Veresen Announces 2014 Second Quarter Results … Announces 2014 Second Quarter Results and Updates...

Veresen Announces 2014 Second Quarter Results and Updates Guidance

CALGARY, ALBERTA (August 6, 2014) – Veresen Inc. (“Veresen” or the “Company”) (TSX: VSN) announced today financial and operating results for the three months ended June 30, 2014.

Highlights

Veresen generated distributable cash1 of $63.7 million ($0.29 per Common Share) in the second

quarter of 2014 compared to $49.2 million ($0.25 per Common Share) in the second quarter of 2013.

Veresen recorded a net loss attributable to Common Shares of $2.4 million ($0.01 net loss per Common Share) in the second quarter of 2014 compared to net income attributable to Common Shares of $11.5 million ($0.06 net income per Common Share) in the second quarter of 2013.

Cash from operating activities was $47.9 million in the second quarter of 2014 compared to $55.0 million in the second quarter of 2013.

In July, Jordan Cove LNG achieved a key regulatory milestone with the receipt of the Notice of Schedule for the environmental review of the LNG terminal and related pipeline from the Federal Energy Regulatory Commission (“FERC”).

Alliance Pipeline filed an application with the National Energy Board (“NEB”) for regulatory approval of the tolls and tariff provisions required for Alliance to implement its proposed new services.

“We continue to make good progress in advancing our key strategic initiatives, including the re-contracting of the Alliance Pipeline and development of Jordan Cove LNG. During the first half of 2014, we also completed key financing activities to bolster our financial strength and flexibility,” said Don Althoff, President and CEO. “The filing of Alliance Pipeline’s revised toll and tariff application with the NEB, is an important milestone in the re-contracting process. Signing of Precedent Agreements with producers and shippers is ongoing as we move through the regulatory process with the NEB.”

Don Althoff added, “With the receipt of our Notice of Schedule from the FERC for our Jordan Cove LNG project, we now have a line of sight to obtaining our Final Environmental Impact Statement, and I’m confident we will obtain this critical permit.”

1 This is not a standard measure under GAAP and may not be comparable to similar measures used by other entities. See

the reconciliation of distributable cash to cash from operating activities in the tables attached to this news release. 1

Financial Highlights Three months ended

June 30 Six months ended

June 30

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

Net income (loss) before tax

Pipeline

30.0 27.5 61.5 52.3

Midstream 8.7 15.6 42.6 27.0

Power 1.7 9.5 (2.0) 10.5

Veresen – Corporate (40.6) (26.6) (69.3) (53.5)

(0.2) 26.0 32.8 36.3 Gain on sale of assets - - 14.3 - Tax recovery (expense) 1.9 (12.3) (10.0) (19.2)

Net income 1.7 13.7 37.1 17.1

Preferred Share dividends (4.1) (2.2) (8.2) (4.4)

Net income (loss) attributable to Common Shares (2.4) 11.5 28.9 12.7

Per Common Share ($) (0.01) 0.06 0.14 0.06

Financial Performance

For the three months ended June 30, 2014, Veresen recorded a net loss attributable to Common Shares of $2.4 million or $0.01 net loss per Common Share compared to net income of $11.5 million or $0.06 per Common Share for the same period last year. The decrease in earnings was primarily driven by higher project development spending related to Jordan Cove LNG, lower midstream earnings, and the revaluation of the York Energy Centre interest rate hedge. Higher project development spending in the second quarter of 2014 reflects Veresen’s efforts to further advance Jordan Cove LNG following its receipt of a conditional order from the U.S. Department of Energy to export liquefied natural gas to those countries that do not have Free Trade Agreement status with the U.S. As Veresen has continued to de-risk this project, the Company has dedicated additional resources towards its commercial, engineering and financing activities and, as anticipated, development spending has increased accordingly. The Midstream business generated net income of $8.7 million before tax for the three months ended June 30, 2014 compared to $15.6 million for the same period in 2013. Hythe/Steeprock generated consistent earnings relative to the comparative period, while Aux Sable’s results were negatively impacted by lower NGL margins resulting from higher gas prices. A revaluation of the York Energy Centre interest rate hedge resulted in an $11.7 million reduction in second quarter Power earnings compared to the same period last year. Partially offsetting this reduction was the receipt of a $3.9 million retroactive adjustment related to York Energy Centre’s power purchase agreement with the Ontario Power Authority. Second quarter 2014 results also reflect an increase in Pipeline earnings from Alliance, primarily due to higher negotiated depreciation rates and contributions from the Tioga Lateral pipeline. 2

Distributable Cash

Three months ended

June 30 Six months ended June 30


Pipeline

40.6 37.9 81.6 76.4

Midstream 27.0 23.7 69.7 50.9

Power 17.8 7.1 24.9 16.9

Veresen – Corporate (15.0) (15.8) (32.0) (34.3)

Current tax (2.6) (1.5) (6.7) (1.7)


Distributable Cash (1)

63.7 49.2 129.3 103.8

Per Common Share ($) 0.29 0.25 0.62 0.52 (1)

See the reconciliation of distributable cash to cash from operating activities in the tables attached to this news release.

For the three months ended June 30, 2014, Veresen generated distributable cash of $63.7 million or $0.29 per Common Share compared to $49.2 million or $0.25 Common Share for the same period in 2013. Higher distributable cash reflects increased contributions from each of Veresen’s Pipeline, Midstream and Power businesses, partially offset by higher taxes and Preferred Share dividends. Overview of Business Segments Pipelines In the second quarter of 2014, Alliance Pipeline filed an application with the NEB for regulatory approval of the tolls and tariff provisions required to implement Alliance’s proposed new services commencing December 1, 2015. The NEB application is a key milestone for Alliance as it reflects a move to a new business model under new natural gas transportation agreements. Regulatory approval will allow Alliance to offer its customers a menu of new services and competitive tolls replacing the 15-year service contracts that expire November 30, 2015. Alliance's new services offering reflects extensive market consultation and includes full-path and segmented receipt and delivery services, a new Canadian trading pool, and a revised hydrocarbon dewpoint specification. Alliance plans to file a regulatory application with the FERC in 2015 to revise its U.S. tariff. Alliance continues to be in active negotiations with prospective and existing shippers with respect to re-contracting its pipeline capacity post-2015. The signing of binding Precedent Agreements will be timed with the RGP agreements that Aux Sable is negotiating with the producer community.

Midstream

Veresen’s maintenance turnaround at the Steeprock natural gas processing plant in British Columbia was completed on budget and on schedule in June 2014. Turnaround activities were performed in a manner consistent with Veresen’s ongoing commitment to the health and safety of its employees and contractors, and safeguarding of the environment. The majority of the costs associated with the turnaround will be recovered under Veresen’s Midstream Services Agreement with Encana Corporation. 3

Aux Sable continues to work with producers within an economic radius of the Alliance pipeline to provide options and value for natural gas and natural gas liquids (“NGLs”) to reach large and liquid U.S. markets. Aux Sable holds several RGP agreements with producers that will enhance the value of the producers’ NGLs. In June 2014, Aux Sable executed an additional long-term RGP agreement with 7G. The agreement significantly increases the volumes originally agreed to by the companies in February 2013. Under this new long-term agreement, volumes of liquids-rich natural gas are expected to ramp up to 500 mmcf/d. These supplies will be processed at Aux Sable’s extraction and fractionation facilities located in Channahon, Illinois. Power

Construction of the Dasque-Middle run-of-river project in northwest British Columbia is proceeding as planned and it is expected to be in-service in the fourth quarter of 2014. Construction of the 33 MW St. Columban wind project is progressing, with commercial in-service expected in the first half of 2015. The 40 MW Grand Valley III wind project continues to advance through the regulatory process. Testing and commissioning of the 13 MW Whitecourt waste heat facility is ongoing and the facility is expected to be in service by the fourth quarter of 2014.

Jordan Cove LNG

In July 2014, Jordan Cove LNG and the associated Pacific Connector Gas Pipeline received their collective Notice of Schedule for environmental review from the FERC. Receipt of this schedule is an important milestone in the regulatory process. FERC’s schedule calls for a final EIS to be issued on February 27, 2015. Based on this schedule, Veresen has reviewed and updated its project timeline and expects to make a final investment decision in mid-2015. With a four-year construction period, commercial LNG production is targeted for mid- to late-2019. Once the FERC issues Jordan Cove LNG its Draft Environment Impact Statement, a public hearing process is initiated. Veresen continues to be in active negotiations to secure long-term arrangements to produce LNG for international customers. Veresen’s objective is to execute binding agreements this year for all of Jordan Cove LNG’s initial capacity of 6 million tonnes per annum. Veresen also continues to negotiate the engineering, procurement and construction contract with a joint venture formed by Kiewit and Black & Veatch for the design and construction the LNG terminal. Veresen expects the EPC contract to be completed in late 2014, following which a Class 1 cost estimate and schedule will be generated by the contractor. In the second quarter of 2014, Veresen engaged Macquarie Capital as its financial advisor for the Jordan Cove LNG project. 2014 Guidance Update Veresen has narrowed its guidance for 2014 distributable cash to be in the range of $1.02 per Common Share to $1.20 per Common Share, with a midpoint of $1.11 per Common Share. Further details concerning 2014 guidance can be found in the "Invest" section of Veresen's web site at www.vereseninc.com.

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http://www.vereseninc.com/

Conference Call and Webcast Veresen will host a conference call and webcast on August 7, 2014 at 9:00 am MT (11:00 am ET) to discuss its results. Dial-in: 1 (888) 231-8191 or 1 (647) 427-7450 Conference ID 72391260 The link to the conference call webcast is available on Veresen’s website by selecting “Invest” and then “Events & Presentations”. A replay of the call will be available at approximately 12:00 pm MT (2:00 pm ET) on August 7, 2014 by dialing 1-855-859-2056 and 1-416-849-0833. The access code is 72391260, followed by the pound sign. The replay will expire at midnight (ET) on August 14, 2014.

