a strong balance sheet. Our debt to capitalization ratio at December 31, 2012, including amounts due within one year, was 46%, compared with 42% at December 31, 2011.

At December 31, 2012, we had working capital of $57.9 million, compared to $131.2 million at December 31, 2011. Our working capital at December 31, 2011 included a $50 million deposit relating to the Hythe/Steeprock acquisition. Upon closing the acquisition, this deposit was applied to the net assets acquired, which were primarily comprised of long-lived assets. We believe our working capital position remains strong and enhances our overall liquidity.

As at December 31, 2012, we had capacity of $451 million under our debt and equity short form base shelf prospectus dated August 22, 2011, which expires in September 2013.

CaSHfRoMoPERaTINGaCTIVITIES


($ Millions) 2012 2011 2012 2011

Pipeline 35.6 32.9 148.1 157.9

Midstream 32.8 32.4 103.3 88.2

Power 6.9 4.6 14.5 13.8


65.1 59.9 179.9 191.4

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For the three and 12 months ended December 31, 2012, cash generated from operating activities was $65.1 million and $179.9 million, respectively, compared to $59.9 million and $191.4 million for the same periods last year, reflecting:

• lower distributions received from Alliance;

• new cash flows from Hythe/Steeprock, partially offset by lower distributions received from Aux Sable;

• higher cash flows from our Power business due to distributions received from York Energy Centre; and

• corporate cash outflows that approximated outflows for the same three-month period last year and were higher compared to the same 12-month period last year due to increased administrative, project development, and interest costs.

INVESTINGaCTIVITIES

For the year ended December 31, 2012, we used $1,080.7 million of cash to fund our investing activities compared to $283.5 million last year. Significant investing activities for the year ended December 31, 2012 included:

• $865.5 million related to the Hythe/Steeprock acquisition;

• $25.0 million related to the acquisition of the remaining 25% interests in East Windsor Cogeneration and EnPower;

• $106.0 million in equity contributions to our jointly-controlled businesses, partially offset by $8.5 million in returns of capital; and

• $91.5 million of capital expenditures, primarily related to an extension of AEGS ($11.1 million), our midstream business ($11.3 million), construction of the Dasque-Middle run-of-river hydro facility ($38.2 million), our operating power facilities ($10.3 million), and the acquisition of land in relation to the Jordan Cove LNG project ($19.8 million).

Significant investing activities for 2011 included:

• $94.6 million primarily related to the acquisition of the Furry Creek and Clowhom run-of-river hydro facilities;

• $50.0 million paid as a deposit on the Hythe/Steeprock acquisition;

• $125.2 million in equity contributions to our jointly-controlled businesses; and

• $18.5 million in capital expenditures.

fINaNCINGaCTIVITIES

For the year ended December 31, 2012, cash provided by financing activities was $894.7 million compared to $84.9 million for the same period last year. Financing activities for the year ended December 31, 2012 were primarily related to the Hythe/Steeprock acquisition and are more fully described below:

• $348.6 million from our December 2011 subscription receipts offering, released from escrow in February 2012;

• $249.1 million of short-term debt borrowed, net of issue costs, and $250.0 million repaid;

• $347.8 million from our March 2012 medium term note offerings, net of issue costs; and

• $193.7 million from our February 2012 Series A Preferred Share offering, net of issue costs.

Other significant financing activities included:

• $11.2 million of senior debt repayments;

• $154.2 million of net draws from our Revolving Credit Facility;

• $104.2 million of Common Share dividend payments;

• $7.7 million of Preferred Share dividend payments; and

• $20.5 million advanced to our jointly-controlled businesses.

Significant financing activities for 2011 included:

• $348.6 million issuance of subscription receipts;

• $348.6 million proceeds from the issuance of subscription receipts held in escrow;

• $202.3 million of senior debt issued, net of issue costs;

• $57.2 million of senior debt repayments;

• $32.4 million of net draws from our Revolving Credit Facility;

• $53.3 million of Common Share dividend payments; and

• $25.5 million advanced to our jointly-controlled businesses.

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2012Debtfinancingactivities

VeresenCorporate

On February 9, 2012, we drew upon a $250 million non-revolving, floating-rate term loan (“New Credit Facility”) to fund a portion of the Hythe/Steeprock acquisition. Terms of the New Credit Facility provided for prepayments at our option at any time without premium or penalty.

On March 14, 2012, we issued $300 million of senior unsecured medium term notes at a fixed interest rate of 3.95% per annum, payable semi-annually in arrears and maturing on March 14, 2017, and $50 million senior unsecured notes at a fixed interest rate 5.05% per annum, payable semi-annually in arrears and maturing on March 14, 2022. We used proceeds from these offerings to retire the New Credit Facility in its entirety.

The medium term notes were issued under our shelf prospectus, a prospectus supplement dated November 4, 2011, and applicable pricing supplements dated March 8, 2012.

2012Equityfinancingactivities

On February 14, 2012, we issued 8.0 million Cumulative Redeemable Preferred Shares, Series A at a price of $25 per Series A Preferred Share. The holders of Series A Preferred Shares are entitled to receive fixed cumulative preferential cash dividends at an annual rate of 4.4%, payable quarterly for an initial period up to but excluding September 30, 2017. 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 us, at our 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 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%.

The Series A Preferred Shares were issued under our shelf prospectus, and a prospectus supplement dated February 7, 2012.

CreditRatings

Maintaining strong and stable ratings is a key aspect of our financing strategy, which provides for long-term access to the capital markets on attractive terms and conditions. Our current ratings are set out below.

DBRS S&P

Senior debt ratings BBB (high) BBBMedium term notes BBB (high) BBBSeries A Preferred Shares P3 (high) P3

The credit ratings represent long-term investment grade credit ratings in respect of our senior unsecured debt.

Dividends

Policy

Our general dividend policy is to establish and maintain a sustainable and stable monthly dividend, having regard for forecast distributable cash and our growth capital requirements.

We pay dividends on a monthly basis to common shareholders of record as at the last business day of each month on the 23rd day of the month following such record date, or if not a business day, then on the preceding business day.

The holders of Series A Preferred Shares are entitled to receive fixed cumulative preferential cash dividends at an annual rate of 4.4%, payable quarterly. The dividend rate will reset on September 30, 2017 and every five years thereafter based on then-market rates.

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SustainabilityofDividendsandProductiveCapacity

We intend to continue to pay dividends, although such dividends are not guaranteed and do not represent a legal obligation. The sustainability of such dividends is a function of several factors including, among other things:

• earnings and cash flows we generate;

• ongoing maintenance of each business’s physical and economic productive capacity;

• our ability to comply with debt covenants and refinance debt as it comes due; and

• our ability to satisfy any applicable legal requirements.

For a complete discussion of the significant risks and uncertainties affecting us, see the “Risks” section contained elsewhere in this MD&A.

DividendsPaid

For the year ended December 31, 2012 we declared dividends of $193.5 million (2011 – $163.0 million), of which $114.3 million (2011 – $51.6 million) was paid to common shareholders in cash and $79.2 million (2011 – $111.4 million) was paid in Common Shares issued under our DRIP.

RestrictionsonDividends

Our ability to pay dividends to common shareholders is dependent on the applicable terms of certain financing and security agreements. On December 31, 2012 no Event of Default under any of these arrangements had occurred or was continuing that would restrict dividends being paid.

Our Revolving Credit Facility restricts us from paying dividends to shareholders when an Event of Default has occurred or is continuing.

Our investments in our operating businesses have been made through debt and equity investments in subsidiary partnerships and corporations. In general, other than covenant restrictions contained in applicable debt arrangements, there are no legal or practical restrictions on such subsidiary partnerships or corporations from transferring funds received from the operating businesses to us except that the subsidiary corporations must meet liquidity and solvency tests under applicable corporate law.

DIVIDENDSPaID/PayablERElaTIVEToCaSHfRoMoPERaTINGaCTIVITIESaNDNETINCoMEaTTRIbuTablEToCoMMoNSHaRES


($ Millions) 2012 2011 2012 2011

Cash from operating activities 65.1 59.9 179.9 191.4

Net income attributable to Common Shares 12.0 14.4 38.9 53.1

Dividends paid/payable 49.4 41.5 193.5 163.0

Less dividends paid in Common Shares under DRIP (10.6) (19.3) (79.2) (111.4)

Net dividends paid/payable 38.8 22.2 114.3 51.6

Excess of cash from operating activities over net dividends paid/payable 26.3 37.7 65.6 139.8

Excess (deficiency) of net income attributable to Common Shares over net dividends paid/payable (26.8) (7.8) (75.4) 1.5

The excess of cash from operating activities over net dividends paid/payable generally represents the cash we use for maintenance capital expenditures, scheduled amortization of any long-term debt, payment of Preferred Share dividends, and cash we retain to fund growth.

Net income attributable to Common Shares is generally less than dividends paid/payable as our net income includes certain non-cash expenses such as depreciation and deferred income taxes, and can include unrealized foreign exchange and fair value losses which are not reflected in calculating the amount of cash available for the payment of dividends. As a result of high participation rates under our DRIP, net income attributable to Common Shares approximated net dividends paid/payable for the three and 12 months ended December 31, 2011. In May 2012, we suspended the Premium DividendTM component of our DRIP (trademark of Canaccord Genuity Corp.), resulting in a lower participation rate for the three and 12 months ended December 31, 2012.

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DistributableCash

The amount of distributable cash we earn is comprised of and will vary depending on:

• distributions received/receivable from our jointly-controlled businesses and cash flows from our wholly-owned and majority-controlled businesses, which, in each case, are after providing for scheduled amortization of long-term debt and capital expenditures that are not growth-oriented or recoverable;

• operating support payments required by each of our businesses;

• cash taxes and financing costs we incur, including scheduled principal repayments on long-term debt;

• our general and administrative costs; and

• cash we hold in reserve.

The calculation of distributable cash for the three and 12 months ended December 31, 2012 and 2011 is set out below.

DISTRIbuTablECaSH


($ Millions, except where noted) 2012 2011 2012 2011

Alliance distributions, prior to withholdings for capital expenditures and net of debt service 32.5 33.5 130.7 135.2

AEGS distributable cash, after non-recoverable capital expenditures and debt service 4.7 3.9 16.8 15.8

Hythe/Steeprock distributable cash, after non-recoverable maintenance capital expenditures 16.5 – 60.3 –Aux Sable distributions, net of support payments, non-recoverable maintenance capital expenditures and debt service 19.8 34.6 64.0 94.2

Power distributable cash, after maintenance capital expenditures and debt service 4.0 1.4 27.1 25.8

77.5 73.4 298.9 271.0

Corporate General and administrative (5.9) (6.4) (27.3) (23.5)

Interest and other finance (9.7) (5.5) (37.1) (24.4)

Principal repayments on senior debt – – – (1.5)

(15.6) (11.9) (64.4) (49.4)

Taxes (3.2) (8.3) (15.4) (28.6)

Preferred Share dividends (2.2) – (7.7) –

(21.0) (20.2) (87.5) (78.0)

Distributable cash (1) 56.5 53.2 211.4 193.0

Distributable cash per Common Share ($) (2) 0.29 0.32 1.09 1.18

Dividends paid/payable (3) 49.4 41.5 193.5 163.0

Dividends paid/payable per Common Share ($) 0.25 0.25 1.00 1.00

(1) See “Non-GAAP Financial Measures” for reconciliation of distributable cash to cash flows from operating activities.(2) The number of Common Shares used to calculate distributable cash per Common Share is based on the average number of Common Shares outstanding at each record

date. For the three months ended December 31, 2012 the average number of Common Shares outstanding for this calculation was 197,493,139 (2011 – 166,305,542) and 203,399,647 (2011 – 172,212,734) on a basic and diluted basis, respectively. For the year ended December 31, 2012, the average number of Common Shares outstanding for this calculation was 193,559,607 (2011 – 163,119,400) and 199,466,172 (2011 – 169,026,820) on a basic and diluted basis, respectively. The number of Common Shares outstanding would increase by 5,906,508 (2011 – 5,907,192) Common Shares if the outstanding Convertible Debentures on December 31, 2012 were converted into Common Shares.

(3) Includes $10.6 million and $79.2 million of dividends for the three and 12 months ended December 31, 2012 (2011 – $19.3 million and $111.4 million, respectively) satisfied through the issuance of Common Shares under our DRIP.

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Distributable cash for the three and 12 months ended December 31, 2012 was $56.5 million and $211.4 million, respectively, compared to $53.2 million and $193.0 million for the same periods last year, reflecting increased cash flows from acquisitions in our Midstream business and recently commissioned power facilities, partially offset by a significant decrease in margin-based earnings from Aux Sable, lower contributions from Alliance, and higher corporate costs. On a per Common Share basis, distributable cash was $0.29 and $1.09 for the three and 12 months ended December 31, 2012, a $0.03 and $0.09 decrease relative to the same periods last year, reflecting a higher number of Common Shares outstanding in the current year.

Our newly acquired Hythe/Steeprock complex generated $16.5 million and $60.3 million of distributable cash for the fourth quarter of 2012 and for the period February 9 to December 31, 2012, respectively. Distributable cash from Hythe/Steeprock is primarily comprised of the minimum volume and fee commitment generated under the MSA, including fee commitments in respect of the reporting period where the recognition in earnings has been deferred for up to 12 months but where payment has been received. Interest costs associated with the Hythe/Steeprock acquisition are included in the corporate segment.

Aux Sable distributed $19.8 million and $64.0 million to us in the three and 12 months ended December 31, 2012, a $14.8 million and $30.2 million decrease compared to the same periods last year. The decreased distributions primarily resulted from lower realized fractionation margins in comparison to record-level margins realized in the same periods last year. The decrease in margin-based cash flows was partially offset by incremental fixed fee cash flows generated from Aux Sable’s processing and transportation assets in Alberta and in the Bakken region of North Dakota.

