UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C.  20549

 

FORM 6-K

 

Report of Foreign Issuer

Pursuant to Rule 13a-16 or 15d-16 of

the Securities Exchange Act of 1934

 

Dated March 29, 2011

 

Commission file number 001-15254

 


 

ENBRIDGE INC.

(Exact name of Registrant as specified in its charter)

 

Canada

 

None

(State or other jurisdiction

 

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

of incorporation or organization)

 

 

 

3000, 425 — 1st Street S.W.

Calgary, Alberta, Canada  T2P 3L8

(Address of principal executive offices and postal code)

 

(403) 231-3900

(Registrants telephone number, including area code)

 


 

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

 

Form 20-F    o

 

Form 40-F      x

 

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

 

Yes                 o

 

No                    x

 

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

 

Yes                 o

 

No                    x

 

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

 

Yes                 o

 

No                    x

 

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

 

N/A

 

THIS REPORT ON FORM 6-K SHALL BE DEEMED TO BE INCORPORATED BY REFERENCE IN THE REGISTRATION STATEMENTS ON FORM S-8 (FILE NO. 333-145236, 333-127265, 333-13456, 333-97305 AND 333-6436), FORM F-3 (FILE NO. 33-77022) AND FORM F-10 (FILE NO. 333-152607 AND 33-170200) OF ENBRIDGE INC. AND TO BE PART THEREOF FROM THE DATE ON WHICH THIS REPORT IS FURNISHED, TO THE EXTENT NOT SUPERSEDED BY DOCUMENTS OR REPORTS SUBSEQUENTLY FILED OR FURNISHED.

 

The following document is being submitted herewith:

 

·      Annual Report for the year ended December 31, 2010.

 

 

 



 

SIGNATURES

 

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

 

 

 

 

 

 

ENBRIDGE INC.

 

 

 

 

(Registrant)

 

 

 

 

 

 

 

 

 

 

Date:

March 29, 2011

 

By:

/s/”Alison T. Love”

 

 

 

 

Alison T. Love

 

 

 

Vice President, Corporate Secretary & Chief Compliance Officer

 

2



 

CHICAGO, IL Energy is essential. It powers our society and economy. It moves people, goods and information. It fuels our cars, heats our home and lights our neighbourhoods. Superior Toronto Buffalo Wood River ENBRIDGE INC. 2010 ANNUAL REPORT Enbridge delivers the energy North Americans need— safely reliably and efficiently. THE ENERGY YOU COUNT ON ENBRIDGE INC. 2010 ANNUAL REPORT

 


2 Assets 12 Discipline 18 Values 24 Operations 26 Letter to Shareholders 33 Corporate Governance 35 Management’s Discussion and Analysis 107 Consolidated Financial Statements 115 Notes to the Consolidated Financial Statements

 


From the company you count on. For the energy to power economic growth, you count on us. For the natural gas that keeps us warm and cooks our food, you count on us. For the green energy that delivers environmental benefits, you count on us. For the peace of mind of a solid investment return, you count on us. It’s what we’ve done for decades, and you can count on Enbridge to continue to deliver. REGINA, SK Through our pipelines to refineries. Through our natural gas distribution networks to homes, offices and factories. From our renewable energy assets to the electrical grid—every second of every day, Enbridge delivers the energy that is integral to our daily lives. Fort McMurray Calgary Edmonton Winnipeg Forward-Looking Information: This Annual Report includes references to forward-looking information. By its nature this information applies certain assumptions and expectations about future outcomes, so we remind you it is subject to risks and uncertainties that affect every business, including ours. The more significant factors and risks that might affect future outcomes for Enbridge are listed and discussed in the “Forward-Looking Information” section on page 40 of this annual report and also in the risk sections of our public disclosure filings, including Management’s Discussion and Analysis, available on both the SEDAR and EDGAR systems at www.sedar.com and www.sec.gov/edgar.shtml.

 


FORT MCMURRAY, AB Our storage terminal located in the heart of Canada’s oil sands region is part of the critical infrastructure we provide to oil sands producers. As the leading pipeline operator in the Fort McMurray to Edmonton/ Hardisty corridor, we offer our customers a wide range of competitive transportation options to reach new markets throughout North America. Edmonton Regina Seattle Calgary 2 ENBRIDGE INC. 2010 ANNUAL REPORT

 


Our assets connect North Americans with the energy they need. Enbridge’s continent-wide energy delivery infrastructure connects secure and reliable sources of energy—crude oil, refined products, natural gas and renewable electricity—to key North American markets. We deliver energy safely and reliably from a number of key continental energy resource developments, including Canada’s oil sands region, the Bakken oil region, major gas plays in both Canada and the U.S., and from our expanding Green Energy assets. LIQUIDS PIPELINES* Our mainline system is the world’s longest, most complex crude oil and liquids pipeline system, and the largest conduit of oil into the United States. GAS PIPELINES, PROCESSING AND ENERGY SERVICES* Our network is serving North America’s prolific gas-producing regions and many of the deepwater platforms in the Gulf of Mexico. GAS DISTRIBUTION* We distribute natural gas to a growing base of residential, commercial and industrial customers in Ontario, Quebec, New Brunswick, Vermont and New York State. GREEN ENERGY* We have a diversified and growing portfolio of renewable and alternative energy projects, including wind, solar, geothermal, waste heat recovery and fuel cells. * Includes assets held directly and indirectly through Sponsored Investments and Corporate investments described in Management’s Discussion and Analysis. ASSETS 3

 


EDMONTON, AB Enbridge’s Edmonton Terminal is the starting point of our mainline system. Comprising six adjacent pipelines with combined capacity of 2.5 million barrels per day, the system transports approximately 65% of western Canadian crude oil exports. 4 ENBRIDGE INC. 2010 ANNUAL REPORT

 


Regina Calgary Fort McMurray Fort St. John We are growing our network to help oil producers reach new markets. Enbridge’s pipeline systems are located in strategically important geographical areas, giving us an unparalleled ability to expand and extend our energy delivery networks throughout North America. We are the leading pipeline operator in both Canada’s oil sands region, the second largest resource play in the world with an estimated 170 billion barrels of proven recoverable reserves, and the rapidly growing Bakken formation in Canada and the United States. We are currently expanding our pipeline capacity in both regions. Enbridge delivers approximately 13% of the United States’ daily crude oil imports. Total number of barrel miles shipped on the Enbridge Mainline system in 2010. One barrel of oil, transported one mile, equals one barrel-mile. In 2010 Enbridge delivered an average of 2.2 million barrels per day along its Mainline system. 13% 399BILLION DAILY U.S. CRUDE OIL IMPORTS ASSETS 5

 


6 ENBRIDGE INC. 2010 ANNUAL REPORT

 


We link major sources of natural gas supply to consumers. All of our gas transportation and processing businesses are located in the right place to serve growing production and meet growing demand for this low-cost, environmentally attractive source of energy. ONSHORE PIPELINES The Alliance and Vector pipelines transport up to 1.6 billion cubic feet per day of natural gas from western Canada to Midwestern U.S. markets and eastern Canada. OFFSHORE PIPELINES With 13 natural gas gathering pipelines and one oil pipeline in five major corridors in the Gulf of Mexico, Enbridge is one of the largest operators in the deepwater Gulf of Mexico. We are well positioned to capture new opportunities in both gas gathering and crude oil pipelines serving the region’s energy resource developments. PROCESSING & ENERGY SERVICES Enbridge Energy Partners is one of the largest processors in Texas, handling about 13% of total production in the state with 65% of its volumes from unconventional sources such as shales and tight sands. Aux Sable, with operations in Canada and the U.S., has a significant presence in the North American gas processing business. GULF OF MEXICO Enbridge has the best positioning for growth of any provider in the deepwater Gulf of Mexico, with an extensive infrastructure and a strong team with an established track record in the region. Houston Gulf of Mexico New Orleans Tulsa We transport about half of all the deepwater natural gas production in the Gulf of Mexico. Enbridge transports, gathers and processes over 6.3 billion cubic feet of natural gas per day through its long-haul transmission, gas gathering and offshore assets. 50% 6.3 BILLION ASSETS 7

 


TORONTO, ON Our customers in Canada’s largest city rely on the natural gas we deliver to cook their food and heat their water, homes and offices. With our focus on operational excellence, Enbridge Gas Distribution regularly ranks among the top utilities in North America for safety and reliability. Ontario-based Enbridge Gas Distribution delivers clean-burning natural gas to 2 million residential, commercial and industrial customers. 2 MILLION 8 ENBRIDGE INC. 2010 ANNUAL REPORT

 


Toledo Chicago Montreal Superior Millions count on us to deliver their natural gas safely and reliably. Enbridge Gas Distribution (EGD) is one of the largest and fastest-growing natural gas distributors in North America, serving 2 million customers and adding over 30,000 new customers every year. EGD has been delivering energy to consumers for over 160 years. Enbridge’s gas distribution business also includes Enbridge Gas New Brunswick and interests in natural gas utilities in Quebec, Vermont and northern New York State. Enbridge Gas Distribution has returned over $44 million to customers through the incentive regulation sharing model, which entered its fourth year in 2011. This agreement has benefited customers and improved returns to shareholders. $44 MILLION ASSETS 9

 


KINCARDINE, ON The 190-MW Enbridge Ontario Wind Power Project is producing enough power to supply about 60,000 homes. Since 2001, we have grown our interests in wind power from 11 MW to 709 MW. In 2010, we marked our entry into the U.S. green energy market with a US$500 million investment in the 250-MW Cedar Point Wind Energy Project in Colorado. Buffalo Ottawa Chicago Superior 10 ENBRIDGE INC. 2010 ANNUAL REPORT

 


Strong fundamentals are driving our green energy growth. Our renewable and alternative power generation investments offer an attractive risk-reward profile similar to other parts of our business, and support society’s desire for a lower impact energy future. Green Power Generation Capacity* (In megawatts and by year of acquisition up to March 2, 2011) Wind Solar Other 41 91 91 93 462 834 854 11 10 09 08 07 06 05 Enbridge has secured $1.5 billion in new green energy projects and we expect that rate of growth to continue. All of our projects are underpinned by long-term power purchase agreements and fixed price contracts, delivering stable cash flows and attractive returns. $1.5 BILLION Enbridge has interests in 854 megawatts of renewable and alternative power generation capacity—enough to meet the energy needs of more than 290,000 homes. Our interests include wind, solar, waste heat recovery, geothermal and fuel cells. *In operation and under construction ASSETS 11

 


CALGARY, AB Our head office Finance team—and all of our employees—are working to ensure that Enbridge continues to deliver superior value to our shareholders in the years and decades ahead. Seattle Fort McMurray Regina Edmonton 12 ENBRIDGE INC. 2010 ANNUAL REPORT

 


Our disciplined approach creates value for shareholders. We have consistently delivered superior value to shareholders for over 55 years as a publicly traded company through our disciplined approach to securing, financing and constructing projects. We are focused on maintaining our strong track record of capital management. We offer investors a unique investment proposition: visible, transparent and sustained earnings and cash flow growth along with a substantial and growing dividend, all while maintaining a reliable business model. Total Shareholder Return (Total Return Index March 1953 = 1) 13.6% Over a period of almost 60 years, we have delivered a 13.6% average annual return to shareholders. 600 1200 1800 2010 1953 Enbridge 13.6% S&P/TSX 9.5% RELIABLE BUSINESS MODEL Our performance is predictable because 95% of our earnings are supported by regulated or long-term contracted assets. HIGH INCOME PAYOUT With a payout policy of 60 – 70% of earnings, we have delivered an 11% average annual dividend increase over the past 10 years. We have never reduced the dividend in our 55+ year history as a publicly traded company. VISIBLE GROWTH We brought $12 billion in projects into service over the past three years, have secured more than $6 billion in projects that will come into service between 2011 and 2014 and have another $30 billion under development. DISCIPLINE 13

 


15% Enbridge increased its annual dividend by 15% in both 2010 and 2011 and aims to pay out 60 – 70% of its adjusted earnings as dividends annually. 14 ENBRIDGE INC. 2010 ANNUAL REPORT

 


Our growth is visible and sustained. The steady growth of our liquids pipelines, natural gas transportation and distribution, and green energy businesses will continue to drive strong earnings growth and even more significant cash flow growth in coming years. * 2011 earnings guidance announced December 1, 2010 of $2.75 to $2.95. Industry-leading Adjusted Earnings per Share Growth (Canadian dollars per share) Adjusted earnings per share have grown at an average annual rate of 9.4% over the past 10 years and are expected to grow on average by 10% annually through the middle of the decade. 1.23 1.34 1.50 1.47 1.59 1.74 1.79 1.88 2.35 2.66 2.95* 11e 10 09 08 07 06 05 04 03 02 01 Growing Dividends (Canadian dollars per share) Enbridge has increased its dividend each year for the past 16 years and is very well positioned for further increases. We expect to be able to continue delivering exceptional dividend growth to our investors. 0.70 0.76 0.83 0.92 1.04 1.15 1.23 1.32 1.48 1.70 1.96 11e 10 09 08 07 06 05 04 03 02 01 FLANAGAN, IL Flanagan is the end point of the Alberta Clipper pipeline, the single largest project we’ve ever completed. Both Alberta Clipper and the unique Southern Lights diluent pipeline, which together represented a capital investment of more than $5 billion, were completed and brought into service in 2010. Our strategy continues to emphasize a high level of financial flexibility. We have ample financial capacity to undertake the many attractive investment opportunities that lie before us. Detroit Chicago Toledo Patoka Superior DISCIPLINE 15

 


Superior Chicago Buffalo Toronto Wood River DEKALB, IL From project development and design, from construction through to operations, Enbridge has developed a strong track record for solid execution and on-time delivery. Our success comes from our strong technical skills and exceptional project management capabilities, combined with partnerships with world-class contractors. As we shift our focus from mainline expansion to key growth areas like the oil sands and the Bakken region, those attributes give producers a compelling reason to choose Enbridge to develop the transportation infrastructure they need. 16 ENBRIDGE INC. 2010 ANNUAL REPORT

 


$30 BILLION Our growth is predictable. The projects we’ve secured give us confidence in predicting our future growth. We have already secured a large portion of the projects that will help us achieve an expected 10% average annual growth rate of adjusted earnings per share through the middle of the decade. We currently have over $6 billion of secured growth projects in Canada and the U.S.—pipelines serving Canada’s oil sands and the Bakken region in Saskatchewan and North Dakota, as well as green energy projects—and another $30 billion in development opportunities. PROJECTS COMPLETED IN 2010 Alberta Clipper Project Southern Lights Pipeline Saskatchewan and North Dakota Systems Expansions Sarnia Solar Project (60-MW Expansion) Talbot Wind Energy Project COMMERCIALLY SECURED GROWTH PROJECTS Amherstburg/Tilbury Solar Projects (2010 – 2011) Greenwich Wind Energy Project (2011) Christina Lake Lateral Project (2011) Cedar Point Wind Energy Project (2011) Edmonton Terminal Expansion (2011 – 2012) Woodland Pipeline (2012) Neal Hot Springs Geothermal Project (2012) Venice Gas Processing Facility (2013) Waupisoo Pipeline Expansion (2013) Bakken Expansion Program (2013) Wood Buffalo Pipeline (2013) Norealis Pipeline (2013) Athabasca Pipeline Capacity Expansion (2013 – 2014) Walker Ridge Gas Gathering System (2014) Big Foot Oil Pipeline (2014) Fort Hills Pipeline System (TBD) DISCIPLINE 17

 


VIRDEN, MB The Wallace District Fire Department serving the Town of Virden has benefited from Enbridge’s Safe Community program, through which we provide financial support to hundreds of first-response organizations across North America. They use the funds to acquire equipment, obtain training or deliver educational programs. Ensuring the safety of the communities in which we operate is one of our core values. Winnipeg Calgary Superior Casper 18 ENBRIDGE INC. 2010 ANNUAL REPORT