MD&A, Financial Statements and Notes

Management's Discussion and Analysis ("MD&A") and consolidated financial statements provide a detailed explanation of Veresen’s financial results for the second quarter ended June 30, 2014 compared to the second quarter ended June 30, 2013 and should be read in conjunction with this news release. These documents are available at www.vereseninc.com and at www.sedar.com.

About Veresen Inc.

Veresen is a publicly-traded dividend paying corporation based in Calgary, Alberta, that owns and operates energy infrastructure assets across North America. Veresen is engaged in three principal businesses: a pipeline transportation business comprised of interests in two pipeline systems, the Alliance Pipeline and the Alberta Ethane Gathering System; a midstream business which includes ownership interests in a world-class natural gas liquids extraction facility near Chicago, the Hythe/Steeprock complex, and other natural gas and NGL processing energy infrastructure; and a power business with a portfolio of assets in Canada and the United States. Veresen is also actively developing a number of greenfield projects and, in the normal course of its business, regularly evaluates and pursues acquisition and development opportunities. Veresen's Common Shares, Series A Preferred Shares, Series C Preferred Shares and 5.75% convertible unsecured subordinated debentures, Series C due July 31, 2017 are listed on the Toronto Stock Exchange under the symbols "VSN", “VSN.PR.A”, “VSN.PR.C” and VSN.DB.C", respectively. For further information, please visit www.vereseninc.com. Forward-Looking Information

Certain information contained herein relating to, but not limited to, Veresen and its businesses constitutes

forward-looking information under applicable securities laws. All statements, other than statements of historical

fact, which address activities, events or developments that Veresen expects or anticipates may or will occur in

the future, are 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 news release

include, but are not limited to, statements with respect to: the ability of Aux Sable and Alliance to implement

new service offerings; the timing of completion of construction and start-up of the Dasque-Middle hydro project

and the St. Columban Wind Project; the estimated capital cost and timing of the final investment decision of the

Jordan Cove LNG project, Veresen’s ability to negotiate long-term service agreements with offtake customers

for LNG; Veresen’s ability to realize its growth objectives; the availability of financing for current capital projects

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and new investment opportunities; and the ability of each of its businesses to generate distributable cash in

2014. The risks and uncertainties that may affect the operations, performance, development and results of

Veresen’s businesses include, but are not limited to, the following factors: the ability of Veresen to successfully

implement its strategic initiatives and achieve expected benefits; levels of oil and gas exploration and

development activity; the status, credit risk and continued existence of contracted customers; the availability

and price of capital; the availability and price of energy commodities; the availability of construction services and

materials; fluctuations in foreign exchange and interest rates; Veresen’s 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 the

prevailing economic conditions in North America. Additional information on these and other risks, uncertainties

and factors that could affect Veresen’s operations or financial results are included in its filings with the securities

commissions or similar authorities in each of the provinces of Canada, as may be updated from time to time.

Readers are also cautioned 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 Veresen believes that the expectations conveyed by the forward-looking

information are reasonable based on information available on the date of preparation, no assurances can be

given as to future results, levels of activity and achievements. Undue reliance should not be placed on the

information contained herein, as actual result achieved will vary from the information provided herein and the

variations may be material. Veresen makes 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 Veresen does 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. Any forward-looking information contained herein is expressly qualified by this cautionary

statement.

Certain financial information contained in this news release may not be standard measures under Generally

Accepted Accounting Principles ("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 Veresen see

Management’s Discussion and Analysis, in particular, the section entitled “Non-GAAP Financial Measures”

contained in the annual Management Discussion and Analysis, filed by Veresen with Canadian securities

regulators.

# # #

For further information, please contact: Dorreen Miller, Director, Investor Relations Phone: (403) 213-3633 Email: [email protected]

NOT FOR DISTRIBUTION TO UNITED STATES NEWSWIRE SERVICES OR FOR DISSEMINATION IN THE UNITED STATES.

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VERESEN INC.Management’s Discussion and AnalysisThree and six months ended June 30, 2014

FINANCIAL AND OPERATING HIGHLIGHTS

Three months ended June 30 Six months ended June 30

($ Millions, except where noted) 2014 2013 2014 2013

Operating Highlights (100%)Pipeline

Alliance – billion cubic feet per day 1.530 1.554 1.593 1.593

AEGS – thousand barrels per day 1 282.8 290.4 289.8 292.8

Midstream

Hythe/Steeprock – million cubic feet per day 2 399.9 412.6 400.0 413.8

Aux Sable – thousand barrels per day 75.5 55.2 66.7 62.7

Power – gigawatt hours (net) 233.7 225.2 489.1 419.1

Financial ResultsEquity income 27.1 41.2 79.3 69.6

Operating revenues 89.3 89.8 181.3 161.4


Per Common Share ($) – basic and diluted (0.01) 0.06 0.14 0.06

Cash from operating activities 47.9 55.0 92.9 92.4

Distributable cash 3, 4 63.7 49.2 129.3 103.8

Per Common Share ($) – basic and diluted 0.29 0.25 0.62 0.52

Dividends paid/payable 5 55.0 49.8 105.4 99.4

Per Common Share ($) 0.25 0.25 0.50 0.50

Capital expenditures 6 39.9 15.0 80.5 24.1

June 30, 2014As at

Dec. 31, 2013

Financial PositionCash and short-term investments 219.5 26.6

Total assets 3,186.5 2,973.4

Senior debt 1,169.3 1,187.5

Subordinated convertible debentures 85.3 86.2

Shareholders’ equity 1,530.6 1,305.7

Common SharesOutstanding – as at period end

7 220,342,222 201,476,244

Average daily volume 575,370 302,801

Price per Common Share – close ($) 18.75 14.27

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 $14.0 million and $25.0 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 three and six months ended June 30, 2014 (2013 -

$11.0 million and $21.8 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 August 1, 2014 we had 220,625,395 Common Shares outstanding.

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This MD&A, dated August 6, 2014, provides a review of the significant events and transactions that affected our

performance during the three and six months ended June 30, 2014 relative to the same periods last year. It

should be read in conjunction with our consolidated financial statements and notes as at and for the three and

six months ended June 30, 2014 and as at and for the year ended December 31, 2013, prepared in accordance

with accounting principles generally accepted in the United States.

ACCOUNTING STANDARDS AND BASIS OF PRESENTATION

Our consolidated financial statements as at and for the three and six months ended June 30, 2014 have been

prepared by management in accordance with US GAAP. 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 2013 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-LOOKING AND NON-GAAP INFORMATION

Some 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; • Aux Sable’s ability to realize upon the extraction agreements with producers and to attract volumes into the Alliance pipeline;• the 2014 pricing environment for ethane and propane;• producer responses to the expansion of the Hythe gas processing facility;• the projected in-service date of NRGreen’s Whitecourt Recovered Energy Project;• the projected in-service date of the Dasque-Middle run-of-river facility;• the projected in-service date of the St. Columban wind project;• 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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OVERALL FINANCIAL PERFORMANCE

Net Income attributable to Common Shares



Net income (loss) before tax

Pipeline 30.0 27.5 61.5 52.3

Midstream 8.7 15.6 42.6 27.0

Power 1.7 9.5 (2.0) 10.5

Veresen–Corporate (40.6) (26.6) (69.3) (53.5)

Gain on sale of assets - - 14.3 -

Tax recovery (expense) 1.9 (12.3) (10.0) (19.2)

Net income 1.7 13.7 37.1 17.1


Net income (loss) attributable to CommonShares (2.4) 11.5 28.9 12.7

Per Common Share ($) (0.01) 0.06 0.14 0.06

For the three and six months ending June 30, 2014, we generated a net loss attributable to Common Shares of

$2.4 million or $0.01 per Common Share and net income of $28.9 million or $0.14 per Common Share,

respectively. For the same periods last year, we generated income of $11.5 million or $0.06 per Common Share

and $12.7 million or $0.06 per Common Share.

The decrease in second quarter earnings was primarily driven by three factors:

• higher project development spending relating to our Jordan Cove LNG project;

• higher natural gas prices impacting midstream earnings; and

• the revaluation of the York Energy Centre interest rate hedge.

Year-to-date earnings were buoyed by the strength of first quarter results, which benefited from an

unprecedented widening of the Chicago - AECO natural gas price differential and gains on asset sales.

In March 2014, our proposed Jordan Cove LNG project received a conditional order from the U.S. Department

of Energy to export LNG to countries that do not have Free Trade Agreement status with the United States. With

the reduction in risk resulting from receipt of this conditional order, we dedicated additional resources towards

our commercial, engineering, and financing work efforts. Consequently, as anticipated, our development

spending has increased accordingly.

The Midstream business generated $8.7 million and $42.6 million of net income before tax for the three and six

months ended June 30, 2014, compared to $15.6 million and $27.0 million for the same periods last year.

Hythe/Steeprock generated consistent earnings relative to the comparative period, while Aux Sable’s results

were negatively impacted by lower NGL margins resulting from higher gas prices.

The Power segment had strong operational performance in the quarter and also reflect the receipt of a $3.9

million retroactive adjustment in relation to York Energy Centre’s power purchase agreement with the Ontario

Power Authority. From an earnings perspective, this was offset by the impact of the revaluation of the York

Energy Centre interest rate hedge which resulted in an $11.7 million and $17.6 million reduction in Power

earnings for the three and six months periods, respectively, compared to the same periods last year.

Current quarter and year-to-date earnings also reflect higher Pipeline earnings from Alliance primarily due to

higher negotiated depreciation rates and contributions from the Tioga Lateral pipeline.