Power distributable cash for the three and 12 months ended December 31, 2012 was $4.0 million and $27.1 million, respectively, a $2.6 million and $1.3 million increase compared to the same periods last year. The increase reflects a $1.2 million and $3.5 million increase from our gas-fired and district energy systems for the three and 12-month periods, respectively, a $0.9 million increase and a $2.5 million decrease from our renewable facilities, and a $0.5 million and $0.2 million decrease in Power-Corporate costs. Within our gas-fired and district energy systems portfolio, York Energy Centre distributed $1.8 million and $5.8 million for the three and 12-month periods, respectively. Distributable cash from the remainder of our gas-fired and district energy systems was lower than amounts generated in the same periods last year as increased debt service and maintenance capital expenditures offset higher EBITDA. Within our renewable power portfolio, Grand Valley wind farm, which was placed into service at the end of the first quarter of 2012, contributed $0.9 million and $1.7 million of distributable cash for the three and 12-month periods. These amounts, as well as higher distributable cash from our B.C. run-of-river facilities, were offset by reduced EBITDA from Glen Park, particularly for the 12-month period.

Distributions from Alliance for the three and 12 months ended December 31, 2012 were $32.5 million and $130.7 million, respectively, a $1.0 million and $4.5 million decrease compared to amounts distributed in the same periods last year. The decrease reflects a lower return on equity due to the ongoing depreciation of Alliance’s investment base. The year-over-year decrease further reflects the impact of additional amounts being distributed in the first quarter of 2011 arising from the minor realignment of Alliance U.S.’s capitalization.

Distributable cash from AEGS was $4.7 million and $16.8 million for the three and 12 months ended December 31, 2012, respectively, a $0.8 million and $1.0 million increase compared to the same periods last year, reflecting higher EBITDA.

Corporate costs for the three and 12 months ended December 31, 2012 were $15.6 million and $64.4 million, a $3.7 million and $15.0 million increase from the same periods last year. Recurring administrative costs for the fourth quarter were $0.9 million lower in comparison to the same period last year, and for the year ended December 31, 2012 were approximately $0.9 million higher than the prior year, reflecting increased costs incurred to support our growing businesses, offset by the downward revaluation of our long-term incentive plan. Non-recurring administrative costs, primarily comprised of costs incurred to integrate the Hythe/Steeprock acquisition in 2012 and the Pristine acquisition in 2011, were $0.3 million and $2.9 million higher for each of the three and 12 months ended December 31, 2012, respectively, compared to the same periods last year. Debt service costs increased by $4.2 million and $12.7 million, respectively, as a result of debt issuances in the first quarter of 2012 to fund the Hythe/Steeprock acquisition.

Cash taxes for the three and 12 months ended December 31, 2012 were $3.2 million and $15.4 million, respectively, a $5.1 million and $13.2 million decrease compared to the same periods last year. The decrease results from reduced midstream earnings from Aux Sable due to lower NGL margins in the United States.

Distributable cash for the three and 12 months ended December 31, 2012 was further reduced by $2.2 million and $7.7 million of Preferred Share dividends. The Preferred Shares were issued on February 14, 2012 to fund the Hythe/Steeprock acquisition.

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ContractualobligationsandCommitments

Certain of our gas-fired power generation facilities have entered into agreements with natural gas suppliers to purchase, in aggregate, a minimum of approximately 15.3 million cubic feet per day, at an estimated cost of approximately $13.3 million in 2013 and $8.7 million in 2014. Veresen has guaranteed some of these obligations.

On April 20, 2012, we, through a wholly-owned subsidiary, entered into a $36.3 million construction contract relating to two hydroelectric run-of-river facilities, Dasque Creek (12 MW) and Middle Creek (8 MW), and a 69 kilovolt transmission line. As at December 31, 2012, there was $23.2 million outstanding on this contract. In addition, we entered into, through the same subsidiary, $18.9 million contracts related to installation of turbines and electrical transmission lines, of which $7.4 million was outstanding at December 31, 2012.

Payments due for contractual obligations in each of the next five years and thereafter are as follows:

Payments due by period

($ Millions) Total Less than 1 year 1 – 3 years 4 – 5 years After 5 years

Senior debt 1,259.3 11.7 447.7 373.1 426.8

Subordinated convertible debentures 86.2 – – 86.2 –Operating leases 52.3 6.9 11.1 8.8 25.5

Other long-term obligations 41.7 0.2 7.4 – 34.1

1,439.5 18.8 466.2 468.1 486.4

Risks

In the course of operating our businesses, we are subject to various risks and uncertainties, which can affect our financial condition and operating results. Our objective is to manage these risks and uncertainties in a balanced manner with a view to mitigate risk while maximizing total shareholder returns. It is senior management’s and the applicable business functional head’s responsibility to identify and to effectively manage the risks of each business. This includes developing risk management strategies, policies, processes and systems. The approach taken by each business will not necessarily identify and eliminate all risks. Further, the risk-mitigating strategies adopted and actions taken may not be successful. In some circumstances, we may choose to reduce our financial risk through specific insurance or hedging programs where the cost is considered reasonable in relation to the associated risks and rewards. In other circumstances, the appropriate risk management strategy may be more fundamental or strategic in nature, based on longer-term considerations. Some risks and uncertainties are market-related systemic risks, while others are either common to all of our businesses or unique to our pipeline, midstream or power businesses. The more significant business risks and uncertainties affecting our businesses are set out below.

MaRKETPRICINGRISKS

CommodityPrice

Our earnings and cash flows are subject to movements in certain commodity prices. Our most significant commodity price exposures are in Aux Sable’s midstream business where NGL margins are driven primarily by the relationship between the price of natural gas and the prices of ethane, propane, butane and condensate. Natural gas is the largest cost component of producing specification NGL products. The prices of ethane, propane, butane and condensate are impacted by a variety of factors, including supply and demand for these products, and the price of crude oil. The long-term NGL Sales Agreement is with an international, integrated energy company, which mitigates the downside risk of low NGL prices while retaining significant upside when NGL margins are favourable.

We are also exposed to movements in energy costs at some of our power facilities where the cost of fuel is not fully recoverable. A significant portion of earnings from our power business is comprised of fixed capacity payments and, as such, these earnings are not significantly influenced by variability in the commodity price of electricity or natural gas.

To further reduce our exposure to commodity price movements, we may occasionally use derivative instruments, including swaps, futures, and options, to hedge such exposures. These activities are subject to senior management or risk committee oversight as well as specific risk management policies and controls. To the extent these contractual arrangements qualify for hedge accounting treatment, any such gains or losses are recorded in other comprehensive income.

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Capitalfundingandliquidity

To fund our existing businesses and future growth, we rely on cash flows generated by our businesses and on the availability of debt and equity from banks and the capital markets. Conditions within these markets can change dramatically, affecting both the availability and cost of this capital. Higher capital costs directly affect our earnings and cash flows and, in turn, may affect total shareholder returns. To reduce these risks, we prepare forecasts to confirm our capital requirements and adhere to a financing strategy that supports being able to access capital on a timely and cost-effective basis. This strategy includes maintaining:

• a prudent capital structure supported by investment-grade credit ratings; and

• sufficient liquidity through cash balances, excess cash flow, committed revolving credit facilities, and our DRIP to meet our obligations.

Through this strategy, we strive to avoid having to raise additional capital where the costs or terms of which would be regarded as being unfavourable. We have summarized recent changes to the components of our capital in the “Liquidity and Capital Resources” section of this MD&A.

foreignCurrency

Significant portions of our assets, net earnings and cash flows are denominated in U.S. dollars. As a result, their accounting and economic values vary with changes in the U.S./Canadian exchange rate. To date, we have not entered into any foreign currency hedges to reduce our currency risk in respect of our net U.S. dollar investment.

We generally use net cash flows from our U.S. operations, supplemented where necessary with U.S. dollar borrowings, to fund our U.S. dollar capital expenditures. From time to time, we have designated U.S. dollar borrowings as a hedge against our U.S. dollar net investment in self-sustaining foreign operations. From an accounting perspective, to the extent these hedges are deemed to be effective, we record any such gains or losses in other comprehensive income.

On December 31, 2012, approximately 37.2% of our net assets were denominated in U.S. dollars. For the year ended December 31, 2012, we recorded an unrealized foreign exchange loss of $5.6 million in other comprehensive income on the re-translation of our U.S. net assets. At December 31, 2012, if the Canadian currency had strengthened or weakened by one cent against the U.S. dollar, with all other variables constant, total assets, net income, and distributable cash would have been $5.1 million, $0.5 million, and $1.4 million, respectively, lower or higher.

InterestRate

We have financed portions of our operations with debt, including floating-rate debt. To the extent interest is not recoverable, we are exposed to fluctuations in interest rates on floating-rate debt and to potentially higher fixed rates at the time existing debt obligations need to be refinanced. To reduce this exposure, we maintain investment-grade credit ratings and generally fund long-term assets utilizing long-term, fixed-rate debt. Our floating-rate debt is primarily comprised of drawdowns under committed bank credit facilities. To reduce our exposure to interest rate fluctuations further, we may occasionally use derivative instruments, including interest rate swaps, collars and forward rate agreements, to hedge against the effect of future interest rate movements. From an accounting perspective, to the extent these hedges are deemed to be effective, we record any such gains or losses in other comprehensive income. On December 31, 2012, 22% of our consolidated long-term debt was floating-rate debt. At December 31, 2012, if interest rates applied to floating-rate debt were 100 basis points higher or lower with all other variables constant, net income before tax and distributable cash each would have been $2.7 million lower or higher.

As part of York Energy Centre’s debt financing in 2010, it entered into two interest rate hedges. These hedges were entered into to manage the exposure to changes in interest rates whereby York Energy Centre receives variable interest rates and pays fixed interest rates. On April 30, 2012, one interest rate hedge was retired. Future changes in interest rates will affect the fair value of the remaining hedge, impacting the amount of unrealized gains or losses recognized in the period through equity income. For the three and 12 months ended December 31, 2012, equity income from York Energy Centre includes a $1.9 million and $0.2 million unrealized mark-to-market gain, respectively, associated with these hedges.

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financialInstruments

The following table summarizes our financial instrument carrying and fair values as at December 31, 2012:

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

assets Cash and short-term investments 16.1 16.1 16.1

Restricted cash 5.8 5.8 5.8

Distributions receivable 39.9 39.9 39.9

Receivables and accrued receivables 72.6 72.6 72.6

Due from jointly-controlled businesses 49.6 49.6 49.6

Other assets 0.8 16.6 17.4 0.8

liabilities Payables and accrued payables 58.2 2.4 60.6 58.2

Dividends payable 12.9 12.9 12.9

Senior debt 1,259.3 1,259.3 1,322.8


Other long-term liabilities 7.7 38.5 46.2 7.7

(1) Fair value excludes non-financial instruments.








Other assets 0.8 14.6 15.4 0.8


Subscriptions receipts payable 348.6 348.6 348.6


Senior debt 765.6 765.6 803.3




For the years ended December 31, 2012 and 2011 the following amounts were recognized in income:

2012 2011

Total interest expense, recorded with respect to other financial liabilities, calculated using the effective rate method 58.6 45.9

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fairValues

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 and accrued payables, dividends payable, subscription receipts payable, and other long-term liabilities approximate their carrying amounts due to the nature of the item and/or the short time to maturity. The fair values of senior debt are calculated by discounting future cash flows using discount rates estimated based on government bond rates plus expected spreads for similarly rated instruments with 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.

Financial instruments measured at fair value as of December 31, 2012 were:

Level 1 Level 2 Level 3 Total


Restricted cash 5.8 5.8

Maturityanalysisoffinancialliabilities

The tables below summarize our 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, 2012:

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

Payables and accrued payables 58.2

Dividends payable 12.9

Senior debt 11.7 447.7 373.1 426.8

Subordinated convertible debentures 86.2





Subscription receipts payable 348.6

Senior debt 11.2 224.2 140.3 389.9


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CoMMoNbuSINESSRISKS

Investment

Our business strategy includes optimizing the value of our existing assets, and developing, constructing and investing in new and existing long-life, high quality energy infrastructure assets. Our ability to achieve accretive growth is influenced by a variety of risks, including our ability to:

• secure necessary regulatory and environmental approvals and permits;

• integrate acquisitions in an optimal manner and achieve expected synergies;

• access capital on a cost-competitive basis;

• complete late-stage development projects on time and within budget; and

• achieve expected operating and financial performance.

To reduce these risks we utilize our key personnel and outside experts, where necessary, to perform a detailed assessment of the risks and rewards associated with all significant investments, including detailed financial modeling and an assessment of its impact on our financial results, risk profile and capital structure. Senior management and the applicable board of directors review every significant investment to ensure it meets our key investment criteria. These activities require substantial management expertise and resources, which, from time to time, may strain our ability to manage existing operations and possibly other strategic growth opportunities. Periodic assessments of previous investments are undertaken to enhance our execution of future growth initiatives.

Counterparty

Through the course of operating our businesses and managing our financial risks, we are exposed to counterparty risks. We are exposed to market pricing and credit-related risks in the event any counterparty, whether a customer, debtor, financial intermediary or otherwise, is unable or unwilling to fulfill their contractual obligations or where such agreements are otherwise terminated and not replaced with agreements on substantially the same terms.

Our trade credit exposures are spread across a diversified set of counterparties, the majority of which are with investment-grade entities operating within the energy sector and are subject to the normal credit risks associated with this sector. In most cases, the contractual arrangements with our customers and the related exposures are long-term in nature. Requiring shippers to provide letters of credit or other suitable security, unless the shippers maintain specified credit ratings or a suitable financial position, reduces Alliance’s exposure. In the case of AEGS, we are primarily dependent on 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. In the case of the Hythe/Steeprock complex, we are primarily dependent on one customer, a major natural gas producer with investment-grade credit ratings. In the case of Aux Sable’s midstream business, earnings and cash flows are primarily dependent upon the long-term NGL Sales Agreement with one of the largest integrated energy companies in the world. The counterparty exposures associated with our power business are diverse and are spread across numerous entities (including a number of government entities in the case of our district energy facilities), and individual counterparties with investment-grade ratings.

We undertake additional measures to manage our credit risks. These measures are generally guided by short-term investment policies and counterparty credit policies and include:

• assessing the financial strength of new and existing counterparties;

• setting limits on exposures to individual counterparties;

• seeking collateral; and

• using contractual arrangements that permit netting of exposures associated with a single counterparty as well as other remedies.

operations

All of our businesses are subject to risks in the operation of their facilities. Operating risks include:

• the breakdown or failure of equipment, information systems or processes;

• the performance of equipment at levels below those originally intended (whether due to misuse, unexpected degradation or design, construction or manufacturing defects);

• failure to maintain adequate supplies of spare parts;

• operator error; and

• labour disputes, fires, explosions, fractures, acts of terrorists and saboteurs, and other similar events, many of which are beyond our control.