 


Strong values guide the way we make decisions and conduct our business. Enbridge’s core values form an integral part of our daily activities. They have helped sustain our success for many years and continue to guide us as we deliver the energy North Americans need—safely, reliably and efficiently. INTEGRITY We operate with integrity, honesty and transparency, and to the highest ethical standards. ACCOUNTABILITY We are accountable for our actions—as individuals and as an organization. INNOVATION AND FLEXIBILITY We embrace innovation and learning. We are flexible, open to change and create new solutions for new challenges. VALUE CREATION We strive to create value and to deliver a prosperous future through growth in the enterprise and excellence in customer service. SOCIAL RESPONSIBILITY We are committed to sustaining safety for our employees and the public, a clean and healthy environment and strong and vibrant communities through socially responsible operations. VALUES 19

 


MARSHALL, MI Within hours of a major leak being discovered on our Line 6B pipeline near Marshall in July 2010, Enbridge’s President & CEO Pat Daniel (right) and Stephen Wuori, President, Liquids Pipelines, relocated to Marshall for over two months to personally oversee our cleanup efforts and address the concerns of local residents. At the height of our response, we had up to 2,500 employees and contractors working on cleanup and remediation. Line 6B was safely returned to service in September 2010. Chicago Toledo Toronto Detroit 20 ENBRIDGE INC. 2010 ANNUAL REPORT

 


We hold ourselves to the highest standards of openness and care. We strive to be a good neighbour in all the communities where we operate. In July 2010, when we experienced the most serious environmental incident in our long history—the leak of approximately 20,000 barrels of crude oil on our Line 6B pipeline near Marshall, Michigan—we immediately accepted responsibility and made a clear commitment to local residents: to clean up the spill and address the impacts on the environment and to the people of Marshall, Battle Creek and area. We are determined at all times to meet our responsibilities, and live up to and exceed the expectations of our stakeholders. VALUES 21

 


22 ENBRIDGE INC. 2010 ANNUAL REPORT

 


ROCKY MOUNTAIN HOUSE, AB Through our Neutral Footprint initiative, we have committed to planting a tree for every tree we remove, conserving an acre of natural habitat for every acre we permanently impact, and generating a kilowatt of renewable energy for every kilowatt of power our operations consume. Since launching the initiative in 2009, we have planted 150,000 trees by teaming up with Tree Canada and other not-for-profit partners. Furthermore, through the $2.5 million investment we have made to the Nature Conservancy of Canada, we will preserve and protect more than 7,400 acres of ecologically sensitive wildlife habitat in Canada to offset our impacts on the land. CSR is integral to how we operate. Enbridge exists to deliver the energy North Americans need—crude oil, natural gas, environmentally responsible power—safely, reliably and efficiently. That is our primary corporate social responsibility (CSR). CSR is also about ensuring our financial strength, conducting our business in an environmentally sustainable manner and maintaining our social license to operate. CSR is integral to the way we operate and is at the heart of our success. To read the Enbridge 2010 Corporate Social Responsibility Report, please visit csr.enbridge.com/csr2010. Fort McMurray Fort St. John Seattle Calgary Edmonton In 2010, Enbridge invested nearly $12 million in over 350 charitable, non-profit and community organizations. Enbridge has a balanced approach to its giving philosophy—investing in education, health and safety, the environment and arts and culture. We believe it’s investments like these that help make communities better places to live. $12MILLION VALUES 23

 


Zama Fort St. John Wood River Toronto Toledo Superior Seattle Salt Lake City Regina Rowatt Portland Patoka Chicago Norman Wells Ottawa Minot Hardisty Fort McMurray Cheecham Edmonton Cushing Cromer Clearbrook Gretna Casper Buffalo Denver Houston Calgary Lethbridge Flanagan New Orleans Montreal 51THOUSAND Enbridge’s network consists of approximately 51,000 miles of pipeline and delivers energy from Canada’s oil sands, growing shale gas plays in Canada and the U.S. and the Gulf of Mexico deepwater oil and gas region. We serve 2 million natural gas customers and our fast growing portfolio of wind, solar and geothermal energy facilities are delivering new sources of renewable energy. 24 ENBRIDGE INC. 2010 ANNUAL REPORT

 


We deliver energy 24/7. Our far-reaching network is always working—connecting vital sources of energy supply with refiners and consumers across North America. When it comes to the energy you count on, count on us. ENBRIDGE INC. Headquarters: Calgary, Alberta, Canada ENBRIDGE ENERGY PARTNERS, L.P. Headquarters: Houston, Texas, USA ENBRIDGE GAS DISTRIBUTION Headquarters: Toronto, Ontario, Canada LIQUIDS SYSTEMS AND JOINT VENTURES NATURAL GAS SYSTEMS AND JOINT VENTURES GAS DISTRIBUTION SOLAR ASSETS WIND ASSETS GEOTHERMAL ASSETS FUEL CELL WASTE HEAT RECOVERY OPERATIONS 25

 


DELIVERING RESULTS Patrick D. Daniel, President and Chief Executive Officer David A. Arledge, Chair of the Board of Directors 26 ENBRIDGE INC. 2010 ANNUAL REPORT

 

 


 

LETTER TO SHAREHOLDERS

 


2010 was a year of significant

 

accomplishment and continued

 

growth, tempered by incidents

 

that will have a lasting impact

 

on our Company.

 

Enbridge had another very strong financial year in 2010, delivering outstanding organic growth across all of its business units and simultaneously securing new projects and assets that will extend the Company’s enviable rate of growth well into the future.

 

As great as these accomplishments were, 2010 was also humbling for Enbridge as we experienced two significant crude oil pipeline leaks in the United States. Applying the lessons learned from those leaks is the top priority for the Company.

STRONG GROWTH

 

Enbridge again achieved industry-leading earnings per share growth in 2010. Adjusted earnings per share rose 13% to $2.66 per common share, which builds on a 25% increase in 2009.

 

Our 2010 growth was driven by two factors: the strong financial performance of all our businesses and the commencement of operations of $6.5 billion in new projects.

 

Over the past three years we have brought over $12 billion in projects into service and we currently have another $6 billion of commercially secured projects coming into service by 2014, as well as $30 billion of new opportunities under development across all of our businesses. In 2010 alone, we secured $4 billion in new growth projects and assets, and in the first two months of 2011 we announced an additional $0.4 billion in investments.


 

 

 

 

 

LETTER TO SHAREHOLDERS

27

 



 


We are well positioned to meet our long-term growth objectives. We anticipate Enbridge’s adjusted earnings per share will grow at an average annual rate of 10% through the middle of this decade and, with the Company’s cash flow anticipated to grow at an even more rapid pace, we expect to continue delivering exceptional dividend growth to our investors. The Board has increased the 2011 dividend by 15%. Enbridge has increased its dividend an average of 11% per year over the past 10 years, and in more than 55 years as a publicly traded company we have never reduced the dividend. Few North American companies can match this record of accomplishment.

 

Our growth opportunities are aligned with our very reliable, low-risk business model that results in highly predictable earnings. We are involved in strategically important geographies, including the Canadian oil sands, the Bakken Formation, the Midwest Texas and Louisiana shale gas plays and offshore natural gas and oil. Our interests in wind, solar and alternative green energy power generation

are focused on the growing renewable energy demand in North America.

 

LIQUIDS PIPELINES

 

In 2010, we put into service—on budget and ahead of schedule—the $3.5 billion Alberta Clipper Project, which represents the largest mainline expansion in Enbridge’s history, and the unique $2.3 billion Southern Lights pipeline from Chicago to Edmonton that is the first to deliver diluent to western Canada.

 

In the Athabasca region we have secured six new projects that are valued at $2.6 billion and are expected to go into service between 2011 and 2014. These include the expansion of the Company’s Athabasca Pipelines, expansion of our Waupisoo Pipeline, three new pipelines—Woodland, Wood Buffalo, and Norealis—and expansion of Enbridge’s Edmonton terminal facilities. Enbridge’s Regional


 

 

FINANCIAL HIGHLIGHTS

 

Year ended December 31,

 

2010

 

 

2009

 

2008

 

(millions of Canadian dollars, except per share amounts)

 

 

 

 

 

 

 

 

Earnings per Common Share

 

2.60

 

 

4.27

 

3.67

 

Adjusted Earnings per Common Share

 

2.66

 

 

2.35

 

1.88

 

Dividends per Common Share

 

1.70

 

 

1.48

 

1.32

 

Total Common Share Dividends Declared

 

648

 

 

555

 

489

 

Return on Average Shareholders’ Equity

 

12.9%

 

 

22.2%

 

22.2%

 

Debt to Debt Plus Shareholders’ Equity

 

66.7%

 

 

66.1%

 

66.6%

 

 

 

 

28

ENBRIDGE INC. 2010 ANNUAL REPORT

 

 



 

OPERATING HIGHLIGHTS

 

 

 

2010

 

 

2009

 

2008

 

Liquids Pipelines—Average Deliveries (thousands of barrels per day)

 

 

 

 

 

 

 

 

Enbridge System 1

 

2,168

 

 

2,054

 

2,030

 

Enbridge Regional Oil Sands System 2

 

291

 

 

259

 

202

 

Spearhead Pipeline

 

144

 

 

121

 

110

 

Olympic Pipeline

 

276

 

 

280

 

291

 

Gas Pipelines, Processing and Energy Services—

 

 

 

 

 

 

 

 

Average Throughput Volume (millions of cubic feet per day)

 

 

 

 

 

 

 

 

Alliance Pipeline US

 

1,600

 

 

1,601

 

1,609

 

Vector Pipeline

 

1,456

 

 

1,334

 

1,321

 

Enbridge Offshore Pipelines

 

1,962

 

 

2,037

 

1,672

 

Gas Distribution—Enbridge Gas Distribution

 

 

 

 

 

 

 

 

Volumes (billions of cubic feet)

 

393

 

 

408

 

433

 

Number of active customers (thousands) 3

 

1,981

 

 

1,937

 

1,898

 

 

1        Enbridge System includes Canadian mainline deliveries in Western Canada and to the Lakehead System at the United States border, as well as Line 8 and Line 9 in Eastern Canada.

 

2        Volumes are for the Athabasca mainline and the Waupisoo Pipeline and exclude laterals on the Enbridge Regional Oil Sands System.

 

3        Number of active customers is the number of natural gas consuming Enbridge Gas Distribution customers at the end of the period.

 

 


Oil Sands System, which currently connects five producing oil sands projects, will connect eight producing projects by 2014. We continue to hear encouraging announcements of growth and investment in the oil sands, and Enbridge is very well positioned to provide a wide range of flexible and cost effective transportation solutions to existing and new shippers.

 

Also in 2010, Enbridge Income Fund and Enbridge Energy Partners, L.P. completed expansions of their Saskatchewan and North Dakota systems, respectively. Additionally, they announced a new $560 million Bakken Expansion Program that will increase capacity out of the region by another 145,000 barrels per day starting in early 2013.

In May 2010, we reached a major milestone when we filed our regulatory application with the National Energy Board for the $5.5 billion Enbridge Northern Gateway Pipeline Project, a proposed twin pipeline system running between Edmonton, Alberta to a new marine terminal in Kitimat, British Columbia to export crude oil and import condensate. We have strong commercial support for Northern Gateway, with a consortium of Canadian producers and Southeast Asian refiners acting as our funding partners as we move through the regulatory process. We are also offering Aboriginal communities along the pipeline route


 

 

 

LETTER TO SHAREHOLDERS

29

 



 


up to 10% of the equity in the project. The project will bring long-term economic and social benefits to not only northern British Columbia and Alberta, but also all of Canada.

 

GAS PIPELINES, PROCESSING AND ENERGY SERVICES

 

All three of our geographically distinct gas pipeline businesses—gathering and processing, offshore pipelines and long-haul transmission—hold strong competitive positions.

 

In 2010, Enbridge Energy Partners grew its natural gas infrastructure in the Lower 48, acquiring US$700 million in assets in the prolific Granite Wash area located in the Texas Panhandle region and southwest Oklahoma.

 

The sanctioning by Chevron in October of its Jack St. Malo project in the Gulf of Mexico has enabled us to advance our US$400 million Walker Ridge Gas Gathering System. We are also in the engineering phase for the US$250 million Big Foot Oil Pipeline. Both of these ultra deepwater projects are commercially secured and are structured to strengthen returns and to align closely with Enbridge’s reliable business model.

 

In early 2011, we announced a $150 million expansion of the condensate processing capacity of our Venice, Louisiana facility to accommodate additional offshore natural gas production.

 

We expect the expansion, which will double capacity to approximately 12,000 barrels of condensate per day, will be in service in late 2013.

 

The Alliance Pipeline is strategically positioned to continue to realize strong returns by virtue of its proximity to liquids-rich shale gas plays in northeast British Columbia and the Bakken Formation.

 

GAS DISTRIBUTION

 

Enbridge Gas Distribution (EGD), one of the fastest growing utilities in North America, is continuing to boost its return on investment under Incentive Regulation in Ontario. EGD is adding over 30,000 new customers a year.

 

In February 2011, Enbridge announced it will invest $145 million to acquire an additional 6.8% interest in Noverco, bringing its total interest to 38.9%. Noverco owns 71% of Gaz Metro Limited Partnership, which owns gas distribution and gas pipelines assets in Quebec and gas and electric power distribution and transmission assets in Vermont.

 

GREEN ENERGY

 

In 2010, we commissioned the 80-MW Sarnia Solar facility, one of the largest photovoltaic solar facilities in the world, announced the 99-MW Greenwich Wind Energy Project in Ontario and entered the U.S. green energy market by securing the 250-MW Cedar Point Wind Energy Project in Colorado.


 

 

 

30

ENBRIDGE INC. 2010 ANNUAL REPORT

 

 



 

 

 

Executive Management Team (left to right)

 

David T. Robottom Executive Vice President & Chief Legal Officer

 

Janet Holder President, Enbridge Gas Distribution

 

J. Richard Bird Executive Vice President, Chief Financial Officer & Corporate Development

 

Al Monaco President, Gas Pipelines, Green Energy & International

 

Stephen J. Wuori President, Liquids Pipelines

 

Patrick D. Daniel President & Chief Executive Officer

 

 

 

 

 

 


We concluded 2010 with the substantial completion of the Talbot Wind Energy project in Ontario, and in February 2011 announced the acquisition of the Amherstburg and Tilbury solar projects.

 

Enbridge has secured over $1.5 billion in green energy projects over the past 18 months and we expect that rate of growth to continue. Our investments generate predictable and reliable returns supported by long-term power-purchase agreements with creditworthy counterparties, combined with fixed price contracts for engineering, procurement and construction. They also support our Neutral Footprint initiative to help ensure that the construction of Enbridge’s new projects have no net environmental impact.

RESPONDING TO INCIDENTS

 

On July 26, 2010 a leak of an estimated 20,000 barrels of crude oil occurred on our Line 6B pipeline near Marshall, Michigan. That leak was the most serious environmental incident in our long history. And on September 9, 2010, an estimated 9,000 barrels of crude oil (of which approximately 1,400 barrels were removed from the pipeline as part of the repair) were released from our Line 6A in an industrial section of Romeoville, Illinois.

 

These incidents tested our ability to respond to the individuals and communities affected by the leaks, to the regulators and numerous agencies involved in the response effort, and to our customers whose deliveries were disrupted by the prolonged shutdown of the affected pipelines.


 

 

 

LETTER TO SHAREHOLDERS

31

 



 


No accident or spill will ever be acceptable to us and we are more determined than ever to meet our goal of zero incidents. We take pride in Enbridge’s employees and the commitment they have demonstrated to responding to these incidents and applying what we have learned to ensure that incidents like these never happen again. The safety and integrity of our operations remains our highest priority. Enbridge’s job is to deliver the energy that North Americans need—safely, reliably and efficiently. That is our primary social responsibility.