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Distributable CashThree months ended June 30 Six months ended June 30


Pipeline 40.6 37.9 81.6 76.4

Midstream 27.0 23.7 69.7 50.9

Power 17.8 7.1 24.9 16.9


Current tax (2.6) (1.5) (6.7) (1.7)


Distributable Cash (1) 63.7 49.2 129.3 103.8

Per Common Share ($) 0.29 0.25 0.62 0.52

(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 for the three and six months ended June 30, 2014, we generated distributable cash of $63.7 million and

$129.3 million or $0.29 and $0.62 per Common Share, compared to $49.2 million and $103.8 million or $0.25

and $0.52 per Common Share for the same periods last year.

The increase in distributable cash reflects increased contributions from each of our business segments, partially

offset by higher taxes and Preferred Share dividends.

Although Aux Sable second quarter earnings decreased relative to the comparative period, distributions

increased by $2.3 million as some of the income earned during the first quarter of 2014 was carried over and

realized as cash in the second quarter. Aux Sable distributions for the year-to-date increased by $16.8 million

compared to the same period last year on the strength of first quarter 2014 earnings.

Distributions from Hythe/Steeprock increased by $1.0 million and $2.0 million over the same periods last year

due to higher capital recoveries and the impact of annual fee escalation.

Alliance generated an additional $2.1 million this quarter and $4.4 million over the first half of the year which

was largely driven by higher negotiated depreciation rates and contributions from the Tioga Lateral pipeline.

Power distributable cash increased on both a quarter and year-to-date basis from higher earnings at York

Energy Centre which benefited from a one-time retroactive revenue settlement adjustment, and higher cash

flows at our other Ontario gas-fired facilities and our Glen Park run-of-river facility, which benefited from high

energy prices influenced by the extreme cold temperatures in the first few months of the year.

Current tax was higher in the current year due primarily to higher U.S.-based taxable earnings from our Pipeline

business.

Higher Preferred Share dividends reflect the October 2013 issuance of Preferred Shares.

Cash from Operating ActivitiesThree months ended June 30 Six months ended June 30

($ Millions) 2014 2013 2014 2013

Pipeline 36.9 37.8 82.3 77.2

Midstream 32.4 26.2 66.0 56.2

Power 14.6 10.5 18.3 24.3


47.9 55.0 92.9 92.4

For the three and six months ended June 30, 2014, we generated $47.9 million and $92.9 million of cash from

operating activities compared to $55.0 million and $92.4 million for the same periods last year. The decrease in

the current quarter reflects higher Corporate cash outflows largely driven by higher project development costs,

partially offset by lower interest costs. These decreases were partially offset by higher operating cash flows from

our Midstream and Power businesses driven by the same factors impacting distributable cash.

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Cash from operating activities on a year-to-date basis is consistent with the prior year, with the changes by

business segment generally reflecting the same factors impacting distributable cash. Power operating cash

flows were further reduced by changes in non-cash working capital and Corporate cash outflows were further

increased by higher project development costs.

RESULTS OF OPERATIONS – BY BUSINESS SEGMENT

Pipeline Business

Three months ended June 30, 2014 Three months ended June 30, 2013

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

Earnings before interest, tax depreciation and amortization (“EBITDA”)

(1) 6.8 - 6.8 6.2 - 6.2

Depreciation and amortization (3.5) - (3.5) (3.5) - (3.5)

Interest and other finance (1.3) - (1.3) (1.2) - (1.2)

Equity income 28.0 28.0 - 26.0 26.0 -

Net income before tax 30.0 28.0 2.0 27.5 26.0 1.5

Distributable cash 40.6 35.8 4.8 37.9 33.7 4.2

Volumes (100%) 1.530 282.8 1.554 290.4

bcf/d mbbls/d (2)bcf/d mbbls/d

(2)

Pipeline Business

Six months ended June 30, 2014 Six months ended June 30, 2013

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

Earnings before interest, tax depreciation and amortization (“EBITDA”)

(1) 13.6 - 13.6 12.8 - 12.8

Depreciation and amortization (7.0) - (7.0) (7.0) - (7.0)

Interest and other finance (2.5) - (2.5) (2.5) - (2.5)

Equity income 57.4 57.4 - 49.0 49.0 -



Volumes (100%) 1.593 289.8 1.593 292.8

bcf/d mbbls/d (2)bcf/d mbbls/d

(2)

(1) 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.

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

Alliance Pipeline

Operational Highlights

Transportation deliveries for the three and six months ended June 30, 2014 averaged 1.530 bcf/d and 1.593

bcf/d, compared to 1.554 bcf/d and 1.593 bcf/d for the same periods last year.

Financial Highlights

Distributable cash for the three and six months ended June 30, 2014 was $35.8 million and $72.0 million

compared to $33.7 million and $67.6 million for the same periods last year. The increases reflect higher

revenues due to an increase in negotiated depreciation rates and contributions from the Tioga Lateral, along

with a weakening of the Canadian dollar in 2014.

Net income before tax for the three and six months ended June 30, 2014 was $28.0 million and $57.4 million

compared to $26.0 million and $49.0 million for the same periods last year. This increase reflects the factors

impacting distributable cash and a first quarter 2013 reduction in the recoverable toll costs.

11

Outlook

Subject to regulatory approval, Alliance is offering capacity for transportation commencing December 1, 2015,

under a proposed new services framework. The new services framework, which includes both fixed and flexible

tolling options, responds to current market requirements and the diverse needs of existing and prospective

shippers. The new service offering includes both full-path and segmented services with a new Canadian trading

pool and a revised hydrocarbon dewpoint specification, which will facilitate the transportation of higher heat

content natural gas. The services offer shippers competitive fixed tolls for medium and long-term services and

biddable tolls for interruptible and seasonal service.

On May 22, 2014, Alliance Canada filed an application with Canada's National Energy Board for regulatory

approval of the tolls and tariff provisions Alliance needs to implement its new services. Similarly, Alliance USA

will be applying to the U.S. Federal Energy Regulatory Commission in 2015 for regulatory approval. On June 6,

2014, the NEB issued a procedural letter for the purpose of soliciting comments from interested parties by July

7, 2014, stating their position with respect to the application and what further process, if any, the NEB should

establish prior to deciding on the application. Comments were submitted by 12 interested parties with 11 parties

supportive of a written proceeding. Alliance filed its reply comments on July 21, 2014 and is awaiting direction

from the NEB as to next steps.

During the first half of 2014, Alliance placed into service several new receipt interconnection facilities that

increased the pipeline's receipt capacity by 130 mmcf/d from developing liquids-rich sources of natural gas in

northeastern British Columbia and northwestern Alberta. The cost to provide these receipt facilities is funded by

the requesting customer. A number of additional receipt interconnection facilities are in the planning and design

stage.

AEGS


Toll volumes for the three and six months ended June 30, 2014 were 282.8 thousand barrels per day and 289.8

mbbls/d, respectively, compared to 290.4 mbbls/d and 292.8 mbbls/d for the same periods last year. A planned

turnaround for a major petrochemical plant served by AEGS and additional outages at facilities connected to

AEGS resulted in lower ethane deliveries relative to last year.


For the three and six months ended June 30, 2014, AEGS generated $4.8 million and $9.6 million in

distributable cash, respectively, and $2.0 million and $4.1 million in net income before tax. Current year results

reflect higher toll revenues.

Midstream Business

Three months ended June 30, 2014 Three months ended June 30, 2013

($ Millions, except where noted) TotalHythe/

Steeprock Aux Sable TotalHythe/

Steeprock Aux Sable

EBITDA 17.8 17.8 - 17.8 17.8 -Depreciation and amortization (9.9) (9.9) - (9.8) (9.8) -Equity income 0.8 - 0.8 7.6 - 7.6



Volumes (100%)Fee Volumes

(1) 399.9 412.6

mmcf/d mmcf/d

Ethane 26.5 9.2

Propane plus 49.0 46.0

75.5 55.2

mbbls/d mbbls/d

12

Midstream Business

Six months ended June 30, 2014 Six months ended June 30, 2013

($ Millions, except where noted) TotalHythe/

Steeprock Aux Sable TotalHythe/

Steeprock Aux Sable

EBITDA 36.0 36.0 - 36.0 36.0 -Depreciation and amortization (19.8) (19.8) - (19.7) (19.7) -Equity income 26.4 - 26.4 10.7 - 10.7



Volumes (100%)Fee Volumes

(1) 400.0 413.8

mmcf/d mmcf/d

Ethane 21.2 19.5

Propane plus 45.5 43.2

66.7 62.7

mbbls/d mbbls/d

(1) 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 20-year midstream services agreement, referred to as

the “MSA”, entered into on February 9, 2012 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.


For the three and six months ended June 30, 2014, fee volumes at Hythe/Steeprock averaged 399.9 mmcf/d

and 400.0 mmcf/d respectively, which is comprised of the minimum volume commitment from our primary

customer and natural gas from third party producers. Fee volumes decreased three percent compared to the

same period last year, reflecting the annual contractual adjustments in the minimum volume commitment under

the MSA and lower volumes from third party producers.

As part of our ongoing commitment to asset integrity and reliability, we successfully completed the Steeprock

facility turnaround in the month of June. The full scope of the turnaround was completed under budget and

ahead of schedule. The minimum volume commitment under the MSA remained applicable during the

turnaround period. A turnaround of this scale for the Steeprock facility is currently planned to be completed

every three years.

During the second quarter of 2014, excluding the turnaround period, the Hythe and Steeprock facilities operated

at reliability factors of 99.8% and 100%, respectively, which exceeded the target factors under the MSA.


For the three and six months ended June 30, 2014, distributable cash for Hythe/Steeprock was $18.7 million

and $37.3 million respectively, compared to $17.7 million and $35.3 million for the same periods last year. The

higher distributable cash was due to a combination of higher revenues related to recovery of maintenance

capital expenditures from our primary customer coupled with the annual fee escalation as per the MSA.