The occurrence or continuance of any of these events could reduce earnings and cash flows.

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We and our businesses employ various inspection and monitoring methods to manage the integrity of our facilities and to minimize system disruptions. Further, we and our businesses maintain safety policies, disaster recovery procedures and insurance coverage at industry acceptable levels in the case of an incident. However, there can be no assurance that these measures will be effective in preventing events that adversely impact the operations of our businesses or that insurance proceeds will be adequate to cover lost earnings and cash flows.

Competition

All of our businesses participate in competitive markets and compete with other companies. Substantially all of our businesses have entered into long-term contractual agreements with varying maturities that serve to reduce the potential impact of this competition. However, we can give no assurances that such agreements will remain in effect or will be replaced with agreements on substantially the same terms. As a result, our future earnings and cash flows are exposed to competitive market forces, particularly at the time any of our existing contracts mature.

We also compete with other businesses for growth and business opportunities, which could impact our ability to grow through acquisitions.

Environmental,HealthandSafety

Our businesses are subject to extensive federal, provincial, state, and local environmental, health and safety laws and regulations typical for the industries and jurisdictions within which they operate, including requirements for compliance obligations pertaining to discharges to air, land and water. Our facilities could experience environmental, health and safety incidents including spills, emission exceedences, or other unplanned events that could result in:

• fines or penalties;

• operational interruptions;

• physical injury to our employees, contractors, or general public;

• environmental contamination clean-up costs; and

• additional costs being incurred to achieve compliance.

We are also exposed to potential changes in future laws and regulations, such as those related to nitrous oxides and greenhouse gas emissions, which could result in more stringent and costly compliance requirements. The Global Warming Act (AB 32) requires gas-fired electricity generation facilities located in California to mitigate 100 percent of their greenhouse gas emissions. Beginning in January 2013, our Ripon and San Gabriel facilities will be required to comply with AB 32. We are actively pursuing mitigation strategies aimed at reducing our compliance costs related to greenhouse gas emission reductions, including participating in the November 2012 and February 2013 auctions for greenhouse gas allowances. We were successful in securing allowances that will enable us to meet our first and second quarter 2013 greenhouse gas obligations. As the greenhouse gas cap and trade program and the implementation of AB 32 remain in early stages, the cost implications associated with greenhouse gas mitigation over the life of the Ripon and San Gabriel facilities are not fully known at this time.

Our businesses may also be subject to opposition by special interest groups which could result in schedule delays and increased costs. These special interest groups have the ability to participate in various regulatory processes and proceedings in an effort to influence the outcome.

As part of the consultative process, our businesses work with Aboriginal groups, local landowners, special interest groups, counties, and municipalities. Stakeholder engagement is aimed at providing interested members of the public with information regarding our businesses and addresses their concerns. Stakeholder consultation does not assure that all risks associated with community opposition can be mitigated.

We are unaware of any outstanding orders, fines, penalties or litigation for our businesses related to EH&S.

Our Board of Directors has established an EH&S Committee to provide corporate oversight regarding EH&S compliance for our businesses. Alliance and Aux Sable also have EH&S Committees which report to their respective board of directors. Through regular reporting, the EH&S Committees ensure compliance with our EH&S corporate policy, including compliance with all applicable laws and regulations and maintaining a healthy and safe work environment for our employees, and the communities within which we operate. To support this commitment, we have established policies, programs, practices, including performance targets and reporting to senior management. Our policies, programs and practices are managed by experienced personnel and periodically reviewed and modified to ensure they conform with current laws, regulations, and industry practices.

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abandonment

Each of our businesses is responsible for monitoring and complying with all laws and regulations concerning the abandonment of its facilities at the end of their respective economic lives and are therefore exposed to the costs associated with any future such abandonment. The costs of abandonment will be a function of then applicable regulatory requirements, which we cannot accurately predict. Where reasonably determinable, we accrue the costs associated with these legal obligations.

Insurance

In the normal course of managing our businesses, we purchase and maintain insurance coverage to reduce certain risks with limits and deductibles that are considered reasonable and prudent. Our insurance does not cover all eventualities because of customary exclusions and/or limited availability and in some instances, our view that the cost of certain insurance coverage is excessive in relation to the risk or risks being covered. Further, there can be no assurance insurance coverage will continue to be available on commercially reasonable terms, that such coverage will ultimately be sufficient, or that insurers will be able to fulfill their obligations should a claim be made.

jointownership

Many of our businesses and material assets are jointly held and are governed by partnership and shareholder agreements. As a result, certain decisions regarding these businesses require a simple majority, while others require 100% approval of the owners. While we believe we have prudent governance and contractual rights in place, there can be no assurance that we will not encounter disputes with partners that may impact operations or cash flows.

DevelopmentRisk

In the normal course of business growth, we participate in the design, construction and operation of new facilities. In developing new projects, we may be required to incur significant preliminary engineering, environmental, permitting and legal-related expenditures prior to determining whether a project is feasible and economically viable. In the event a project is not completed or does not operate at anticipated performance levels, we may be unable to recover our investment.

From time to time, due to long lead times required for ordering equipment, we may place orders for equipment and make deposits thereon or advance projects before obtaining all requisite permits and licenses. We only take such actions where we reasonably believe such licenses or permits will be forthcoming in due course prior to the requirement to expend the full amount of the purchase price. However, any delay in permitting or failure to obtain the necessary permits could adversely affect our earnings and cash flows.

There is a risk that projects under development or construction may not be completed on time, on budget or at all. Projects may have delays, interruption of operations or increased costs due to many factors.

Projects are approved for development on a project-by-project basis after considering strategic fit, the inherent risks, and expected financial returns. We believe this approach to project development, combined with an experienced management team, staff and contract personnel, minimizes development costs and execution risk.

buSINESS-SPECIfICRISKS

RisksSpecifictoourPipelinebusiness

ExtensionofTransportationContracts;SupplyandDemand

Each of Alliance and AEGS derive revenues from long-term transportation contracts, the vast majority of which have primary terms ending on December 1, 2015 and December 31, 2018, respectively. Beyond such terms, the transportation commitments and the associated revenues will depend on various factors, including the supply of, and the demand for, natural gas and ethane, respectively, produced from western Canada and the ability of Alliance and AEGS to compete at the supply and demand ends of their respective systems. Supply depends upon a number of factors including the:

• level of exploration, drilling, reserves and production of natural gas;

• price of natural gas and NGLs;

• price and composition of natural gas available from alternative Canadian and United States sources;

• availability of natural gas in excess of domestic demand for export;

• regulatory environments in Canada and the United States; and

• transportation pricing of competitors.

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The level of commitments for transport on the Alliance pipeline after December 1, 2015 may be negatively impacted by the development of new sources of natural gas. In particular, shale gas deposits in the United States could provide an alternate source of natural gas to the Chicago hub, decreasing the U.S. northeast region’s reliance on natural gas imports from Canada, and correspondingly, decreasing commitments for transport on the Alliance pipeline.

Demand for natural gas in the midwestern and northeastern United States depends, among other things, on weather, price and consumption, and alternative energy sources. Upon maturity of the existing transportation contracts, Alliance faces competition in pipeline transportation to Chicago area delivery points from both existing pipelines and proposed projects. Any new or upgraded pipelines could either allow shippers and competing pipelines to have greater access to natural gas markets served by Alliance and the pipelines to which it is connected or offer natural gas transportation services that are more desirable to shippers than those provided by Alliance due to location, facilities or other factors. In addition, competing pipelines could charge rates or provide transportation services to locations that result in greater net profit for shippers, which could result in reduced revenues and cash flows for Alliance.

Two large petrochemical companies, each of whom own and operate world-class petrochemical facilities in Alberta, drive the demand for ethane shipped on AEGS. If, for any reason, either of these customers, or their successors, ceased to operate these facilities or otherwise reduced or eliminated the quantities of ethane purchased by them, this could have a negative effect on the quantity of ethane transported on AEGS and our earnings and cash flows.

We can give no assurance as to the respective abilities of Alliance and AEGS to replace contact commitments from shippers or to negotiate terms similar to those under current transportation contracts upon their expiry in 2015 and 2018, respectively.

RateRegulation

Alliance is subject to Canadian and United States federal regulation by the NEB and the FERC, respectively. AEGS is subject to Canadian provincial regulation by the Alberta Utilities Commission. The ability of our pipelines to generate earnings and cash flows could be adversely affected by changes in pipeline regulation, including:

• changes in interpretations of existing regulations by courts or regulators;

• the exclusion of any cost of service amounts;

• any other adverse change to the rates on the respective rate structures or terms and conditions of service; and

• in the case of Alliance, a reduction in the negotiated rate of return on equity.

RecoveryofCapital

Alliance is permitted to recover from shippers costs incurred in the construction and operation of the pipeline system that are actually and reasonably incurred in accordance with NEB and FERC regulations. Alliance has firm transportation service agreements for 90.5% and 84.7% of its Canadian and U.S. capacity, respectively, until December 1, 2015, 2.3% and 2.1% until December 1, 2016, 1.5% and 1.4% until October 31, 2013, and 5.7% of its U.S. capacity until February 1, 2020. Firm transportation agreements for the remaining capacity extend until December 1, 2018. Alliance is exposed to economic risk associated with the recovery of capital beyond the term of the transportation service agreements. There is no assurance that Alliance will be able to replace the transportation agreements with contracts, the terms of which would enable recovery of the remaining capital cost directly through tolls.

RiskSpecifictoallianceandauxSable

Interdependency

There is a significant degree of interdependency between Alliance and Aux Sable, which are related parties through common controlling ownership interests. On one hand, should Aux Sable fail to provide heat content management services to Alliance U.S. for any reason, the Alliance pipeline and its shippers may experience operational issues, including in certain circumstances an interruption or curtailment of transportation service on the Alliance pipeline. On the other hand, the volume and composition of inlet natural gas available to Aux Sable is dependent on the volumes transported on the Alliance pipeline, which is subject to supply and demand factors, including competitive pressures from other pipeline systems, and the operating performance of the Alliance pipeline.

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RisksSpecifictotheHythe/SteeprockComplex

PlantTurnaround

We are scheduled to perform a major plant turnaround at the Hythe/Steeprock complex in May 2013 that will take approximately 16 days. There is a risk the turnaround could extend longer than expected if additional remedial work on equipment is required. Our strategy to mitigate the risk of an extended outage involves hiring competent engineering and technical staff to plan the turnaround and building remedial work into the schedule. We have retained many of the same staff who have participated in previous successful turnaround activities at the Hythe/Steeprock complex. Should the turnaround extend past the scheduled completion date, we will be unable to charge the full fees associated with operating the plant to third party producers, and will forfeit certain operating incentives contained in the MSA.

NaturalGasThroughput

As with any natural gas processing complex, the Hythe/Steeprock complex faces the risk of lower throughput due to potential production declines, particularly at times of lower drilling activity in the industry. We believe this risk is mitigated by our long-term take or pay contract with a major producer for a substantial component of the Hythe/Steeprock complex’s capacity, and by our commercial development efforts to increase third party volumes to the facility. Further, exploration and development activity in the Montney production area of British Columbia and Alberta, where the Hythe/Steeprock complex is located, has remained active, even in the current challenging natural gas pricing environment.

RisksSpecifictothePowerbusiness

GasSupply

The operation of our gas-fired power generation and London district energy facilities requires the delivery of natural gas. If there is any interruption in the provision of natural gas for any of these facilities, the ability to generate electricity and, in the case of the cogeneration facilities, steam or distilled water, will be negatively affected and may have a negative impact on our earnings and cash flows. These facilities are dependent on pipeline deliveries of natural gas and a functioning and integrated North America supply grid. We have attempted to mitigate this risk by purchasing natural gas at major supply hubs and entering into firm delivery contracts with major transporters of natural gas.

CriticalaccountingPolicies

Alliance is subject to rate regulation in Canada and the United States. Our consolidated financial statements are prepared in accordance with US GAAP, which include specific provisions applicable to rate-regulated businesses, such as Alliance. As a consequence, these principles may differ from those used by non-rate-regulated entities. In order to achieve a proper matching of revenues and expenses, certain revenues and expenses are recognized in equity income from Alliance differently than would otherwise be expected under US GAAP applicable to non-regulated businesses.

Alliance transportation contracts are designed to provide toll revenues sufficient to recover all prudently incurred costs, including an 11.26% return on equity in Canada and a 10.88% return on equity in the United States. The period in which costs are recovered from toll receipts may differ from the period when these costs are expensed under US GAAP. Differences between Alliance’s recorded toll revenue and actual toll receipts give rise to receivable or payable balances, reflected in our equity investment in Alliance. In the case of Alliance’s Canadian rate-regulated business, the taxes payable method is used to recover tax expense and, as such, Alliance’s Canadian tolls do not include the recovery of future income taxes. For purposes of calculating tolls, depreciation of the Alliance pipeline is based on negotiated rates contained in the transportation contracts, while depreciation expense under US GAAP, reflected in our equity income from Alliance, is recorded on a straight-line basis at a rate of four percent per annum commencing on the in-service date. The negotiated depreciation rates were generally less than the straight-line rate in earlier years resulting in accrued revenues and receivables in those years. These receivables are expected to be recovered from shippers in subsequent years when the negotiated depreciation in the toll exceeds the depreciation recorded for financial statement purposes.

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CriticalaccountingEstimates

The preparation of our consolidated financial statements requires us to make judgements, estimates and assumptions about future events when applying US GAAP that affect the recorded amounts of certain assets, liabilities, revenues and expenses. These judgements, estimates and assumptions are subject to change as the events occur or new information becomes available. The following highlights our more significant accounting estimates. Readers should also refer to note three of our consolidated financial statements for more detailed disclosures of our significant accounting policies.

Impairmentoflong-livedassets

We evaluate, at least annually, our long-lived assets for impairment when events or changes in circumstances indicate, in our judgement, the carrying value of such assets may not be recoverable. If we determine the recoverability of the asset’s carrying value has been impaired, the amount of the impairment is determined by estimating the fair value of the assets and recording a loss for the amount the carrying value exceeds the estimated fair value. Judgements and assumptions are inherent in the determination of the recoverability of such assets and the estimate of their fair value.