 

MANAGEMENT AND BOARD CHANGES

 

We wish to express our sincerest thanks to Steve Letwin, who retired from Enbridge as Executive Vice President, Gas Transportation & International, in October 2010. Steve was a significant contributor over his 11 years as a member of Enbridge’s leadership team. Enbridge announced a new structure for its executive management team to capitalize on their strengths and reflect the continued growth and evolution of the Company.

 

In November 2010, the Board of Directors announced the appointment of Maureen Kempston-Darkes, retired Group Vice President and President, Latin America, Africa and Middle East, General Motors Corporation, and the first woman to lead General Motors of Canada. As a successful and accomplished Canadian businesswoman with experience in the automotive, transportation and energy industries, she brings a valued perspective to Enbridge’s Board.

IN CONCLUSION

 

Our positive financial results in 2010 reflect the collective efforts of our 6,400 employees across the organization to achieve our vision of being the leading energy delivery company in North America. We thank all of them for their outstanding work and continuing commitment to our corporate values.

 

Enbridge has an exceptionally strong asset base, a proven ability to develop new businesses, and a track record of on-time, on-budget execution. The Company offers investors visible and sustained earnings growth, a substantial and growing dividend and a very reliable business model.

 

The unique combination of these attributes will continue to deliver superior results for our shareholders—solid returns that you can count on.

 

David A. Arledge

Chair of the Board of Directors

 

Patrick D. Daniel

President and Chief Executive Officer

 

March 2, 2011

 


 

 

 

32

ENBRIDGE INC. 2010 ANNUAL REPORT

 

 



 

CORPORATE GOVERNANCE

 

 

 

 

 

 

Board of Directors (left to right)

Catherine L. Williams Corporate Director, Calgary, Alberta

 

 

David A. Leslie Corporate Director, Toronto, Ontario

George K. Petty Corporate Director, San Luis Obispo, California

 

 

Charles W. Fisher Corporate Director, Calgary, Alberta

David A. Arledge Chair of the Board, Enbridge Inc., Naples, Florida

 

 

Patrick D. Daniel President & Chief Executive Officer, Enbridge Inc., Calgary,

J. Lorne Braithwaite Corporate Director, Thornhill, Ontario

Alberta

 

 

V. Maureen Kempston-Darkes Corporate Director, Weston, Florida

Charles E. Shultz Chair & Chief Executive Officer, Dauntless Energy Inc., Calgary,

 

Alberta

Dan C. Tutcher Corporate Director, Houston, Texas

 

 

J. Herb England Chairman & Chief Executive Officer, Stahlman-England Irrigation Inc., Naples, Florida

James J. Blanchard Senior Partner, DLA Piper U.S., LLP, Beverly Hills, Michigan

 

 

 


At Enbridge, corporate governance means that a comprehensive system of stewardship and accountability is in place and functioning among Directors, management and employees of the Company.

 

Enbridge is committed to the principles of good governance, and the Company employs a variety of policies, programs and practices to manage corporate governance and ensure compliance.

 

The Board of Directors is responsible for the overall stewardship of Enbridge and, in discharging that responsibility, reviews, approves

and provides guidance with respect to the strategic plan of the Company and monitors implementation.

 

The Board approves all significant decisions that affect the Company and reviews its results. The Board also oversees identification of the Company’s principal risks on an annual basis, monitors risk management programs, reviews succession planning and seeks assurance that internal control systems and management information systems are in place and operating effectively.

 


 

 

 

CORPORATE GOVERNANCE

33

 



 

FINANCIAL RESULTS

 

 

 

 

 

 

 

 

Management’s Discussion and Analysis

 

 

 

 

 

35   Overview

 

  66   Gas Pipelines, Processing and Energy Services

36   Performance Overview

 

  75   Sponsored Investments

41   Corporate Vision and Key Objective

 

  83   Corporate

41   Corporate Strategy

 

  85   Liquidity and Capital Resources

45   Industry Fundamentals

 

  88   Contingencies and Commitments

47   Growth Projects

 

  90   Quarterly Financial Information

48  Liquids Pipelines

 

  91   Related Party Transactions

48  Gas Pipelines, Processing and Energy Services

 

  92   Risk Management and Financial Instruments

48  Sponsored Investments

 

102   Critical Accounting Estimates

55  Corporate

 

104   Change in Accounting Policies

56   Liquids Pipelines

 

105   Controls and Procedures

62   Gas Distribution

 

106   Non-GAAP Reconciliations

 

 

 

 

 

 

 

 

 

Consolidated Financial Statements

 

 

 

 

 

107  Management’s Report

 

112   Consolidated Statements of Shareholders’ Equity

108  Independent Auditor’s Report

 

113   Consolidated Statements of Cash Flows

110  Consolidated Statements of Earnings

 

114   Consolidated Statements of Financial Position

111  Consolidated Statements of Comprehensive Income

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Notes to the Consolidated Financial Statements

 

 

 

 

115  1.  General Business Description

 

136   18.  Other Long-Term Liabilities

116  2.  Summary of Significant Accounting Policies

 

136   19.  Non-Controlling Interests

121  3.  Changes in Accounting Policies

 

136   20.  Share Capital

121  4.  Segmented Information

 

137   21.  Stock Option and Stock Unit Plans

124  5.  Financial Statement Effects of Rate Regulation

 

141   22.  Components of Accumulated Other

126  6.  Gain on Sale of Investments

 

Comprehensive Income/(Loss)

127  7.  Accounts Receivable and Other

 

141   23.  Risk Management

127  8.  Inventory

 

147   24.  Fair Value of Financial Instruments

128  9.  Property, Plant and Equipment

 

151   25.  Capital Disclosures

129   10. Joint Ventures

 

152   26.  Income Taxes

131   11. Long-Term Investments

 

153   27.  Post Employment Benefits

132   12. Deferred Amounts and Other Assets

 

158   28.  Other Income

132   13. Intangible Assets

 

158   29.  Changes in Operating Assets and Liabilities

133   14. Goodwill

 

158   30.  Related Party Transactions

133   15. Accounts Payable and Other

 

160   31.  Commitments and Contingencies

134   16. Debt

 

162   32.  Guarantees

135   17. Non–Recourse Debt

 

163   33.  United States Accounting Principles

 

 

 

 

 

 

167   Glossary

 

171   2010 Awards and Recognition

168   Five-Year Consolidated Highlights

 

172   Investor Information

170   Enbridge Businesses

 

 

 

 

 

 

 

 

34

 

ENBRIDGE INC. 2010 ANNUAL REPORT

 

 



 

MANAGEMENT’S DISCUSSION AND ANALYSIS

 

 

 

This Management’s Discussion and Analysis (MD&A) dated February 18, 2011 should be read in conjunction with the audited consolidated financial statements and notes thereto of Enbridge Inc. (Enbridge or the Company) for the year ended December 31, 2010, which are prepared in accordance with Canadian generally accepted accounting principles (GAAP). All financial measures presented in this MD&A are expressed in Canadian dollars, unless otherwise indicated. Additional information related to the Company, including its Annual Information Form, is available on SEDAR at www.sedar.com.

 

 

Overview

 

Enbridge is a North American leader in delivering energy. As a transporter of energy, Enbridge operates, in Canada and the United States, the world’s longest crude oil and liquids transportation system. The Company also has a significant involvement in the natural gas transmission and midstream businesses. As a distributor of energy, Enbridge owns and operates Canada’s largest natural gas distribution company and provides distribution services in Ontario, Quebec, New Brunswick and New York State. As a clean energy generator, Enbridge is expanding its interests in renewable and green energy technologies, including wind, solar, and geothermal energy, and hybrid fuel cells. Enbridge employs approximately 6,400 people, primarily in Canada and the United States.

 

The Company’s activities are carried out through five business segments: Liquids Pipelines, Gas Distribution, Gas Pipelines, Processing and Energy Services, Sponsored Investments and Corporate, as discussed below.

 

LIQUIDS PIPELINES

 

Liquids Pipelines consists of common carrier and contract crude oil, natural gas liquids (NGLs) and refined products pipelines and terminals in Canada and the United States, including the Enbridge System, the Enbridge Regional Oil Sands System, Southern Lights Pipeline and other feeder pipelines.

GAS DISTRIBUTION

 

Gas Distribution consists of the Company’s natural gas utility operations, the core of which is Enbridge Gas Distribution Inc. (EGD) which serves residential, commercial and industrial customers, primarily in central and eastern Ontario as well as northern New York State. This business segment also includes natural gas distribution activities in Quebec and New Brunswick.

 

GAS PIPELINES, PROCESSING AND ENERGY SERVICES

 

Gas Pipelines, Processing and Energy Services consists of investments in natural gas pipelines, processing and green energy projects, the Company’s commodity marketing businesses, and international activities.

 

Investments in natural gas pipelines include the Company’s interests in the United States portion of Alliance Pipeline (Alliance Pipeline US), Vector Pipeline and transmission and gathering pipelines in the Gulf of Mexico. Investments in processing includes the Company’s interest in Aux Sable, a natural gas fractionation and extraction business. The commodity marketing businesses manage the Company’s volume commitments on Alliance and Vector Pipelines, as well as perform commodity storage, transport and supply management services, as principal and agent.

 

 

 

MANAGEMENT’S DISCUSSION AND ANALYSIS

35

 

 



 

SPONSORED INVESTMENTS

 

Sponsored Investments includes the Company’s 25.5% ownership interest in Enbridge Energy Partners, L.P. (EEP), Enbridge’s 66.7% investment in the United States segment of the Alberta Clipper Project through EEP and Enbridge Energy, L.P. (EELP) and an overall 72% economic interest in Enbridge Income Fund (EIF), held both directly and indirectly through Enbridge Income Fund Holdings Inc. (EIFH). Enbridge manages the day-to-day operations of, and develops and assesses opportunities for each of these investments, including both organic growth and acquisition opportunities.

 

EEP transports crude oil and other liquid hydrocarbons through common carrier and feeder pipelines and transports, gathers, processes and markets natural gas and NGLs. The primary operations of EIF include a crude oil and liquids pipeline and gathering system, a 50% interest in the Canadian portion of Alliance Pipeline (Alliance Pipeline Canada) and partial interests in several green energy investments.

 

CORPORATE

 

Corporate consists of the Company’s investment in Noverco Inc. (Noverco), new business development activities, general corporate investments and financing costs not allocated to the business segments.

 

Performance Overview

 

 

 

Three Months Ended

 

 

 

 

 

 

December 31,

 

 

Year Ended December 31,

 

 

 

2010

 

 

2009

 

 

2010

 

 

2009

 

 

2008

 

(millions of Canadian dollars, except per share amounts)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Earnings Applicable to Common Shareholders

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Liquids Pipelines

 

117

 

 

141

 

 

512

 

 

445

 

 

328

 

Gas Distribution

 

60

 

 

74

 

 

155

 

 

186

 

 

161

 

Gas Pipelines, Processing and Energy Services

 

32

 

 

15

 

 

121

 

 

428

 

 

767

 

Sponsored Investments

 

56

 

 

38

 

 

137

 

 

141

 

 

111

 

Corporate

 

61

 

 

32

 

 

38

 

 

355

 

 

(46

)

 

 

326

 

 

300

 

 

963

 

 

1,555

 

 

1,321

 

Earnings per Common Share

 

0.87

 

 

0.81

 

 

2.60

 

 

4.27

 

 

3.67

 

Diluted Earnings per Common Share

 

0.86

 

 

0.80

 

 

2.57

 

 

4.25

 

 

3.64

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Adjusted Earnings 1

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Liquids Pipelines

 

117

 

 

141

 

 

512

 

 

454

 

 

332

 

Gas Distribution

 

54

 

 

60

 

 

167

 

 

154

 

 

141

 

Gas Pipelines, Processing and Energy Services

 

31

 

 

22

 

 

123

 

 

116

 

 

141

 

Sponsored Investments

 

48

 

 

39

 

 

209

 

 

151

 

 

101

 

Corporate

 

(12

)

 

(23

)

 

(27

)

 

(20

)

 

(38

)

 

 

238

 

 

239

 

 

984

 

 

855

 

 

677

 

Adjusted Earnings per Common Share 1

 

0.64

 

 

0.64

 

 

2.66

 

 

2.35

 

 

1.88

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash Flow Data

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash provided by operating activities

 

375

 

 

182

 

 

1,851

 

 

2,017

 

 

1,372

 

Cash used in investing activities

 

(746

)

 

(1,162

)

 

(2,674

)

 

(3,306

)

 

(2,853

)

Cash provided by financing activities

 

152

 

 

912

 

 

749

 

 

1,109

 

 

1,840

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Dividends

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Common Share Dividends Declared

 

163

 

 

139

 

 

648

 

 

555

 

 

489

 

Dividends Paid per Common Share

 

0.425

 

 

0.370

 

 

1.70

 

 

1.48

 

 

1.32

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity sales

 

3,280

 

 

2,491

 

 

11,990

 

 

9,720

 

 

13,432

 

Transportation and other services

 

863

 

 

696

 

 

3,137

 

 

2,746

 

 

2,699

 

 

 

4,143

 

 

3,187

 

 

15,127

 

 

12,466

 

 

16,131

 

Total Assets

 

30,120

 

 

28,169

 

 

30,120

 

 

28,169

 

 

24,701

 

Total Long-Term Liabilities

 

18,542

 

 

16,392

 

 

18,542

 

 

16,392

 

 

13,179

 

 

1

Adjusted earnings and adjusted earnings per common share are non-GAAP measures that do not have any standardized meaning prescribed by generally accepted accounting principles. For more information on non-GAAP measures see pages 41 and 106.

 

 

 

36

 

ENBRIDGE INC. 2010 ANNUAL REPORT

 

 



 

EARNINGS APPLICABLE TO COMMON SHAREHOLDERS

 

Earnings applicable to common shareholders for the three months ended December 31, 2010 were $326 million, an increase of $26 million compared with $300 million for the fourth quarter of 2009. The increase was primarily attributable to higher Sponsored Investments earnings, including Alberta Clipper contributions and a dilution gain on reduced ownership in EEP, as well as increased unrealized foreign exchange and derivative gains in Corporate. Offsetting these increases were lower contributions from Liquids Pipelines due in part to the elimination of annual performance metrics under the 2010 interim toll agreement, lower contributions from Gas Distribution due to higher operating costs and additional remediation costs on the Line 6B and 6A crude oil releases as discussed below.

 

Earnings applicable to common shareholders were $963 million, or $2.60 per common share, for the year ended December 31, 2010, compared with $1,555 million, or $4.27 per common share, for the year ended December 31, 2009. The Company’s earnings for 2010 included the positive impacts of projects coming into service in 2010, including the Alberta Clipper, Southern Lights Pipeline and the Sarnia Solar energy projects. Compared with 2009, earnings have increased further due to customer growth in Gas Distribution and improved contributions from green energy, partially offset by less favourable weather conditions in the Company’s gas distribution franchise areas. These operational improvements were overwhelmed by the absence of one-time favourable items experienced in 2009, including a $329 million gain on the disposal of Oleoducto Central S.A. (OCENSA) and unrealized derivative and intercompany foreign exchange gains.

 

 

Additionally, 2010 results were impacted by the Line 6B and 6A crude oil releases. Earnings for the fourth quarter of 2010 and for the year ended December 31, 2010 reflected the Company’s share of EEP’s costs, before insurance recoveries and excluding fines and penalties, of $21 million and $103 million, respectively, related to these incidents. Lost revenue associated with downtime on both Line 6B and 6A of $3 million (net to Enbridge) further contributed to the year-over-year decrease in earnings. See Sponsored Investments – Enbridge Energy Partners – EEP Lakehead System Line 6B and 6A Crude Oil Releases.