Net income before tax for the three and six months ended June 30, 2014 was $7.9 million and $16.2 million

respectively, approximating earnings from the same periods last year and underscoring the stability of earnings

generated under the MSA.

13

Aux SableNGL Market Overview


2014 2013 2014 2013

Average USGC ethane margin (US$/gallon) 0.00 0.00 (0.01) 0.01

Average USGC propane plus margin (US$/gallon) 0.76 0.70 0.84 0.77

Average Henry Hub natural gas (US$/mmbtu) 4.58 4.01 4.83 3.75

Average WTI crude oil (US$/bbl) 102.99 94.2 100.84 94.3

Average Chicago - AECO differential ($/mmbtu) 0.38 0.64 2.64 0.57

Following the volatile natural gas price environment in the first quarter created by extremely cold temperatures

in the U.S. Mid-West, natural gas prices moderated in the second quarter. The Chicago Citygate gas price

averaged US$4.65 per mmbtu in the second quarter compared to US$9.74 per mmbtu in the first quarter and

US$4.08 per mmbtu for the second quarter in 2013.

U.S. Gulf Coast ethane margins were zero or close to zero on a quarter and year-to-date basis in both 2014 and

2013. Ethane continues to be oversupplied with widespread rejection, particularly in the Rockies, Upper

Midwest and Appalachian regions, driving down prices which in turn are completely offset by the cost of make-

up gas.

USGC propane plus margins for the three and six month periods increased relative to the same periods last

year due to a stronger pricing environment. Margins realized by Aux Sable were less favourable due to higher

make-up gas costs.

Following a volatile first quarter in 2014 that saw propane in short supply due to a harsh winter, a strong crop

drying season and significant year-over-year growth in export activity, propane storage levels in the U.S.

rebounded sharply in the second quarter, primarily driven by USGC inventory builds. Overall, U.S. propane

inventories were 52 million barrels at the end of the second quarter of 2014, more than doubling over the first

quarter and only 2%, or 1 million barrels, below the end of the second quarter of 2013.



2014 2013 2014 2013

Average volume receipts

Prairie Rose Pipeline (mmcf/d) 98.0 107.0 93.0 102.0

Average sales

Ethane (mbbls/d) 26.5 9.2 21.2 19.5

Propane plus (mbbls/d) 49.0 46.0 45.5 43.2

Total NGLs (mbbls/d) 75.5 55.2 66.7 62.7

During the three and six months ended June 30, 2014, Aux Sable processed 98% of the natural gas delivered

by Alliance compared to 99% for the same periods last year. The slight decreases are attributed to uneconomic

margins coupled with brief operational downtime for maintenance.

Receipts into the Prairie Rose Pipeline in North Dakota averaged 98 mmcf/d and 93 mmcf/d during the three

and six months ended June 30, 2014, respectively, compared to 107 mmcf/d and 102 mmcf/d for the same

periods last year. The average heat content of the natural gas delivered to the Alliance interconnection at

Bantry, North Dakota was approximately 1,365 btu/ft3 and 1,372 btu/ft3 for the three and six months ended

June 30, 2014, respectively, compared to 1,381 btu/ft3 and 1,375 btu/ft3 for the same periods last year. Prairie

Rose Pipeline’s volumes and heat content have been reduced due to the movement of certain volumes to the

Tioga Lateral, commencing in the second quarter of 2014. The heat content of the liquids-rich natural gas

stream being delivered out of the Bakken continues to be very high. In comparison, the heat content including

14

western Canada natural gas delivered on the Alliance system for the six months ended June 30, 2014 averaged

1,120 btu/ft3.

Aux Sable sold 75.5 mbbls/d and 66.7 mbbls/d of NGLs during the three and six months ended June 30, 2014,

respectively, compared to 55.2 mbbls/d and 62.7 mbbls/d for the same periods last year. Average ethane

volumes sold increased to 26.5 mbbls/d and 21.2 mbbls/d for the three and six months ended June 30, 2014,

respectively, from 9.2 mbbls/d and 19.5 mbbls/d for the same periods last year. Increased ethane sales volumes

are attributable to lower reinjection, although margins remain very low.

Propane plus sales volumes were 49 mbbls/d and 45.5 mbbls/d for the three and six months ended June 30,

2014, respectively, compared to 46 mbbls/d and 43.2 mbbls/d for the same periods last year due to increased

contracted volumes, primarily from the success Aux Sable has achieved through their Rich Gas Premium

Agreement initiative, and the commencement of the Tioga Lateral in the second quarter of 2014.


For the three months ended June 30, 2014, Aux Sable generated $8.3 million of distributable cash and $0.8

million in net income before tax, compared to $6.0 million of distributable cash and $7.6 million in net income

before tax during the same period last year. For the six months ended June 30, 2014, Aux Sable generated

$32.4 million of distributable cash and $26.4 million of net income before tax, compared to $15.6 million of

distributable cash and $10.7 million of net income before tax during the same period last year.

Net income decreased in the current quarter primarily due to higher make-up gas prices, and lower volumes

flowing through Aux Sable's Palermo Conditioning Plant as a result of the Hess Tioga Gas Plant commencing

service in May 2014. Net income on a year-to-date basis increased significantly, benefiting from the positive

margins generated from the purchase and sale of natural gas utilizing Alliance pipeline capacity held by certain

Aux Sable entities in the first quarter. Aux Sable benefited from the significant widening Chicago - AECO gas

price differential driven by the extreme cold winter weather in the U.S. Mid-West during the first quarter.

Distributable cash increased during the quarter and on a year-to-date basis. Some of the income earned during

the first quarter of 2014 was carried over and realized as cash in the second quarter. Year-to-date distributions

increased on the strength of first quarter 2014 earnings.

For the six months ended June 30, 2014, the Channahon fractionation facility generated $6.2 million of margin-

based lease revenues, none of which was recognized in income. During the same period last year, the facility

generated $11.6 million, of which $1.1 million was recognized in the second quarter. The decrease from the

prior year reflects the high cost of make-up gas eroding NGL margins, particularly in the first quarter.

Power BusinessThree months ended June 30, 2014 Three months ended June 30, 2013

($ Millions, exceptwhere noted) Total

Gas-Fired/DistrictEnergy Renewables

Power-Corporate Total


Power-Corporate

EBITDA 14.7 11.3 5.4 (2.0) 12.4 10.2 4.9 (2.7)

Depreciation and amortization (10.7) (8.4) (2.3) - (8.4) (6.0) (2.3) (0.1)

Interest and other finance (3.8) (2.4) (1.4) - (3.6) (2.5) (1.1) -

Equity income 1.3 0.5 0.8 - 9.1 8.6 0.5 -

Foreign exchange andother 0.2 - - 0.2 - - - -

Net income (loss)before tax 1.7 1.0 2.5 (1.8) 9.5 10.3 2.0 (2.8)

Distributable cash 17.8 13.9 6.0 (2.1) 7.1 6.3 3.5 (2.7)

Volumes (GWh)Gross 261.0 93.0 168.0 - 250.2 92.2 158.0 -

Net 233.7 86.9 146.8 - 225.2 87.1 138.1 -

15

Power BusinessSix months ended June 30, 2014 Six months ended June 30, 2013

($ Millions, exceptwhere noted) Total


Power-Corporate Total


Power-Corporate

EBITDA 25.8 21.5 8.7 (4.4) 22.1 19.5 7.4 (4.8)

Depreciation and amortization (20.8) (16.2) (4.6) - (16.9) (12.2) (4.5) (0.2)

Interest and other finance (7.3) (4.9) (2.4) - (7.2) (5.0) (2.2) -

Equity income - (2.0) 2.0 - 12.5 10.9 1.6 -

Foreign exchange andother 0.3 - - 0.3 - - - -

Net income (loss)before tax (2.0) (1.6) 3.7 (4.1) 10.5 13.2 2.3 (5.0)

Distributable cash 24.9 20.1 9.3 (4.5) 16.9 16.2 5.5 (4.8)

Volumes (GWh)Gross 563.3 276.0 287.3 - 475.5 195.0 280.5 -

Net 489.1 248.2 240.9 - 419.1 182.2 236.9 -

Operational Highlights and Project Updates

During the first half of 2014, our power facilities operated in line with our expectations.

We continue to progress construction of the Dasque-Middle run-of-river hydro facility in northwest British

Columbia. Commercial in-service is expected in the fourth quarter of 2014.

The 13-MW Whitecourt waste heat facility, currently being constructed by NRGreen, is nearing completion. The

commercial in-service date has been delayed to the fourth quarter of 2014. Construction of the 33 MW St.

Columban wind project commenced during the first quarter of 2014 with completion and in-service date

expected in Q1 2015.


For the three and six months ended June 30, 2014, distributable cash was $17.8 million and $24.9 million, an

increase of $10.7 million and $8.0 million compared to the same periods last year.

Our gas-fired facilities and district energy systems contributed $7.6 million of additional distributable cash for the

current period compared to last year primarily due to higher cash flows from the York Energy Centre. In addition

to its strong operating performance, York Energy Centre results reflect a retroactive adjustment received in

relation to its power purchase agreement with the OPA. The amendment to the contract was made to address

current Independent Electricity System Operator market rules that were not contemplated in the original

contract. The original contract payment mechanism resulted in a misalignment between contract capacity and

actual power generation. The amended contract capacity payment mechanism corrects this misalignment. The

retroactive adjustment was applied to the period from commencement of operations in May 2012 to April 2014,

amounting to $3.9 million.

Second quarter distributable cash from our renewable power facilities increased by $2.5 million compared to the

same three month period last year, driven primarily by higher production at our Glen Park run-of-river hydro

facility and EnPower.

Net income before tax was $1.7 million for the three months ended June 30, 2014 and a net loss of $2.0 million

for the six months ended June 30, 2014, a $7.8 million and $12.5 million decrease compared to the same

periods last year. The decrease is mainly attributable to a $3.5 million and $7.7 million fair value loss related to

York Energy Centre's interest rate hedges in the current quarter and year-to-date 2014, respectively, compared

to a $8.2 million and $9.9 million gain for the same periods in 2013, coupled with higher depreciation associated

with our California cogeneration facilities.