In our view, at December 31, 2012, there has not been impairment in the carried value of our long-lived assets.

assetRetirementobligation

The estimated fair value of legal obligations associated with the retirement of tangible long-lived assets is to be recognized in the period in which they are incurred if a reasonable estimate of a fair value can be determined. The asset retirement cost, deemed to be the fair value of 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 these assets. This amortization is included in depreciation and amortization in the consolidated statement of income. Increases in the asset retirement obligation resulting from the passage of time are recorded as accretion expense in depreciation and amortization in the consolidated statement of income and comprehensive income, over the estimated time period until settlement of the obligation. Actual expenditures incurred are charged against the accumulated asset retirement obligation.

We have recognized provisions for asset retirement obligations in our consolidated financial statements with respect to the AEGS pipeline system, the Hythe/Steeprock complex, and the EnPower, East Windsor Cogeneration, Furry Creek and Clowhom power facilities.

With respect to our jointly-controlled businesses, Aux Sable’s Septimus and Heartland facilities, and the NRGreen and Grand Valley power facilities have each recognized provisions for asset retirement obligations. Aux Sable has not recognized a provision for asset retirement obligations in respect of its U.S.-based assets as the expected legal obligations are not material. Alliance has not recognized an asset retirement obligation provision for the Alliance pipeline. It is not currently possible to make a reasonable estimate of the fair value of the liability for the Alliance pipeline due to the indeterminate timing and scope of the asset retirement. The NEB’s LMCI action plan, previously discussed in the “Results of Operations by Business Segment – Pipeline Business – Alliance Pipeline” section of this MD&A, addresses the need for a collection method for funding pipeline abandonment costs. The LMCI plan is not a method for determining the timing of retirement obligations. However, in the event the plan results in a reasonable estimate of asset retirement obligations for accounting purposes, financial statement recognition of those obligations may be made in future periods. As a result, regulatory assets and liabilities may be recognized to the extent the timing of recovery from shippers differs from the recognition of abandonment costs for accounting purposes. We believe it is reasonable to assume that all asset retirement obligations associated with the Alliance pipeline will be recoverable through future tolls.

Depreciationandamortization

Our pipeline, plant and other capital assets and intangible assets are depreciated and amortized based on their estimated useful lives. A change in the estimation of useful lives could have a material impact on our consolidated net income.

Regulatoryasset

Our equity investment in Alliance includes a long-term receivable for the cumulative difference between depreciation expense included in our equity income from Alliance and depreciation expense included in Alliance’s transportation tolls. The carrying value of this asset reflects our assessment as to the ultimate recoverability of this receivable.

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NewaccountingStandards

The following new Accounting Standards Updates have been issued, as of December 31, 2011.

In May 2011, the Financial Accounting Standards Board (“FASB”) issued ASU 2011-04, “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in US GAAP and International Financial Reporting Standards (IFRS)”. ASU 2011-04 results in a consistent definition of fair value, as well as common requirements for measurement and disclosure of fair value information between US GAAP and IFRS. In addition, the amendments set forth enhanced disclosure requirements with respect to recurring Level 3 measurements, non-financial assets measured or disclosed at fair value, transfers between levels in the fair value hierarchy, and assets and liabilities disclosed but not recorded at fair value. The revised fair value measurement guidance became effective on a prospective basis for the Company’s interim and annual periods beginning January 1, 2012. We adopted this ASU effective January 1, 2012. The impact of this is not material to us.

In June 2011, the FASB issued ASU 2011-05, “Presentation of Comprehensive Income”. This ASU provides two options for presenting items of net income, comprehensive income and total comprehensive income, by either creating one statement of income and comprehensive income or two separate consecutive statements. This guidance became effective for interim and annual periods beginning after December 15, 2011. We adopted this ASU effective January 1, 2012 and have elected to use two separate consecutive statements.

In December 2011, the FASB issued ASU 2011-12, “Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05”. This ASU defers certain provisions of ASU 2011-05 pertaining to the presentation of reclassifications adjustments, including amounts reclassified out of accumulated OCI, such as realized gains and losses on a derivative instrument designated as a cash flow hedge. This guidance became effective for interim and annual periods beginning after December 15, 2011. We adopted this ASU effective January 1, 2012. The impact of adoption is not material to us.

In December 2011, the FASB issued ASU 2011-11, “Balance Sheet: Disclosures about Offsetting Assets and Liabilities”. This ASU provides guidance for enhanced disclosures on the effect or potential effect of netting arrangements on an entity’s financial position. This guidance is effective for annual and interim periods beginning on or after January 1, 2013 and is not expected to have a material impact to us.

In February 2013, the FASB issued ASU 2013-02, “Comprehensive Income: Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income”. This ASU provides guidance for enhanced disclosure on amounts reclassified out of cumulative other comprehensive income. This guidance is effective for annual and interim periods beginning after December 15, 2012, and is not expected to have a material impact to us.

Non-GaaPfinancialMeasures

Certain financial measures referred to in this MD&A are not measures recognized under US GAAP. These non-GAAP financial measures do not have standardized meanings prescribed by US GAAP and therefore may not be comparable to similar measures presented by other entities. We caution investors not to construe these non-GAAP financial measures as alternatives to other measures of financial performance calculated in accordance with US GAAP. We further caution investors not to place undue reliance on any one financial measure.

We provide the following non-GAAP financial measures to assist investors with their evaluation of us, including their assessment of our ability to generate distributable cash to fund monthly dividends. We consider these non-GAAP financial measures, together with other financial measures calculated in accordance with US GAAP, to be important factors that assist investors in assessing performance.

DistributableCash– represents the cash we have available for distribution to common shareholders after providing for debt service obligations, preferred dividends, and any maintenance and sustaining capital expenditures. Distributable cash does not include distribution reserves, if any, available in jointly-controlled businesses, project development costs, or transaction costs incurred in conjunction with acquisitions. Project development costs are discretionary, non-recoverable costs incurred to assess the commercial viability of greenfield business initiatives unrelated to our operating businesses. We consider transaction costs to be part of the consideration paid for an acquired business and, as such, are unrelated to our operating businesses. The investment community uses distributable cash to assess the source and sustainability of our dividends. The following is a reconciliation of distributable cash to cash from operating activities.

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RECoNCIlIaTIoNofDISTRIbuTablECaSHToCaSHfRoMoPERaTINGaCTIVITIES


($ Millions) 2012 2011 2012 2011

Cash from operating activities 65.1 59.9 179.9 191.4

Add (deduct): Project development costs (1) 7.0 2.5 23.9 11.1

Change in non-cash working capital (19.8) (12.4) 30.0 (12.3)

Deferred revenue 2.8 – 2.8 – Principal repayments on senior notes (2.9) (2.9) (11.3) (10.8)

Maintenance capital expenditures (2.7) (1.1) (7.5) (2.9)

Distributions earned greater (less) than distributions received (2) 6.3 7.2 (1.6) 16.5

Preferred Share dividends (2.2) – (7.7) – Current tax on Preferred Share dividends 2.9 – 2.9 –

Distributable cash 56.5 53.2 211.4 193.0

(1) Represents costs incurred by us in relation to projects where the recoverability of such costs has not yet been established. Amounts incurred for the three and 12 months ended December 31, 2012 relate primarily to the Jordan Cove LNG terminal project, the Pacific Connector Gas Pipeline project, and various power development projects.

(2) Represents the difference between distributions declared by jointly-controlled businesses and distributions received.

DistributableCashperCommonShare– reflects the per common share amount of distributable cash calculated based on the average number of common shares outstanding on each record date.

EbITDa– refers to earnings before interest, taxes, depreciation and amortization. EBITDA is reconciled to net income before tax by deducting interest, depreciation and amortization, and asset impairment losses, if any. The investment community uses this measure, together with other measures, to assess the source and sustainability of cash distributions.

Powernetincomebeforetaxandnon-controllinginterestwithjointly-controlledpowerbusinessespresentedonaproportionatelyconsolidatedbasis– Under US GAAP, we account for each of York Energy Centre, NRGreen and Grand Valley using the equity method due to our joint control of these entities. However, we believe the presentation of their earnings on a proportionately consolidated line-by-line basis provides more insightful information. We and the investment community use EBITDA on a proportionately consolidated basis to assess the performance of our Power business. The following reconciles the results of our power business as presented in “Results of Operations – Power Business” to the results as presented in accordance with US GAAP.

PowERbuSINESS


Reverse Reverse proportionate proportionate consolidation; consolidation; Proportionately apply equity Proportionately apply equity ($ Millions) Consolidated accounting uSGaaP Consolidated accounting US GAAP

ProportionatelyConsolidatedEbITDa 17.6 (7.9) 9.7 8.1 (0.5) 7.6

Depreciation & amortization (11.7) 3.5 (8.2) (9.0) 0.6 (8.4)

Interest (7.2) 3.5 (3.7) (3.6) (0.2) (3.8)

Fair value gains (losses) 1.9 (1.9) – (4.7) 4.7 –Foreign exchange and other 0.1 (0.1) – – (0.1) (0.1)

Equity income (loss) – 2.9 2.9 – (4.5) (4.5)

Netincomebeforetaxesandnon-controllinginterest 0.7 – 0.7 (9.2) – (9.2)

36



Reverse Reverse proportionate proportionate consolidation; consolidation; Proportionately apply equity Proportionately apply equity ($ Millions) Consolidated accounting uSGaaP Consolidated accounting US GAAP

ProportionatelyConsolidatedEbITDa 65.5 (21.0) 44.5 48.3 (3.1) 45.2

Depreciation & amortization (43.3) 9.8 (33.5) (35.3) 1.9 (33.4)

Interest (23.4) 9.3 (14.1) (15.2) 0.3 (14.9)

Fair value gains (losses) 0.2 (0.2) – (21.7) 21.7 –Foreign exchange and other – – – (0.1) – (0.1)

Equity income (loss) – 2.1 2.1 – (20.8) (20.8)

Netincomebeforetaxesandnon-controllinginterest (1.0) – (1.0) (24.0) – (24.0)

Segmentedassetsasapercentageoftotalassetsasdeterminedonaproportionatelyconsolidatedbasis–Under US GAAP, we account for each of our jointly-controlled businesses using the equity method. As a result, total assets under US GAAP reflect the net asset position of each of our equity investments in jointly-controlled businesses. However, we believe the presentation of segmented assets as a percentage of total assets on a proportionately consolidated basis provides more insightful information. We and the investment community use these measures to gain a better understanding of the relative asset contributions from each of our businesses. The following reconciles the results of our segmented assets as presented in “Business Overview” to segmented assets as presented in accordance with US GAAP.

ToTalaSSETS

Reverse proportionate Proportionately consolidation; Consolidated Proportionately apply equity At at December 31, 2012 ($ Millions) % Consolidated accounting uSGaaP

Pipeline 45 1,936.8 (989.9) 946.9

Midstream 29 1,263.8 (47.9) 1,215.9

Power 25 1,100.1 (218.2) 881.9

Corporate 1 48.6 50.7 99.3

Total Assets 100 4,349.3 (1,205.3) 3,144.0

SelectedQuarterlyfinancialInformation

2012 2011

($ Millions, except where noted) Q4 Q3 Q2 Q1 Q4 Q3 Q2 Q1

Operating revenues 67.7 71.5 70.0 55.0 42.4 48.8 41.9 41.1

Net income attributable to Common Shares 12.0 11.4 7.2 8.3 14.4 11.1 17.1 10.5

Net income per Common Share ($) – basic and diluted 0.06 0.06 0.03 0.05 0.09 0.07 0.10 0.07

Distributable cash 56.5 61.4 51.9 41.6 53.2 54.4 48.7 36.7

Distributable cash per Common Share ($) – basic and diluted 0.29 0.31 0.26 0.23 0.32 0.33 0.30 0.23

Cash from operating activities 65.1 48.5 36.9 29.4 59.9 54.5 43.4 33.6

37

Significant items that affected quarterly financial results include the following:

• Fourth quarter 2012 reflected continued weakness in NGL market conditions, resulting in decreased fractionation margins, increased results from our Power business and increased administrative and finance costs to support the Hythe/Steeprock acquisition. Fourth quarter results also included an $4.3 million and a $16.5 million contribution to net income before tax and distributable cash, respectively, from Hythe/Steeprock.

• Third quarter 2012 reflected continued weakness in NGL market conditions, resulting in decreased fractionation margins, reduced results from our Power business and increased administrative and finance costs to support the Hythe/Steeprock acquisition. Third quarter results also included an $8.0 million and a $17.3 million contribution to net income before tax and distributable cash, respectively, from Hythe/Steeprock.

• Second quarter 2012 reflected continued weakness in NGL market conditions, resulting in decreased fractionation margins, reduced results from our Power business and increased administrative and finance costs to support the Hythe/Steeprock acquisition. Second quarter results also included a $5.9 million and a $16.9 million contribution to net income before tax and distributable cash, respectively, from Hythe/Steeprock.

• First quarter 2012 included a $5.1 million and a $9.5 million contribution to net income before tax and distributable cash, respectively, from Hythe/Steeprock.

• Fourth quarter 2011 reflected the recognition of $30.6 million of NGL margin-based lease revenues, a new record for us, in net income attributable to Common Shares through our equity income from Aux Sable and distributable cash.

• Third quarter 2011 reflected the recognition of $24.4 million of NGL margin-based lease revenues in net income attributable to Common Shares through our equity income from Aux Sable and distributable cash, and incremental earnings contributed from our power facilities acquired in the fourth quarter of 2010 and the first quarter of 2011, offset by a $12.1 million (after tax) or $0.07 per Common Share unrealized mark-to-market loss on York Energy’s interest rate swap.

• Second quarter 2011 reflected solid financial performance from our operating businesses.

• First quarter 2011 reflected the recognition of $10.1 million of NGL margin-based lease revenues in net income attributable to Common Shares through our equity income from Aux Sable and distributable cash.

DisclosureControlsandProcedures

Disclosure controls and procedures are designed to provide reasonable assurance that all relevant information is gathered and reported to senior management, including the President & Chief Executive Officer (CEO) and Senior Vice President, Finance and Chief Financial Officer (CFO), on a timely basis so appropriate decisions can be made regarding public disclosure.

We have evaluated the effectiveness of the design and operation of our disclosure controls and procedures, under the supervision of our CEO and CFO. Based on this evaluation, we concluded the disclosure controls and procedures, as defined in National Instrument 52-109, were effective as of December 31, 2012.

