veresen announces 2014 third quarter results and updates ...€¦ · veresen announces 2014 third...

Veresen Announces 2014 Third Quarter Results and Updates Guidance

CALGARY, ALBERTA (November 3, 2014) – Veresen Inc. (“Veresen” or the “Company”) (TSX: VSN) announced today financial and operating results for the three and nine months ended September 30, 2014.

Highlights

Veresen generated distributable cash1 of $54.9 million ($0.25 per Common Share) in the third quarter

of 2014 compared to $69.3 million ($0.35 per Common Share) in the third quarter of 2013.

Veresen recorded net income attributable to Common Shares of $2.5 million ($0.01 per Common Share) in the third quarter of 2014 compared to net income attributable to Common Shares of $27.9 million ($0.14 per Common Share) in the third quarter of 2013.

Cash from operating activities was $50.4 million in the third quarter of 2014 compared to $44.0 million in the third quarter of 2013.

In September 2014, Veresen entered into an agreement to acquire a 50% convertible preferred interest in the Ruby pipeline system ("Ruby") for US$1.425 billion.

Concurrent with the Ruby acquisition, Veresen issued 56.1 million subscription receipts at a price of $16.40 per subscription receipt for gross proceeds of approximately $920 million.

In response to customer demand, an expansion of the Aux Sable Channahon Facility has been approved, which will allow for approximately 24,500 barrels per day of additional fractionation capacity, above the current nameplate capacity of approximately 107,000 barrels per day.

“Our third quarter earnings and distributable cash were in line with our expectations and, as expected, the market environment for natural gas liquids margins continued to be challenging,” said Don Althoff, President and CEO of Veresen. “Importantly, over the course of 2014, Veresen has advanced a number of projects that begin to build out a robust platform for future growth. The Ruby acquisition is a great example, providing natural gas connectivity from competitive supply regions to high-value markets and, down the road, integrating in Jordan Cove LNG.” Don Althoff added, “Producers recognize that transporting natural gas liquids out of Alberta and the Bakken into the U.S. Midwest represents a compelling alternative, and this view underpins the decision to proceed with an expansion at Aux Sable. Given that the initial focus of our strategy has been to fill the fractionation capacity at the Channahon Facility beyond December 2015, proceeding with this expansion demonstrates that our re-contracting strategy is on track. This expansion is supported by solid project economics and commercial customer support.”

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

September 30 Nine months ended

September 30

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

Net income (loss) before tax

Pipeline

30.6 27.8 92.1 80.1

Midstream 17.9 33.6 60.5 60.6

Power 2.8 6.2 0.8 16.7

Veresen – Corporate (43.2) (29.9) (112.5) (83.4)

8.1 37.7 40.9 74.0 Gain on sale of assets - - 14.3 - Tax expense (1.5) (7.6) (11.5) (26.8)

Net income 6.6 30.1 43.7 47.2

Preferred Share dividends (4.1) (2.2) (12.3) (6.6)

Net income attributable to Common Shares 2.5 27.9 31.4 40.6

Per Common Share ($) 0.01 0.14 0.15 0.20

For the three months ended September 30, 2014, Veresen recorded net income attributable to Common Shares of $2.5 million or $0.01 per Common Share compared to net income of $27.9 million or $0.14 per Common Share for the same period last year. Third quarter earnings reflect solid performance from Veresen’s pipeline, power and independent midstream business. However, results continued to be negatively impacted by weak natural gas liquids (“NGLs”) margins. Third quarter earnings further reflect higher project development spending related to Veresen’s efforts to advance Jordan Cove LNG’s regulatory, commercial, engineering, procurement and construction (“EPC”), and financing work streams. Power earnings also reflect the impact of the revaluation of the York Energy Centre interest rate hedge, resulting in a $2.7 million reduction in Power earnings for the three months ended September 30, 2014 compared to the same period last year.

Distributable Cash

Three months ended

September 30 Nine months ended

September 30


Pipeline

40.7 39.9 122.3 116.3

Midstream 27.1 43.4 96.8 94.3

Power 14.8 12.2 39.7 29.1

Veresen – Corporate (15.9) (18.1) (47.9) (52.4)

Current tax (7.7) (5.9) (14.4) (7.6)


Distributable Cash (1)

54.9 69.3 184.2 173.1

Per Common Share ($) 0.25 0.35 0.86 0.87 (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 September 30, 2014, Veresen generated distributable cash of $54.9 million or $0.25 per Common Share compared to $69.3 million or $0.35 Common Share for the same period in 2013. The decrease in distributable cash primarily reflects lower contributions from Veresen’s Aux Sable midstream business.

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Overview of Business Segments Pipelines Subject to regulatory approval, Alliance pipeline is offering capacity for natural gas transportation commencing December 1, 2015 under a proposed new services framework. This framework includes both fixed and flexible tolling options and responds to current market dynamics and the diverse needs of existing and prospective shippers. The offering also includes full-path and segmented services with a new Canadian trading pool (the Alliance Transfer Pool or “ATP”) 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. In May 2014, Alliance Canada filed an application with Canada’s National Energy Board (“NEB”) for regulatory approval of the tolls and tariff provisions required to implement its new services. While the NEB process is underway, and is expected to be completed in mid-2015, Alliance has been working with producers to sign Precedent Agreements to secure capacity on its system. Shippers have expressed interest in each of Alliance’s firm service offerings – receipt, delivery and full-path. There is approximately 6 billion cubic feet per day (“bcf/d”) of natural gas produced within Alliance’s gathering area, with approximately 4 bcf/d of natural gas currently connected to the Alliance’s extensive gathering system. Alliance has placed into service several new receipt interconnection facilities that have increased its receipt capacity from developing liquids-rich sources of natural gas in northeast British Columbia and northwest Alberta, and a number of receipt interconnection facilities are also in the planning and design stage. Market fundamentals are driving substantial investment opportunities in North American gathering, processing and pipeline infrastructure, so Alliance is well-positioned for further re-contracting beyond 2015.

Midstream

As part of Aux Sable’s strategy to attract liquids-rich natural gas to its Channahon Facility for the period following the expiry of Alliance’s current transportation contracts on December 1, 2015, efforts have focused on working with producers developing liquids-rich fields in the Montney and Duvernay which are not yet connected to the Alliance pipeline system. Aux Sable has offered Rich Gas Premium (“RGP”) agreements which share NGLs margins with producers. The RGP agreements allow producers to avoid capital investment and receive NGL value tied to large, liquid U.S. Midwest markets. Aux Sable has executed several RGP agreements to date and, as a result, Aux Sable’s ability to extract additional NGLs beyond 2015 at the Channahon Facility is reaching its limit. In response to customer demand, an expansion of the Channahon Facility has been approved which will allow for approximately 24,500 barrels per day of additional fractionation capacity, over and above the current nameplate capacity of 107,000 barrels per day. The Channahon Facility expansion, which will increase propane and butane processing capacity, has an estimated capital cost of US$130 million (gross) and is expected to be completed in mid-2016. Veresen holds an approximate 43% interest in Aux Sable. With respect to Veresen’s wholly-owned Canadian midstream assets, the Company continues to explore significant opportunities to grow its midstream footprint in the Western Canadian Sedimentary Basin. The Company believes the continued development of the Montney and Duvernay resource plays will drive significant additional infrastructure requirements, and Veresen is well-positioned to offer innovative, customer-focused solutions to meet producers’ needs.

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Power

Construction of the Dasque-Middle run-of-river project in northwest British Columbia is nearing completion, with the facility 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 received regulatory approval by Ontario’s environmental regulator on October 15, 2014; however, the Renewable Energy Approval may be appealed to the Environmental Review Tribunal, in writing, within 15 days of the decision.