16

Veresen-CorporateThree months ended June 30 Six months ended June 30

($ Millions) 2014 2013 2014 2013

Equity loss 3.0 1.5 4.5 2.6

General & administrative 6.3 5.7 14.2 14.2

Project development 21.0 9.1 30.3 15.8

Depreciation and amortization 0.7 0.6 1.3 1.1

Interest and other finance 9.2 10.8 19.0 21.4

Foreign exchange and other 0.4 (1.1) - (1.6)

Net expenses before tax 40.6 26.6 69.3 53.5

Current tax 4.2 2.4 9.9 3.4

Deferred tax (6.1) 9.9 0.1 15.8

Net expenses 38.7 38.9 79.3 72.7

Effective rate 950.0% 47.3% 21.2% 52.9%

Distributable cash (15.0) (15.8) (32.0) (34.3)

For the three and six months ended June 30, 2014, we incurred $40.6 million and $69.3 million, respectively, of

net corporate expenses before taxes, a $14.0 million and $15.8 million increase compared to the same periods

last year. The increase largely reflects higher project development spending related to our Jordan Cove LNG

and Pacific Connector Gas Pipeline projects.

Current tax is higher in 2014 due primarily to higher U.S.-based taxable earnings from our Pipeline business.

Our effective tax rate for the six months ending June 30, 2014 was lower due to higher Canadian earnings

which are subject to a lower tax rate relative to the U.S. and the gains on sale of the Culliton Creek run-of-river

development project and our 50% interest in Alton Gas Storage which are subject to the Canadian capital gains

tax rate.

Jordan Cove LNG Development Project

On March 24, 2014, we received a conditional order from the U.S. DOE to export LNG from the proposed

Jordan Cove LNG export terminal to those countries that do not have FTA status with the United States. Under

the DOE order, we are permitted to export natural gas to meet Jordan Cove's initial LNG capacity production of

six million tonnes per annum (mtpa). The DOE authorization is for a term of 20 years, commencing on the date

of first export.

In the first quarter of 2014, we also received authorization from the DOE to import natural gas from Canada to

serve the proposed Jordan Cove LNG terminal.

In July 2014, Jordan Cove LNG and the associated Pacific Connector Gas Pipeline received their collective

Notice of Schedule for environmental review from the FERC. Receipt of this schedule is an important milestone

in the regulatory process. FERC’s schedule calls for a final Environment Impact Statement ("EIS") to be issued

on February 27, 2015. Based on this schedule, we reviewed and updated the project timeline and expect to

make a final investment decision in mid-2015. With a four-year construction period, commercial LNG production

is targeted for mid- to late-2019. Once the FERC issues Jordan Cove LNG its Draft EIS, a public hearing

process is initiated.

We continue to be in active negotiations to secure long-term arrangements to produce LNG for international

customers. Our objective is to execute binding agreements this year for all of Jordan Cove LNG’s initial capacity

of 6 million tonnes per annum.

We also continue to negotiate the engineering, procurement and construction contract with a joint venture

formed by Kiewit and Black & Veatch for the design and construction of the LNG terminal. We expect the EPC

contract to be completed in late 2014, following which a Class 1 cost estimate and schedule will be generated

by the contractor.

We are making good progress in determining the optimal ownership interest for the Company in Jordan Cove

LNG, with the objective of maximizing shareholder value while managing the risk profile associated with the

project. Ultimately, the ownership structure may be driven by the desire of off-take customers to take an equity

17

position in the project. Beyond off-take customers, we are also considering other strategic partners. In the

second quarter of 2014, we engaged Macquarie Capital as our financial advisor for the Jordan Cove LNG

project.

LIQUIDITY AND CAPITAL RESOURCES


($ Millions, except where noted) 2014 2013 2014 2013

Cash flows

Operating activities 47.9 55.0 92.9 92.4

Investing activities (48.7) (28.8) (65.9) (62.8)

Financing activities 184.4 (20.8) 166.6 (18.1)

June 30, 2014 December 31, 2013

Cash and short-term investments 219.5 26.6

Capitalization

Senior debt (1) 1,169.3 41% 1,187.5 45%

Subordinated convertible debentures 85.3 3% 86.2 3%

Other long-term liabilities 48.6 2% 48.5 2%

Shareholders’ equity 1,530.6 54% 1,305.7 50%

2,833.8 100% 2,627.9 100.0%

(1) Includes current portion of long-term senior debt.

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, 2013.

At June 30, 2014, we had cash and short-term investments of $219.5 million (December 31, 2013 - $26.6

million) and non-cash working capital of $60.8 million, excluding $200.0 million of senior notes due in July 2014

(December 31, 2013 - $43.6 million). Our cash balance as at June 30, 2014 included the proceeds of the June

10, 2014 $200.0 million senior note issuance, discussed below, which was used to redeem the $200 million

senior notes maturing in July 2014.

We expect to continue to utilize cash from operations, drawings on our Revolving Credit Facility, and cash

raised through our April 2014 common equity issuance (see Equity Financing Activities) and DRIP to fund our

cash requirements. Our Revolving Credit Facility is undrawn as at June 30, 2014.

Investing Activities For the six months ended June 30, 2014, we used $65.9 million of cash to fund our investing activities,

compared to $62.8 million in the same period last year. Significant investing activities for the six months ended

June 30, 2014 included:

• $12.7 million in equity contributions to our jointly-controlled businesses;

• $80.5 million of capital expenditures, primarily related to the construction of the Dasque-Middle run-of-

river hydro facility ($23.9 million), the St. Columban wind project ($48.5 million), our Midstream business

($4.6 million), and our operating power facilities ($3.4 million);

• $18.7 million of proceeds from the sale of assets; and

• $11.2 million return of capital relating to Aux Sable Canada's sale of a 50% interest in the Septimus Gas

Plant.

Investing activities for the same period last year included:

• $35.9 million in equity contributions to our jointly-controlled businesses; and

18

• $24.1 million of capital expenditures, primarily related to our Midstream business ($8.0 million),

construction of the Dasque-Middle run-of-river hydro facility ($9.9 million), and our operating power

facilities ($4.3 million).

Financing Activities For the six months ended June 30, 2014, we had $166.6 million of cash inflows to fund our financing activities,

compared to $18.1 million cash used for the same period last year. Financing activities for the six months ended

June 30, 2014 included:

• $272.9 million of Common Shares issued, net of issue costs;

• $80.1 million of Common Share dividend payments;

• $162.5 million of net repayments on our Revolving Credit Facility;

• $198.7 million of long-term debt issued, net of issue costs;

• $56.3 million of senior debt repayments; and

• $8.2 million of Preferred Share dividend payments.

Significant financing activities for the same period last year included:

• $77.6 million of Common Shares dividend payments;

• $67.0 million of net draws from our Revolving Credit Facility;

• $5.8 million of senior debt repayments; and

• $4.4 million of Preferred Share dividend payments.

Equity Financing Activities On April 3, 2014 we issued 17.3 million Common Shares at a price of $16.50 per share, providing gross

proceeds of approximately $284.6 million. The net proceeds from the Offering will be used to finance

development costs relating to our proposed Jordan Cove LNG development project, to partially fund 2014

growth capital expenditures relating to our Dasque-Middle and St. Columban renewable power projects

currently under construction, to reduce our outstanding indebtedness and for general corporate purposes.

Debt Financing Activities On June 10, 2014, we issued $200 million of senior unsecured medium term notes maturing on June 13,

2019, bearing interest at 3.06% per annum. The net proceeds of the offering were used on July 10, 2014 to

redeem all of our outstanding $200 million senior notes, which were scheduled to mature on July 28, 2014.

In June 2014, the term of the Revolving Credit Facility was extended such that it now matures on

May 31, 2018.

On May 30, 2014 we extinguished the remaining outstanding balance of $50.4 million of the

Clowhom term loan, which was scheduled to mature on February 21, 2016.

DIVIDENDS

PolicyOur 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 our Common Shares 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 4.40%, payable quarterly. The dividend rate will reset on September 30, 2017 and every five

years thereafter based on then-market rates.

The holders of Series C Preferred Shares are entitled to receive fixed cumulative preferential cash dividends at

an annual rate of 5.00%, payable quarterly. The dividend rate will reset on March 31, 2019 and every five years

thereafter based on then-market rates.

19

Sustainability of Dividends and Productive CapacityWe 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 in our 2013 MD&A.

Dividends Paid/Payable Relative to Cash from Operating Activities and Net Income Attributable to Common Shares


($ Millions) 2014 2013 2014 2013



Dividends paid/payable 55.0 49.8 105.4 99.4

Less dividends paid in Common Shares under DRIP (14.0) (11.0) (25.0) (21.8)

Net dividends paid/payable 41.0 38.8 80.4 77.6

Excess of cash from operating activities over netdividends paid/payable 6.9 16.2 12.5 14.8

Deficiency of net income attributable to Common Shares over net dividends paid/payable (43.4) (27.3) (51.5) (64.9)

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, 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 tax, and can include unrealized foreign

exchange and fair value gains and losses which are not reflected in calculating the amount of cash available for

the payment of dividends.

FINANCIAL INSTRUMENTS

We and our jointly-controlled businesses periodically enter into interest rate hedges to manage interest rate

exposures. For the three and six months ended June 30, 2014, equity income from York Energy Centre includes

a $3.5 million and a $7.7 million unrealized mark-to-market loss ($2.6 million and $5.8 million after tax),

associated with an interest rate hedge. For the same periods last year, equity income from York Energy Centre

includes a $8.2 million and $9.9 million unrealized mark-to-market gain, respectively ($6.1 million and $7.4

million after tax).