 

Comparability of earnings applicable to common shareholders for the year ended December 31, 2010 with the prior year is impacted by the effect of unrealized derivative and intercompany foreign exchange gains and losses which totaled a gain of $59 million in 2010 compared with a gain of $305 million in 2009. Further, earnings for the year ended December 31, 2009 reflected gains on the disposition of investments, including OCENSA, of $354 million whereas no dispositions occurred in 2010.

 

Compared with 2008, earnings applicable to common shareholders for the year ended December 31, 2009 increased $234 million. Included in earnings for the year ended December 31, 2009 was a $329 million gain related to the sale of the Company’s investment in OCENSA and a $25 million gain related to the sale of NetThruPut (NTP). Earnings for the year ended December 31, 2008 included a gain of $556 million related to the sale of the Company’s investment in Compañía Logística de Hidrocarburos CLH, S.A. (CLH). The remaining variances primarily resulted from allowance for equity funds used during construction (AEDC) in Liquids Pipelines and Sponsored Investments, as well as a higher contribution from EEP, and movements in unrealized fair value gains and losses on derivative instruments and unrealized foreign exchange gains on the translation of foreign denominated intercompany loans.

 

 

 

MANAGEMENT’S DISCUSSION AND ANALYSIS

37

 

 



 

 

 

ADJUSTED EARNINGS

 

Adjusted earnings were $238 million, or $0.64 per common share, for the three months ended December 31, 2010, compared with $239 million, or $0.64 per common share, for the three months ended December 31, 2009. Positive contributors in the quarter included Gas Pipelines, Processing and Energy Services whose Aux Sable and Energy Services businesses benefited from favourable margins in the period and who also incurred lower business development costs compared with the fourth quarter of 2009. Adjusted earnings from Sponsored Investments increased due to contributions from Alberta Clipper, both through EEP and EELP, and the acquisition of gas gathering assets in the fourth quarter of 2010. Partially offsetting these items are lower adjusted earnings from Liquids Pipelines due primarily to the 2010 interim toll agreement no longer including annual performance metrics, higher business development costs and higher taxes. Gas Distribution also incurred higher operating costs, depreciation and taxes in the fourth quarter of 2010 compared with the same period of 2009.

 

Adjusted earnings were $984 million, or $2.66 per common share, for the year ended December 31, 2010, compared with $855 million, or $2.35 per common share, for the year ended December 31, 2009. The increase in adjusted earnings primarily reflected contributions from projects coming into service, including the Alberta Clipper Project, the Southern Lights Pipeline and the Sarnia Solar Project, as well as strong performance from the Company’s existing liquids and natural gas assets. The Company also realized improved adjusted earnings from Gas Distribution due to customer growth and favourable operating performance. Sponsored Investments further contributed to year-over-year increases in adjusted earnings, benefiting from EEP contributions and its expansions and acquisition completed in 2010.

 

Adjusted earnings for the year ended December 31, 2009 were $855 million, or $2.35 per common share, compared with $677 million, or $1.88 per common share, for the year ended December 31, 2008. The $178 million increase over 2008 was largely driven by higher adjusted earnings from Enbridge System and Southern Lights Pipeline, within Liquids Pipelines, including the impact of AEDC. Adjusted earnings in 2009 also include an increased contribution from EEP resulting from higher crude oil delivery volumes, tariff surcharges for recent expansions, and the Company’s increased ownership interest. Further positive contributions were realized by Enbridge Offshore Pipelines (Offshore) due to higher volumes and Energy Services due to higher volumes and the impact of realizing favourable storage and transportation margins.

 

CASH FLOWS

 

The Company’s strong operating results and the success of its growth projects resulted in cash provided by operating activities of $1,851 million for the year ended December 31, 2010. Operating cash flow, together with cash provided by financing activities, funded the Company’s ongoing growth initiatives in 2010, including capital expenditures of $2,357 million.

 

 

38

 

ENBRIDGE INC. 2010 ANNUAL REPORT

 

 



 

For the three months ended December 31, 2010, cash provided by operating and financing activities substantially funded investing activities of $746 million, which consisted primarily of capital expenditures. The decline in additions to property, plant and equipment in the fourth quarter of 2010 compared with the fourth quarter of 2009 reflected the completion of several substantial construction projects that were under development in 2009, including Alberta Clipper and Southern Lights Pipeline.

 

DIVIDENDS

 

The Company has paid, and consistently increased, common share dividends since its public inception in 1953. Based on estimated 2011 dividends, the annual rate of increase has averaged 10.8% since 2001 and 10.1% since inception. In December 2010, the Company announced a 15% increase in its quarterly dividend to $0.49 per common share, or $1.96 annualized, effective March 1, 2011. The Company continues to target a payout of approximately 60% to 70% of adjusted earnings as dividends and, with the most recent dividend increase, the 2011 payout is expected to be near the upper end of the range. In 2010, dividends paid per share were 64% of adjusted earnings per share (2009 – 63%, 2008 – 70%).

 

The following chart shows dividends per common share for the last 10 years, as well as estimated dividends for 2011, based on the quarterly dividend of $0.49 per common share declared by the Board of Directors on December 1, 2010.

 

 

REVENUES

 

The Company generates revenue from two primary sources: commodity sales, and transportation and other services.

 

Commodity sales revenue of $11,990 million (2009 – $9,720 million) is earned through the Company’s natural gas distribution and energy marketing activities and is subject to fluctuations in commodity prices. While revenues generated by the natural gas distribution business vary with the price of natural gas, earnings are not affected due to the pass through nature of these costs. Similarly, the impact of commodity prices on revenues derived from the Company’s energy marketing activities do not directly impact earnings since commodity prices also affect input costs associated with such activities. The period-over-period variances in commodity sales are primarily driven by natural gas and crude oil commodity prices and similar trends were experienced in commodity costs over these periods.

 

Transportation and other services includes revenue derived from the Company’s liquids transportation and natural gas transmission services, renewable energy generation and related services. Contributing to the increase in transportation and other services revenue in 2010 are Alberta Clipper and Southern Lights Pipeline, which entered service in April 2010 and July 2010, respectively.

 

For the year ended December 31, 2010, transportation and other services revenue increased to $3,137 million compared with $2,746 million in 2009. Main contributors to this variance include increased contributions from Liquids Pipelines growth projects that entered service in 2010, including Alberta Clipper and Southern Lights Pipeline and full year contributions from the initial phase of the Sarnia Solar Project which entered service in December 2009 as well as the expansion which was completed in September 2010.

 

 

 

MANAGEMENT’S DISCUSSION AND ANALYSIS

39

 

 



 

FORWARD-LOOKING INFORMATION

 

Forward-looking information, or forward-looking statements, have been included in this MD&A to provide the Company’s shareholders and potential investors with information about the Company and its subsidiaries and affiliates, including management’s assessment of Enbridge’s and its subsidiaries’ future plans and operations. This information may not be appropriate for other purposes. Forward-looking statements are typically identified by words such as “anticipate”, “expect”, “project”, “estimate”, “forecast”, “plan”, “intend”, “target”, “believ” and similar words suggesting future outcomes or statements regarding an outlook. Forward-looking information or statements included or incorporated by reference in this document include, but are not limited to, statements with respect to: expected earnings or adjusted earnings; expected earnings or adjusted earnings per share; expected costs related to projects under construction; expected in-service dates for projects under construction; expected capital expenditures; estimated future dividends; and expected costs related to leak remediation and potential insurance recoveries.

 

Although Enbridge believes that these forward-looking statements are reasonable based on the information available on the date such statements are made and processes used to prepare the information, such statements are not guarantees of future performance and readers are cautioned against placing undue reliance on forward-looking statements. By their nature, these statements involve a variety of assumptions, known and unknown risks and uncertainties and other factors, which may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Material assumptions include assumptions about: the expected supply and demand for crude oil, natural gas and natural gas liquids; prices of crude oil, natural gas and natural gas liquids; expected exchange rates; inflation; interest rates; the availability and price of labour and pipeline construction materials; operational reliability; customer project approvals; maintenance of support and regulatory approvals for the Company’s projects; anticipated in-service dates; and weather. Assumptions regarding the expected supply and demand of crude oil, natural gas and natural gas liquids, and the prices of these commodities, are material to and underlay all forward-looking statements. These factors are relevant to all forward-looking statements as they may impact current and future levels of demand for the Company’s services. Similarly, exchange rates, inflation and interest rates impact the economies and business environments in which the Company operates, may impact levels of demand for the Company’s services and cost of inputs, and are therefore inherent in all forward-looking statements. Due to the interdependencies and correlation of these macroeconomic factors, the impact of any one assumption on a forward-looking statement cannot be determined with certainty, particularly with respect to expected earnings or adjusted earnings and associated per share amounts, or estimated future dividends. The most relevant assumptions associated with forward-looking statements on projects under construction, including estimated in-service dates, and expected capital expenditures include: the availability and price of labour and pipeline construction materials; the effects of inflation and foreign exchange rates on labour and material costs; the effects of interest rates on borrowing costs; and the impact of weather and customer and regulatory approvals on construction schedules.

 

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

 

 

 

40

ENBRIDGE INC. 2010 ANNUAL REPORT

 

 



 

NON-GAAP MEASURES

 

This MD&A contains references to adjusted earnings/(loss), which represent earnings or loss applicable to common shareholders adjusted for non-recurring or non-operating factors on both a consolidated and segmented basis. These factors are reconciled and discussed in the financial results sections for the affected business segments. Management believes that the presentation of adjusted earnings/(loss) provides useful information to investors and shareholders as it provides increased transparency and predictive value. Management uses adjusted earnings/(loss) to set targets, assess performance of the Company and set the Company’s dividend payout target. Adjusted earnings/(loss) and adjusted earnings/(loss) for each of the segments are not measures that have a standardized meaning prescribed by Canadian GAAP and are not considered GAAP measures; therefore, these measures may not be comparable with similar measures presented by other issuers. See Non-GAAP Reconciliations for a reconciliation of the GAAP and non-GAAP measures.

 

Corporate Vision and Key Objective

 

Enbridge’s vision is to be the leading energy delivery company in North America. While the Company may be viewed as having achieved elements of this vision, enhancing and sustaining this position remains a continuing long-term pursuit. The Company’s objective is to generate superior economic value for shareholders through investing capital in energy infrastructure businesses which generate reliable earnings and cash flow. Consistently applied, such stewardship should continue to generate attractive returns on invested capital and, in turn, provide for consistent and growing dividend distributions and related capital appreciation to its shareholders.

 

Corporate Strategy

 

In support of its long-term vision and objective, the Company employs several key strategies that guide decision making across the enterprise. The Company’s strategies include:

 

·     focusing on project execution and operating excellence;

·     leveraging the strategic location of its existing asset base;

·     developing new platforms for growth and diversification;

·     maintaining financial strength and flexibility; and

·     developing people, safety and environmental stewardship, and corporate social responsibility.

 

Enbridge’s strategy is reviewed annually with direction from its Board of Directors. The Company continually assesses ways to generate value for shareholders, including reviewing opportunities that may lead to acquisitions, dispositions or other strategic transactions, some of which may be material. Opportunities are screened, analyzed and must meet operating, strategic and financial criteria before being pursued.

 

FOCUSING ON PROJECT EXECUTION AND OPERATIONS

 

Effective management of operations and project execution is the foundation of Enbridge’s strategic plan. Operational excellence is particularly critical in an environment where customers have become increasingly cost conscious, competition in the Company’s core business has intensified and environmental stewardship has heightened.

 

Successful execution of the existing slate of commercially secured projects is a significant driver of Enbridge’s near-term earnings and cash flow growth, and, therefore, a strategic priority. Project execution is a core competency at Enbridge and the Company continues to build upon its project management skills and processes, primarily through the Major Projects support team which was established in early 2008. Major Projects manages projects above $50 million for all liquids, natural gas and renewable projects and continues to deliver projects on time and on budget. Major Projects focuses on success factors such as cost estimation, regulatory permitting, material and labour sourcing and project governance. All Major Projects are governed through a formal, disciplined stage gating process which requires the completion of

 

 

 

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pre-defined project deliverables, such as project execution and risk management plans, prior to management approving projects to proceed through predefined stage gates within the project lifecycle. This competency is highly valued and represents another Enbridge strength when competing for new business.

 

With respect to safety and system integrity, Enbridge employs the best available practices and technologies for integrity management, systems maintenance and operations in order to mitigate risks to the public, our employees and the environment.

 

STRENGTHENING OUR CORE BUSINESS

 

The Company has an established history of serving the North American transportation needs of key crude oil and natural gas markets. The Company is focused on adding value for customers and improving customers’ profitability. This focus has aligned the Company with its customers and relevant supply and demand fundamentals and has consistently formed a basis for the Company’s strategy. However, evolving supply and demand fundamentals and growing competition are serving to create new opportunities and challenges within the Company’s core businesses. Amid this changing business environment, the Company is strengthening its core business position and aggressively pursuing new opportunities to expand and extend its current asset base.

 

Extending the reach of the current asset base is a multi-faceted objective. Key strategies within the Liquids Pipelines segment include regional pipeline development, gathering system and storage infrastructure expansion and new market access. Regional pipeline development primarily includes projects which connect new oil sands lease production to existing hubs upstream of the Canadian mainline. Enbridge’s planned investment of $2.6 billion in commercially secured regional oil sands transportation facilities that are expected to go into service between 2011 and 2014 continue to advance this objective. The Company is also expanding its gathering systems in Saskatchewan and North Dakota which are strategically located to capture increased production from the Bakken play. As transportation needs grow so too do terminal and storage infrastructure requirements throughout the network, and the Company’s strategy is to seek opportunities to provide additional capacity in the Fort McMurray and Hardisty, Alberta regions as well as in the Cushing, Oklahoma area. The Company continues to pursue opportunities to provide its customers broader market access for Canadian bitumen and synthetic crudes and provide new sources of supply for refiners. These efforts include leveraging existing pipeline networks into additional United States markets as well as developing the proposed Northern Gateway pipeline to provide access to markets off the Pacific Coast of Canada.

 

The fundamentals of the natural gas market in North America have been altered significantly in recent years with the emergence of unconventional shale gas plays. The Company’s natural gas strategy includes expanding its footprint in these emerging areas. Alliance Pipeline is well positioned to service the Montney play in northeast British Columbia and the Bakken play, and is currently evaluating opportunities to expand its service offerings in that area. In addition to these onshore strategies, the Company continues to pursue and win natural gas gathering expansion opportunities for ultra-deep projects in the Gulf of Mexico which improve the risk and return profile of its investment in this area.

 

 

 

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DEVELOPING NEW PLATFORMS FOR GROWTH AND DIVERSIFICATION

 

The development of new platforms to diversify and sustain long-term growth is an important strategy for Enbridge. Renewable energy is a significant source of potential new growth as government initiatives and changing social beliefs are creating new opportunities to deliver green energy solutions with risk and return characteristics consistent with Enbridge’s business model. Renewable energy projects can deliver stable cash flows and attractive returns through the use of long-term power purchase agreements and fixed price engineering, procurement and construction contracts. Renewable energy is also an important part of Enbridge’s corporate social responsibility strategies, particularly with respect to greenhouse gas emissions (GHG) and the environment. Business development efforts in renewable energy are focused primarily on clean power projects, including wind, solar, waste heat recovery, fuel cell, geothermal and natural gas fired generation initiatives.

 

Similar to renewable energy, carbon dioxide (CO2) capture and sequestration not only supports Enbridge’s social investment strategy but also represents a potentially significant investment opportunity, should the technology prove viable.

 

The Company’s Alternative and Emerging Technologies group is exploring other longer-term energy technologies to sustain the Company’s favourable position. In addition, the International group is actively seeking new opportunities outside of North America.