InternalControlsoverfinancialReporting

We are responsible for establishing and maintaining adequate internal controls over financial reporting to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with US GAAP. We assessed the design and effectiveness of internal controls over financial reporting as at December 31, 2012, and, based on that assessment, determined the design and operating effectiveness of internal controls over financial reporting was effective. However, because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements on a timely basis.

No changes were made to internal controls over financial reporting during the period ended December 31, 2012 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.

38

TotheShareholdersofVeresenInc.

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 (US GAAP). If alternative accounting methods exist, management has chosen those it deems most appropriate in the circumstances. Financial statements are not precise 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 the year with management and the external auditors to satisfy itself that management’s responsibilities are being discharged; 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.

The independent external auditors, PricewaterhouseCoopers LLP, have been appointed by the shareholders of Veresen to express an opinion as to whether the consolidated financial statements of Veresen present fairly, in all material respects, its financial position as at December 31, 2012 and 2011 and its results of operations and cash flows for the years then ended in accordance with US GAAP.

Donalthoff RichardG.weech

President and Chief Executive Officer Senior Vice President, March 6, 2013 Finance and Chief Financial Officer

Management‘s Report

39

TotheShareholdersofVeresenInc.

We have audited the accompanying consolidated financial statements of Veresen Inc., which comprise the consolidated statements of financial position as of December 31, 2012 and December 31, 2011 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 significant accounting policies and other explanatory information.

Management’sresponsibilityfortheconsolidatedfinancialstatements

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’sresponsibility

Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards. 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 in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. An audit also includes evaluating the appropriateness of accounting 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, 2012 and December 31, 2011 and 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.

Charteredaccountants

Calgary, Alberta, CanadaMarch 6, 2013

Independent Auditor’s Report

40

Consolidated Statement of Financial Position

(Canadian $ Millions; shares in Millions) December31,2012 December 31, 2011

aSSETS Current assets Cash and short-term investments 16.1 21.9 Restricted cash (note 5) 5.8 354.6 Distributions receivable 39.9 43.4

Receivables 53.7 25.0 Accrued receivables 18.9 7.3 Due from jointly-controlled businesses (note 21) 1.5 25.5 Other (note 8) 10.0 75.5

145.9 553.2 Investments in jointly-controlled businesses (note 6) 957.4 934.1 Rate-regulated asset (note 7) 76.4 85.8 Pipeline, plant and other capital assets (note 9) 1,443.8 768.7

Intangible assets (note 10) 455.0 197.3 Due from jointly-controlled businesses (note 21) 48.1 3.6 Other assets 17.4 15.4

3,144.0 2,558.1

lIabIlITIES Current liabilities Payables 19.6 14.0 Interest payable 12.5 8.2

Accrued payables 28.5 37.3 Deferred revenue 2.8 – Subscription receipts payable (note 16) – 348.6 Dividends payable 12.9 2.7 Current portion of long-term senior debt (note 11) 11.7 11.2

88.0 422.0 Long-term senior debt (note 11) 1,247.6 754.4 Subordinated convertible debentures (note 12) 86.2 86.2 Deferred taxes (note 14) 316.2 321.7 Other long-term liabilities (note 13) 46.2 35.0

1,784.2 1,619.3

SHaREHolDERS’EQuITy Share capital (note 16) Preferred shares 195.2 – Common shares (197.8 and 166.6 outstanding at December 31, 2012 and 2011, respectively) 1,804.3 1,391.0 Additional paid-in capital 4.3 – Cumulative other comprehensive loss (164.8) (159.2)

Accumulated deficit (479.3) (324.7)

1,359.7 907.1

Non-controlling interest (note 15) 0.1 31.7

1,359.8 938.8

3,144.0 2,558.1

Commitments and Contingencies (note 17)

See accompanying Notes to the Consolidated Financial Statements

Approved by the Board of Directors of Veresen Inc.

Donalthoff bertranda.Valdman

Director Director

41

Consolidated Statement of Income


(Canadian $ Millions, except per Common Share amounts (note 16)) 2012 2011

Equity income (note 6) 135.8 155.1

Operating revenues 264.2 174.2

Operations and maintenance (112.4) (85.1)

General, administrative and project development (69.5) (51.9)

Depreciation and amortization (83.1) (48.4)

Interest and other finance (58.6) (45.9)

Foreign exchange and other (0.9) (1.6)

Net income before taxes and non-controlling interest 75.5 96.4

Current taxes (note 14) (18.2) (28.1)

Deferred taxes (note 14) (10.6) (15.1)

Net income before non-controlling interest 46.7 53.2

Non-controlling interest (note 15) (0.1) (0.1)

Net income 46.6 53.1

Preferred Share dividends (7.7) –

Net income attributable to Common Shares 38.9 53.1

Net income per Common Share Basic and diluted 0.20 0.33

Consolidated Statement of Comprehensive Income


(Canadian $ Millions) 2012 2011


Other comprehensive income (loss) Cumulative translation adjustment Unrealized foreign exchange gain (loss) on translation (5.6) 13.5 Cumulative translation adjustment reclassified to net income – 0.8

Other – 1.8

Other comprehensive income (loss) (5.6) 16.1

Comprehensive income before non-controlling interest 41.1 69.3

Comprehensive income attributable to non-controlling interest (0.1) (0.1)

Comprehensive income 41.0 69.2

Preferred Share dividends (7.7) –

Comprehensive income attributable to Common Shares 33.3 69.2


42

Consolidated Statement of Cash Flows



Operating Net income before non-controlling interest 46.7 53.2

Equity income (note 6) (135.8) (155.1)

Distributions from jointly-controlled businesses 204.4 230.2

Depreciation and amortization 83.1 48.4

Foreign exchange gain and other non-cash items (0.3) (3.2)

Deferred taxes 10.6 15.1

Changes in non-cash working capital (note 20) (28.8) 2.8

179.9 191.4

Investing Acquisitions, net of cash acquired (890.5) (144.6)

Investments in jointly-controlled businesses (106.0) (125.2)

Return of capital from jointly-controlled businesses 8.5 – Pipeline, plant and other capital assets (91.5) (18.5)

Restricted cash 0.4 (3.6)

Other (1.6) 8.4

(1,080.7) (283.5)

Financing Subscription receipts issued – 348.6 Restricted cash 348.4 (347.1)

Short-term debt issued, net of issue costs 249.1 – Short-term debt repaid (250.0) – Long-term debt issued, net of issue costs 347.8 202.3 Long-term debt repaid (11.2) (57.2)

Net change in credit facilities 154.2 32.4 Preferred Shares issued, net of issue costs 193.7 – Common Share dividends paid (104.2) (53.3)

Preferred Share dividends paid (7.7) – Advances to jointly-controlled businesses (20.5) (25.5)

Other (4.9) (15.3)

894.7 84.9

Decrease in cash and short-term investments (6.1) (7.2)

Effect of foreign exchange rate changes on cash and short-term investments 0.3 6.5

Cash and short-term investments at the beginning of the year 21.9 22.6

Cash and short-term investments at the end of the year 16.1 21.9

Supplemental disclosure of cash flow information Interest paid 57.6 48.1 Taxes paid, net of refunds received 19.9 27.6


43

Consolidated Statement of Shareholders’ Equity



PreferredShares January 1 – – Series A Preferred Shares issued, net of issue costs (note 16) 195.2 –

Balance at the end of the year 195.2 –

CommonShares January 1 1,391.0 1,279.6

Subscription receipts converted into Common Shares, net of issue costs (note 16) 334.1 – Common Shares issued under Premium Dividend and Dividend Reinvestment Plan (“DRIP”) 75.6 100.3

December 31 1,800.7 1,379.9

Common Shares to be issued under DRIP 3.6 11.1

Balance at the end of the year 1,804.3 1,391.0

additionalpaid-incapital January 1 – –Additional paid-in capital from disposition of non-controlling interest (note 4) 4.3 –

Balance at the end of the year 4.3 –

Cumulativeothercomprehensiveloss January 1 (159.2) (175.3)

Other comprehensive income (loss) (5.6) 16.1

Balance at the end of the year (164.8) (159.2)

accumulateddeficit January 1 (324.7) (214.8)

Net income 46.6 53.1 Preferred Share dividends (7.7) – Common Share dividends (193.5) (163.0)

Balance at the end of the year (479.3) (324.7)

1,359.7 907.1

Non-controllinginterest January 1 31.7 31.5

Non-controlling interest disposition (note 4) (31.7) –Non-controlling interest acquisition – 0.1

Net income attributable to non-controlling interest 0.1 0.1

Balance at the end of the year 0.1 31.7

Shareholders’ Equity 1,359.8 938.8


44

Notes to the Consolidated Financial StatementsYears ended December 31, 2012 and 2011 ($ Millions, except where noted)

Note1.Descriptionofbusiness

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, 2012 the Company’s businesses were comprised of the following:

Entity (1) businessDescriptionownership

Interest(%)

CoNTRollED

Pipelinebusiness

Alberta Ethane Gathering System L.P. (“AEGS”) AEGS owns a 1,330-kilometre pipeline system that transports purity ethane from various Alberta ethane extraction plants to Alberta’s major petrochemical complexes located near Joffre and Fort Saskatchewan, Alberta.

100

Midstreambusiness

Hythe/Steeprock The Hythe/Steeprock complex is comprised of two natural gas processing plants with combined functional capacity of 516 mmcf/d, as well as approximately 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

Powerbusiness

Gas-Fired Generation

• East Windsor Cogeneration LP (“East Windsor Cogeneration”)

• London Cogeneration

• Ripon Cogeneration

• San Gabriel Cogeneration

• Brush II Generation Facility

• an 86-MW cogeneration facility located in Windsor, Ontario

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

• a 49-MW cogeneration facility located in Ripon, California

• a 44-MW cogeneration facility located in Pomona, California

• a 70-MW combined cycle power cogeneration facility located in Brush, Colorado

100(2011 – 75%)

(note 4)

100

100

100

100

District Energy

• 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-River Hydro

• Northbrook New York, LLC (“Northbrook”)

• Swift Power Corp. (“Swift”)

• Furry Creek LP (“Furry Creek”)

• Clowhom LP (“Clowhom”)

• Culliton Creek Power Limited Partnership (“Culliton”)

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

• a run-of-river development company based in Vancouver, B.C. currently constructing Dasque-Middle, a 20-MW run-of-river power facility 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.

• a run-of-river development company based in Vancouver, B.C.

100

100

99 (note 4)

100 (note 4)

100

Pristine Power Inc. (“Pristine”) • electricity developer and operator 100

Waste Heat

• 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(2011 – 75%)

(note 4)

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

45

Entity (1) businessDescriptionownership

Interest(%)

joINTly-CoNTRollED

Pipelinebusiness

Alliance Pipeline Limited Partnership (“Alliance Canada”)

Alliance Pipeline L.P. (“Alliance U.S.”)

(Collectively “Alliance” or “Alliance Pipeline”)

Alliance owns a 3,000-kilometre natural gas pipeline comprised of a mainline and various connecting lateral pipelines. The Alliance pipeline extends from northeastern B.C. to points near Chicago, Illinois.

50

Midstreambusiness(Collectively“auxSable”)

Aux Sable Canada L.P.

Sable NGL Canada L.P.

(Collectively “Aux Sable Canada”)

Aux Sable Canada owns:• NGL injection facilities on the Alliance pipeline in Alberta and B.C.,• an off-gas processing facility in Fort Saskatchewan, Alberta, • a natural gas processing plant in northeastern B.C., and• a natural gas pipeline to connect its gas processing plant to the Alliance pipeline

50

Aux Sable Liquid Products L.P. (“ASLP”)

Aux Sable Midstream LLC (“ASM”)

Alliance Canada Marketing L.P. (“ACM”)

Sable NGL Services L.P. (“Sable NGL Services”)

(Collectively “Aux Sable U.S.”)

Aux Sable U.S. owns:• a natural gas liquids (“NGL”) extraction and fractionation facility near 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 adjacent to the NGL extraction and fractionation facility, and • short-term and long-term natural gas transportation capacity on the Alliance pipeline

42.7

Powerbusiness

Gas-Fired Generation

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

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

50

Waste Heat

• 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 under construction located at Alliance’s Windfall compressor station in Alberta

50

Wind Power

• Grand Valley I Limited Partnership (“Grand Valley”)

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

75

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

46

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Note2.basisofPresentation

These consolidated financial statements have been prepared by management in accordance with accounting principles generally accepted in the United States of America (“US GAAP”). For periods ending before January 1, 2012, the Company prepared its consolidated financial statements in accordance with accounting principles generally accepted in Canada (“Canadian GAAP”).

On June 27, 2011, the Company applied to Canadian securities regulators for exemptive relief under section 5.1 of National Instrument 52-107 – Acceptable Accounting Principles and Auditing Standards (“NI 52-107”) from the requirements of section 3.2 of NI 52-107. Specifically, the Company sought permission to prepare and file its financial statements in accordance with US GAAP for financial years commencing on and after January 1, 2012. On July 15, 2011, the Canadian securities regulators granted exemptive relief to Veresen for financial years and interim periods commencing on or after January 1, 2012 and ending before January 1, 2015. The Company’s Board of Directors has approved the adoption of US GAAP for this three-year period. Comparative figures, which were previously presented in accordance with Canadian GAAP as defined under Part V of the Canadian Institute of Chartered Accountants Handbook, have been adjusted as necessary to be compliant with the Company’s policies under US GAAP. The amounts adjusted for the comparative period are the same as those reported in the Company’s consolidated US GAAP financial statements as at and for the years ended December 31, 2011 and December 31, 2010, filed with Canadian security regulators on April 20, 2012.

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 entities in connection with Alliance. The requirements provide for certain revenues and expenses being recognized differently than otherwise expected under US GAAP applicable to non-regulated businesses. 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 that affect the reported amounts of assets, liabilities, revenues, expenses, financial instruments and taxes. Actual amounts could differ from these estimates. Significant estimates used in the preparation of these consolidated financial statements relate to the determination of any impairment in the carried value of long-term assets, the estimated useful lives over which certain assets are depreciated or amortized, and the measurement of asset retirement obligations.

These consolidated financial statements include the accounts of the Company and its subsidiaries. The Company consolidates its interest in entities over which it is able to exercise control. To the extent there are interests owned by other parties, the other parties’ interests are included in Non-Controlling Interest. Veresen accounts for its jointly-controlled businesses using the equity method.