Jordan Cove LNG

Veresen has been expanding its capability to execute on Jordan Cove LNG’s key project milestones and the Company continues to make strong progress in advancing its four key work streams. Activities to date have focused on regulatory approvals and permitting, commercial off-take agreements, advancing engineering to obtain an updated cost estimate and finalizing an EPC contract, and project financing. Veresen has also advanced the organizational structure of Jordan Cove LNG to ensure the appropriate resources are in place for the success of the project. Supporting this objective, in October 2014, the Company announced the appointment of Elizabeth (Betsy) Spomer as President and Chief Executive Officer of Jordan Cove LNG LLC and an Executive Vice President of Veresen. Ms. Spomer brings over 30 years of experience in the energy industry, having spent the majority of her career in the LNG industry. With a final investment decision for Jordan Cove LNG expected in 2015, Veresen plans to continue to augment its LNG team, adding professionals who will be required through the construction and operating phases. Ms. Spomer and her team will be based in Houston, Texas. Acquisition of 50% Interest in Ruby On September 22, 2014, Veresen entered into an agreement with Global Infrastructure Partners (“GIP”) to acquire GIP’s 50% convertible preferred interest in Ruby. The pipeline is a newly-built, large-scale natural gas transmission system delivering U.S. Rockies natural gas production to markets in the western United States. The 680-mile, 42-inch pipeline has a capacity of approximately 1.5 bcf/d, with expansion potential to 2.0 bcf/d through the addition of compression. Ruby originates at the Opal hub in Wyoming and extends to the Malin hub in Oregon. The Malin hub is the main interconnect to the proposed Pacific Connector Gas Pipeline (50% owned by Veresen), which would supply Veresen’s proposed Jordan Cove LNG terminal. Ruby is an ideal fit for Veresen as it offers immediate long-term contracted cash flows with downside protection through the preferred interest structure, and provides significant future added upside related to the Jordan Cove LNG project.

Today, Veresen received notice from the Committee on Foreign Investment in the United States ("CFIUS") that there are no unresolved national security issues relating to Veresen's acquisition of Ruby. The clearance by CFIUS was without conditions and terminates the review of the transaction. The completion of the Ruby acquisition remains subject to customary closing conditions. Closing is expected to occur on November 6, 2014.On October 1, 2014, in conjunction with the Ruby acquisition, Veresen completed the issuance of 56,120,000 subscription receipts at a price of $16.40 per subscription receipt for gross proceeds of approximately $920 million. The net proceeds of the offering will be used to partially fund the Ruby acquisition.

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2014 Guidance Update Veresen has narrowed its guidance for 2014 distributable cash to be in the range of $1.05 per Common Share to $1.17 per Common Share, with the midpoint unchanged at $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. Conference Call and Webcast Veresen will host a conference call and webcast on November 4, 2014 at 6:30 am MT (8:30 am ET) to discuss its results and activities. Dial-in: 1 (888) 231-8191 or 1 (647) 427-7450 Conference ID 27910985. The link to the conference call webcast is available on Veresen’s website at www.vereseninc.com. A replay of the call will be available at approximately 9:30 am MT (11:30 am ET) on November 4, 2014 by dialing 1 (855) 859-2056 and 1 (416) 849-0833. The access code is 27910985, followed by the pound sign. The replay will expire at midnight (ET) on November 11, 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 third quarter ended September 30, 2014 compared to the third quarter ended September 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, including the Jordan Cove LNG terminal to be constructed in Coos Bay, Oregon and the Pacific Connector Gas Pipeline. In the normal course of its business, Veresen 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

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http://www.vereseninc.com/

http://www.vereseninc.com/

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, and 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 and new investment opportunities; the timing of the closing of the acquisition of an interest in the Ruby pipeline system, and the ability to, and timing of, any expansion of the system; 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 Analysis

Three and nine months ended September 30, 2014

FINANCIAL AND OPERATING HIGHLIGHTS

Three months endedSeptember 30

Nine months endedSeptember 30

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

Operating Highlights (100%)Pipeline

Alliance – billion cubic feet per day 1.501 1.514 1.567 1.569

AEGS – thousand barrels per day 1 280.2 285.8 286.6 290.5

Midstream

Hythe/Steeprock – million cubic feet per day 2 400.1 427.2 400.1 413.8

Aux Sable – thousand barrels per day 79.3 67.6 70.9 64.3

Power – gigawatt hours (net) 164.7 201.1 653.8 620.2

Financial ResultsEquity income 33.8 50.6 113.1 120.2

Operating revenues 82.0 84.5 263.3 245.9


Per Common Share ($) – basic and diluted 0.01 0.14 0.15 0.20

Cash from operating activities 50.4 44.0 143.3 136.4

Distributable cash 3, 4 54.9 69.3 184.2 173.1

Per Common Share ($) – basic and diluted 0.25 0.35 0.86 0.87

Dividends paid/payable 5 55.4 50.0 160.8 149.4

Per Common Share ($) 0.25 0.25 0.75 0.75

Capital expenditures 6 31.4 14.4 111.9 38.5

September 30, 2014As at

Dec. 31, 2013

Financial PositionCash and short-term investments 26.2 26.6

Total assets 3,025.3 2,973.4

Senior debt 1,011.6 1,187.5

Subordinated convertible debentures 51.7 86.2

Shareholders’ equity 1,552.2 1,305.7

Common SharesOutstanding – as at period end

7 223,456,044 201,476,244

Average daily volume 561,101 302,801

Price per Common Share – close ($) 17.03 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 $13.9 million and $38.8 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 nine months ended September 30, 2014

(2013 - $11.4 million and $33.2 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 October 30, 2014 we had 227,243,892 Common Shares outstanding.

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This MD&A, dated November 3, 2014, provides a review of the significant events and transactions that affected

our performance during the three and nine months ended September 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 nine months ended September 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 nine months ended September 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 30.6 27.8 92.1 80.1

Midstream 17.9 33.6 60.5 60.6

Power 2.8 6.2 0.8 16.7

Veresen–Corporate (43.2) (29.9) (112.5) (83.4)

Gain on sale of assets - - 14.3 -

Tax expense (1.5) (7.6) (11.5) (26.8)

Net income 6.6 30.1 43.7 47.2



Per Common Share ($) 0.01 0.14 0.15 0.20

For the three and nine months ending September 30, 2014, we generated net income attributable to Common

Shares of $2.5 million or $0.01 per Common Share and $31.4 million or $0.15 per Common Share, respectively.

For the same periods last year, we generated income of $27.9 million or $0.14 per Common Share and $40.6

million or $0.20 per Common Share.

Solid third quarter operating earnings from our pipeline, independent midstream, and power businesses were

offset by reduced earnings from our Aux Sable midstream business, reflecting the continued weak NGL market

environment.

These same factors are reflected in our year-to-date operating results. However, lower NGL margins at Aux

Sable were offset by strong earnings in the first quarter due to the significant widening of the Chicago - AECO

gas price differential driven by the extreme cold weather in the U.S. Mid-West.

Both quarter and year-to-date earnings were impacted by higher project development spending relating to our

Jordan Cove project. 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 increased accordingly.

Our Power segment was impacted by the revaluation of the York Energy Centre interest rate hedge, which

resulted in a $2.7 million and $20.3 million reduction in Power net income before tax for the three and nine

months periods, respectively, compared to the same periods last year.

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Distributable CashThree months ended

September 30Nine months ended

September 30


Pipeline 40.7 39.9 122.3 116.3

Midstream 27.1 43.4 96.8 94.3

Power 14.8 12.2 39.7 29.1


Current tax (7.7) (5.9) (14.4) (7.6)


Distributable Cash (1) 54.9 69.3 184.2 173.1

Per Common Share ($) 0.25 0.35 0.86 0.87

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

MD&A.

For the three and nine months ended September 30, 2014, we generated distributable cash of $54.9 million and

$184.2 million or $0.25 and $0.86 per Common Share, compared to $69.3 million and $173.1 million or $0.35

and $0.87 per Common Share for the same periods last year.

Solid cash flows generated by our pipeline and power businesses on both a quarter and year-to-date basis were

offset by the effect of continued weak NGL fractionation margins. Distributable cash from our Midstream

segment for the nine months ending September 30 benefited from the strength of first quarter 2014 cash flows,

more than offsetting the weaker fractionation margins. Distributions from Hythe/Steeprock remained consistent

compared to the same periods last year.

Alliance generated an additional $0.8 million this quarter and $5.1 million over the first three quarters of the year

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

pipeline.

Higher distributable cash from our power business during the third quarter was driven by strong operating

performance at our gas-fired facilities. On a year-to-date basis, distributable cash increased as a result of 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.