 

PRESERVING FINANCIAL STRENGTH AND FLEXIBILITY

 

Disciplined capital management is a fundamental and company differentiating characteristic. As an asset-intensive business, Enbridge creates value for its investors through maximizing the spread between its return on invested capital and its cost of funds. Enbridge’s financial strategies are designed to ensure the Company has sufficient liquidity to meet its capital requirements. To support this objective, the Company develops financing plans and strategies to maintain and improve Enbridge’s credit ratings, diversify its funding sources and maintain ready access to capital markets in both Canada and the United States.

 

A key tenet of the Company’s reliable business model is mitigation of exposure to market price risks. As a result, the Company has developed a robust risk management process which ensures earnings volatility from market price risk remains contained. Enbridge will continue to proactively hedge interest rate, foreign exchange and commodity price exposures. As well, the continued management of counterparty credit risk remains an ongoing priority.

 

 

 

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DEVELOPING PEOPLE

 

Strong employees and leaders are the foundation of any successful company and developing its people remains a strategic priority for Enbridge. Key priorities related to building and improving Enbridge’s organizational and workforce capabilities and Human Resource services include:

 

·     strengthening the leadership culture;

·     enabling and accelerating career development for leaders and employees;

·     developing capability and capacity for effective change management;

·     reinforcing a values-based organization; and

·     ensuring human resource systems can provide strategic information for decision making.

 

RESPONDING TO ENVIRONMENTAL PRIORITIES

 

Enbridge has strong corporate social responsibility practices. Enbridge defines corporate social responsibility as conducting business in an ethical and responsible way, protecting the environment and the health and safety of people, supporting human rights and engaging, respecting and supporting the communities and cultures with which the Company works. Enbridge’s 2010 Corporate Social Responsibility Report can be found at http://www.enbridge.com/AboutEnbridge/CorporateSocialResponsibility/CSRReports.aspx. None of the information contained on, or connected to, the Enbridge website is incorporated or otherwise part of this MD&A.

 

In 2009, the Company launched an enterprise-wide goal of achieving a neutral environmental footprint by 2015. The goal consists of three key commitments:

 

·     we will plant a tree for every tree we remove to build new facilities;

·     we will conserve an acre of natural or wilderness land for every acre we permanently impact from the construction of new facilities; and

·     we will generate a kilowatt hour of renewable energy, through our investments in renewable energy, for each kilowatt hour of power consumed by our operations.

 

Land impacts will be addressed as soon as practically possible, but within five years of the in-service date of the project responsible for triggering the neutral footprint obligation. To achieve its neutral footprint goal, Enbridge is working with the Nature Conservancy of Canada and will work with nature conservancies in the United States to help purchase natural wilderness lands throughout North America. Progress on the Company’s neutral footprint initiative include:

 

·     155,000 trees removed; 150,000 tree seedlings planted

·     624 acres disturbed; 1,118 acres conserved through the Nature Conservancy of Canada

·     electricity consumption is forecast to increase, over the 2008 consumption level, by 1,077 gigawatts per hour (GWh) by 2015; Enbridge’s existing renewable power generating facilities and those under construction will produce approximately 2,170 GWh

 

 

 

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Industry Fundamentals

 

SUPPLY AND DEMAND FOR LIQUIDS

 

Canadian crude exports continue to grow into the United States, further solidifying Canada as its number one supplier. Combined conventional and oil sands established reserves of approximately 175 billion barrels suggest that Canada will continue to grow this relationship, albeit against growing concern over the environmental footprint of oil sands crude. The National Energy Board (NEB) estimates that total Western Canadian Sedimentary Basin (WCSB) production averaged approximately 2.6 million barrels per day (bpd) in 2010 (2009 – 2.4 million bpd; 2008 – 2.4 million bpd).

 

Sustained oil prices above the $70 mark have led to resurgence in oil sands project announcements that had slowed during the economic downturn. These announcements provide optimism for oil sands production growth in the medium term. The question remains whether industry can avoid the capital cost inflation which overwhelmed projects during the most recent boom as companies competed for resources. The Canadian Association of Petroleum Producers’ (CAPP) June 2010 growth case estimates indicate that future WCSB production is expected to steadily increase by 4% annually to more than 3.7 million bpd by 2020. This forecasted growth of 1.1 million bpd is largely attributed to increased oil sands production in Alberta.

World crude oil demand was approximately 2 million bpd higher in 2010 relative to 2009, with China as the major contributor of demand growth. North American demand growth remains relatively flat and is projected to remain that way into the near future. The continued growth of biofuels further suppresses United States crude requirements. Canadian crude imports into the United States Midwest are growing while United States overall crude imports from other countries has declined relative to past years. Midwest refinery runs and margins are showing stability versus other markets. Planned reconfiguration of refineries in the Midwest will increase the demand for Canadian crude into one of Enbridge’s key markets.

 

With the expected increase in heavy oil production in western Canada, there is an increasing requirement for condensate (or similar light commodity) to be used as a blending agent in order to transport these high viscosity volumes to market. Condensate is a light hydrocarbon which is conventionally a bi-product of natural gas production or NGLs fractionation. Production of this commodity is decreasing in western Canada but, with the increasing demand for diluents from heavy oil producers, there has been an increasing need to import. Currently, volumes are transported via rail to Alberta from the United States as well as from international sources via tankers and rail from the West Coast. Also in mid-2010, Enbridge’s Southern Lights condensate pipeline began importing incremental volumes of condensate from the United States to Alberta to meet producer’s needs.

 

 

 

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SUPPLY AND DEMAND FOR NATURAL GAS

 

The North American natural gas market has entered into a period of abundant supply primarily due to horizontal drilling of shale gas plays in the United States. Rapidly evolving drilling and completion technologies have increased the average productivity of new wells and reversed the established trend of diminishing productivity. Improved well productivity and drilling efficiencies have combined to reduce production costs such that shale gas production is among the most economic source of gas in North America. Considering the widespread nature and vast resource endowment of unconventional gas, North America is expected to have excess supply for some time. As such, several projects to import liquefied natural gas (LNG) into North America were cancelled during the year; instead, proposals to export LNG derived from domestic production have gained momentum. Further, projects to transport northern gas to southern markets have been deferred. Despite delays with the construction and commissioning of liquefaction facilities, global LNG capacity expanded significantly in 2010. LNG imports are expected to remain close to contractual minimums for several years; conversely, North American spot cargoes of LNG are expected to be delivered to markets in Asia, Europe and South America in the near future.

 

Emphasis in drilling shifted over the year from the established shale plays in the mid-continent region (such as the Barnett, Fayetteville and Woodford shale plays) to the massive and higher-productivity plays such as Haynesville in northwest Louisiana, Marcellus in Appalachia and the Montney region in northeast British Columbia. In addition, producers have been increasingly shifting attention to more liquids-rich targets; namely, the Eagle Ford shale and Granite Wash plays in Texas. The rapid increase in drilling and corresponding production growth will continue to lead to abundant opportunities for gathering, processing and short-haul connectivity.

 

Regional production growth patterns have also impacted long-haul infrastructure. For example, rapid growth in production from the Marcellus shale play has contributed to sharply displace imports of Canadian gas into the northeast United States and has even spurred proposals to export gas into eastern Canada.

 

Weather extremes in both winter and summer seasons helped to propel North American natural gas demand in 2010. Gas demand was further supported by the recovering industrial sector following the recent economic recession, and an increased amount of gas for coal substitution in power generation as gas prices were comparatively weak. Although economic recovery was slowing in the second half of 2010, growth is expected to continue at a modest pace into 2011. Overall, natural gas demand should experience moderate growth over the next several years.

 

As growth in unconventional gas supply continues to outpace growth in demand, North America is expected to remain in a relatively low gas price environment. Moreover, gas prices will continue to experience downward pressure until gas drilling is reduced sufficiently to temper production growth. Oil prices, in contrast, are expected to increase; consequently, the wide disparity between gas and oil prices should continue to support strong gas processing and fractionation spreads.

 

 

 

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SUPPLY AND DEMAND FOR GREEN ENERGY

 

While traditional forms of energy are expected to represent the major source of North American energy supply for years to come, a grass roots shift to a lower carbon intensive economy has commenced. As overall North American energy needs continue to grow, particularly the need for electricity to meet commercial and residential demand, opportunities arise for renewable energy projects driven by reduced reliance on carbon-intensive fuels and heightened environmental awareness. Renewable energy, including wind, solar and geothermal, is attractively positioned to capture a significant portion of incremental and replacement generation capacity over the next 25 years.

 

Electricity demand growth is expected to average approximately 1% to 2% annually to 2035. The Energy Information Administration (EIA) forecasts that United States generation capacity will increase by 220,000 megawatts (MW) or over 20% from 2010 to 2035, with the vast majority of new generation coming from gas-fired generation and renewable energy sources. According to the NEB, average Canadian electricity demand is expected to grow by 1% per year over the next ten years. Growth in nuclear and coal-fired generation is expected to be limited due to permitting challenges, long lead times and uncertainty of environmental regulations, leaving opportunity for incremental demand to be met by renewable sources and natural gas.

 

Expanding renewable energy infrastructure in North America is not without challenges. Projects are typically highly capital intensive and renewable technology is in early stages relative to mature energy sources. Further, renewable projects must balance the benefit of reduced carbon emissions with land disturbances and projects aesthetics. High quality wind and solar resources may often be found in regions at long distances from high demand markets, introducing the need for new transmission capacity to move the increasing supply of renewable power to markets. Renewable generation results in greater load variability, creating further opportunities for gas-fired generating capacity to support system reliability. Natural gas is abundant and low cost and will form a growing part of the generation supply mix in North America.

 

Many factors will impact the pace of future development in renewable energy, including, but not limited to, the pace of economic recovery, technological advances, future energy or climate change regulations and continued government support. The forecasted increase in power generation arising from renewable sources is in part supported by government incentives. The continuing ability to obtain tax or other government incentives, and the ability to secure long-term power purchase agreements through government or investor-owned power authorities is required to support project economics based on current costs and technologies. What is clear is that a mix of alternative energy sources will play an increasingly important role in the North American energy space for years to come and there will be a continued drive to develop and promote green energy.

 

Growth Projects

 

Over the last three years Enbridge has placed into service over $12 billion in growth projects. In 2010 alone, Enbridge placed into service $6.5 billion of growth projects, including the $3.5 billion Alberta Clipper project, the largest liquids pipeline project in the Company’s history, as well as the $2.3 billion Southern Lights Pipeline. Enbridge has also secured over $6 billion in new infrastructure growth projects in strategically significant areas including the Canadian Oil Sands and Bakken formation, mid-west Texas and Louisiana shale gas plays and offshore natural gas and oil, as well as wind, solar and other renewable projects. In addition, the Company has a further $30 billion in growth opportunities under development, but not yet commercially secured, for the post-2011 period, of which it expects to be successful on a significant portion.

 

 

 

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The table below summarizes the current status of the Company’s commercially secured projects, separated into the Company’s business segments. These growth projects are expected to help Enbridge sustain its anticipated average annual earnings per share growth rate of 10% through the middle of this decade.

 

 

 

Actual/Estimated

 

 

 

 

 

 

 

 

Capital Cost 1

 

Expenditures to Date

 

Expected In-Service Date

 

Status

 

 

 

 

 

 

 

 

 

(Canadian dollars, unless stated otherwise)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

LIQUIDS PIPELINES

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

1.  Alberta Clipper – Canadian portion

 

$2.2 billion

 

$2.2 billion

 

2010

 

Complete

2.  Southern Lights Pipeline

 

$0.5 billion +
US$1.6 billion

 

$0.5 billion +
US$1.5 billion

 

Light Sour Line – 2009;
Diluent Line – 2010

 

Complete

3.  Christina Lake Lateral Project

 

$0.3 billion

 

$0.1 billion

 

2011

 

Under construction

4.  Woodland Pipeline

 

$0.5 billion

 

No significant
expenditures to date

 

2012

 

Entering construction phase

5.  Edmonton Terminal Expansion

 

$0.3 billion

 

No significant
expenditures to date

 

2011 – 2012
(in phases)

 

Regulatory and
pre-construction

6.  Wood Buffalo Pipeline

 

$0.4 billion

 

No significant
expenditures to date

 

2013

 

Regulatory and
pre-construction

7.  Norealis Pipeline

 

$0.5 billion

 

No significant
expenditures to date

 

2013

 

Regulatory and
pre-construction

8.  Waupisoo Pipeline Expansion

 

$0.4 billion

 

No significant
expenditures to date

 

2013

 

Pre-construction

9.  Athabasca Pipeline Capacity Expansion

 

$0.4 billion

 

No significant
expenditures to date

 

2013 – 2014
(in phases)

 

Regulatory and
pre-construction

10.  Fort Hills Pipeline System

 

$2.0 billion

 

$0.1 billion

 

TBD

 

Commercially secured; pending customer timing

 

GAS PIPELINES, PROCESSING AND ENERGY SERVICES

 

11.  Sarnia Solar Project

 

$0.4 billion

 

$0.4 billion

 

2010

 

Complete

12.  Talbot Wind Energy Project

 

$0.3 billion

 

$0.3 billion

 

2010

 

Complete

13.  Greenwich Wind Energy Project

 

$0.3 billion

 

$0.2 billion

 

2011

 

Under construction

14.  Cedar Point Wind Energy Project

 

US$0.5 billion

 

US$0.4 billion

 

2011

 

Under construction

15.  Amherstburg/Tilbury Solar Projects

 

$0.1 billion

 

No significant
expenditures to date

 

2011/2010

 

Under construction/ Complete

16.  Venice Gas Processing Facility

 

$0.2 billion

 

No significant
expenditures to date

 

2013

 

Pre-construction

17.  Walker Ridge Gas Gathering System

 

US$0.4 billion

 

No significant
expenditures to date

 

2014

 

Pre-construction

18.  Big Foot Oil Pipeline

 

US$0.2 billion

 

No significant
expenditures to date

 

2014

 

Pre-construction

 

 

 

 

 

 

 

 

 

SPONSORED INVESTMENTS

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

19.  EEP/EELP – Alberta Clipper – United States portion

 

US$1.2 billion

 

US$1.2 billion

 

2010

 

Complete

20.  EIF – Saskatchewan System Capacity Expansion

 

$0.1 billion

 

$0.1 billion

 

2010

 

Complete

21.  EEP – Bakken Expansion Program

 

US$0.4 billion

 

No significant
expenditures to date

 

2013

 

Regulatory and
pre-construction

22.  EIF – Bakken Expansion Program

 

$0.2 billion

 

No significant
expenditures to date

 

2013

 

Regulatory and
pre-construction

 

1     These amounts are estimates only and subject to upward or downward adjustment based on various factors.

 

Risks related to the development and completion of growth projects are described under

Risk Management and Financial Instruments.

 

 

 

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LIQUIDS PIPELINES

 

Alberta Clipper Project

 

The Alberta Clipper Project, which was placed in service April 1, 2010 on schedule and on budget, involved the construction of a new 36-inch diameter pipeline from Hardisty, Alberta to Superior, Wisconsin generally within or alongside Enbridge’s existing rights-of-way in Canada and EEP’s existing rights-of-way in the United States. The new pipeline interconnects with the existing mainline system in Superior where it provides access to Enbridge’s full range of delivery points and storage options, including Chicago, Toledo, Sarnia, Patoka and Cushing. Alberta Clipper has an initial capacity of 450,000 bpd, is expandable to 800,000 bpd and now forms part of the existing Enbridge System in Canada and the EEP Lakehead System in the United States.

 

The cost of the project was $2.2 billion and US$1.2 billion, including allowance for funds used during construction (AFUDC), for the Canadian and United States segments, respectively. Enbridge funded 66.7% of the United States segment of the Alberta Clipper project through EELP.

 

For the United States segment of Alberta Clipper, tariffs filed with the Federal Energy Regulatory Commission (FERC) were approved and became effective April 1, 2010. Filings in early 2010 by shippers requesting the FERC to delay making the tariffs effective were dismissed by the FERC in March 2010.