Certain comparative figures have been reclassified to conform to the presentation adopted in 2012.

Note3.SummaryofSignificantaccountingPolicies

NewaccountingPronouncements

The following new Accounting Standards Updates (“ASU”) have been issued, as of December 31, 2011.

In May 2011, the Financial Accounting Standards Board (“FASB”) issued ASU 2011-04, “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in US GAAP and International Financial Reporting Standards (IFRS)”. ASU 2011-04 results in a consistent definition of fair value, as well as common requirements for measurement and disclosure of fair value information between US GAAP and IFRS. In addition, the amendments set forth enhanced disclosure requirements with respect to recurring Level 3 measurements, non-financial assets measured or disclosed at fair value, transfers between levels in the fair value hierarchy, and assets and liabilities disclosed but not recorded at fair value. The revised fair value measurement guidance became effective on a prospective basis for the Company’s interim and annual periods beginning January 1, 2012. The Company adopted this ASU effective January 1, 2012 and the impact of this is not material to the Company.

In June 2011, the FASB issued ASU 2011-05, “Presentation of Comprehensive Income”. This ASU provides two options for presenting items of net income, comprehensive income and total comprehensive income, by either creating one statement of income and comprehensive income or two separate consecutive statements. This guidance became effective for interim and annual periods beginning after December 15, 2011. The Company adopted this ASU effective January 1, 2012 and has elected to use two separate consecutive statements.

47

In December 2011, the FASB issued ASU 2011-12, “Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05”. This ASU defers certain provisions of ASU 2011-05 pertaining to the presentation of reclassifications adjustments, including amounts reclassified out of accumulated OCI, such as realized gains and losses on a derivative instrument designated as a cash flow hedge. This guidance became effective for interim and annual periods beginning after December 15, 2011. The Company adopted this ASU effective January 1, 2012. The impact of this is not material to the Company.

In December 2011, the FASB issued ASU 2011-11, “Balance Sheet: Disclosures about Offsetting Assets and Liabilities”. This ASU provides guidance for enhanced disclosures on the effect or potential effect of netting arrangements on an entity’s financial position. This guidance is effective for annual and interim periods beginning on or after January 1, 2013 and is not expected to have a material impact to the Company.

In February 2013, the FASB issued ASU 2013-02, “Comprehensive Income: Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income”. This ASU provides guidance for enhanced disclosure on amounts reclassified out of cumulative other comprehensive income. This guidance is effective for annual and interim periods beginning after December 15, 2012, and is not expected to have a material impact to the Company.

CashandShort-TermInvestments

Cash and short-term investments comprise cash and highly liquid investments with original maturities of 90 days or less and carrying values which approximate market value. A portion of these short-term investments are held in trust accounts, the majority of which are permitted to be used for operating, capital expenditure and working capital purposes.

Pipeline,PlantandotherCapitalassets

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 Not depreciated or net realizable value

Expenditures that increase or prolong the service life or capacity of an asset are capitalized. Maintenance and repair costs are expensed as incurred. Construction work in progress, which includes capitalized interest, will be reclassified to pipeline, plant and power facilities and depreciated over the estimated useful life upon commencement of operations.

Intangibleassets

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.

Impairmentoflong-livedassets

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 judgement, 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 of the carrying value has been impaired. If the carrying value exceeds the sum of undiscounted cash flows, the carrying value of the assets is deemed to be impaired. The amount by which the carrying value exceeds the estimated fair value is recognized as an impairment loss.

Judgements 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.

48


assetRetirementobligations

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.

RevenueRecognition

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 facilities receive fixed capacity payments that are not dependent upon the amount of energy delivered to customers. This revenue is 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 volume credit has expired.

Rate-Regulatedaccounting

One of the Company’s jointly-controlled businesses, Alliance, 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 taxes would not be recognized in these consolidated financial statements.

ProjectDevelopmentCosts

The Company expenses project development costs as incurred. Project development costs are only capitalized when, in management’s judgement, 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.

CapitalizedInterest

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

foreignCurrencyTranslation

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 Canadian dollars using the exchange rate in effect at the balance sheet date, and all revenues and expenses are translated into Canadian dollars at average exchange rates during the year. The resulting net cumulative translation gain or loss is deferred and reported 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-TermIncentiveCompensation

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 the LTIP are further dependent upon the achievement of specified performance targets. Expenses related to the various LTIPs and DSU plan are accounted for on an accrual basis.

49


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, 2012 and 2011, 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.

IncomeTaxes

The Company uses the liability method of accounting for income taxes. Under this method, current income taxes are recognized for the estimated income taxes payable in respect of the current year, which includes an accrual for interest and penalties, if any. Deferred tax assets and liabilities are recognized for temporary differences between the tax and accounting asset and liability bases using enacted tax rates and laws expected to apply when the liabilities are settled and the assets realized. Deferred tax assets are recognized in circumstances where it is considered more likely than not the related income tax benefits will be realized.

When appropriate, the Company records a valuation allowance against deferred tax assets to reflect that these tax assets may not be realized. In determining whether a valuation allowance is appropriate, the Company considers whether it is more likely than not that all or some portion of its deferred tax assets will not be realized, based on management’s judgments using available evidence about future events.

At times, the Company may claim tax benefits that may be challenged by a tax authority. The Company recognizes tax benefits only for tax positions that are more likely than not to be sustained upon examination by tax authorities. The amount recognized is measured as the largest amount of benefit that has a greater than 50% likelihood to be realized upon settlement. A liability for “unrecognized tax benefits” is recorded for any tax benefits claimed in the Company’s tax returns that do not meet these recognition and measurement standards.

ShareIssuanceCosts

Costs directly attributable to the raising of equity are charged against the related share capital. Costs related to shares not yet issued are recorded as deferred share issuance costs and presented as other current assets in the Consolidated Statement of Financial Position. These costs are deferred until the issuance of the shares to which the costs relate, at which time the costs are charged against the related share capital or charged to operations if the shares are not issued.

Note4.acquisitions

acquisitionofHythe/SteeprockGasGatheringandProcessingComplex

On February 9, 2012, the Company, through a wholly-owned subsidiary, acquired the Hythe/Steeprock gas gathering and processing complex for $907.5 million. On June 21, 2012, the Company acquired the remaining portion of the associated midstream assets, which are regulated by the NEB, for $8.0 million. The acquired business is located in the Cutbank Ridge region of Alberta and British Columbia.

The acquisition of Hythe/Steeprock has been accounted for using the acquisition method, as set out below, and its results of operations since the date of acquisition have been reported on a consolidated basis. Transaction costs of $0.5 million were recorded in general and administrative expenses. The purchase price was allocated to assets and liabilities as described below:

Capital assets $646.6

Intangible assets 280.3

Asset retirement obligation (11.4)

$915.5

The acquired intangible assets, representing customer relationship and service agreement intangibles, are being amortized over a weighted average of approximately 20 years.

50


For the period February 9, 2012 to December 31, 2012, the Company recorded revenues of $95.7 million and net income before tax of $23.3 million related to the acquired business. Had the acquisition occurred on January 1, 2011, pro forma consolidated operating revenues would have been approximately $276.1 million and consolidated net income would have been approximately $40.2 million for the year ended December 31, 2012 ($287.2 million and $51.8 million respectively, for the year ended December 31, 2011). The pro forma financial information is presented for informational purposes only and is not necessarily indicative of what the financial position or results of operations actually would have been had the acquisition been completed at the dates indicated.

acquisitionofInterestsinEastwindsorCogenerationandEnPower

On February 3, 2012, the Company purchased the 25% interest held by a partner in each of East Windsor Cogeneration LP and EnPower Green Energy Generation Limited Partnership for $70 million, including working capital at closing and the assumption of $45 million of debt. The acquisition increased the Company’s interest in each of these entities from 75% to 100%. As a result, the Company has removed the associated non-controlling interest balance from shareholders’ equity. The difference between the fair value and book value of non-controlling interest was recorded as additional paid-up capital, as the acquisition did not result in a change in control.

b.C.Run-of-Riverfacilities

On February 14, 2011, the Company acquired a 99% ownership interest in Furry Creek and 100% of the assets comprising the Clowhom hydroelectric facilities in British Columbia, and rights to other development projects for $100.7 million, including working capital at closing and net of project debt of $12.1 million. The acquisition of Furry Creek and Clowhom has been accounted for using the acquisition method and its results of operations since the date of acquisition have been reported on a consolidated basis. Transaction costs of $1.8 million were recorded in general and administrative expenses. The purchase price was allocated to assets and liabilities as described below:

Working capital, including cash of $1.6 million 0.9

Capital assets 107.4

Intangible assets 8.6

Long-term debt (including current portion) (12.1)

Other long-term liabilities (1.4)

Deferred tax liability (2.6)

Non-controlling interest (0.1)

100.7

The intangible assets, representing water licenses and land right of way, are being amortized over a weighted average of approximately 35 years.

Note5.RestrictedCash

2012 2011

Subscription receipts – 348.6

Other Power 5.8 6.0

5.8 354.6

Proceeds from the Company’s December 16, 2011 subscription receipt offering were held in escrow at December 31, 2011 pending the fulfillment or waiver of certain conditions (note 16).

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Note6.Investmentsinjointly-Controlledbusinesses

Condensed financial information (100%) for the Company’s jointly-controlled businesses as at and for the year ended December 31:

asat yearended December December asatDecember31,2012 yearendedDecember31,2012 31,2012 31,2012

Non- Non- Profit (Loss) Equity Current Current Current Current Senior before Ownership Equity Income100% Assets Assets Liabilities (1) Liabilities (1) Debt Revenues Expenses Tax (%) Investment (Loss)

Alliance Canada (2) 95.8 1,704.9 25.5 17.5 1,200.1 466.9 358.9 108.0 50 319.0 50.0

Alliance U.S. (3) (6) 187.6 1,196.3 68.7 11.4 664.2 289.3 227.4 61.9 50 284.6 32.2

Aux Sable Canada 20.6 124.7 16.6 7.5 – 106.0 92.2 13.8 50 59.6 6.9

ASLP (4) (6) 55.1 378.5 60.1 5.3 11.9 215.3 121.6 93.7 42.7 115.3 41.4

ASM (6) 47.4 218.4 34.8 0.3 – 374.4 336.1 38.3 42.7 94.9 16.4

ACM 1.1 – 3.4 – – 111.0 135.3 (24.3) 42.7 0.4 (8.3)

Sable NGL Services 1.3 – 0.8 – – 6.8 12.8 (6.0) 50 0.3 (3.0)

York Energy Centre (5) 16.7 304.5 6.3 48.2 267.3 37.9 32.0 5.9 50 46.2 1.3

NRGreen 24.6 90.7 10.8 5.6 40.6 11.2 9.1 2.1 50 29.6 1.0

Grand Valley 4.2 54.6 4.1 45.0 – 5.1 4.8 0.3 75 7.2 0.2

Other 1.6 0.8 1.4 – – – 6.2 (6.2) 33.3–75 0.3 (2.3)

957.4 135.8

As at Year ended December December As at December 31, 2011 Year ended December 31, 2011 31, 2011 31, 2011

Non- Non- Profit (Loss) Equity Current Current Current Current Senior before Ownership Equity Income100% Assets Assets Liabilities (1) Liabilities (1) Debt Revenues Expenses Tax (%) Investment (Loss)

Alliance Canada (2) 94.5 1,839.0 39.5 18.6 1,278.0 459.6 344.4 115.2 50 342.0 53.7

Alliance U.S. (3) (6) 120.2 1,276.5 52.1 12.1 658.7 293.6 229.2 64.4 50 299.0 33.3

Aux Sable Canada 19.0 127.1 15.8 7.9 9.3 70.2 58.7 11.5 50 55.6 5.7

ASLP (4) (6) 53.1 362.9 48.5 6.1 62.2 473.6 260.5 213.1 42.7 82.6 91.8

ASM (6) 24.7 186.4 16.6 2.6 – 106.5 95.8 10.7 42.7 80.4 4.6

ACM 1.1 – 2.2 – – 163.2 189.6 (26.4) 42.7 0.7 (8.7)

Sable NGL Services 1.0 – 0.7 – – 6.9 13.4 (6.5) 50 0.2 (3.2)

York Energy Centre (5) 31.7 299.7 26.3 48.3 238.2 – 43.6 (43.6) 50 55.2 (21.8)

NRGreen 13.0 63.7 5.9 1.8 43.0 11.8 9.0 2.8 50 13.3 1.4

Grand Valley 4.9 42.1 40.9 – – – – – 75 4.6 –Other 0.9 0.8 1.1 – – – 3.8 (3.8) 33.3–75 0.5 (1.7)

934.1 155.1

(1) Current liabilities and non-current liabilities exclude senior debt.(2) At December 31, 2012, the Company had a $63.2 million (December 31, 2011 – $66.5 million) difference between the carrying value of Alliance Canada and 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, 2012, the Company had a $18.2 million (December 31, 2011 – $20.1 million) negative difference between the carrying value of Alliance U.S. and 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, 2012, the Company had a $32.8 million (December 31, 2011 – $35.4 million) negative difference between the carrying value of ASLP and 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, 2012, the Company had a $48.3 million (December 31, 2011 – $49.9 million) difference between the carrying value of York Energy Centre and 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.

(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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Note7.Rate-Regulatedaccounting

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 and administrative costs, allowances for depreciation, allowances for taxes, costs of indebtedness, and an allowed return on equity.

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 amounts related to accrued expenses that are expected to be recovered from shippers in future tolls. Similarly, no revenue is recognized by Alliance Pipeline in a given period for tolls received that do not relate to current period expenses accrued in that period. Differences between Alliance Pipeline’s recorded transportation revenue and actual toll receipts are included in Alliance Pipeline’s current assets or current 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 on the rate of return on rate base approved by regulators and are expected to be recovered in future tolls. Accordingly, these costs are being amortized to earnings on a basis consistent with the underlying assets.

A long-term receivable is recorded in Alliance Pipeline’s non-current assets related to the cumulative excess of depreciation expense charged for accounting purposes over depreciation expense recovered as revenue under Alliance’s transportation contracts. Alliance expects to recover this amount over a number of years when depreciation rates prescribed in the transportation contracts are expected to exceed depreciation rates used for accounting purposes.