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 September 30 Nine months ended September 30

($ Millions) 2014 2013 2014 2013

Pipeline 41.6 39.6 123.9 116.8

Midstream 24.9 30.9 90.9 87.1

Power 26.6 15.6 44.9 39.9


50.4 44.0 143.3 136.4

For the three and nine months ended September 30, 2014, we generated $50.4 million and $143.3 million of

cash from operating activities compared to $44.0 million and $136.4 million for the same periods last year. The

higher operating cash flows during the third quarter from our pipeline and power businesses, partially offset by a

decrease in our midstream businesses, generally reflect the same factors impacting distributable cash and

changes in power non-cash working capital. Corporate cash outflows remained consistent compared to the

same period last year as higher project development costs and current taxes were offset by lower interest costs

and changes in non-cash working capital.

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

business segment generally reflecting the same factors impacting distributable cash. Corporate cash outflows

were mainly driven by the same factors impacting the third quarter.

RESULTS OF OPERATIONS – BY BUSINESS SEGMENT

Pipeline BusinessThree months ended September 30,

2014Three months ended September 30,

2013

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

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

(1) 6.9 - 6.9 6.8 - 6.8

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

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

Equity income 28.4 28.4 - 25.8 25.8 -

Net income before tax 30.6 28.4 2.2 27.8 25.8 2.0

Distributable cash 40.7 36.0 4.7 39.9 35.2 4.7

Volumes (100%) 1.501 280.2 1.514 285.8

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

(2)

Pipeline BusinessNine months ended September 30,

2014Nine months ended September 30,

2013

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

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

(1) 20.5 - 20.5 19.6 - 19.6

Depreciation and amortization (10.5) - (10.5) (10.5) - (10.5)

Interest and other finance (3.7) - (3.7) (3.8) - (3.8)

Equity income 85.8 85.8 - 74.8 74.8 -



Volumes (100%) 1.567 286.6 1.569 290.5

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 nine months ended September 30, 2014 averaged 1.501 bcf/d and

1.567 bcf/d, compared to 1.514 bcf/d and 1.569 bcf/d for the same periods last year.

Financial Highlights

Distributable cash for the three and nine months ended September 30, 2014 was $36.0 million and $108.0

million compared to $35.2 million and $102.8 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 throughout 2014.

Net income before tax for the three and nine months ended September 30, 2014 was $28.4 million and $85.8

million compared to $25.8 million and $74.8 million for the same periods last year. The increases reflect 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 offering effective

December 1, 2015. Similarly, Alliance USA will be applying to the U.S. Federal Energy Regulatory Commission

in 2015 for regulatory approval. On August 20, 2014 the NEB issued a Hearing Order establishing a written

proceeding for the review of Alliance Canada's new services offering application. The hearing concludes with

oral final argument scheduled to start April 15, 2015. A decision by the NEB is expected mid-year 2015.

During the first three quarters of 2014, Alliance placed into service several new receipt interconnection facilities

that increased the pipeline's receipt capacity by up to 470 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.

2015 Tolls

Alliance made its 2015 Canadian toll filing to the NEB on October 31, 2014, and is expected to make its 2015

U.S. negotiated rate filing with the Federal Energy Regulatory Commission on November 28, 2014. The firm

transportation toll is expected to increase from $0.96/mcf in 2014 to $1.00/mcf in 2015 on Alliance Canada, but

decrease from US$0.60/mcf to US$0.58/mcf on Alliance U.S., resulting in a system-wide net toll increase of

approximately $0.02/mcf.

AEGS


Toll volumes for the three and nine months ended September 30, 2014 were 280.2 mbbls/d and 286.6 mbbls/d,

respectively, compared to 285.8 mbbls/d and 290.5 mbbls/d for the same periods last year. An unplanned

outage by a major petrochemical plant served by AEGS resulted in lower ethane deliveries in the current quarter

relative to last year.


For the three and nine months ended September 30, 2014, AEGS generated $4.7 million and $14.3 million in

distributable cash, respectively, and $2.2 million and $6.3 million in net income before tax. Current year results

reflect higher toll revenues.

Ruby Pipeline

On September 22, 2014, we entered into an agreement with Global Infrastructure Partners to acquire its 50%

convertible preferred interest in the Ruby pipeline system for US $1.425 billion. The acquisition will be made

through a wholly-owned subsidiary of Veresen. Ruby is a newly-built, large-scale natural gas transmission

system delivering U.S. Rockies natural gas production to markets in the western United States. The 680-mile,

42-inch pipeline has a current capacity of approximately 1.5 bcf/d, with expansion potential to 2.0 bcf/d through

the addition of compression. Ruby originates at the Opal hub in Wyoming and extends to the Malin hub in

Oregon. The Malin hub is the main interconnect to the proposed Pacific Connector Gas Pipeline (50% owned by

Veresen), which would supply our proposed Jordan Cove LNG terminal. El Paso Pipeline Partners, an affiliate of

Kinder Morgan Inc., holds the remaining 50% ownership interest in Ruby through a common equity interest.

Kinder Morgan, North America's largest natural gas pipeline operator, will continue to operate Ruby on a day-to-

day basis.

The acquisition will be funded by proceeds from a $920 million subscription receipt offering and from new credit

facilities (details of the financing is discussed in the Liquidity and Capital Resources section of this MD&A). On

November 3, 2014, we received notice from the Committee on Foreign Investment in the United States

("CFIUS") that there are no unresolved national security issues relating to Veresen's acquisition of Ruby. The

12

clearance by CFIUS was without conditions and terminates the review of the transaction. The completion of the

Ruby acquisition remains subject to customary closing conditions. Closing is expected to occur on November 6,

2014.

Following the announcement of the acquisition, on September 22, 2014, Standard & Poor's Rating Services

affirmed its ratings, including its 'BBB' long-term corporate credit rating. On September 23, 2014, Dominion

Bond Rating Service placed our Issuer Rating and Senior Unsecured Notes rating of BBB (high) and our

Preferred Shares rating of Pfd-3 (high) Under Review with Negative Implications, with ratings to be finalized

upon completion of the acquisition.

Midstream BusinessThree months endedSeptember 30, 2014

Three months endedSeptember 30, 2013

($ Millions, except where noted) TotalHythe/

SteeprockAux

Sable TotalHythe/

SteeprockAux

Sable

EBITDA 18.9 18.9 - 19.3 19.3 -Depreciation and amortization (9.9) (9.9) - (9.8) (9.8) -Equity income 8.9 - 8.9 24.1 - 24.1



Volumes (100%)Fee Volumes

(1) 400.1 427.2

mmcf/d mmcf/d

Ethane 27.2 22.0

Propane plus 52.1 45.6

79.3 67.6

mbbls/d mbbls/d

Midstream BusinessNIne months ended

September 30, 2014Nine months ended

September 30, 2013

($ Millions, except where noted) TotalHythe/

SteeprockAux

Sable TotalHythe/

SteeprockAux

Sable

EBITDA 54.9 54.9 - 55.3 55.3 -Depreciation and amortization (29.7) (29.7) - (29.5) (29.5) -Equity income 35.3 - 35.3 34.8 - 34.8



Volumes (100%)Fee Volumes

(1) 400.1 413.8

mmcf/d mmcf/d

Ethane 23.2 20.3

Propane plus 47.7 44.0

70.9 64.3

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.

13


For the three and nine months ended September 30, 2014, fee volumes at Hythe/Steeprock averaged 400.1

mmcf/d, which is comprised of the minimum volume commitment from our primary customer and natural gas

from third party producers. Fee volumes decreased six percent compared to the third quarter last year due to

higher actual volumes processed post-Hythe turnaround last year combined with lower actual volumes being

processed this year as a result of downstream pipeline pressure restrictions impacting our Hythe plant.

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 third quarter of 2014, the Hythe and Steeprock facilities operated at reliability factors of 100% and

99%, respectively, exceeding the target factors under the MSA.


For the three and nine months ended September 30, 2014, distributable cash for Hythe/Steeprock was $19.0

million and $56.3 million, respectively, compared to $19.8 million and $55.1 million for the same periods last

year. The reduction in distributable cash for the quarter resulted from lower third party revenues. The increase

in distributable cash for the nine months ended September 30, 2014 was due to higher revenues attributed to

recovery of maintenance capital expenditures from our primary customer and the annual fee escalation as per

the MSA.