 

Interim tolls for the Enbridge mainline, including recovery of costs related to the Canadian segment of Alberta Clipper, went into effect April 1, 2010 and, as directed by the NEB, reflected the forecasted Alberta Clipper toll presented in 2007. A NEB hearing was originally scheduled for November 2010 which would have considered Enbridge’s final toll application, including Alberta Clipper at the full revenue requirement based on it being used and useful, as well as remaining aspects of the February 2010 filing made by certain shippers. However, at the joint request of the primary intervenors and the Company, the NEB hearing has been suspended. The Company and the intervenors are currently in discussions that could, if successful, narrow the existing issues, minimize the scope of or eliminate the need for the hearing. The Company continues to believe the shippers’ Alberta Clipper filings to be without merit.

 

Southern Lights Pipeline

 

The Southern Lights Pipeline was completed ahead of schedule and was placed in service on July 1, 2010. The 180,000 bpd Southern Lights Pipeline transports diluent from Chicago, Illinois to Edmonton, Alberta. The project included reversing the flow of a portion of Enbridge’s Line 13, a crude oil pipeline which ran from Edmonton to Clearbrook, Minnesota. In order to replace the light crude capacity that would be lost through the reversal of Line 13, the Southern Lights Project also included the construction of a new 20-inch diameter light sour crude oil pipeline (LSr Pipeline) from Cromer, Manitoba to Clearbrook, and modifications to existing Line 2. These changes to the existing crude oil system increased southbound light crude system capacity by approximately 45,000 bpd, net of the Line 13 lost capacity.

 

The total cost of the project was US$1.6 billion for the United States segment and $0.5 billion for the Canadian segment. Remaining costs primarily relate to right-of-way restoration and final work on the Line 13 facilities.

 

Both the Canadian and United States portion of the tariff for uncommitted shippers on the Southern Lights Pipeline has been challenged. Accordingly, a FERC hearing process has been initiated. The NEB has yet to confirm the process, if any, to be followed regarding the Canadian tariff challenge. No material financial impacts to the Company are anticipated.

 

 

 

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Christina Lake Lateral Project

 

The Christina Lake Lateral Project includes a new pipeline terminal and blended products pipeline, which will allow the Cenovus and ConocoPhillips partnership to deliver increased Christina Lake production volumes directly into the Athabasca Pipeline. The expansion project will add two 375,000 barrel tanks and 26 kilometres (16 miles) of 30-inch diameter pipeline to the existing Christina Lake lateral and terminal facilities, which include two eight-inch lateral lines plus 240,000 barrels of tankage, that connect to the Athabasca Pipeline. The estimated cost of the additional facilities is approximately $0.3 billion, with expenditures to date of $0.1 billion. The facilities are expected to be in service in the third quarter of 2011.

 

Woodland Pipeline

 

Enbridge entered into an agreement with Imperial Oil Resources Ventures Limited (Imperial Oil) and ExxonMobil Canada Properties (ExxonMobil) to provide for the transportation of blended bitumen from the Kearl oil sands mine to crude oil hubs in the Edmonton, Alberta area. The project will be phased with the mine expansion, with the first phase involving construction of a new 140-kilometre (87-mile) 36-inch diameter pipeline from the mine to the Cheecham Terminal, and service on Enbridge’s existing Waupisoo Pipeline from Cheecham to the Edmonton area. The new Woodland Pipeline may be extended from Cheecham to Edmonton as part of future expansions. The Woodland Pipeline is being undertaken as a joint venture between Enbridge, Imperial Oil and ExxonMobil. Regulatory approval for the Phase I facilities was received from the Energy Resources Conservation Board (ERCB) in June 2010 and construction is underway. The total estimated cost of the Phase I pipeline from the mine to the Cheecham Terminal and related facilities is approximately $0.5 billion. Enbridge expects the pipeline will come into service in late 2012.

 

Edmonton Terminal Expansion

 

The Edmonton Terminal Expansion Project involves expanding the tankage of the mainline terminal at Edmonton, Alberta by one million barrels at an estimated cost of $0.3 billion. The expansion is required to accommodate growing oil sands production receipts both from Enbridge’s Waupisoo Pipeline and other non-Enbridge pipelines. The expansion will be conducted over two phases and will consist of the construction of four tanks and the installation of a short segment of pipeline and related infrastructure. Subject to regulatory approval and construction pace, the expansion is expected to be completed in 2012.

 

Wood Buffalo Pipeline

 

Enbridge entered into an agreement with Suncor Energy Inc. to construct a new, 95-kilometre (59-mile) 30-inch diameter crude oil pipeline, connecting the Athabasca Terminal, which is adjacent to Suncor’s oil sands plant, to the Cheecham Terminal, which is the origin point of Enbridge’s Waupisoo Pipeline. The Waupisoo Pipeline already delivers crude oil from several oil sands projects to the Edmonton mainline hub. The new Wood Buffalo pipeline will parallel the existing Athabasca Pipeline between the Athabasca and Cheecham Terminals. The estimated capital cost is approximately $0.4 billion and, pending regulatory approval, the new pipeline is expected to be in service by mid-2013.

 

Norealis Pipeline

 

In order to provide pipeline and terminaling services to the proposed Husky-operated Sunrise Oil Sands Project, the Company will construct a new originating terminal (Norealis Terminal), a 112-kilometre (66-mile) 24-inch diameter pipeline (Norealis Pipeline) from the proposed Norealis Terminal to the Cheecham Terminal, and additional tankage at Cheecham. The estimated cost of the project is approximately $0.5 billion. Subject to regulatory approval, the facilities are expected to be in service in late 2013.

 

 

 

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Waupisoo Pipeline Expansion

 

The Waupisoo Pipeline Expansion, which received regulatory approval in November, will provide 65,000 bpd of additional capacity in the second half of 2012 and an estimated 190,000 bpd of additional capacity in the second half of 2013 when the expansion is fully in service. The project will accommodate recent additional shipper commitments of 229,000 bpd. The estimated cost of the project is approximately $0.4 billion.

 

Athabasca Pipeline Capacity Expansion

 

The Company will undertake an expansion of its Athabasca Pipeline to its full capacity to accommodate additional contractual commitments including recent incremental shipping commitments by the Christina Lake Oilsands Project operated by Cenovus. This expansion will increase the capacity of the Athabasca Pipeline to its maximum capacity of approximately 570,000 bpd, depending on crude slate. The estimated cost of this full expansion is approximately $0.4 billion with an expected in service date of 2013 for an initial 430,000 bpd of capacity with the balance of the capacity expected to be available by early 2014, subject to regulatory approval. The Athabasca Pipeline transports crude oil from various oil sands projects to the mainline hub at Hardisty, Alberta.

 

Fort Hills Pipeline System

 

In November 2007, Enbridge was selected by Fort Hills Energy L.P. (FHELP) as its pipeline and terminaling services provider for the initial phase of the Fort Hills project and all subsequent expansions. In late 2008, FHELP announced that its final investment decision for the mining portion of the project was being deferred until costs could be reduced, and commodity prices and financial markets strengthened. It also announced that the Fort Hills upgrader was put on hold and that a decision to proceed with the upgrader would be made at a later date. Accordingly, the scope of the Fort Hills Pipeline System is being reevaluated by FHELP and the planned in-service date for the project has been deferred beyond the original planned date of mid-2011. FHELP has until June 2011 to give notice to proceed. Expenditures to date are approximately $0.1 billion and are commercially recoverable from FHELP.

 

Northern Gateway Project

 

The Northern Gateway Project involves constructing a twin 1,177- kilometre (731-mile) pipeline system from near Edmonton, Alberta, to a new marine terminal in Kitimat, British Columbia. One pipeline would transport crude oil for export from the Edmonton area to Kitimat and is proposed to be a 36-inch diameter line with an initial capacity of 525,000 bpd. The other pipeline would be used to import condensate and is proposed to be a 20-inch diameter line with an initial capacity of 193,000 bpd.

 

Northern Gateway submitted an application to the NEB on May 27, 2010. The Joint Review Panel (JRP) established to review the proposed project, pursuant to the NEB Act and the Canadian Environmental Assessment Act, has a broad mandate to assess the potential environmental effects of the project and to determine if it is in the public interest. The JRP conducted sessions with the public and Aboriginal groups to receive comments on the draft List of Issues, additional information which Northern Gateway should be required to file and locations for the oral hearings. The JRP decided to obtain these comments prior to issuing a Hearing Order or initiating further procedural steps in the joint review process. On January 19, 2011, the JRP advised that prior to issuing a procedural order it requires additional detail on the design and risk assessment of the pipelines. This information will be provided to the JRP along with prior commitments for other updates in the first quarter of 2011.

 

Subject to continued commercial support, regulatory and other approvals, and adequately addressing landowner, Aboriginal and local community concerns, the Company estimates that Northern Gateway could be in-service by late 2016 at the earliest, at an estimated cost of $5.5 billion. Expenditures to date, which relate primarily to the regulatory process, are approximately $0.2 billion, including $0.1 billion

 

 

 

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ENBRIDGE INC. 2010 ANNUAL REPORT

 

 



 

in funding secured from Western Canada producers and Pacific Rim refiners toward the costs of seeking the necessary regulatory approvals for the project. Given the many uncertainties surrounding the Northern Gateway Project, including final ownership structure, the potential financial impact of the project cannot be determined at this time.

 

The JRP posts public filings related to Northern Gateway on its website at http://gatewaypanel.review-examen.gc.ca/clf-nsi/hm-eng.html and Enbridge also maintains a Northern Gateway Project site in addition to information available on www.enbridge.com. The full regulatory application submitted to the NEB and the 2010 Enbridge Northern Gateway Corporate Social Responsibility Report are available on www.northerngateway.ca. None of the information contained on, or connected to, the JRP website, the Northern Gateway Project website or Enbridge’s website is incorporated in or otherwise part of this MD&A.

 

GAS PIPELINES, PROCESSING AND ENERGY SERVICES

 

Sarnia Solar Project

 

The Company developed the 80-MW Sarnia Solar Project with First Solar, Inc. (First Solar). The initial 20-MW facility attained commercial operation in December 2009 and the 60-MW expansion was completed three months ahead of schedule in early September 2010. Power output of the facility is sold to the Ontario Power Authority (OPA) under a 20-year power purchase agreement. The final capital cost of both facilities was approximately $0.4 billion.

 

Talbot Wind Energy Project

 

Enbridge developed the 99-MW Talbot Wind Energy Project near Chatham, Ontario with Renewable Energy Systems Canada Inc. (RES Canada). The project was completed in December 2010. Enbridge has a 90% interest in the project and an option to acquire the remaining 10% interest. The project utilizes 43 Siemens 2.3-MW wind turbines and, under a multi-year fixed price agreement, Siemens is providing operations and maintenance services for the wind turbines. The Talbot Wind Energy Project power output is sold to the OPA under a 20-year power purchase agreement. The final capital cost of the project was approximately $0.3 billion.

 

Greenwich Wind Energy Project

 

The Company is developing the 99-MW Greenwich Wind Energy Project on the northern shore of Lake Superior in Ontario with RES Canada. Enbridge has a 90% interest in the project and an option to acquire the remaining 10% interest. RES Canada is constructing the project under a fixed price, turnkey, engineering, procurement and construction agreement. The project utilizes 43 Siemens 2.3-MW wind turbines and, under a multi-year fixed price agreement, Siemens will provide operations and maintenance services for the wind turbines. The Greenwich Wind Energy Project will deliver energy to the OPA under a 20-year power purchase agreement. The project is expected to be completed in the third quarter of 2011. The total estimated capital cost is $0.3 billion, with expenditures to date of $0.2 billion.

 

Cedar Point Wind Energy Project

 

Enbridge is developing the 250-MW Cedar Point Wind Energy Project, near Denver, Colorado with RES Americas, at an expected cost of approximately US$0.5 billion. RES Americas is constructing the wind project under a fixed price, turnkey, engineering, procurement and construction agreement. The project is comprised of 139 Vestas V90 1.8-MW wind turbines on 20,000 acres of leased private land. The Cedar Point Wind Energy Project will deliver electricity into the Public Service Company of Colorado grid under a 20-year, fixed price power purchase agreement. Construction on the project has commenced and is expected to be completed in the fourth quarter of 2011, with expenditures to date of US$0.4 billion.

 

 

 

MANAGEMENT’S DISCUSSION AND ANALYSIS

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Neal Hot Springs Geothermal Project

 

The Company has partnered with U.S. Geothermal Inc. to develop the 35-MW Neal Hot Springs Geothermal Project located in Malheur County, Oregon. U.S. Geothermal is constructing the plant and will operate the facility. Once completed, anticipated to be in the second quarter of 2012, the project will deliver electricity to the Idaho Power grid under a 25-year power purchase agreement. Enbridge will invest up to approximately $24 million for a 20% interest in the project.

 

Amherstburg and Tilbury Solar Projects

 

The Company entered into agreements to acquire two new solar energy projects totaling 20 MW generating capacity from First Solar for $0.1 billion. The 5-MW Tilbury Solar Project, completed in December 2010, is located in Tilbury, Ontario. The Amherstburg II Solar Project, located in Amherstburg, Ontario, consists of two separate projects of 10 MW and 5 MW each. First Solar constructed (and, in the case of the Amherstburg II Solar Project, will construct) the projects for Enbridge under fixed price engineering, procurement and construction contracts. Construction is expected to begin in March 2011 and is expected to be complete in the third quarter of 2011. Enbridge will sell the facilities’ power output to the Ontario Power Authority pursuant to 20-year power purchase agreements under the terms of the Ontario Government’s Renewable Energy Standard Offer Program.

 

Venice Gas Processing Facility

 

On January 31, 2011, the Company announced plans for an estimated $0.2 billion expansion of the condensate processing capacity of its Venice, Louisiana facility within its offshore gas business. The expanded condensate processing capacity will be required to accommodate additional natural gas production from the recently sanctioned Olympus offshore oil and gas development. Natural gas production from Olympus will move to Enbridge’s onshore facility at Venice via Enbridge’s Mississippi Canyon offshore pipeline where it will be processed to separate and stabilize the condensate. The expansion, which will more than double the capacity of the facility to approximately 12,000 barrels of condensate per day, is expected to be in service in late 2013.

 

Walker Ridge Gas Gathering System

 

The Company executed definitive agreements in the last quarter of 2010 with Chevron Corp. to expand its central Gulf of Mexico offshore pipeline system. Under the terms of the agreements, Enbridge will construct, own and operate the Walker Ridge Gas Gathering System (WRGGS) to provide natural gas gathering services to the proposed Jack, St. Malo and Big Foot ultra-deepwater developments. The WRGGS includes 274 kilometres (170 miles) of 8-inch or 10-inch diameter pipeline at depths of up to approximately 2,150 meters (7,000 feet) with capacity of 0.1 billion cubic feet per day (bcf/d). WRGGS is expected to be in service in 2014 and is expected to cost approximately US$0.4 billion.

 

Big Foot Oil Pipeline

 

The Company entered into a letter of intent (LOI) with Chevron USA, Inc., Statoil Gulf of Mexico LLC and Marubeni Oil & Gas (USA) Inc. to construct and operate a 64-kilometre (40-mile) 20-inch oil pipeline with capacity of 100,000 bpd from the proposed Big Foot ultra-deepwater development in the Gulf of Mexico. This crude oil pipeline project is complementary to Enbridge’s plans to construct the WRGGS. The estimated cost of the Big Foot Oil Pipeline, which will be located about 274 kilometres (170 miles) south of the coast of Louisiana, is approximately US$0.2 billion and is expected to be in service in 2014.