Alliance’s Canadian rate-regulated operations recover tax expense using the taxes payable method, as prescribed by the NEB for ratemaking purposes. The Company has recorded a rate-regulated asset on its statement of financial position which offsets the deferred tax liability recorded.

Note8.otherCurrentassets

2012 2011

Prepaid expenses and other 6.0 7.3

Inventory 4.0 4.0

Acquisition deposit – 50.0

Deferred share issue costs – 14.2

10.0 75.5

acquisitionDeposit

The deposit represents the funds paid by the Company upon signing the purchase and sale agreement in connection with the acquisition of the Hythe/Steeprock complex (note 4).

DeferredShareIssueCosts

Deferred share issue costs relate to the subscription receipts offering. Such costs were charged to shareholders’ equity when the subscription receipts were exchanged for Common Shares (note 16).

53

Note9.Pipeline,PlantandotherCapitalassets

2012 2011 accumulated Netbook Accumulated Net book Cost depreciation value Cost depreciation value

Pipeline 469.3 (100.3) 369.0 302.8 (84.6) 218.2

Plant 498.0 (97.0) 401.0 – – –Power facilities 590.4 (30.1) 560.3 588.1 (88.8) 499.3

Administrative 9.6 (5.2) 4.4 9.1 (4.4) 4.7

Capital spares 0.9 – 0.9 0.9 – 0.9

Land 47.4 – 47.4 33.2 – 33.2

Construction work in progress 60.8 – 60.8 12.4 – 12.4

1,676.4 (232.6) 1,443.8 946.5 (177.8) 768.7

The cost and accumulated depreciation of pipeline, plant and other capital assets deemed to be under operating leases at December 31, 2012 was $92.0 million and $55.0 million, respectively (2011 – cost: $90.1 million, accumulated depreciation: $52.9 million). For the year ended December 31, 2012, these assets generated $29.4 million in operating lease revenues (2011 – $31.0 million).

Note10.Intangibleassets

2012 2011 accumulated Netbook Accumulated Net book Cost amortization value Cost amortization value

Midstream customer relationship and service agreement (note 4) 283.6 (12.6) 271.0 – – –Power agreements and licenses (note 4) 256.7 (79.4) 177.3 258.6 (69.1) 189.5

Ethane transportation agreements (“ETAs”) 15.6 (8.9) 6.7 15.6 (7.8) 7.8

555.9 (100.9) 455.0 274.2 (76.9) 197.3

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 the primary customer, 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 when constructed and 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, which expire on December 31, 2018, shippers are committed to pay a minimum firm toll based on 90% of total committed volume, and to reimburse AEGS for all operating costs, including maintenance capital.

The intangible assets are amortized on a straight-line basis. For the year ended December 31, 2012, total amortization expense for intangible assets was $23.9 million (2011 – $14.0 million). Annual amortization expense for each of the next 5 years is expected to be approximately $24.6 million.

54


Note11.long-TermSeniorDebt

2012 2011

Veresen Revolving credit facility 222.0 67.0

5.6% Senior notes due 2014 200.0 200.0

3.95% Medium term notes due 2017 300.0 –4.0% Medium term notes due 2018 150.0 150.0

5.05% Medium term notes due 2022 50.0 –

922.0 417.0

Less: current portion – –

922.0 417.0

aEGS 5.565% Senior notes due 2020 90.9 94.0

Less: current portion (3.1) (3.0)

87.8 91.0

EastwindsorCogeneration (1) 6.283% Senior bonds due 2029 161.2 166.5


155.5 161.2

ClowhomandfurryCreek Term loan due 2016 52.4 53.9

7.2947% Term loan due 2024 11.0 11.6


61.3 63.4

EnPower (1) 6.65% Term loan due 2018 21.8 22.6


21.0 21.8

1,247.6 754.4

(1) For 2011, these amounts reflect 100% of corresponding amounts contained in financial statements of the respective entities, which Veresen controlled by virtue of its majority ownership interest. The balances related to the portion not owned by Veresen are reflected in Non-Controlling Interest (note 15).

Veresen

RevolvingCreditfacilities

On December 23, 2010, the Company entered into a new revolving credit facility with a syndicate of Canadian chartered banks (the “Revolving Credit Facility”) for a three-year term. In November 2011, the term of the Revolving Credit Facility was extended to mature on November 30, 2015. In December 2011, the Company increased the maximum principal amount available under this facility from $450 million to $550 million. In December 2012, the term of the Revolving Credit Facility was extended such that it now matures on December 13, 2016. Outstanding advances bear interest based on various quoted floating rates plus a margin. A standby fee applies to any undrawn amounts. As at December 31, 2012, the Company had no letters of credit outstanding, leaving $328.0 million available under this facility (as at December 31, 2011, the Revolving Credit Facility had no letters of credit outstanding, leaving $483.0 million available under this facility).

On February 28, 2011, the Company entered into a second revolving credit agreement which provides for a $45.0 million revolving credit facility. In December 2012, the term of the second revolving credit agreement was extended such that it now matures on December 13, 2016. As at December 31, 2012, the Company had $21.0 million of letters of credit outstanding (2011 – $20.5 million), leaving $24.0 million (2011 – $24.5 million) available under this facility.

55

MediumTermNotes

On March 14, 2012, the Company issued $300 million and $50 million of senior unsecured medium term notes maturing on March 14, 2017 and March 14, 2022, respectively, and bearing interest at 3.95% and 5.05%, respectively.

On November 22, 2011, the Company issued $150 million of senior unsecured medium term notes maturing on November 22, 2018, and bearing interest at 4.0%.

VeresenNewCreditfacility

On February 9, 2012, the Company drew upon a $250 million non-revolving, floating-rate term loan, the terms of which provided for prepayments at the Company’s option at any time without premium or penalty. On March 14, 2012, the Company used the proceeds from its medium term note offerings to retire this facility in its entirety.

Clowhom

In February 2011, Clowhom entered into credit agreements with a Canadian chartered bank, which provide for a $55 million amortizing term facility and $2 million operating facility. The term facility was fully drawn and the funds used to repay amounts initially drawn on the Revolving Credit Facility to fund the Clowhom acquisition. Outstanding advances bear interest on floating rates, plus a margin.

CompliancewithDebtCovenants

Each of Veresen and its businesses were in compliance with their respective debt covenants as at December 31, 2012 and 2011.

ScheduledPrincipalRepaymentsoflong-TermSeniorDebt

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

For the years ending December 31,

2013 11.7

2014 212.5

2015 235.2

2016 60.0

2017 313.1

Thereafter 426.8

1,259.3

Note12.SubordinatedConvertibleDebentures

2012 2011

Series C Subordinated convertible debentures due 2017 86.2 86.2

Less: current portion – –

86.2 86.2

The Series C subordinated convertible debentures rank equally with all other unsecured and subordinated indebtedness of the Company. These debentures mature on July 31, 2017 and are convertible, at the holder’s option, into shares of the Company at a conversion price of $14.60 per Common Share and are redeemable at the option of the Company after July 31, 2013.

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Note13.otherlong-Termliabilities

2012 2011

Asset retirement obligations 34.1 20.8

Transportation contracts 6.9 9.4

Other 7.6 7.2

48.6 37.4


46.2 35.0

assetRetirementobligations

At December 31, 2012, $20.1 million of the consolidated asset retirement obligation (“ARO”) relates to AEGS (2011 – $18.9 million). This represents management’s estimate of the cost to abandon the ethane transportation pipeline and the timing of the costs to be incurred. Estimated cash flows were discounted at AEGS’ weighted average credit-adjusted risk free rate of return of 6.3% (2011 – 6.3%) and an inflation rate of 2.3% (2011 – 2.3%). The total undiscounted amount of future cash flows required to settle the obligation is estimated to be $110.9 million (2011 – $110.9 million). The estimated ARO costs reflect such activities as dismantling, demolition and disposal of a portion of the pipeline as well as remediation and restoration of the surface land. Payments to settle the obligation are not expected to occur prior to 2040.

The Company recognized an $11.4 million ARO relating to the Hythe/Steeprock complex upon acquisition in February 2012. At December 31, 2012, $12.0 million of the consolidated ARO relates to Hythe/Steeprock. This represents management’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% and an inflation rate of 2.0%. The total undiscounted amount of future cash flows required to settle the obligation is estimated to be $99.9 million. Expenditures to settle the obligation are not expected to occur prior to 2044.

2012 2011

Asset retirement obligations, January 1 20.8 18.6

Liabilities recognized in the current year 11.4 1.0

Accretion expense 1.9 1.2

Asset retirement obligations, December 31 34.1 20.8

TransportationContracts

The obligation under the transportation contracts relates to proceeds received by Veresen in connection with its acquisitions of additional interests in Alliance Canada Marketing and its assumption of the associated liability arising from the firm transportation contracts. This liability is being amortized on a straight-line basis over the remaining term of the transportation contracts.

other

Other long-term liabilities primarily represent $7.5 million of accruals for LTIP (2011 – $7.2 million). Payments made under the LTIP in 2012 were $6.8 million (2011 – $1.8 million).

Note14.Taxes

ComponentsofTaxes

The following is a summary of the significant components of the Company’s tax expense:

2012 2011

Current tax expense 18.2 28.1

Deferred tax expense (recovery) Origination and reversal of temporary differences 42.2 (3.3)

Change in loss carry-forwards (28.7) 18.0

Change in valuation allowance (2.9) 0.4

Total deferred tax expense 10.6 15.1

Total tax expense 28.8 43.2

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GeographicalComponents

Net income (loss) before taxes and non-controlling interest for the years ended 2012 and 2011 are as follows:

2012 2011

Net Income (loss) before taxes and non-controlling interest Canada 9.4 (21.6)

United States 66.1 118.0

Net Income before taxes and non-controlling interest 75.5 96.4

Tax expense for the years ended 2012 and 2011 are as follows:

2012 2011

Current tax expense Canada 6.8 0.1


Total current tax expense 18.2 28.1

Deferred tax expense Canada 7.1 1.6


Total deferred tax expense 10.6 15.1

Total tax expense 28.8 43.2

ComponentsofDeferredTaxes

The provision for deferred taxes arises from temporary differences in the carrying values of assets and liabilities for financial statement and income tax purposes and the effect of loss carryforwards. The items comprising the deferred tax assets and liabilities are as follows:

2012 2011

Deferred tax liabilities (assets) Investments in jointly-controlled businesses 232.6 214.1

Regulatory assets 76.4 85.8

Pipeline, plant and other capital assets 88.2 64.4

Non-capital losses (65.5) (36.7)

Asset retirement obligations (8.5) (5.1)

Deferred revenue and costs (7.0) (0.8)

Total net deferred tax liabilities 316.2 321.7

The above deferred tax balances at December 31, 2012 and 2011 are net of valuation allowances of $2.1 million and $4.6 million, respectively.

58


TaxReconciliation

The provision for taxes differs from the result that would be obtained by applying the combined Canadian federal and provincial statutory income tax rate to earnings before taxes. The difference results from a number of factors summarized in the following reconciliation:

2012 2011

Net income before taxes and non-controlling interest 75.5 96.4

Canadian statutory income tax rate 25.0% 26.5%

Income taxes at statutory rate 18.9 25.5

Increase (decrease) resulting from: Higher income tax rates in other jurisdictions 10.5 14.6

Deferred taxes related to Canadian regulated operations 7.2 6.9

Deductible intercompany interest expense (5.7) (5.2)

Adjustment in respect of prior periods (2.9) (2.0)

Withholding tax on foreign dividend – 3.0

Other 0.8 0.4

Taxes 28.8 43.2


Effective tax rate 38.1% 44.8%

The Company has Canadian and U.S. non-capital losses of $258.0 million (2011 – $127.0 million) and $0.4 million (2011 – $7.3 million), respectively. Canadian losses expire beginning in 2026. U.S. losses will expire in varying amounts from 2021 to 2029.

The Company has no unrecognized tax benefits as the recognition and measurement criterion has been met. It is more likely than not that the Company will realize its tax positions.

The Company is subject to Canadian federal and provincial income tax, and U.S. federal and state income tax. All Canadian federal and provincial income tax returns are subject to examination by the taxation authorities. All U.S. federal income tax returns and generally all U.S. state income tax returns for 2009 and subsequent years continue to remain subject to examination by the taxation authorities. In addition, years relating to non-operating losses are subject to examination.

Note15.Non-ControllingInterest

The Company’s non-controlling interests included in the Consolidated Statement of Financial Position were as follows:

2012 2011

Furry Creek 0.1 0.1

East Windsor Cogeneration – 27.0

EnPower – 4.6

0.1 31.7

The Company’s non-controlling interests included in the Consolidated Statement of Income and Comprehensive Income were as follows:

For the year ended 2012 2011

East Windsor Cogeneration 0.1 0.3

EnPower – (0.2)

0.1 0.1

Note16.ShareCapital

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.

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CommonShares

2012 2011

Common Shares Number Value Number Value

January 1 Opening balance (1) 167,374,180 1,391.0 158,861,727 1,279.6

Convertible Debentures converted into Common Shares, net of issue costs (2012 and 2011: nil) 684 – 342 –Common Shares issued under Premium Dividend and Dividend Reinvestment Plan (“DRIP”) (2) 5,704,289 75.6 7,739,986 100.3

Common Shares exchanged from subscription receipts, net of issue costs (2012: $18.2 million) 24,725,000 334.1 – –

December 31 197,804,153 1,800.7 166,602,055 1,379.9

Common Shares to be issued under DRIP (2) 308,753 3.6 772,125 11.1

198,112,906 1,804.3 167,374,180 1,391.0

(1) Includes 772,125 Common Shares valued at $11.1 million (2011 –709,321 Common Shares; $8.7 million) subsequently issued under DRIP.(2) Represents Common Shares issued to satisfy a portion of the Company’s dividends.

On December 16, 2011, the Company completed the sale of 24.7 million subscription receipts at a price of $14.10 per subscription receipt for gross proceeds of $348.6 million. The gross proceeds from the sale of the subscription receipts were being held by an escrow agent pending fulfillment or waiver of certain conditions (note 5). On February 9, 2012, each outstanding subscription receipt of Veresen was automatically exchanged for one Common Share of Veresen and a dividend equivalent payment of $0.1666 per subscription receipt in respect of the dividends declared by Veresen for the months ending December 31, 2011 and January 31, 2012.