Net income before tax for the three and nine months ended September 30, 2014 decreased by $0.5 million and

$0.6 million, respectively, to $9.0 million and $25.2 million primarily due to lower third party revenue.

Aux SableNGL Market Overview



2014 2013 2014 2013

Average USGC ethane margin (US$/gallon) (0.03) 0.01 (0.01) 0.02

Average USGC propane plus margin (US$/gallon) 0.79 0.85 0.82 0.80

Average Henry Hub natural gas (US$/mmbtu) 3.94 3.55 4.53 3.68

Average Chicago Citygate natural gas (US$/mmbtu) 3.99 3.64 6.13 3.79

Average WTI crude oil (US$/bbl) 97.17 105.90 99.61 98.16

Average Chicago - AECO differential ($/mmbtu) 0.33 1.34 1.86 0.83

General weakness in U.S. Gulf Coast ethane margins continued in the third quarter of 2014 as ethane remained

oversupplied with widespread rejection, particularly in the Rockies and Appalachian regions, keeping prices

depressed while completely offset by the cost of make-up gas.

USGC propane plus margins weakened during the third quarter of 2014 relative to the same period last year.

Propane plus margins were slightly higher on a year-to-date basis on the strength of the first half of the year.

While the pricing environment remained strong through most of 2014, margins realized by Aux Sable were less

favourable due to higher make-up gas costs, which is priced at Chicago.

Propane storage levels in the U.S. increased significantly throughout the third quarter, reaching a record-level

77 million barrels at the end of third quarter 2014, a 45% increase from the second quarter. Propane prices

remained relatively firm due to the expectations of higher seasonal demand heading towards winter, particularly

for crop drying.

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

in the U.S. Mid-West, prices moderated in the second quarter and continued to stabilize in the third quarter of

14

2014. The Chicago Citygate gas price averaged US$3.99 per mmbtu in the third quarter, down from US$4.65

per mmbtu in the second quarter of 2014 but up compared to US$3.64 per mmbtu for the third quarter in 2013.


Three months ended September 30 Nine months ended September 30

2014 2013 2014 2013

Average volume receipts

Prairie Rose Pipeline (mmcf/d) 105.8 110.0 97.4 104.6

Average sales

Ethane (mbbls/d) 27.2 22.0 23.2 20.3

Propane plus (mbbls/d) 52.1 45.6 47.7 44.0

Total NGLs (mbbls/d) 79.3 67.6 70.9 64.3

During the three and nine months ended September 30, 2014, Aux Sable processed 98% of the natural gas

delivered by Alliance compared to 99% for the same periods last year. The slight decrease is attributed to

uneconomic ethane margins coupled with brief operational downtime for maintenance.

Receipts into the Prairie Rose Pipeline in North Dakota averaged 106 mmcf/d and 97 mmcf/d during the three

and nine months ended September 30, 2014, respectively, compared to 110 mmcf/d and 105 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 1,355 btu/ft3 and 1,366 btu/ft3 for the three and nine months ended

September 30, 2014, respectively, compared to 1,394 btu/ft3 and 1,382 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

western Canadian natural gas delivered on the Alliance system for the nine months ended September 30, 2014

averaged 1,125 btu/ft3.

Aux Sable sold 79.3 mbbls/d and 70.9 mbbls/d of NGLs during the three and nine months ended September 30,

2014, respectively, compared to 67.6 mbbls/d and 64.3 mbbls/d for the same periods last year. Average ethane

volumes sold increased to 27.2 mbbls/d and 23.2 mbbls/d for the three and nine months ended September 30,

2014, respectively, from 22.0 mbbls/d and 20.3 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 52.1 mbbls/d and 47.7 mbbls/d for the three and nine months ended

September 30, 2014, respectively, compared to 45.6 mbbls/d and 44.0 mbbls/d for the same periods last year

due primarily to the success Aux Sable has achieved through its Rich Gas Premium Agreement initiative, and

the commencement of the Tioga Lateral in the second quarter of 2014.

15


Components of Aux Sable Equity Income:

Three months ended September 30 Nine months ended September 30

(Veresen's share; $ Millions) 2014 2013 2014 2013

Margin based lease revenues

Amount generated during period 8.3 11.3 18.2 26.7

Margin recognized from prior period 6.2 10.5 - -

(Unrecognized margin generated in period) (3.3) (1.8) (3.3) (1.8)

Amount recognized as revenue 11.2 20.0 14.9 24.9

Pipeline capacity margin (5.0) (0.5) 5.5 (8.2)

Other margin based activities 1.8 4.1 11.7 12.5

Fixed fee activities 8.3 9.0 26.8 28.5

General, administrative, operating andmaintenance (4.7) (5.7) (15.1) (15.6)

Depreciation and amortization (2.7) (2.6) (8.1) (7.6)

Interest and other finance - (0.2) (0.4) 0.3

Net income before tax / equity income 8.9 24.1 35.3 34.8

For the three months ended September 30, 2014, Aux Sable generated $8.1 million of distributable cash and

$8.9 million in net income before tax, compared to $23.6 million of distributable cash and $24.1 million in net

income before tax during the same period last year. For the nine months ended September 30, 2014, Aux Sable

generated $40.5 million of distributable cash and $35.3 million of net income before tax, compared to $39.2

million of distributable cash and $34.8 million of net income before tax during the same period last year.

Net income and distributable cash decreased in the current quarter primarily due to lower fractionation margins

driven by higher make-up gas prices, lower volumes flowing through Aux Sable's Palermo Conditioning Plant as

a result of the Hess Tioga Gas Plant commencing service in May 2014, and lower pipeline capacity margins

relating to the purchase and sale of natural gas by certain Aux Sable entities utilizing Alliance pipeline capacity.

Net income and distributable cash on a year-to-date basis increased slightly, as lower fractionation margins

were more than offset by positive pipeline capacity margins benefiting 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.

For the nine months ended September 30, 2014, Aux Sable's Channahon fractionation facility generated $12.0

million of margin-based lease revenues, of which $8.7 million has been recognized in income. During the same

period last year, the facility generated $21.0 million, of which $19.2 million was recognized in that period. The

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

quarter of 2014.

Outlook

As part of Aux Sable's strategy to attract liquids-rich natural gas to its Channahon Facility for the period

following December 1, 2015, efforts have focused on working with producers developing liquids-rich fields in the

Montney and Duvernay which are not yet connected to the Alliance Pipeline system. Aux Sable has offered Rich

Gas Premium agreements which share natural gas liquids margins with producers. These agreements allow

producers to avoid immediate capital investment and provide NGL value tied to large, liquid U.S. Midwest

markets. Aux Sable has executed several RGP agreements and, as a result, Aux Sable's ability to extract

additional NGLs at the Channahon Facility has reached the plant's capacity. In response to customer demand,

the owners of Aux Sable, including us, have approved an expansion of the Channahon Facility which will allow

for approximately 24,500 barrels per day of additional fractionation capacity, over and above the plant's current

nameplate capacity of 107,000 barrels per day. The Channahon Facility expansion, which will increase the

propane and butane processing capacity, has an estimated capital cost of US$130 million (gross) and is

expected to be completed in mid-2016.

16

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

($ Millions, exceptwhere noted) Total

Gas-Fired/DistrictEnergy Renewables

Power-Corporate Total


Power-Corporate

EBITDA 16.3 14.8 3.0 (1.5) 16.5 14.4 3.7 (1.6)

Depreciation and amortization (10.6) (8.2) (2.4) - (9.2) (6.8) (2.3) (0.1)

Interest and other finance (2.9) (2.5) (0.4) - (3.7) (2.5) (1.2) -

Equity income 0.1 0.2 (0.1) - 2.6 2.8 (0.2) -

Foreign exchange andother (0.1) - - (0.1) - - - -

Net income (loss)before tax 2.8 4.3 0.1 (1.6) 6.2 7.9 - (1.7)

Distributable cash 14.8 13.0 3.3 (1.5) 12.2 11.8 2.0 (1.6)

Volumes (GWh)Gross 187.7 81.8 105.9 - 236.1 125.5 110.6 -

Net 164.7 77.8 86.9 - 201.1 108.2 92.9 -

Power BusinessNine months ended September 30, 2014 Nine months ended September 30, 2013

($ Millions, exceptwhere noted) Total


Power-Corporate Total


Power-Corporate

EBITDA 42.1 36.3 11.7 (5.9) 38.6 34.1 10.9 (6.4)

Depreciation and amortization (31.4) (24.4) (7.0) - (26.1) (19.0) (6.8) (0.3)

Interest and other finance (10.2) (7.4) (2.8) - (10.9) (7.5) (3.4) -

Equity income 0.1 (1.8) 1.9 - 15.1 13.7 1.4 -

Foreign exchange andother 0.2 - - 0.2 - - - -

Net income (loss)before tax 0.8 2.7 3.8 (5.7) 16.7 21.3 2.1 (6.7)

Distributable cash 39.7 33.1 12.6 (6.0) 29.1 28.0 7.5 (6.4)

Volumes (GWh)Gross 751.0 357.8 393.2 - 711.6 320.5 391.1 -

Net 653.8 326.0 327.8 - 620.2 290.4 329.8 -

Operational Highlights and Project Updates

For the three months ended September 30, 2014, our power facilities operated in line with our expectations,

providing consistent earnings compared to the same period last year.