NEW ACCOUNTING STANDARDS

Effective January 1, 2014, the Company adopted Accounting Standards Update ("ASU") 2013-04 "Obligations Resulting from Joint and Several Liability Arrangements". This ASU provides guidance on disclosure and

measurement for obligations with fixed amounts at a reporting date resulting from joint and several liability

arrangements. This guidance was applied retrospectively and did not have a material impact to the Company.

In April 2014, the FASB issued ASU 2014-08, "Presentation of Financial Statements and Property, Plant, and Equipment: Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity". This

ASU provides guidance for changes in criteria and enhanced disclosures for reporting discontinued operations.

20

This guidance is effective for annual and interim periods beginning after December 15, 2014, and is to be

applied prospectively. We are currently evaluating the impact of the standard.

In May 2014, the FASB issued ASU 2014-09, "Revenue from Contracts with Customers". This ASU provides

guidance for changes in criteria for revenue recognition from contracts with customers. This guidance is

effective for annual and interim periods beginning after December 15, 2016, and is to be applied retrospectively.

We are currently evaluating the impact of the standard.

NON-GAAP FINANCIAL MEASURES

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.

Distributable Cash - represents the cash we have available for distribution to common shareholders after

providing for debt service obligations, Preferred Share 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.

Reconciliation of Distributable Cash to Cash From Operating Activities


($ Millions) 2014 2013 2014 2013


Add (deduct):

Project development costs (1)

21.0 9.1 30.3 15.8

Change in non-cash working capital 1.4 (4.5) 21.5 8.3

Principal repayments on senior notes (2.9) (3.0) (5.9) (5.8)

Maintenance capital expenditures (1.2) (1.8) (3.8) (3.8)

Distributions earned greater (less) than distributions received

(2) - (4.2) (0.7) (0.3)


Current tax on Preferred Share dividends 1.6 0.8 3.2 1.6

Distributable cash 63.7 49.2 129.3 103.8

(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 six months ended June 30, 2014 relate primarily to the Jordan Cove LNG terminal project, the Pacific

Connector Gas Pipeline project, and various other development projects.

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

Distributable Cash per Common Share - 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, tax, 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.

21

SELECTED QUARTERLY FINANCIAL INFORMATION

2014 2013 2012 (1)

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

Operating revenues 89.3 92.0 78.8 84.5 89.8 71.6 67.7 71.5

Net income attributable to Common Shares (2.4) 31.3 12.6 27.9 11.51.2 13.1

12.5

Net income per Common Share ($) – basic and diluted (0.01) 0.16 0.06 0.14 0.06 0.01 0.07 0.06

Distributable cash 63.7 65.6 55.8 69.3 49.2 54.6 56.5 61.4

Distributable cash per Common Share ($) –basic and diluted 0.29 0.33 0.28 0.35 0.25 0.27 0.29 0.31

Cash from operating activities 47.9 45.0 81.6 44.0 55.0 37.4 65.1 48.5

(1) Certain comparative figures have been revised. See Note 1 in our June 30, 2014 consolidated financial statements.

Significant items that affected quarterly financial results include the following:

• Second quarter 2014 reflects lower earnings from Aux Sable and higher project development costs.

• First quarter 2014 reflected higher earnings from Aux Sable.

• Fourth quarter 2013 reflected continued weakness in ethane market conditions, increased finance costs

and higher Corporate costs.

• Third quarter 2013 reflected improved margin-based lease revenues for Aux Sable and higher

contributions from Hythe/Steeprock.

Third quarter 2013 reflected improved margin-based lease revenues for Aux Sable and higher

contributions from Hythe/Steeprock.

• Second quarter 2013 reflected continued weakness in NGL market conditions and increased finance

costs.

• First quarter 2013 reflected continued weakness in NGL market conditions and increased administrative

and finance costs.

• 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 a $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.

DISCLOSURE CONTROLS AND PROCEDURES

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 June 30, 2014.

INTERNAL CONTROLS OVER FINANCIAL REPORTING

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 June 30, 2014, 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.

22

No changes were made to internal controls over financial reporting during the period ended June 30, 2014 that

have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.

23

Veresen Inc.

Consolidated Statement of Financial Position

(Canadian $ Millions; number of shares in Millions; unaudited) June 30, 2014 December 31, 2013

AssetsCurrent assets


Restricted cash 5.8 3.7

Distributions receivable 46.3 46.2

Receivables 88.0 62.9

Other 12.1 11.3

371.7 150.7

Investments in jointly-controlled businesses (note 3) 822.4 857.7

Rate-regulated asset 29.0 34.7

Pipeline, plant and other capital assets 1,488.9 1,438.1

Intangible assets 413.3 430.7

Other assets 61.2 61.5

3,186.5 2,973.4

LiabilitiesCurrent liabilities

Payables 66.6 55.0

Dividends payable 13.6 13.2

Current portion of long-term senior debt (note 4) 211.2 212.4

291.4 280.6

Long-term senior debt (note 4) 958.1 975.1

Subordinated convertible debentures 85.3 86.2

Deferred tax liabilities 272.5 277.3

Other long-term liabilities 48.6 48.5

1,655.9 1,667.7

Shareholders’ EquityShare capital (note 5)

Preferred shares 341.4 341.4

Common shares (220.3 and 201.5 outstanding at June 30,2014 and December 31, 2013, respectively) 2,147.4 1,848.6

Additional paid-in capital 4.3 4.3

Cumulative other comprehensive loss (131.4) (134.0)

Accumulated deficit (831.1) (754.6)

1,530.6 1,305.7

3,186.5 2,973.4

Commitments and Contingencies (note 10)

See accompanying Notes to the Consolidated Financial Statements

24

Veresen Inc.

Consolidated Statement of Income

(Canadian $ Millions, except per Common Share Three months ended June 30 Six months ended June 30amounts (note 5); unaudited) 2014 2013 2014 2013

Equity income (note 3) 27.1 41.2 79.3 69.6

Operating revenues 89.3 89.8 181.3 161.4

Operations and maintenance (44.8) (47.0) (95.0) (78.7)

General, administrative and project development (32.5) (21.2) (55.4) (41.8)

Depreciation and amortization (24.8) (22.3) (48.9) (44.7)

Interest and other finance (14.3) (15.6) (28.8) (31.1)

Foreign exchange and other (0.2) 1.1 0.3 1.6

Gain on sale of assets (note 9) - - 14.3 -

Net income (loss) before tax (0.2) 26.0 47.1 36.3

Current tax (4.2) (2.4) (9.9) (3.4)

Deferred tax 6.1 (9.9) (0.1) (15.8)

Net income 1.7 13.7 37.1 17.1



Net income (loss) per Common Share

Basic and diluted (0.01) 0.06 0.14 0.06

Consolidated Statement of Comprehensive Income

(Canadian $ Millions; unaudited)

Three months ended June 30 Six months ended June 302014 2013 2014 2013

Net income 1.7 13.7 37.1 17.1

Other comprehensive income (loss)

Cumulative translation adjustment

Unrealized foreign exchange gain (loss) on translation (17.9) 15.4 2.6 24.7

Other comprehensive income (loss) (17.9) 15.4 2.6 24.7

Comprehensive income (loss) (16.2) 29.1 39.7 41.8


Comprehensive income (loss) attributable to Common Shares (20.3) 26.9 31.5 37.4


25

Veresen Inc.

Consolidated Statement of Cash FlowsThree months ended June 30 Six months ended June 30

(Canadian $ Millions; unaudited) 2014 2013 2014 2013Operating

Net income 1.7 13.7 37.1 17.1

Equity income (27.1) (41.2) (79.3) (69.6)

Distributions from jointly-controlled businesses 52.9 45.5 117.1 92.0

Depreciation and amortization 24.8 22.3 48.9 44.7

Foreign exchange and other non-cash items 3.7 0.6 3.2 (0.8)

Deferred tax (6.1) 9.9 0.1 15.8

Gain on sale of assets (note 9) - - (14.3) -

Changes in non-cash working capital (note 8) (2.0) 4.2 (19.9) (6.8)

47.9 55.0 92.9 92.4

Investing

Proceeds from sale of assets (note 9) - - 18.7 -

Investments in jointly-controlled businesses (7.4) (13.5) (12.7) (35.9)

Return of capital from jointly-controlled businesses - - 11.2 -

Pipeline, plant and other capital assets (39.9) (15.0) (80.5) (24.1)

Restricted cash (1.2) (0.4) (2.1) (2.9)

Other (0.2) 0.1 (0.5) 0.1

(48.7) (28.8) (65.9) (62.8)

Financing

Restricted cash - - - 3.9

Long-term debt issued, net of issue costs 198.7 - 198.7 -

Long-term debt repaid (54.1) (3.8) (56.3) (5.8)

Net change in credit facilities (188.8) 23.0 (162.5) 67.0

Common Shares issued, net of issue costs 272.9 - 272.9 -

Common Share dividends paid (40.6) (38.8) (80.1) (77.6)

Preferred Share dividends paid (4.1) (2.2) (8.2) (4.4)

Repayments from jointly-controlled businesses 0.4 0.4 0.8 0.7

Other - 0.6 1.3 (1.9)

184.4 (20.8) 166.6 (18.1)

Increase in cash and short-term investments 183.6 5.4 193.6 11.5

Effect of foreign exchange rate changes on cash andshort-term investments (0.8) 0.1 (0.7) 0.2

Cash and short-term investments at the beginning of theperiod 36.7 22.3 26.6 16.1

Cash and short-term investments at the end of the period 219.5 27.8 219.5 27.8


26

Veresen Inc.