The weighted average number of Common Shares outstanding used to determine net income per Common Share on a basic and diluted basis for the year ended December 31, 2012, was 192,523,492 (2011 – 162,630,440). The number of Common Shares outstanding would increase by 5,906,576 (2011 – 5,907,192) if the outstanding convertible debentures on December 31 were converted into Common Shares. These were excluded from the diluted earnings per Common Share calculation as the effect was anti-dilutive for the years ended December 31, 2012 and 2011.

Dividends

For the year ended December 31, 2012, the Company declared and paid dividends to common shareholders in the amount of $193.5 million or $1.00 per Common Share (2011 – $163.0 million or $1.00 per Common Share).

PremiumDividendandDividendReinvestmentPlan

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.

PreferredShares

On February 14, 2012, the Company issued 8 million Cumulative Redeemable Preferred Shares, Series A (“Series A Preferred Shares”) at a price of $25 per Series A Preferred Share. The holders of Series A Preferred Shares are entitled to receive fixed cumulative preferential cash dividends at an annual rate of 4.4%, payable quarterly for an initial period up to but excluding September 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%.

Dividends

In 2012, the Company made cash dividend payments of $7.7 million or $ 0.96 per share in respect of the Series A Preferred Shares.

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Note17.CommitmentsandContingencies

Veresen has operating leases for office premises and vehicles. Included in general, administrative and project development expense are lease expenses of $4.3 million (2011 – $2.6 million). Expected future minimum lease payments under the operating leases are as follows:

For the years ending December 31 Operating leases

2013 6.9

2014 5.7

2015 5.4

2016 4.7

2017 4.1

Thereafter 25.5

Total minimum lease payments 52.3

Certain of the Company’s gas-fired power generation facilities have entered into agreements with natural gas suppliers to purchase, in aggregate, a minimum of approximately 15.3 million cubic feet per day, at an estimated cost of approximately $13.3 million in 2013 and $8.7 million in 2014. Veresen has guaranteed some of these obligations.

On April 20, 2012, the Company, through a wholly-owned subsidiary, entered into a $36.3 million construction contract relating to two hydroelectric run-of-river facilities, Dasque Creek (12 MW) and Middle Creek (8 MW), and a 69 kilovolt transmission line. As at December 31, 2012, there was $23.2 million outstanding on this contract. In addition, the Company, through the same subsidiary, entered into contracts with an aggregate value of $18.9 million related to installation of turbines and electrical transmission lines, of which $7.4 million was outstanding at December 31, 2012.

On March 30, 2012, the Company’s equity accounted investees, Aux Sable Liquid Products, L.P., Aux Sable Extraction LP and Aux Sable Canada Ltd., were served with a Statement of Claim relating to differences in interpretation of certain terms of the NGL Sales Agreement. The Company’s share of the potential exposure, through its equity investment, is approximately $13.0 million (42.7%). At this time, the Company is unable to predict the likely outcome of this matter.

Note18.financialInstrumentsandRiskManagement


The following table summarizes the Company’s financial instrument carrying and fair values as at December 31, 2012:







Other assets 0.8 16.6 17.4 0.8



Senior debt 1,259.3 1,259.3 1,322.8




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Other assets 0.8 14.6 15.4 0.8


Subscriptions receipts payable 348.6 348.6 348.6


Senior debt 765.6 765.6 803.3




For the years ended December 31, 2012 and 2011 the following amounts were recognized in income:

2012 2011

Total interest expense, recorded with respect to other financial liabilities, calculated using the effective rate method 58.6 45.9

fairValues

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 and accrued payables, dividends payable, subscription receipts payable, and other long-term liabilities approximate their carrying amounts due to the nature of the item and/or the short time to maturity. The fair values of senior debt are calculated by discounting future cash flows using discount rates estimated based on government bond rates plus expected spreads for similarly rated instruments with 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.

Financial instruments measured at fair value as of December 31, 2012 were:

Level 1 Level 2 Level 3 Total


Restricted cash 5.8 5.8

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Maturityanalysisoffinancialliabilities

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.





Senior debt 11.7 447.7 373.1 426.8






Subscription receipts payable 348.6

Senior debt 11.2 224.2 140.3 389.9


CurrencyRisk

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. To the extent these hedges were deemed to be effective, any such gains or losses were recorded in other comprehensive income. For the years ended December 31, 2012 and December 31, 2011, there were no net investment hedges.

On December 31, 2012, approximately 37% of the Company’s net assets were denominated in U.S. dollars (2011 – 49%).

InterestRateRisk

At December 31, 2012, 22% of consolidated long-term debt was floating-rate debt (2011 – 17%).

Veresen and its jointly-controlled businesses periodically enter into interest rate hedges to manage interest rate exposures. York Energy Centre, a jointly-controlled business, entered into two interest rate hedges (“hedges”) as part of its debt financing. These hedges were entered into to manage the exposure to changes in interest rates whereby York Energy Centre receives variable interest rates and pays fixed interest rates. The first hedge, which was retired on April 30, 2012, had an initial notional amount of $37.3 million (50%) which increased over the term of the construction period of the York Energy Centre up to a maximum of $101.4 million (50%). The second hedge became effective upon the conversion of York Energy Centre’s construction facility to a term facility on July 31, 2012. This hedge had an initial notional amount of $135.1 million (50%) which declines over its 20-year term. Future changes in interest rates will affect the fair values of the hedges, 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 hedges in place as at December 31 2012:

Variable Debt Interest Rate Fixed Rate Notional Amount (50%) Fair Value (50%) Term

CAD-BA-CDOR 4.24% $133.6 $(24.1) April 30, 2012 to June 30, 2032

The following is a summary of the interest rate hedges in place as at December 31, 2011:

Variable Debt Interest Rate Fixed Rate Notional Amount (50%) Fair Value (50%) Term

CAD-BA-CDOR 1.57% $ 91.1 $(0.1) August 31, 2010 to April 30, 2012

CAD-BA-CDOR 4.24% $135.1 $(24.2) April 30, 2012 to June 30, 2032

The fair values approximate the amount that York Energy Centre would have either paid or received to settle the contract, and are included in the Company’s investment in York Energy Centre.

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CreditRisk

Veresen and its jointly-controlled businesses are exposed to credit risk as revenues are dependent upon the ability of customers to 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’s business is concentrated in the natural gas transportation industry and its revenue is dependent upon the ability of its shippers to pay their monthly demand charges. Alliance limits, to some degree, its exposure to this credit risk by requiring its shippers to provide letters of credit or other suitable security unless they maintain specified credit ratings or can demonstrate equivalent financial strength. As at December 31, 2012, Alliance held $21.4 million in letters of credit and cash deposits as security from its shippers.

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.

In the case of the Hythe/Steeprock complex, the Company is primarily dependent on one customer, a major natural gas producer, with investment-grade credit ratings.

Aux Sable’s earnings and cash flows are primarily dependent upon the long-term NGL Sales Agreement with a large, integrated energy company.

The counterparty exposures associated with the Company’s power business are diverse and are spread across numerous entities (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 satisfied with the credit quality of its financial assets. The maximum exposure to credit risk related to non-derivative financial assets is their carrying value, as disclosed previously in the table “Financial Instruments”.

liquidityRisk

Veresen and its businesses manage their liquidity requirements utilizing cash from operations, excess cash and undrawn committed credit facilities. The Company believes these sources of funding are sufficient to meet its expected liquidity requirements.

All financial liabilities classified as current on the balance sheet are expected to be settled within one year.

Note19.SegmentedInformation

Pipelines Midstream Power Corporate (1) Total

Year ended December 31 2012 2011 2012 2011 2012 2011 2012 2011 2012 2011

Equity income (loss) 82.2 87.0 53.4 90.2 2.1 (20.8) (1.9) (1.3) 135.8 155.1

Operating revenues 49.9 47.7 95.7 – 118.6 126.5 – – 264.2 174.2

Operations and maintenance (22.4) (21.6) (36.7) – (53.3) (63.5) – – (112.4) (85.1)

General, administrative and project development (2.5) (2.2) (1.6) – (20.8) (17.8) (44.6) (31.9) (69.5) (51.9)

Depreciation and amortization (13.3) (12.9) (34.1) – (33.5) (33.4) (2.2) (2.1) (83.1) (48.4)

Interest and other finance (5.2) (5.4) – – (14.1) (14.9) (39.3) (25.6) (58.6) (45.9)

Foreign exchange and other – – – – – (0.1) (0.9) (1.5) (0.9) (1.6)

Net income (loss) before taxes and non-controlling interest 88.7 92.6 76.7 90.2 (1.0) (24.0) (88.9) (62.4) 75.5 96.4

Taxes (2) – – – – – – (28.8) (43.2) (28.8) (43.2)

Non-controlling interest – – – – (0.1) (0.1) – – (0.1) (0.1)

Net income (loss) 88.7 92.6 76.7 90.2 (1.1) (24.1) (117.7) (105.6) 46.6 53.1

Preferred Share dividends – – – – – – (7.7) – (7.7) –

Net income (loss) attributable to Common Shares 88.7 92.6 76.7 90.2 (1.1) (24.1) (125.4) (105.6) 38.9 53.1

Total assets (3) 946.9 998.5 1,215.9 229.1 881.9 883.9 99.3 446.6 3,144.0 2,558.1

Capital expenditures (4) 11.1 0.3 11.3 – 48.5 10.7 20.6 7.5 91.5 18.5

(1) Reflects unallocated amounts applicable to Veresen’s head office activities. Corporate office general and administrative costs for the year ended December 31, 2012 include project development costs of $17.0 million (2011 – $8.3 million).(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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2012

Canada u.S. Total

Revenues 231.1 33.1 264.2

Equity income from jointly-controlled businesses 47.7 88.1 135.8

Investments in jointly-controlled businesses 462.5 494.9 957.4

Pipeline, plant and other capital assets 1,341.9 101.9 1,443.8

2011

Canada U.S. Total

Revenues 136.8 37.4 174.2

Equity income from jointly-controlled businesses 26.6 128.5 155.1

Investments in jointly-controlled businesses 471.7 462.4 934.1

Pipeline, plant and other capital assets 677.6 91.1 768.7

Revenues earned from one customer within the Company’s midstream segment represent approximately 36% of the Company’s 2012 operating revenues. Revenues earned from one customer within the Company’s power segment represent approximately 12% (2011 – 18%) of the Company’s 2012 operating revenues. No other customer represents over 10% of operating revenues in 2012 or 2011.

Note20.SupplementalCashflowInformation

2012 2011

Accounts receivable (32.4) (0.9)

Accrued receivables (11.6) (1.4)

Other assets (2.9) 0.6

Payables 9.1 (1.4)

Interest payable 4.4 0.1

Deferred revenue 2.8 –Accrued payables 1.8 5.8

Changes in non-cash operating working capital (28.8) 2.8

Note21.RelatedPartyTransactions

On March 30, 2012, the Company provided a $47.0 million amortizing term loan to Grand Valley, a jointly-controlled business. Principal and interest are payable on a quarterly basis. The loan bears interest of 5.2% and the maturity date is December 31, 2031.

As at December 31, 2011, the Company had a short-term construction loan receivable of $25.5 million due from Grand Valley which was settled in March 2012.

Note22.SubsequentEvents

Dividends

On February 19, 2013, the Company declared a quarterly dividend of $0.275 per share for the period ending March 31, 2013 in respect of the Series A Preferred Shares, payable on March 31, 2013 to shareholders of record on March 15, 2013.

On January 22, 2013 and February 19, 2013, the Company declared dividends of $0.0833 per Common Share for each of January and February 2013, respectively. These dividends are payable on February 22, 2013 to shareholders of record on January 31, 2013, and March 22, 2013 to shareholders of record on February 28, 2013, respectively.

VSN

Corporate Information

65

offICERS

Stephen W.C. Mulherin Chairman

Don L. Althoff President and Chief Executive Officer

David I. Holm Executive Vice President, Corporate and Business Development

Richard G. Weech Senior Vice President, Finance and Chief Financial Officer

Kevan S. King Senior Vice President, General Counsel and Secretary

DIRECToRS

J. Paul Charron (1, 3) Calgary, Alberta

John E. Feick (3, 4)* Calgary, Alberta

Maureen E. Howe (1, 4) Vancouver, British Columbia

Robert J. Iverach (1, 2, 3) Calgary, Alberta

Rebecca A. McDonald (2, 4) Houston, Texas

Stephen W.C. Mulherin (3) Calgary, Alberta

Henry W. Sykes (2, 4) Calgary, Alberta

Bertrand A. Valdman (1, 2) Bellevue, Washington

Don L. Althoff Calgary, Alberta

1 Member of the Audit Committee 2 Member of the Corporate Governance and Nominating Committee 3 Member of the Compensation Committee 4 Member of the Environmental, Health and Safety Committee

*Not standing for re-election in 2013

PublIClyTRaDEDSECuRITIES

Listed on the Toronto Stock Exchange:

CommonSharesTrading Symbol: VSN Dividend: Monthly Record Date: Last business day of each month Payment Date: 23rd day of the month following the

record date or, if not a business day, the prior business day

5.75%ConvertibleDebentures,SeriesCTrading Symbol: VSN.DB.C Interest Payable: Semi-annually on July 31

and January 31

PreferredShares,SeriesaTrading Symbol: VSN.PR.A Fixed cumulative dividends at an annual rate of 4.40%, payable quarterly

TRaNSfERaGENTaNDREGISTRaR

Computershare Trust Company of Canada 600, 530 – 8th Avenue S.W. Calgary, Alberta T2P 3S8

Phone: 1-800-564-6253 Toll Free Fax: 1-888-453-0330

Computershare also has offices in Vancouver, Toronto, Winnipeg, Montreal

NoTICEofaNNualMEETING

2:00 pm, May 8, 2013

Livingston Club Conference Centre, Livingston Place (South Tower)

Plus 15, 222 – 3rd Avenue S.W. Calgary, Alberta

All shareholders are invited to attend.

Suite 900 Livingston Place South Tower222 – 3rd Avenue SW Calgary AB T2P 0B4

learnmoreaboutVeresenatwww.vereseninc.com

2 0 1 2 V E R E S E N I N C . 97 98 99 00 01 02

2012 veresen inc. · net income attributable to common shares 38.9 5 3.1 132.7 per common share ($)...

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