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 is expected in 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.

Our proposed Grand Valley III wind project, currently under development, received its Renewable Energy

Approval from the Ontario Minister of Environment and Climate Change on October 15, 2014. The 40 megawatt

wind project will be located near the Town of Grand Valley. We continue to advance this project and expect to

make a final investment decision in the fourth quarter of 2014.

17


For the three and nine months ended September 30, 2014, distributable cash was $14.8 million and $39.7

million, respectively, representing an increase of $2.6 million and $10.6 million compared to the same periods

last year.

The current quarter increase reflects strong operational performance across our gas-fired and renewable energy

facilities.

Our gas-fired, district energy and renewable energy facilities generated higher cash flows during the nine

months ending September 30, 2014 compared to the same period last year. In addition to its strong operating

performance, York Energy Centre results reflect a $3.9 million retroactive adjustment from the Ontario Power

Authority recognized in the second quarter of 2014. Our district energy systems benefited from stronger

operational performance and lower maintenance costs. Renewable power facilities provided higher cash flows

as our Glen Park run-of-river hydro facility benefited from robust energy prices in the first quarter of 2014 and

higher water flows throughout 2014.

Net income before tax was $2.8 million and $0.8 million for the three and nine months ended September 30,

2014, decreasing by $3.4 million and $15.9 million over the same periods last year. Higher operating earnings

were offset by higher depreciation at our California cogeneration facilities, and by the revaluation of the York

Energy Centre interest rate hedge which resulted in a $2.7 million and $20.3 million reduction in Power net

income before tax for the three and nine month periods, respectively, compared to the same periods last year.

Veresen-CorporateThree months ended September 30 Nine months ended September 30

($ Millions) 2014 2013 2014 2013

Equity loss 3.5 1.8 8.0 4.4

General & administrative 7.6 7.8 21.8 22.0

Project development 28.5 8.1 58.8 23.9

Depreciation and amortization 0.6 0.5 1.9 1.6

Interest and other finance 9.0 10.8 28.0 32.2

Foreign exchange and other (6.0) 0.9 (6.0) (0.7)

Net expenses before tax 43.2 29.9 112.5 83.4

Current tax 9.3 6.8 19.2 10.2

Deferred tax (7.8) 0.8 (7.7) 16.6

Net expenses 44.7 37.5 124.0 110.2

Effective rate 18.5% 20.2% 20.8% 36.2%

Distributable cash (15.9) (18.1) (47.9) (52.4)

For the three and nine months ended September 30, 2014, we incurred $43.2 million and $112.5 million,

respectively, of net corporate expenses before taxes, a $13.3 million and $29.1 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, partially offset by a $4.9 million unrealized gain on

forward foreign exchange contracts entered into to manage the fluctuating Canadian to US dollar exchange rate

relating to the Ruby acquisition (the forward exchange contracts are discussed in the Financial Instruments

section of this MD&A).

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 nine months ending September 30, 2014 was lower than the same period last year

due to higher Canadian earnings which are subject to a lower tax rate relative to the U.S. and the gains on the

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

18

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 by the first quarter of 2015 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 or early 2015, 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

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.

We've advanced the organizational structure of Jordan Cove LNG to ensure the appropriate resources are in

place for the success of the project. Supporting this objective, in October 2014, we announced the appointment

of Elizabeth (Betsy) Spomer as President and Chief Executive Officer of Jordan Cove LNG LLC and as an

Executive Vice President of Veresen. Ms. Spomer brings over 30 years of experience in the energy industry,

having spent the majority of her career in the LNG industry. With a final investment decision for Jordan Cove

LNG expected in 2015, we plan to continue to augment our LNG team, adding professionals who will be

required through the construction and operating phases. Ms. Spomer and her team will be based in Houston,

Texas.

19

LIQUIDITY AND CAPITAL RESOURCES



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

Cash flows

Operating activities 50.4 44.0 143.3 136.4

Investing activities (39.0) (31.4) (104.9) (94.2)

Financing activities (205.0) (14.8) (38.4) (32.9)

September 30, 2014 December 31, 2013

Cash and short-term investments 26.2 26.6

Capitalization

Senior debt (1) 1,011.6 38% 1,187.5 45%

Subordinated convertible debentures 51.7 2% 86.2 3%

Other long-term liabilities 50.2 2% 48.5 2%

Shareholders’ equity 1,552.2 58% 1,305.7 50%

2,665.7 100% 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 September 30, 2014, we had cash and short-term investments of $26.2 million (December 31, 2013 - $26.6

million) and non-cash working capital of $38.8 million (December 31, 2013 - $43.6 million).

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

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

requirements. Our Revolving Credit Facility was drawn by $44.1 million as at September 30, 2014.

Investing Activities For the nine months ended September 30, 2014, we used $104.9 million of cash to fund our investing activities,

compared to $94.2 million in the same period last year. Significant investing activities for the nine months ended

September 30, 2014 included:

• $19.2 million in equity contributions to our jointly-controlled businesses;

• $111.9 million of capital expenditures, primarily related to the construction of the Dasque-Middle run-of-

river hydro facility ($40.1 million), the St. Columban wind project ($57.6 million), our Midstream business

($10.0 million), and our operating power facilities ($4.2 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:

• $53.2 million in equity contributions to our jointly-controlled businesses; and

• $38.5 million of capital expenditures, primarily related to the construction of the Dasque-Middle-run-of-

river hydro facility ($18.1 million), or Midstream business ($12.6 million), and our operating power

facilities ($5.6 million).

Financing Activities For the nine months ended September 30, 2014, we used $38.4 million cash to fund our financing activities,

compared to $32.9 million cash used for the same period last year. Financing activities for the nine months

ended September 30, 2014 included:

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

20

• $121.0 million of Common Share dividend payments;

• $121.1 million of net repayments on our Revolving Credit Facility;

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

• $258.1 million of senior debt repayments; and

• $12.3 million of Preferred Share dividend payments.

Significant financing activities for the same period last year included:

• $116.2 million of Common Shares dividend payments;

• $93.0 million of net draws from our Revolving Credit Facility;

• $7.9 million of senior debt repayments; and

• $6.6 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.

Subsequent Event

On October 20, 2014, we redeemed the remaining issued and outstanding 5.75% Convertible Unsecured

Subordinated Debentures, Series C due July 31, 2017. As at September 30, 2014, there was $51.7 million

principal amount of Series C Debentures issued and outstanding.

Ruby Acquisition FinancingTo fund our acquisition of the 50% convertible preferred interest in Ruby, we will utilize net cash proceeds from

our October subscription receipt offering and drawings on a new unsecured non-revolving term loan ("New

Credit Facility").

On October 1, 2014 we issued 56,120,000 subscription receipts at a price of $16.40 per subscription receipt for

gross proceeds of approximately $920 million. This included the issuance of 7,320,000 subscription receipts on

the exercise in full of the over-allotment option granted to the underwriters, which was exercised concurrently

with the closing of the offering. The balance of the purchase price will be funded with a drawing under our New

Credit Facility.

The gross proceeds from the issue of the subscription receipts will be held by an escrow agent pending, among

other things, receipt of all regulatory and government approvals required to finalize the Ruby acquisition, and

fulfillment or waiver of all other outstanding conditions precedent to closing the Ruby acquisition.