Consolidated Statement of Shareholders' EquitySix months ended June 30

(Canadian $ Millions; unaudited) 2014 2013Preferred SharesBalance at the beginning and end of the period 341.4 195.2

Common SharesJanuary 1 1,848.6 1,804.3

Convertible debentures converted into Common Shares, net of issue costs (note 5) 0.9 -

Common Shares issued under Premium Dividend and Dividend Reinvestment Plan ("DRIP") 20.2 18.1

Common Shares issued, net of issue costs 272.9 -

June 30 2,142.6 1,822.4

Common Shares to be issued under DRIP 4.8 3.7

Balance at the end of the period 2,147.4 1,826.1

Additional paid-in capitalBalance at the beginning and end of the period 4.3 4.3

Cumulative other comprehensive lossJanuary 1 (134.0) (164.8)

Other comprehensive income 2.6 24.7

Balance at the end of the period (131.4) (140.1)

Accumulated deficitJanuary 1 (754.6) (608.1)

Net income 37.1 17.1

Preferred Share dividends (8.2) (4.4)

Common Share dividends (105.4) (99.4)

Balance at the end of the period (831.1) (694.8)

Shareholders' Equity 1,530.6 1,190.7


27

Notes to the Consolidated Financial Statements

Three and six months ended June 30, 2014 and 2013

(Canadian $ Millions, except where noted; unaudited)

1. Basis of Presentation

These unaudited interim consolidated financial statements of Veresen Inc. (“Veresen” or the “Company”) have

been prepared by management in accordance with accounting principles generally accepted in the United States

of America (“US GAAP”).

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 carrying 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.

The accounting policies applied are consistent with those outlined in Veresen’s annual audited consolidated

financial statements for the year ended December 31, 2013. The year-end balance sheet data was derived from

audited financial statements but these interim financial statements do not include all disclosures required by US

GAAP and should be read in conjunction with the December 31, 2013 audited consolidated financial statements.

Operating results for the three and six months ended June 30, 2014 and June 30, 2013 are not necessarily

indicative of the results for the full year.

In management’s opinion the interim consolidated financial statements contain all adjustments, consisting only of

normal recurring adjustments, which management considers necessary to present fairly the Company’s financial

position as at June 30, 2014 and results of operations and cash flows for the three and six months ended June

30, 2014 and 2013.

2. New Accounting Pronouncements

Effective January 1, 2014, the Company adopted Accounting Standards Update ("ASU") 2013-04 "Obligations Resulting from Joint and Several Liability Arrangements". This ASU provides guidance on disclosure and

measurement for obligations with fixed amounts at a reporting date resulting from joint and several liability

arrangements. This guidance was applied retrospectively and did not have a material impact to the Company.

In April 2014, the Financial Accounting Standards Board ("FASB") issued ASU 2014-08, "Presentation of Financial Statements and Property, Plant, and Equipment: Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity". This ASU provides guidance for changes in criteria and enhanced disclosures for

reporting discontinued operations. This guidance is effective for annual and interim periods beginning after

December 15, 2014, is to be applied prospectively. The Company is currently evaluating the impact of the

standard.

In May 2014, the FASB issued ASU 2014-09, "Revenue from Contracts with Customers". This ASU provides

guidance for changes in criteria for revenue recognition from contracts with customers. This guidance is effective

for annual and interim periods beginning after December 15, 2016, is to be applied retrospectively. The Company

is currently evaluating the impact of the standard.

28

3. Investments in Jointly-Controlled Businesses

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

As at June 30, 2014Six months ended

June 30, 2014As at June

30, 2014

Sixmonths

endedJune 30,

2014

100%CurrentAssets

Non-CurrentAssets

Current Liabilities(1)

Non-Current

Liabilities(1)Senior

Debt Revenues Expenses

Profit(Loss)before

TaxOwner-

ship (%)Equity

Investment

EquityIncome(Loss)

Alliance Canada (2)

143.9 1,333.7 63.3 16.2 1,078.6 235.6 174.2 61.4 50 196.5 27.1

Alliance U.S. (3) (6)

95.8 1,113.9 80.8 9.2 596.4 179.4 114.0 65.4 50 230.8 30.3

Aux Sable Canada 57.1 106.8 54.0 6.6 - 377.4 362.5 14.9 50 51.0 7.3

ASLP (4) (6)

59.3 436.6 82.7 7.8 12.1 77.1 77.6 (0.5) 42.7 133.4 0.8

ASM (6)

34.4 236.0 28.9 0.4 - 275.5 253.5 22.0 42.7 101.5 9.4

ACM 13.6 - 3.3 - - 165.9 156.2 9.7 42.7 4.4 5.3

Sable NGL Services 2.1 - 0.3 - - - (7.3) 7.3 50 0.9 3.6

York Energy Centre (5)

30.4 283.6 7.2 36.1 260.2 44.3 45.8 (1.5) 50 42.1 (2.0)

NRGreen 12.5 137.7 7.3 5.6 32.6 6.3 3.9 2.4 50 51.9 1.2

Grand Valley 4.8 51.5 2.3 0.6 43.7 4.3 3.2 1.1 75 7.3 0.8

Other (6)

5.1 - 0.3 - - - 9.0 (9.0) 50-75 2.6 (4.5)

822.4 79.3

As at December 31, 2013Six months ended

June 30, 2013

As atDecember

31, 2013

Sixmonths

endedJune 30,

2013

100%CurrentAssets

Non-CurrentAssets

Current Liabilities (1)

Non-Current

Liabilities (1)Senior

Debt Revenues Expenses

Profit(Loss)before

taxOwner-

ship (%)Equity

Investment

EquityIncome(Loss)

Alliance Canada (2)

135.4 1,393.3 62.8 16.4 1,120.3 224.4 168.2 56.2 50 203.9 24.9

Alliance U.S. (3) (6)

109.2 1,162.8 83.9 12.3 645.2 160.3 109.6 50.7 50 236.2 24.1

Aux Sable Canada 50.2 131.2 45.5 7.8 - 93.8 85.4 8.4 50 62.1 4.2

ASLP (4) (6)

61.1 436.9 46.7 8.2 19.0 61.7 57.9 3.8 42.7 140.8 2.5

ASM (6)

41.2 234.4 33.0 0.5 - 242.9 218.4 24.5 42.7 101.2 10.5

ACM 1.1 - 1.5 - - 79.7 93.8 (14.1) 42.7 0.3 (4.8)

Sable NGL Services 0.5 - 0.1 - - 2.9 6.3 (3.4) 50 0.2 (1.7)

York Energy Centre (5)

17.8 289.6 6.4 20.7 260.2 30.3 6.0 24.3 50 54.3 10.9

NRGreen 22.4 135.2 10.6 5.5 39.8 5.7 3.9 1.8 50 50.9 0.9

Grand Valley 3.9 52.8 3.8 43.5 - 4.2 3.2 1.0 75 7.1 0.7

Other (6)

2.4 0.8 1.6 - - - 4.9 (4.9) 50-75 0.7 (2.6)

857.7 69.6

Upon acquisition of investments accounted for under the equity method, the Company prepared purchase price

allocations of the purchase price to the assets and liabilities of the underlying investee and adjusts equity method

earnings for the amortization of purchase price adjustments allocated to depreciable assets.

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

(2) At June 30, 2014, the Company had a $57.5 million (December 31, 2013 - $60.7 million) increase in the carrying value of Alliance

Canada compared to the underlying equity in the net assets primarily resulting from the purchase price discrepancy as part of the

acquisitions in 1997, 2002, and 2003 resulting in 50% ownership.

(3) At June 30, 2014, the Company had a US$10.2 million (December 31, 2013 - US$ 8.7 million) decrease in the carrying value of Alliance

U.S. compared to the underlying equity in the net assets primarily resulting from the purchase price discrepancy as part of the

acquisitions in 1997, 2002, and 2003 resulting in 50% ownership.

(4) At June 30, 2014, the Company had a US$30.3 million (December 31, 2013 - US$ 31.2 million) decrease in the carrying value of ASLP

compared to the underlying equity in the net assets primarily resulting from the purchase price discrepancy as part of the acquisitions in

1997, 2002, and 2003 resulting in 42.7% ownership.

(5) At June 30, 2014, the Company had a $44.6 million (December 31, 2013 - $45.8 million) increase in the carrying value of York Energy

Centre compared to the underlying equity in the net assets primarily resulting from the purchase price discrepancy as part of the

acquisition in 2010 resulting in 50% ownership. Expenses include unrealized gains or losses on the interest rate hedge (note 6).

29

(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.

4. Long-term Debt

On June 10, 2014, Veresen issued $200 million of senior unsecured medium term notes maturing on June 13,

2019, bearing interest at 3.06% per annum, payable semi-annually in arrears on June 13 and December 13 of

each year, commencing on December 13, 2014. The net proceeds of the offering were used by the Company on

July 10, 2014 to redeem all of its outstanding $200 million aggregate principal of 5.60% senior notes which were

scheduled to mature on July 28, 2014 (note 11).

In June 2014, the term of the Revolving Credit Facility was extended so that it now matures on May 31, 2018.

Outstanding advances bear interest based on various quoted floating rates plus a margin. At June 30, 2014, the

Facility was undrawn (December 31, 2013 - $162.0 million).

On May 30, 2014 the Corporation extinguished the remaining outstanding balance of $50.4 million of the

Clowhom term loan, which was scheduled to mature on February 21, 2016.

5. Share Capital

Common SharesThe weighted average number of Common Shares outstanding used to determine net income per Common Share

on a basic and diluted basis for the three months ended June 30, 2014, was 218,503,923 (2013 – 199,066,665)

and 224,371,232 (2013 – 204,973,173), respectively. The weighted average number of Common Shares

outstanding used to determine net income per Common Share on a basic and diluted basis for the six months

ended June 30, 2014, was 210,580,717 (2013 – 198,627,825) and 216,467,274 (2013 – 204,534,333),

respectively. The number of Common Shares outstanding would increase by 5,842,274 (2013 – 5,906,508) if the

outstanding convertible debentures on June 30, 2014 were converted into Common Shares. These were

excluded from the diluted earnings per Common Share calculation as the effect was anti-dilutive for the three and

six months ended June 30, 2014 and 2013. During the six months ended June 30, 2014, $0.9 million of the 5.75%

convertible debentures were converted into 64,234 Common Shares.