 

 

 

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SPONSORED INVESTMENTS

 

Bakken Expansion Program

 

EEP and EIF will proceed, subject to customary regulatory approvals, with a joint project to further expand crude oil pipeline capacity to accommodate growing production from the Bakken and Three Forks formations located in Montana, North Dakota, Saskatchewan and Manitoba. The Bakken Expansion Program will increase takeaway capacity from the Bakken area by an initial 145,000 bpd, which can be readily expanded to 325,000 bpd. The Bakken Expansion Program will involve United States projects undertaken by EEP at a cost of approximately US$0.4 billion and Canadian projects undertaken by EIF at a cost of approximately $0.2 billion. As of August 2010, EEP and EIF had received sufficient long-term shipping commitments from anchor shippers to enable the Bakken Expansion Program to proceed. A binding open season was subsequently conducted to enable other shippers to secure capacity on the expansion at the same terms as the anchor shippers, which was successfully concluded in February 2011 with commitments received for an aggregate of 100,000 bpd of capacity. The Bakken Expansion Program is expected to be completed by the first quarter of 2013.

 

Enbridge Income Fund

 

Saskatchewan System Capacity Expansion

 

Phase II of the Saskatchewan System Capacity Expansion included three separate projects that served to reduce capacity constraints at a variety of locations. Collectively, the projects increased capacity across the system by approximately 125,000 bpd. Construction was substantially completed in December 2010. The final capital cost of the projects was approximately $0.1 billion.

 

CORPORATE

 

Project Pioneer

 

In June 2010, Enbridge announced it will participate in the development of the TransAlta-led Project Pioneer, Canada’s first fully-integrated carbon capture and storage (CCS) project involving retro-fitting a coal-fired electricity plant. When complete, Project Pioneer is expected to be one of the largest CCS facilities in the world and among the first to have an integrated underground storage system. Enbridge brings to Project Pioneer expertise in the design and construction of pipeline infrastructure, as well as extensive knowledge in CO2 sequestration.

 

 

 

MANAGEMENT’S DISCUSSION AND ANALYSIS

55

 



 

Liquids Pipelines

 

EARNINGS

 

 

 

2010

 

 

2009

 

 

2008

 

(millions of Canadian dollars)

 

 

 

 

 

 

 

 

 

Enbridge System

 

327

 

 

295

 

 

212

 

Enbridge Regional Oil Sands System

 

73

 

 

72

 

 

69

 

Southern Lights Pipeline

 

82

 

 

58

 

 

27

 

Spearhead Pipeline

 

29

 

 

17

 

 

12

 

Feeder Pipelines and Other

 

1

 

 

12

 

 

12

 

Adjusted Earnings

 

512

 

 

454

 

 

332

 

Enbridge Regional Oil Sands System – leak remediation costs

 

 

 

(9

)

 

 

Feeder Pipelines and Other – asset impairment loss

 

 

 

 

 

(4

)

Earnings

 

512

 

 

445

 

 

328

 

 

Liquids Pipelines adjusted earnings were $512 million in 2010 compared with adjusted earnings of $454 million in 2009 and $332 million in 2008. The adjusted earnings increases were supported by substantially all segment assets, but were primarily due to bringing into service the new Alberta Clipper and Southern Lights Pipeline.

 

 

While under construction, certain regulated pipelines are entitled to recognize AEDC in earnings. These amounts will be collected in tolls once the pipelines are in service. The earnings impact of AEDC for the Enbridge System for the year ended December 31, 2010 was $29 million (2009 – $74 million; 2008 – $18 million). Recognition of AEDC on Alberta Clipper ceased following its in service date of April 1, 2010 when cash tolls commenced. The earnings impact of AEDC for the Southern Lights Pipeline was $32 million (2009 – $44 million; 2008 – $27 million) for the year ended December 31, 2010. Recognition of AEDC on the Southern Lights Pipeline ceased following its in service date of July 1, 2010.

 

Liquids Pipelines earnings were impacted by the following non-recurring or non-operating adjusting items:

 

·     Clean up and remediation costs related to a valve leak within the Enbridge Cheecham Terminal on the Enbridge Regional Oil Sands System in January 2009, which is not indicative of the expected future performance of this asset.

·     In the fourth quarter of 2008, the Company recorded an impairment loss of $4 million on Manyberries Pipeline, a small feeder pipeline located in Canada.

 

 

 

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ENBRIDGE INC. 2010 ANNUAL REPORT

 

 



 

ENBRIDGE SYSTEM

 

The mainline system is comprised of Enbridge System and Lakehead System (the portion of the mainline in the United States that is operated by Enbridge and owned by EEP). Enbridge has operated, and frequently expanded, the mainline system since 1949. Through six adjacent pipelines with a combined capacity of approximately 2.5 million bpd, the system transports various grades of crude oil and diluted bitumen from western Canada to the midwest region of the United States and eastern Canada. Also included within the Enbridge System and located in eastern Canada are two crude oil pipelines and one refined products pipeline with a combined capacity of 0.4 million bpd. Average system utilization in 2010 was 79% and it is expected to decrease in 2011 due to a combination of additional pipeline capacity being added to the system by the Company in 2010 and a new pipeline placed into service by a competitor during the year.

 

Incentive Tolling

 

Tolls on Enbridge System are governed by various agreements, which are subject to the approval of the NEB. The NEB’s jurisdiction over the Enbridge System includes statutory authority over matters such as construction, rates and ratemaking agreements and other contractual arrangements with customers. Significant agreements include the incentive tolling settlement (ITS) applicable to the Enbridge mainline system (excluding Line 8 and Line 9), the Terrace agreement, the SEP II Risk Sharing agreement, Alberta Clipper agreement and the Southern Access Expansion agreement which are recovered via the Mainline Expansion Toll. Tolls on the core mainline system have been governed by ITS since 1995, with the most recent ITS term effective through 2010. The Company has reached agreement with industry to roll forward the 2010 ITS agreement for a year and will file the 2011 ITS with the NEB in March 2011. The 2011 ITS has similar terms as the 2010 ITS. Discussions with industry continue for a longer term settlement agreement which will support a competitive toll structure. Until all matters before the NEB are settled, interim tolls will continue to be collected for the Enbridge System.

 

The ITS agreement allows for continued throughput protection on the Canadian mainline, the flow through of costs not controllable by Enbridge and includes an earnings incentive mechanism for controllable costs. The NEB Line 9 hearing scheduled for September 2010 and the Alberta Clipper NEB hearing scheduled for November 2010 have been suspended while the Company and the intervenors pursue settlement discussions including the long-term Canadian mainline tolling agreement.

 

In conjunction with the Terrace Agreement, the 2010 ITS continues the throughput protection provisions included in earlier incentive tolling arrangements, ensuring the Company was largely insulated from volume fluctuations beyond its control. Accordingly the agreements establish tolls based on an agreed capacity and an allowed revenue requirement. Where actual volumes on the pipeline fall short of the agreed capacity and Enbridge is unable to fully collect its annual revenue requirement, the deficiency is collectible from shippers in the following year and a receivable, referred to as tolling deferrals, is recognized.

 

 

 

MANAGEMENT’S DISCUSSION AND ANALYSIS

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This basis may affect the timing of recognition of revenues compared with that otherwise expected under Canadian GAAP for companies that are not rate-regulated. As at December 31, 2010, $91 million (2009 – $98 million) was recorded as tolling deferrals.

 

Enbridge pays taxes each year only on the tolls collected in cash; therefore the tax payable on the tolling deferrals lags behind the recognition of the revenue. As the Terrace capacity is increasingly utilized, there will be less tolling deferrals recorded and more cash tolls collected. This will result in the Company paying taxes in future years on both the tolling deferral realization and the current year’s cash tolls.

 

Results of Operations

 

Enbridge System earnings were $327 million for the year ended December 31, 2010 compared with $295 million for the year ended December 31, 2009. The increase in earnings resulted from a higher Alberta Clipper contribution since entering service on April 1, 2010 and favourable operating performance. These positive factors were partially offset by higher taxes in the Terrace component.

 

Enbridge System earnings were $295 million for the year ended December 31, 2009 compared with $212 million for the year ended December 31, 2008. Enbridge System earnings increased due to increased tolls from a higher rate base as a result of Line 4 entering service in April 2009, lower financing costs as well as higher AEDC on Alberta Clipper. These positive impacts were partially offset by higher operating costs, including compensation.

 

ENBRIDGE REGIONAL OIL SANDS SYSTEM

 

Enbridge Regional Oil Sands System includes two long haul pipelines, the Athabasca Pipeline and the Waupisoo Pipeline, as well as a variety of other facilities including the MacKay River, Christina Lake, Surmont and Long Lake facilities. It also includes Hardisty Caverns Limited Partnership, which provides storage service; and three large terminals: the Athabasca Terminal located north of Fort McMurray, Alberta, the Cheecham Terminal, located 95 kilometres south of Fort McMurray where the Waupisoo Pipeline initiates, and the Hardisty Contract Terminal, one of the largest crude oil terminals in North America.

 

The Athabasca Pipeline is a 540-kilometre (335-mile) synthetic and heavy oil pipeline, built in 1999, that links the Athabasca oil sands in the Fort McMurray, Alberta region to a pipeline hub at Hardisty, Alberta. The Athabasca Pipeline has an ultimate design capacity of approximately 570,000 bpd, dependent on viscosity of crude being shipped. It is currently configured to transport approximately 345,000 bpd.

 

The Company has a long-term (30-year) take-or-pay contract with the major shipper on the Athabasca Pipeline which commenced in 1999. Revenue is recorded based on the contract terms negotiated with the major shipper, rather than the cash tolls collected.

 

 

 

The Waupisoo Pipeline is a 380-kilometre (236-mile) synthetic and heavy oil pipeline that entered into service on May 31, 2008 and provides access to the Edmonton market for oil sands producers. The Waupisoo Pipeline initiates at Enbridge’s Cheecham Terminal and terminates at its Edmonton Mainline Terminal. The pipeline currently has a design capacity, dependent on crude slate, of up to 350,000 bpd, which can ultimately be expanded to 600,000 bpd.

 

 

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ENBRIDGE INC. 2010 ANNUAL REPORT

 

 



 

Enbridge has a long-term (25-year) take-or-pay commitment with the four founding shippers on the Waupisoo Pipeline who collectively have contracted for approximately one-third of the initial capacity on the line. The associated revenues provide for a base return on equity (ROE) with significant upside potential as incremental founders and third party volumes are added.

 

The Hardisty Contract Terminal, which is comprised of 19 tanks with a working capacity of approximately 7.5 million barrels of storage, was fully operational by October 1, 2009. In June 2010, the Company acquired the remaining 50% of the Hardisty Caverns Limited Partnership (Hardisty Caverns) previously owned by CCS Corporation for $52 million. The Hardisty Caverns facility, now wholly owned by Enbridge, also includes four salt caverns totaling 3.1 million barrels of capacity. The capacity at the facility is fully subscribed under long-term contracts that are generating revenues from storage and terminalling fees.

 

Results of Operations

 

Adjusted earnings for the year ended December 31, 2010 were $73 million compared with $72 million for the year ended December 31, 2009 and $69 million for the year ended December 31, 2008. In both the year ended December 31, 2010 and December 31, 2009, the increase in Enbridge Regional Oil Sands System adjusted earnings reflected higher volumes, increased tolls on certain laterals and the continued positive impact of terminal infrastructure additions, partially offset by higher operating costs.

 

Enbridge Regional Oil Sands System earnings for 2009 were impacted by a $9 million after-tax expense resulting from the clean up and remediation costs related to a valve leak within the Enbridge Cheecham Terminal in January 2009, which is not indicative of the expected future performance of this asset.

 

SOUTHERN LIGHTS PIPELINE

 

The 180,000 bpd, 20-inch diameter Southern Lights Pipeline was placed into service on July 1, 2010 and began transporting diluent from Chicago, Illinois to Edmonton, Alberta.

 

Enbridge receives tariffs under long-term (15-year) contracts with committed shippers. Tariffs provide for recovery of all operating and debt fiancing costs plus a ROE at a pre-determined rate. Uncommitted volumes, up to a specified amount, provide for tariff revenues that are fully credited to all shippers. Enbridge retains 25% of uncommitted tariff revenues on volumes above the specified amount, with the remainder being credited to shippers.

 

Results of Operations

 

Earnings for the year ended December 31, 2010 were $82 million compared with $58 million for the year ended December 31, 2009. Southern Lights Pipeline earnings reflected operating earnings from its in-service date of July 1, 2010 in addition to AEDC recognized on a growing capital base while the project was under construction during the first six months of 2010. The increase in 2010 earnings was partially offset by a decrease in earnings from the new light sour pipeline, which became operational during the first quarter of 2009 and was subsequently transferred to the Enbridge System effective May 1, 2010.

 

Earnings for the year ended December 31, 2009 were $58 million compared with $27 million for the year ended December 31, 2008. The increased earnings reflected AEDC recognized on a growing capital base while the project was under construction. In 2009, earnings from the new light sour pipeline, which became operational during the first quarter of 2009, were also reflected in earnings.

 

 

 

MANAGEMENT’S DISCUSSION AND ANALYSIS

59

 

 



 

SPEARHEAD PIPELINE

 

Spearhead Pipeline delivers crude oil from Chicago, Illinois to Cushing, Oklahoma. The performance of this pipeline steadily increased and with further support of new committed shippers, the Spearhead Pipeline Expansion was completed in May 2009. This expansion increased the capacity from 125,000 bpd to 193,300 bpd from the new initiating point of Flanagan, Illinois to Cushing.

 

Initial committed shippers and expansion shippers currently account for more than 70% of the 193,300 bpd capacity on Spearhead. Both the initial committed shippers and expansion shippers were required to enter into 10 year shipping commitments at negotiated rates that were offered during the open season process. The balance of the capacity is currently available to uncommitted shippers on a spot basis at FERC approved rates.

 

Results of Operations

 

Spearhead Pipeline earnings increased to $29 million for the year ended December 31, 2010 compared with $17 million for the year ended December 31, 2009 and $12 million for the year ended December 31, 2008. The earnings increases were due to higher volumes resulting from the expansion completed in May 2009. Earnings during 2010 were also positively impacted by the recognition of make-up rights which expired in the period, and lower operating costs.

 

 

 

FEEDER PIPELINES AND OTHER

 

Feeder Pipelines and Other primarily includes the Company’s 85% interest in Olympic Pipeline Company (Olympic Pipeline), the largest refined products pipeline in the State of Washington, transporting approximately 290,000 bpd of gasoline, diesel, and jet fuel. It also includes the NW System, which transports crude oil from Norman Wells in the Northwest Territories to Zama, Alberta; interests in a number of liquids pipelines in the United States; contract tankage facilities; and business development costs related to Liquids Pipelines activities.

 

Results of Operations

 

Adjusted earnings for Feeder Pipelines and Other were $1 million in 2010 compared with $12 million in both 2009 and 2008. The adjusted earnings decrease for 2010 compared with 2009 was due to a number of small factors including a decrease in earnings from Toledo Pipeline due to the Line 6B shutdown, a decrease in earnings from Olympic Pipeline, as well as an increase in business development costs.

 

BUSINESS RISKS

 

The risks identified below are specifi c to the Liquids Pipelines business. General risks that affect the Company as a whole are described under Risk Management and Financial Instruments.

 

 

 

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ENBRIDGE INC. 2010 ANNUAL REPORT

 

 



 

Supply and Demand

 

The expansion of the Company’s liquids pipelines depends on the supply of, and demand for, crude oil and other liquid hydrocarbons from western Canada. Supply, in turn, depends on a number of variables, including the price of crude oil and bitumen, the availability and cost of capital and labour for oil sands projects, the price of natural gas used for steam production and changes in plans by shippers. Supply risk to existing facilities is largely mitigated given the Company’s throughput insensitive commercial terms or cost of service arrangements on many of its Liquids Pipelines assets. Demand depends, among other things, on weather, gasoline price and consumption, manufacturing levels, alternative energy sources and global supply disruptions. Crude oil prices have become less volatile over the past couple of years which has resulted in oil sands producers recommencing projects that had been previously cancelled or deferred, creating increased demand in the WCSB for new pipeline infrastructure.