The New Credit Facility will rank pari passu with our senior unsecured obligations, including our existing

Revolving Credit Facility. It will have a two-year term from the closing of the acquisition and will bear interest at

a quoted floating rate plus a margin. Prepayments will be permitted at our option at any time and upon the

occurrence of certain events, in each case without premium or penalty.

The New Credit Facility is expected to be in a form similar to our Revolving Credit Facility, and is expected to

contain representations and warranties, affirmative and negative covenants (including requirements to meet

certain financial ratios on an ongoing basis) and events of default that are customary for bank credit facilities of

this nature.

21

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.

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 55.4 50.0 160.8 149.4

Less dividends paid in Common Shares under DRIP (13.9) (11.4) (38.8) (33.2)

Net dividends paid/payable 41.5 38.6 122.0 116.2

Excess of cash from operating activities over netdividends paid/payable 8.9 5.4 21.3 20.2

Deficiency of net income attributable to Common Shares over net dividends paid/payable (39.0) (10.7) (90.6) (75.6)

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.

22

FINANCIAL INSTRUMENTS

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

exposures. For the three and nine months ended September 30, 2014, equity income from York Energy Centre

includes a $0.8 million and a $8.5 million unrealized mark-to-market loss ($0.6 million and $6.4 million after tax),

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

includes a $1.9 million and $11.8 million unrealized mark-to-market gain, respectively ($1.4 million and $8.8

million after tax).

Veresen entered into forward foreign exchange contracts to manage the foreign exchange exposure relating to

the acquisition of a 50% convertible preferred interest in Ruby for US$1.425 billion. As at September 30, 2014, we

committed to purchase US$800 million at fixed Canadian rates for settlement at a future date which is intended to

approximate the expected closing date of the acquisition. The weighted average foreign exchange rate of these

contracts is approximately 1.116 Canadian dollars for each US dollar. For the three and nine months ended

September 30, 2014, net income includes a $4.9 million unrealized gain associated with the forward foreign

exchange contracts ($3.7 million after tax).

Subsequent to September 30, 2014 we committed to purchase an additional US$625 million at fixed Canadian

rates for settlement at a future date. The weighted average foreign exchange rate of these contracts is approximately

1.115 Canadian dollars for each US dollar. The weighted average foreign exchange rate of all our forward foreign

exchange contracts totaling US$1.425 billion is approximately 1.115.

CONTINGENCIES

On August 18, 2014, we were named as a respondent in an application commenced by Energy Fundamentals

Group Inc. in the Ontario Superior Court of Justice in Toronto on August 14, 2014. In the application, EFG

seeks a declaration that, pursuant to a letter agreement dated July 27, 2005 between EFG and Fort Chicago

Energy Partners L.P., the predecessor to Veresen, EFG has the option to acquire up to 20% of Veresen's equity

interest in the Jordan Cove LNG terminal and related assets in Coos Bay, Oregon.

We believe that the option held by EFG applied only to the prior proposal to build an LNG import terminal and is

not valid with respect to the current proposed liquefaction and LNG export terminal.

NEW ACCOUNTING STANDARDS

Effective January 1, 2014, we 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 us.

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.

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.

23

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)

28.5 8.1 58.8 23.9

Change in non-cash working capital (15.1) 12.0 6.4 20.3

Principal repayments on senior notes (2.7) (2.9) (8.6) (8.7)

Maintenance capital expenditures (0.9) (1.2) (4.7) (5.0)

Distributions earned greater (less) than distributions received

(2) (2.8) 10.6 (3.5) 10.3


Current tax on Preferred Share dividends 1.6 0.9 4.8 2.5

Distributable cash 54.9 69.3 184.2 173.1

(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 nine months ended September 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.

24

SELECTED QUARTERLY FINANCIAL INFORMATION

2014 2013 2012 (1)

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

Operating revenues 82.0 89.3 92.0 78.8 84.5 89.8 71.6 67.7

Net income (loss) attributable to CommonShares 2.5 (2.4) 31.3 12.6 27.9 11.5 1.2 13.1

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

Distributable cash 54.9 63.7 65.6 55.8 69.3 49.2 54.6 56.5

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

Cash from operating activities 50.4 47.9 45.0 81.6 44.0 55.0 37.4 65.1

Significant items that affected quarterly financial results include the following:

• Third quarter 2014 reflects lower earnings from Aux Sable and higher Jordan Cove related project

development costs.

• 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.

• 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.

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 September 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 September 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.

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

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

reporting.

25

Veresen Inc.

Consolidated Statement of Financial Position

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

AssetsCurrent assets


Restricted cash 6.9 3.7

Distributions receivable 45.1 46.2

Receivables 75.0 62.9

Other (note 6) 16.4 11.3

169.6 150.7

Investments in jointly-controlled businesses (note 3) 836.9 857.7

Rate-regulated asset 26.7 34.7

Pipeline, plant and other capital assets 1,519.2 1,438.1

Intangible assets 408.4 430.7

Other assets 64.5 61.5

3,025.3 2,973.4

LiabilitiesCurrent liabilities

Payables 79.0 55.0

Dividends payable 14.2 13.2

Current portion of long-term senior debt (note 4) 11.4 212.4

104.6 280.6

Long-term senior debt (note 4) 1,000.2 975.1

Subordinated convertible debentures 51.7 86.2

Deferred tax liabilities 266.4 277.3

Other long-term liabilities 50.2 48.5

1,473.1 1,667.7

Shareholders’ EquityShare capital (note 5)

Preferred shares 341.4 341.4

Common shares (223.5 and 201.5 outstanding at September30, 2014 and December 31, 2013, respectively) 2,197.8 1,848.6

Additional paid-in capital 4.3 4.3

Cumulative other comprehensive loss (107.3) (134.0)

Accumulated deficit (884.0) (754.6)

1,552.2 1,305.7

3,025.3 2,973.4

Commitments and Contingencies (note 10)

See accompanying Notes to the Consolidated Financial Statements

26

Veresen Inc.

Consolidated Statement of Income

(Canadian $ Millions, except per Common ShareThree months ended


September 30amounts (note 5); unaudited) 2014 2013 2014 2013

Equity income (note 3) 33.8 50.6 113.1 120.2

Operating revenues 82.0 84.5 263.3 245.9

Operations and maintenance (35.7) (38.2) (130.7) (116.9)

General, administrative and project development (40.8) (19.8) (96.2) (61.6)

Depreciation and amortization (24.6) (22.8) (73.5) (67.5)

Interest and other finance (12.6) (15.7) (41.4) (46.8)

Foreign exchange and other (note 6) 6.0 (0.9) 6.3 0.7

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

Net income before tax 8.1 37.7 55.2 74.0

Current tax (9.3) (6.8) (19.2) (10.2)

Deferred tax 7.8 (0.8) 7.7 (16.6)

Net income 6.6 30.1 43.7 47.2



Net income per Common Share

Basic and diluted 0.01 0.14 0.15 0.20

Consolidated Statement of Comprehensive Income

(Canadian $ Millions; unaudited)



2014 2013 2014 2013

Net income 6.6 30.1 43.7 47.2

Other comprehensive income (loss)

Cumulative translation adjustment

Unrealized foreign exchange gain (loss) on translation 24.1 (10.0) 26.7 14.7

Other comprehensive income (loss) 24.1 (10.0) 26.7 14.7

Comprehensive income 30.7 20.1 70.4 61.9


Comprehensive income attributable to Common Shares 26.6 17.9 58.1 55.3


27

Veresen Inc.