On April 3, 2014, the Company issued 17.3 million Common Shares at a price of $16.50 per share for aggregate

gross proceeds of approximately $284.6 million.

Preferred SharesOn October 21, 2013, the Company issued 6 million Cumulative Redeemable Preferred Shares, Series C ("Series

C Preferred Shares") at a price of $25 per Series C Preferred Share. The holders of Series C Preferred Shares

are entitled to receive fixed cumulative preferential cash dividends at an annual rate of 5.00%, payable quarterly

for an initial period up to but excluding March 31, 2019, if and when declared by the Board of Directors. The

dividend rate will reset on March 31, 2019 and every five years thereafter at a rate equal to the sum of the then

five-year Government of Canada bond yield plus 3.01%. The Series C Preferred Shares are redeemable by the

Company, at the Company's option, on March 31, 2019 and on March 31 of every fifth year thereafter.

Holders of Series C Preferred Shares have the right to convert all or any part of their shares into Cumulative

Redeemable Preferred Shares, Series D ("Series D Preferred Shares") subject to certain conditions, on March 31,

2019 and on March 31 of every fifth year thereafter. The holders of Series D Preferred Shares are entitled to

receive quarterly floating rate cumulative dividends at a rate equal to the sum of the then 90-day Government of

Canada treasury bill rate plus 3.01%.

30

6. Fair Value Measurement and Derivative Financial Instruments

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, other assets, payables, dividends 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.

Veresen has categorized senior debt as Level 2. At June 30, 2014 senior debt had a carrying value of $1,169.3

million (December 31, 2013 – $1,187.5 million) and fair value of $1,223.4 million (December 31, 2013 – $1,226.3

million).

Financial instruments measured at fair value as at June 30, 2014 were:

Level 1 Level 2 Level 3 Total


Restricted cash 5.8 5.8

Veresen and its jointly-controlled businesses periodically enter into interest rate hedges (“hedges”) to manage

interest rate exposures. As at June 30, 2014 and December 31, 2013, York Energy Centre, a jointly-controlled

business, had one interest rate hedge. Future changes in interest rates will affect the fair value of the hedge,

impacting the amount of unrealized gains or losses included in equity income from jointly-controlled businesses

recognized in the period.

The following is a summary of the interest rate hedge in place as at June 30, 2014:

Variable Debt Interest Rate Fixed RateNotional Amount

(50%)Fair

Value (50%) Term

CAD-BA-CDOR 4.36% $128.3 $(18.0) April 30, 2012 to June 30, 2032

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

Variable Debt Interest Rate Fixed RateNotional Amount

(50%)Fair

Value (50%) Term

CAD-BA-CDOR 4.24% $130.1 $(10.3) 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.

On May 30, 2014, York Energy Centre extended its five-year term loan to mature on June 28, 2019. Concurrent

with extending the term loan, York Energy Centre extended its interest rate hedge at a new fixed rate of 4.36% to

mature on June 28, 2019. 31

7. Segmented Information

Pipelines Midstream Power Corporate(1) Total

Three months ended June 30 2014 2013 2014 2013 2014 2013 2014 2013 2014 2013

Equity income (loss) 28.0 26.0 0.8 7.6 1.3 9.1 (3.0) (1.5) 27.1 41.2

Operating revenues 16.8 13.2 37.6 44.7 34.9 31.9 - - 89.3 89.8

Operations and maintenance (9.3) (6.0) (18.8) (25.5) (16.7) (15.5) - - (44.8) (47.0)

General, administrative andproject development (0.7) (1.0) (1.0) (1.4) (3.5) (4.0) (27.3) (14.8) (32.5) (21.2)

Depreciation and amortization (3.5) (3.5) (9.9) (9.8) (10.7) (8.4) (0.7) (0.6) (24.8) (22.3)

Interest and other finance (1.3) (1.2) - - (3.8) (3.6) (9.2) (10.8) (14.3) (15.6)

Foreign exchange and other - - - - 0.2 - (0.4) 1.1 (0.2) 1.1

Gain on sale of assets - - - - - - - - - -

Net income (loss) before tax 30.0 27.5 8.7 15.6 1.7 9.5 (40.6) (26.6) (0.2) 26.0

Tax expense(2) - - - - - - 1.9 (12.3) 1.9 (12.3)

Net income (loss) 30.0 27.5 8.7 15.6 1.7 9.5 (38.7) (38.9) 1.7 13.7

Preferred Share dividends - - - - - - (4.1) (2.2) (4.1) (2.2)

Net income (loss) attributable toCommon Shares 30.0 27.5 8.7 15.6 1.7 9.5 (42.8) (41.1) (2.4) 11.5

Total assets(3) 707.5 754.9 1,212.7 1,234.8 959.1 920.5 307.2 100.3 3,186.5 3,010.5

Capital expenditures(4) - 0.1 2.7 5.9 37.1 8.8 0.1 0.2 39.9 15.0

Pipelines Midstream Power Corporate(1) Total

Six months ended June 30 2014 2013 2014 2013 2014 2013 2014 2013 2014 2013

Equity income (loss) 57.4 49.0 26.4 10.7 - 12.5 (4.5) (2.6) 79.3 69.6

Operating revenues 31.5 25.5 69.1 75.4 80.7 60.5 - - 181.3 161.4

Operations and maintenance (16.6) (11.0) (30.9) (36.8) (47.5) (30.9) - - (95.0) (78.7)

General, administrative andproject development (1.3) (1.7) (2.2) (2.6) (7.4) (7.5) (44.5) (30.0) (55.4) (41.8)

Depreciation and amortization (7.0) (7.0) (19.8) (19.7) (20.8) (16.9) (1.3) (1.1) (48.9) (44.7)

Interest and other finance (2.5) (2.5) - - (7.3) (7.2) (19.0) (21.4) (28.8) (31.1)

Foreign exchange and other - - - - 0.3 - - 1.6 0.3 1.6

Gain on sale of assets - - - - - - 14.3 - 14.3 -

Net income (loss) before tax 61.5 52.3 42.6 27.0 (2.0) 10.5 (55.0) (53.5) 47.1 36.3

Tax expense(2) - - - - - - (10.0) (19.2) (10.0) (19.2)

Net income (loss) 61.5 52.3 42.6 27.0 (2.0) 10.5 (65.0) (72.7) 37.1 17.1

Preferred Share dividends - - - - - - (8.2) (4.4) (8.2) (4.4)

Net income (loss) attributable toCommon Shares 61.5 52.3 42.6 27.0 (2.0) 10.5 (73.2) (77.1) 28.9 12.7

Total assets(3) 707.5 754.9 1,212.7 1,234.8 959.1 920.5 307.2 100.3 3,186.5 3,010.5

Capital expenditures(4) - 1.7 4.6 8.0 75.7 14.2 0.2 0.2 80.5 24.1

(1) Reflects unallocated amounts applicable to Veresen’s head office activities. Corporate office general and administrative costs for the

three and six months ended June 30, 2014 include project development costs of $21.0 million (2013 - $9.1 million) and $30.3 million

(2013 - $15.8 million), respectively.

(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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8. Supplemental Cash Flow Information

Three months ended June 30 Six months ended June 302014 2013 2014 2013

Receivables (9.2) (17.8) (21.6) (13.0)

Other assets 1.4 0.7 (1.2) (1.9)

Payables 5.8 21.3 2.9 8.1

Changes in non-cash operating working capital (2.0) 4.2 (19.9) (6.8)

9. Gain on Sale of Assets

Sale of Culliton Creek run-of-river hydro project ("Culliton")

On January 31, 2014, the Company closed the sale of Culliton for an agreed upon sale price of $10.4 million,

resulting in an after-tax gain of approximately $5.2 million. The carrying value of net assets sold as at January 31,

2014 was $4.2 million, including $3.9 million of intangible assets, classified within the Corporate segment.

Sale of Alton natural gas storage project ("Alton")

On February 20, 2014 the Company closed the sale of its 50% interest in Alton, a proposed underground storage

facility in Nova Scotia, for an agreed upon sale price of $8.3 million, resulting in an after-tax gain of approximately

$7.5 million. The carrying value of net assets sold as at February 20, 2014 was $0.3 million, which represents the

Company's investment in the jointly-controlled business, classified within the Corporate segment.

10. Commitments and Contingencies

On March 30, 2012, a Statement of Claim was filed against the Company’s equity-accounted investees, Aux

Sable Liquid Products, L.P., Aux Sable Canada L.P., Aux Sable Extraction LP and Aux Sable Canada Ltd., relating

to differences in interpretation of certain terms of the NGL Sales Agreement. The Company’s equity-accounted

investees were served with this Statement of Claim on March 18, 2013. The Company’s share of the potential

exposure, through its equity investments, is approximately US$13.0 million (42.7%). Further potential differences

in interpretation of certain terms of the NGL Sales Agreement have also been identified on additional years not

currently the subject of any claims. The Company has recognized an estimated minimum amount within a range

of possible amounts sufficient to potentially settle these claims. At this time, the Company is unable to predict the

likely outcome of this matter. The Company will continue to assess the matter and the amount of loss accrued

may change in the future.

11. Subsequent Events

Common Share DividendsOn July 22, 2014, the Company declared its July dividend of $0.0833 per Common Share, payable on August 22,

2014 to shareholders of record on July 31, 2014.

On July 10, 2014 the Company redeemed all of its outstanding $200 million aggregate principal of 5.60% senior

notes that were scheduled to mature on July 28, 2014.

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Veresen Announces 2014 Second Quarter Results … Announces 2014 Second Quarter Results and Updates...

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