Consolidated Statement of Cash FlowsThree months ended


September 30(Canadian $ Millions; unaudited) 2014 2013 2014 2013Operating

Net income 6.6 30.1 43.7 47.2

Equity income (33.8) (50.6) (113.1) (120.2)

Distributions from jointly-controlled businesses 50.9 51.0 168.0 143.0

Depreciation and amortization 24.6 22.8 73.5 67.5

Foreign exchange and other non-cash items (5.7) 2.4 (2.5) 1.6

Deferred tax (7.8) 0.8 (7.7) 16.6

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

Changes in non-cash working capital (note 8) 15.6 (12.5) (4.3) (19.3)

50.4 44.0 143.3 136.4

Investing

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

Investments in jointly-controlled businesses (6.5) (17.3) (19.2) (53.2)

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

Pipeline, plant and other capital assets (31.4) (14.4) (111.9) (38.5)

Restricted cash (1.1) 0.3 (3.2) (2.6)

Other - - (0.5) 0.1

(39.0) (31.4) (104.9) (94.2)

Financing

Restricted cash - - - 3.9

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

Long-term debt repaid (201.8) (2.1) (258.1) (7.9)

Net change in credit facilities 41.4 26.0 (121.1) 93.0

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

Common Share dividends paid (40.9) (38.6) (121.0) (116.2)

Preferred Share dividends paid (4.1) (2.2) (12.3) (6.6)

Repayments from jointly-controlled businesses 0.4 0.4 1.2 1.1

Other - 1.7 1.3 (0.2)

(205.0) (14.8) (38.4) (32.9)

Increase (decrease) in cash and short-term investments (193.6) (2.2) - 9.3

Effect of foreign exchange rate changes on cash andshort-term investments 0.3 (0.1) (0.4) 0.1

Cash and short-term investments at the beginning of theperiod 219.5 27.8 26.6 16.1

Cash and short-term investments at the end of the period 26.2 25.5 26.2 25.5


28

Veresen Inc.

Consolidated Statement of Shareholders' EquityNine months ended September 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) 34.6 -

Common Shares issued under Premium Dividend and Dividend Reinvestment Plan("DRIP") 34.4 29.4

Common Shares issued, net of issue costs 275.8 -

September 30 2,193.4 1,833.7

Common Shares to be issued under DRIP 4.4 3.8

Balance at the end of the period 2,197.8 1,837.5

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 26.7 14.7

Balance at the end of the period (107.3) (150.1)

Accumulated deficitJanuary 1 (754.6) (608.1)

Net income 43.7 47.2

Preferred Share dividends (12.3) (6.6)

Common Share dividends (160.8) (149.4)

Balance at the end of the period (884.0) (716.9)

Shareholders' Equity 1,552.2 1,170.0


29

Notes to the Consolidated Financial Statements

Three and nine months ended September 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 nine months ended September 30, 2014 and September 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 September 30, 2014 and results of operations and cash flows for the three and nine months ended

September 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, and 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, and is to be applied retrospectively. The

Company is currently evaluating the impact of the standard.

30

3. Investments in Jointly-Controlled Businesses

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

As at September 30, 2014Nine months endedSeptember 30, 2014

As atSeptember

30, 2014

Ninemonths

endedSeptember

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)

182.8 1,306.8 81.3 15.3 1,078.6 356.2 265.0 91.2 50 192.4 40.2

Alliance U.S. (3) (6)

128.4 1,143.1 94.6 11.8 620.0 271.0 172.7 98.3 50 239.2 45.6

Aux Sable Canada 67.2 108.1 67.5 8.4 - 559.5 545.3 14.2 50 50.0 7.0

ASLP (4) (6)

71.4 456.4 73.5 9.1 12.1 139.0 115.4 23.6 42.7 145.7 11.5

ASM (6)

35.9 248.4 28.5 0.9 - 394.5 367.6 26.9 42.7 108.0 11.5

ACM 4.6 - 3.1 - - 209.6 208.7 0.9 42.7 0.7 2.1

Sable NGL Services 1.2 - 0.3 - - - (6.4) 6.4 50 0.5 3.2

York Energy Centre (5)

19.4 279.6 6.5 37.7 258.3 58.5 58.6 (0.1) 50 39.2 (1.9)

NRGreen 11.5 138.4 7.3 5.6 33.6 9.0 6.1 2.9 50 51.2 1.5

Grand Valley 4.0 50.8 2.3 0.6 43.3 5.6 4.9 0.7 75 6.5 0.5

Other (6)

7.8 - 0.9 - - - 15.7 (15.7) 50-75 3.5 (8.1)

836.9 113.1

As at December 31, 2013Nine months endedSeptember 30, 2013

As atDecember

31, 2013

Ninemonths

endedSeptember

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 1,120.3 339.6 252.9 86.7 50 203.9 38.4

Alliance U.S. (3) (6)

109.2 1,162.8 83.9 12.3 645.2 242.8 165.8 77.0 50 236.2 36.4

Aux Sable Canada 50.2 131.2 45.5 7.8 - 145.3 132.9 12.4 50 62.1 6.1

ASLP (4) (6)

61.1 436.9 46.7 8.2 19.0 131.6 85.0 46.6 42.7 140.8 20.9

ASM (6)

41.2 234.4 33.0 0.5 - 373.2 340.1 33.1 42.7 101.2 14.1

ACM 1.1 - 1.5 - - 118.3 134.2 (15.9) 42.7 0.3 (4.9)

Sable NGL Services 0.5 - 0.1 - - 6.6 9.4 (2.8) 50 0.2 (1.4)

York Energy Centre (5)

17.8 289.6 6.4 20.7 260.2 47.9 16.8 31.1 50 54.3 13.7

NRGreen 22.4 135.2 10.6 5.5 39.8 8.2 6.1 2.1 50 50.9 1.0

Grand Valley 3.9 52.8 3.8 43.5 - 5.3 4.9 0.4 75 7.1 0.3

Other (6)

2.4 0.8 1.6 - - - 8.4 (8.4) 50-75 0.7 (4.4)

857.7 120.2

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 September 30, 2014, the Company had a $55.8 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 September 30, 2014, the Company had a US$11.0 million (December 31, 2013 - US$ 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 September 30, 2014, the Company had a US$29.8 million (December 31, 2013 - US$ 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 September 30, 2014, the Company had a $43.9 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).

31

(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.

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

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

the Facility was drawn by $44.1 million (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 September 30, 2014, was 220,772,300 (2013 –

199,106,048) and 226,515,911 (2013 – 205,012,556), 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 nine

months ended September 30, 2014, was 214,015,243 (2013 – 199,085,684) and 219,853,628 (2013 –

204,992,192), respectively. The number of Common Shares outstanding would increase by 3,538,248 (2013 –

5,906,508) if the outstanding convertible debentures on September 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 nine months ended September 30, 2014 and 2013. During the nine months ended

September 30, 2014, $34.6 million of the 5.75% convertible debentures were converted into 2,368,260 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%.

32

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 September 30, 2014 senior debt had a carrying value of

$1,011.6 million (December 31, 2013 – $1,187.5 million) and fair value of $1,060.3 million (December 31, 2013 –

$1,226.3 million).

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

Level 1 Level 2 Level 3 Total


Restricted cash 6.9 6.9

Other 4.9 4.9

Interest Rate Hedge

Veresen and its jointly-controlled businesses periodically enter into interest rate hedges to manage interest rate

exposures. As at September 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 September 30, 2014:

Variable Debt Interest Rate Fixed RateNotional Amount

(50%)Fair

Value (50%) Term

CAD-BA-CDOR 4.36% $127.3 $(18.9) 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.

33

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.

Foreign Exchange Hedge

In September 2014, Veresen entered into forward foreign exchange contracts to manage the foreign exchange

exposure relating to the acquisition of a 50% interest in the Ruby pipeline system (note 11). As at September 30,

2014 Veresen committed to purchase $800 million US Dollars at fixed Canadian rates for settlement at a future

date. Future changes in foreign exchange rates will affect the fair value of the hedges, impacting the amount of

unrealized gains or losses recognized in the period.

Contract TypeNotional Amount

(US $)Forward Rate(Canadian $)

Fair Value Term

Call $106.0 $1.1150 $1.4 September 22, 2014 to November 3, 2014

Synthetic Forward $94.0 $1.1150 $0.5 September 22, 2014 to November 3, 2014

Forward $200.0 $1.1118 $1.8 September 24, 2014 to October 31, 2014

Forward $200.0 $1.1178 $0.6 September 26, 2014 to October 31, 2014

Forward $200.0 $1.1175 $0.6 September 26, 2014 to November 3, 2014

$800.0 $4.9

For the three and nine month period ending September 30, 2014, the Company recognized a $4.9 million

unrealized pre-tax gain associated with the forward foreign exchange contracts, included within foreign exchange

and other in the Consolidated Statement of Income, classified within the Corporate segment.

34

7. Segmented Information

Pipelines Midstream Power Corporate(1) TotalThree months endedSeptember 30 2014 2013 2014 2013 2014 2013 2014 2013 2014 2013

Equity income (loss) 28.4 25.8 8.9 24.1 - 2.5 (3.5) (1.8) 33.8 50.6

Operating revenues 15.0 15.0 32.4 35.6 34.6 33.9 - - 82.0 84.5

Operations and maintenance (7.6) (7.6) (12.6) (16.0) (15.5) (14.6) - - (35.7) (38.2)

General, administrative andproject development (0.5) (0.6) (0.9) (0.3) (3.3) (3.0) (36.1) (15.9) (40.8) (19.8)

Depreciation and amortization (3.5) (3.5) (9.9) (9.8) (10.6) (9.0) (0.6) (0.5) (24.6) (22.8)

Interest and other finance (1.2) (1.3) - - (2.4) (3.6) (9.0) (10.8) (12.6) (15.7)

Foreign exchange and other - - - - - - 6.0 (0.9) 6.0 (0.9)

Net income (loss) before tax 30.6 27.8 17.9 33.6 2.8 6.2 (43.2) (29.9) 8.1 37.7

Tax expense(2) - - - - - - (1.5) (7.6) (1.5) (7.6)

Net income (loss) 30.6 27.8 17.9 33.6 2.8 6.2 (44.7) (37.5) 6.6 30.1

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

Net income (loss) attributable toCommon Shares 30.6 27.8 17.9 33.6 2.8 6.2 (48.8) (39.7) 2.5 27.9

Total assets(3) 708.0 736.0 1,206.6 1,230.3 996.3 925.3 114.4 93.7 3,025.3 2,985.3

Capital expenditures(4) - 0.1 5.4 4.6 25.9 9.5 0.1 0.2 31.4 14.4

Pipelines Midstream Power Corporate(1) TotalNine months endedSeptember 30 2014 2013 2014 2013 2014 2013 2014 2013 2014 2013

Equity income (loss) 85.8 74.8 35.3 34.8 - 15.0 (8.0) (4.4) 113.1 120.2

Operating revenues 46.5 40.5 101.5 111.0 115.3 94.4 - - 263.3 245.9

Operations and maintenance (24.2) (18.6) (43.5) (52.8) (63.0) (45.5) - - (130.7) (116.9)

General, administrative andproject development (1.8) (2.3) (3.1) (2.9) (10.7) (10.5) (80.6) (45.9) (96.2) (61.6)

Depreciation and amortization (10.5) (10.5) (29.7) (29.5) (31.4) (25.9) (1.9) (1.6) (73.5) (67.5)

Interest and other finance (3.7) (3.8) - - (9.7) (10.8) (28.0) (32.2) (41.4) (46.8)

Foreign exchange and other - - - - 0.3 - 6.0 0.7 6.3 0.7

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

Net income (loss) before tax 92.1 80.1 60.5 60.6 0.8 16.7 (98.2) (83.4) 55.2 74.0

Tax expense(2) - - - - - - (11.5) (26.8) (11.5) (26.8)

Net income (loss) 92.1 80.1 60.5 60.6 0.8 16.7 (109.7) (110.2) 43.7 47.2

Preferred Share dividends - - - - - - (12.3) (6.6) (12.3) (6.6)

Net income (loss) attributable toCommon Shares 92.1 80.1 60.5 60.6 0.8 16.7 (122.0) (116.8) 31.4 40.6

Total assets(3) 708.0 736.0 1,206.6 1,230.3 996.3 925.3 114.4 93.7 3,025.3 2,985.3

Capital expenditures(4) - 1.8 10.0 12.6 101.6 23.7 0.3 0.4 111.9 38.5

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

three and nine months ended September 30, 2014 include project development costs of $28.5 million (2013 - $8.1 million) and $58.8

million (2013 - $23.9 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.

35

8. Supplemental Cash Flow Information



2014 2013 2014 2013Receivables 18.3 9.3 (3.3) (3.7)

Other assets 0.8 2.1 (0.4) 0.2

Payables (3.5) (23.9) (0.6) (15.8)

Changes in non-cash operating working capital 15.6 (12.5) (4.3) (19.3)

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.

On August 18, 2014, the Company named as a respondent in an application commenced by Energy

Fundamentals Group Inc. ("EFG") in the Ontario Superior Court of Justice in Toronto on August 14, 2014. In the

application, EFG seeks a declaration that, pursuant to a letter agreement dated July 27, 2005 between EFG and

Fort Chicago Energy Partners L.P., the predecessor to Veresen, EFG has the option to acquire up to 20% of

Veresen's equity interest in the Jordan Cove LNG terminal and related assets in Coos Bay, Oregon. The

Company believes that the option held by EFG applied only to the prior proposal to build an LNG import terminal

and is not valid with respect to the current proposed liquefaction and LNG export terminal.

11. Subsequent Events

Acquisition of a 50% Interest in Ruby PipelineOn September 22, 2014, the Company announced it had entered into an agreement to acquire, through a wholly-

owned subsidiary, two entities which hold an aggregate 50% convertible preferred interest in Ruby Pipeline

Holding Company, LLC, which owns the Ruby pipeline system ("Ruby"), for cash consideration of US$1.425

billion. The acquisition is expected to close in November 2014 and will be funded with proceeds from the October

1, 2014 subscription receipt offering and from a new unsecured non-revolving term loan ("New Credit Facility").

36

Ruby is a natural gas transmission system delivering U.S. Rockies natural gas production to markets in the

western United States. The 680-mile, 42-inch pipeline has a current capacity of approximately 1.5 billion cubic

feet per day ("bcf/d"). Ruby originates at the Opal hub in Wyoming and extends to the Malin hub in Oregon.

The acquisition will be accounted for as an investment using the cost method. Transaction costs of approximately

US$7.1 million will be classified with the investment in Ruby on the balance sheet in accordance with the cost

method of accounting. The purchase price allocation below is preliminary pending a final determination of the

value of the assets acquired and transaction costs incurred.

Consideration

Cash consideration to be paid US $ 1,425.0

Allocation of Consideration

Cash 22.7

Investment in convertible preferred units in Ruby Pipeline HoldingCompany, LLC 1,402.3

1,425.0

Transaction costs 7.1

Investment in Ruby Pipeline US $ 1,432.1

Subscription Receipt OfferingOn October 1, 2014, the Company issued 56.1 million subscription receipts ("the Offering") at a price of $16.40

per subscription receipt. The aggregate gross proceeds from the Offering are approximately $920 million. Each

subscription receipt entitles the holder thereof to receive, concurrent with the closing of the Ruby acquisition and

upon satisfaction of certain escrow release conditions, one Common Share of Veresen plus an amount equal to

the dividends Veresen declares on the Common Shares, if any, for record dates which occur during the period

from October 1, 2014 to the date immediately preceding the date that Common Shares are issued on the

exchange of subscription receipts, net of any applicable withholding taxes.

New Credit FacilityThe New Credit Facility is a new unsecured non-revolving term loan that will be used with the net proceeds from

the Offering to fund the 50% convertible preferred interest in Ruby. It will rank pari passu with the Company's

senior unsecured obligations, including the existing Revolving Credit Facility. It will have a two-year term from the

closing of the acquisition and will bear interest at a quoted floating rate plus a margin. Prepayments will be

permitted at the Company's option at any time and upon the occurrence of certain events, in each case without

premium or penalty.

The New Credit Facility is expected to be in a form similar to the Revolving Credit Facility, and is expected to

contain representations and warranties, affirmative and negative covenants (including requirements to meet

certain financial ratios on an ongoing basis) and events of default that are customary for bank credit facilities of

this nature.

Early Redemption of Series C DebenturesOn October 20, 2014 (the "Redemption Date"), the Company redeemed the remaining issued and outstanding

5.75% Convertible Unsecured Subordinated Debentures, Series C due July 31, 2017 (the "Series C

Debentures"). As at September 30, 2014, there was $51.7 million principal amount of Series C Debentures issued

and outstanding. The accrued and unpaid interest on the Series C Debentures issued and outstanding as of the

Redemption Date was $12.76 per $1,000 principal amount of Series C Debentures.

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

November 21, 2014 to shareholders of record on October 31, 2014.

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