 

Also, shippers are not required to enter into long-term shipping commitments on Enbridge’s mainline system; rather, monthly volume nominations are accepted. The Company’s existing right-of-way provides a competitive advantage as it can be difficult and costly to obtain new rights of way for new pipelines. The ITS and Terrace Agreement as well as the Southern Access and Alberta Clipper agreements on the Enbridge System provide throughput protection which insulates the Company from negative volume fluctuations beyond its control. The Lakehead System, owned by EEP, has no similar throughput protection on its base or Terrace systems, but does on its SEP II, Southern Access and Alberta Clipper expansions.

 

Competition

 

Competition among existing pipelines is based primarily on the cost of transportation, access to supply, the quality and reliability of service, contract carrier alternatives and proximity to markets. Other competing carriers are available to ship western Canadian liquids hydrocarbons to markets in either Canada or the United States. Competition also arises from new pipeline proposals that provide access to market areas currently served by the Company’s liquids pipelines. One such competing project began commercial operations in early 2010 and will serve markets at Wood River, Illinois and Cushing, Oklahoma. This pipeline has an initial capacity of 435,000 bpd and an ultimate stated capacity of 591,000 bpd. Commercial support has also been announced to construct additional ex-Alberta capacity of 500,000 bpd to Nederland, Texas, for an in-service date during 2013. Competing alternatives for delivering western Canadian liquid hydrocarbons into the United States or other markets could erode shipper support for current or future expansion. However, the Company believes that its liquids pipelines provide attractive options to producers in the WCSB due to its competitive tolls and multiple delivery and storage points. Increased competition could arise from new feeder systems servicing the same geographic regions as the Company’s feeder pipelines.

 

The Company continues to adapt to the changes in its business environment. Enbridge is committed to performance excellence and is focused on becoming more efficient, more collaborative, more innovative and more cost effective so that the Company can pass those benefits on to its customers through service, savings, reliability and responsiveness.

 

Potential Pressure Restrictions

 

The Company’s liquids systems consist of individual pipelines of varying ages. With appropriate inspection and maintenance, the physical life of a pipeline is indefi nitely long; however, as pipelines age the level of expenditures required for inspection and maintenance may increase. Pressure restrictions may from time to time be established on the Company’s pipelines. Pressure restrictions reduce the available capacity of the applicable line segment and could result in a loss of throughput if and when the full capacity of that line segment would otherwise have been utilized. While the Enbridge System is volume-protected, EEP’s Lakehead System and certain other pipelines would be adversely affected by any pressure restrictions that do reduce volumes transported. Temporary pressure restrictions have been established on some sections of certain pipelines pending completion of specific inspection and repair programs.

 

 

 

MANAGEMENT’S DISCUSSION AND ANALYSIS

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Regulation

 

The Enbridge System and other liquids pipelines are subject to the actions of various regulators, including the NEB. Actions of the regulators related to tariffs, tolls and facilities impact earnings from those operations. A portion of the Enbridge System and other liquids pipelines earnings are affected by changes in market interest rates. The Company believes that regulatory risk is reduced through the negotiation of long-term agreements with shippers, such as the ITS, which govern the majority of the segment’s assets.

 

National Energy Board Decision

 

In October 2009, the NEB released a decision stating the generic multi-pipeline formula used to determine allowed ROE for pipeline companies is no longer in effect. The formula will not be replaced; instead returns will be determined through negotiated settlement between shippers and pipelines. As the formula is referenced in some current industry settlements, the NEB will continue to publish the generic ROE for 2010 and 2011, and if requested will continue to publish it post-2011.

 

Certain of the Company’s Liquids assets are regulated by the NEB and reference the multi-pipeline rate. The Company does not expect there will be a material financial impact as a result of this decision.

 

Gas Distribution

 

EARNINGS

 

 

 

2010

 

 

2009

 

2008

 

(millions of Canadian dollars)

 

 

 

 

 

 

 

 

Enbridge Gas Distribution (EGD)

 

135

 

 

129

 

123

 

Other Gas Distribution and Storage

 

32

 

 

25

 

18

 

Adjusted Earnings

 

167

 

 

154

 

141

 

EGD – (warmer)/colder than normal weather

 

(12

)

 

17

 

23

 

EGD – impact of tax rate changes

 

 

 

21

 

 

EGD – interest income on GST refund

 

 

 

7

 

 

EGD – provision for one–time charges

 

 

 

 

(3

)

Other Gas Distribution and Storage – asset impairment loss

 

 

 

(10

)

 

Other Gas Distribution and Storage – adoption of new accounting standard

 

 

 

(3

)

 

Earnings

 

155

 

 

186

 

161

 

 

Adjusted earnings from Gas Distribution were $167 million for the year ended December 31, 2010 compared with $154 million for 2009 and $141 million for 2008. The increase in Gas Distribution adjusted earnings primarily resulted from continuing higher contributions from EGD under its Incentive Regulation (IR) arrangement and modest growth in the Company’s other gas distribution businesses.

 

Gas Distribution earnings were impacted by the following non-recurring or non-operating adjusting items:

 

·     EGD earnings are adjusted to reflect the impact of weather.

·     In 2009, earnings from EGD reflected the impact of favourable tax rate changes.

·     Earnings from EGD for 2009 included interest income of $7 million related to the recovery of excess GST remitted to Canada Revenue Agency.

·     Earnings from EGD for 2008 included a $3 million provision for one-time charges to better align certain operating practices with its strategy under IR.

 

 

 

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·     Other Gas Distribution and Storage earnings for 2009 reflected a $10 million asset impairment loss which included goodwill.

·     Other Gas Distribution and Storage reflected the write-off of $3 million in deferred development costs as a result of adopting a change in accounting standards, effective January 1, 2009.

 

ENBRIDGE GAS DISTRIBUTION

 

EGD is Canada’s largest natural gas distribution company and has been in operation for more than 160 years. It serves approximately 2.0 million customers in central and eastern Ontario and parts of northern New York State. EGD’s utility operations are regulated by the Ontario Energy Board (OEB) and by the New York State Public Service Commission.

 

Incentive Regulation

 

In 2007, the Company filed a rate application with the OEB requesting a revenue cap incentive rate mechanism calculated on a revenue per customer basis for the 2008 to 2012 period. The OEB approved the IR Settlement Agreement (the IR Framework) with customer representatives.

 

The objectives of the IR Framework are as follows:

 

·     reduce regulatory costs;

·     provide incentives for improved efficiency;

·     provide more flexibility for utility management; and

·     provide more stable rates to its customers.

 

Under the IR Framework, Enbridge is allowed to earn and fully retain 100 basis points (bps) over the base return. Any return over 100 bps must be shared with customers on an equal basis. Enbridge estimates the customer portion of 2010 earnings over the allowed threshold to be $19 million (2009 – $19 million).

 

Rate Adjustment Applications

 

In September 2010, EGD filed an application with the OEB to adjust rates for 2011 pursuant to the approved IR formula. The total distribution revenue applied for was approved by the OEB, with the rate adjustment being effective January 1, 2011.

 

In September 2009, EGD filed an application with the OEB to adjust rates for 2010 pursuant to the approved IR formula and to seek approval for specific changes to the Rate Handbook. Subsequent to filing a settlement agreement with ratepayer groups with the OEB, in March 2010 EGD received approval of a fiscal 2010 final rate order from the OEB. The 2010 final rate order approved the implementation of a rate change effective April 1, 2010, which enabled EGD to recover the approved revenues as if rates were effective January 1, 2010.

 

Results of Operations

 

Adjusted earnings for the year ended December 31, 2010 were $135 million compared with $129 million for the year ended December 31, 2009. The increase in EGD adjusted earnings was primarily a result of continued favourable performance under IR, reflecting customer growth, higher distribution charges and lower taxes, partially offset by higher depreciation expense. Depreciation expense increased due to a higher overall asset base, including the implementation of a new customer billing system in late 2009.

 

 

 

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Adjusted earnings for the year ended December 31, 2009 were $129 million compared with $123 million for the year ended December 31, 2008. The increase in EGD’s adjusted earnings was primarily due to customer growth and lower interest expense, offset by higher operating costs and estimated accrued earnings sharing with customers under the current IR term caused primarily by a reduced rate base resulting from lower cost gas in storage.

 

EGD earnings were impacted by the following non-recurring or non-operating adjusting items:

 

·     Earnings for each period are adjusted to reflect the impact of weather. Weather is a significant driver of delivery volumes given that a significant portion of EGD customers use natural gas for space heating.

·     In 2009, earnings reflected the impact of favourable tax rate changes.

·     Earnings for 2009 included interest income of $7 million related to the recovery of excess GST remitted to Canada Revenue Agency.

·     Earnings from 2008 included a $3 million provision for one-time charges to better align certain operating practices with its strategy under IR.

 

Business Risks

 

The risks identified below are specific to EGD. General risks that affect the Company as a whole are described under Risk Management and Financial Instruments.

 

Regulatory Risk

 

The formula currently approved by the OEB for determination of the ROE, which is embedded and escalated within rates over the IR period, is based on the OEB’s risk assessment of EGD for the 2007 fiscal year.

 

In December 2009, the OEB issued a report making several changes to the cost of capital for Ontario’s regulated utilities. The new policy guidelines forecasted a new base level ROE of approximately 9.85% for EGD’s 2010 rate year, which is higher than the 8.37% currently permitted. In its 2010 rate application, EGD applied to the OEB for approval to use the new ROE formula to determine the annual earnings sharing for 2010 and the remainder of the IR term. While the OEB issued a decision in May 2010 that the new ROE is not to be used for such earnings sharing determinations, EGD anticipates applying the new ROE to determine rates after the conclusion of the IR term, effective for the rate year beginning 2013. In addition, EGD has appealed the OEB’s May 2010 decision to the Ontario Divisional Court. The Company’s appeal was heard by the Divisional Court in January 2011, but the Court has not yet released its decision.

 

 

The IR Framework allows certain categories of expense, from a cost of service view, and uncontrollable external factors, which will permit EGD to recover, with OEB approval, certain costs that are beyond management control, but are necessary for the maintenance of its services. The settlement also includes a mechanism to reassess the IR plan and return to cost of service if there are signifi cant and unanticipated developments that threaten the sustainability of the IR plan. The above noted terms set out in the settlement mitigate EGD’s risk to factors beyond management’s control.

 

 

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Natural Gas Cost Risk

 

EGD does not profit from the sale of natural gas nor is it at risk for the difference between the actual cost of natural gas purchased and the price approved by the OEB. This difference is deferred as a receivable from or payable to customers until the OEB approves its refund or collection. EGD monitors the balance and its potential impact on customers and will request interim rate relief that will allow EGD to recover or refund the natural gas cost differential. EGD has a quarterly rate adjustment mechanism in place that allows for the quarterly adjustment of rates to reflect changes in natural gas prices. Adjustments are subject to prior approval by the OEB. However, the cost of natural gas does affect the amount of EGD’s investment in gas in storage on which it earns a rate base return. Consequently, a lower gas price will reduce EGD’s earnings.

 

Volume Risks

 

Since customers are billed on both a fixed charge and on a volumetric basis, EGD’s ability to collect its total IR formula revenue depends on achieving the forecast distribution volume established in the rate-making process. Under IR, volume forecasts are reviewed and approved by the OEB annually. The probability of realizing such volume is contingent upon four key forecast variables: weather, economic conditions, pricing of competitive energy sources and growth in the number of customers. Over the life of the current IR agreement, the portion of fixed charges will increase annually thereby reducing this risk.

 

Weather is a significant driver of delivery volumes, given that a significant portion of EGD’s customer base uses natural gas for space heating. For the years ended December 31, 2010, 2009 and 2008, (warmer)/colder than normal weather resulted in a reduction to earnings of $12 million and an increase to earnings of $17 million and $23 million, respectively.

 

Distribution volume may also be impacted by the increased adoption of energy efficient technologies, along with more efficient building construction, that continues to place downward pressure on consumption. In addition, conservation efforts by customers further contribute to the decline in annual average consumption.

 

Sales and transportation of gas for customers in the residential and small commercial sectors account for approximately 80% (2009 – 81%; 2008 – 79%) of total distribution volume. Sales and transportation service to large volume commercial and industrial customers is more susceptible to prevailing economic conditions. As well, the pricing of competitive energy sources affects volume distributed to these sectors as some customers have the ability to switch to an alternate fuel. Customer additions are important to all market sectors as continued expansion adds to the total consumption of natural gas.

 

Even in those circumstances where EGD attains its total forecast distribution volume, it may not earn its expected ROE due to other forecast variables such as the mix between the higher margin residential and commercial sectors and the lower margin industrial sector.

 

This distribution volume risk for general service customers is mitigated by the average use true-up variance account that was established under the IR Framework. This variance account enables recovery from or repayment to customers of amounts representing variances in the actual and forecast average use by general service customers. EGD remains at risk of distribution volumes for large volume contract commercial and industrial customers.

 

OTHER GAS DISTRIBUTION AND STORAGE

 

Other Gas Distribution includes natural gas distribution utility operations in Quebec, and New Brunswick, the most significant being Enbridge Gas New Brunswick (EGNB) (100% owned and operated by the Company), which owns the natural gas distribution franchise in the province of New Brunswick. EGNB is constructing a new distribution system and has approximately 11,000 customers. Approximately 790 kilometres (490 miles) of distribution main has been installed with the capability of attaching approximately 30,000 customers.

 

 

 

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Results of Operations

Other Gas Distribution and Storage adjusted earnings were $32 million for the year ended December 31, 2010, compared with $25 million for the year ended December 31, 2009 and $18 million for the year ended December 31, 2008, primarily due to an increased contribution from Enbridge’s Ontario unregulated gas storage business and from franchise growth at EGNB.

 

EGNB is regulated by the New Brunswick Energy and Utilities Board (EUB). As it is currently in the development period, EGNB’s cost of service exceeds its distribution revenues. The EUB has approved the deferral of the shortfall between distribution revenues and the cost of service during the development period for recovery in future rates. The recovery period is expected to start in 2013 and end no sooner than December 31, 2040. On December 31, 2010, the regulatory deferral asset was $171 million (2009 – $155 million).

 

Other Gas Distribution and Storage earnings were impacted by the following non-recurring or non-operating adjusting items:

 

·

Earnings for 2009 reflected a $10 million asset impairment loss which included goodwill.

·

Other Gas Distribution and Storage reflected the write-off of $3 million in deferred development costs as a result of adopting a change in accounting standards, effective January 1, 2009.

 

Gas Pipelines, Processing and Energy Services

 

EARNINGS

 

 

2010

 

 

2009

 

2008

 

(millions of Canadian dollars)

 

 

 

 

 

 

 

Enbridge Offshore Pipelines (Offshore)

23

 

 

29

 

7

 

Alliance Pipeline US

25

 

 

27

 

25

 

Vector Pipeline

15

 

 

16

 

14

 

Aux Sable

37

 

 

26

 

28

 

Energy Services

20

 

 

29

 

17

 

Other

3

 

 

(11

)

50

 

Adjusted Earnings

123

 

 

116

 

141

 

Offshore – property insurance recoveries from hurricanes

2

 

 

4

 

 

Alliance Pipeline US – shipper claim settlement

 

 

 

2

 

Aux Sable – unrealized derivative fair value gains/(losses)

7

 

 

(36

)

56

 

Aux Sable – loan forgiveness

 

 

7

 

 

Energy Services – unrealized derivative fair value gains/(losses)

(12

)

 

3

 

23

 

Energy Services – Lehman and SemGroup credit recovery/(loss)

1

 

 

1

 

(6

)

Other – gain on sale of investments

 

 

329

 

561

 

Other – impact of tax rate changes

 

 

4

 

 

Other – asset impairment loss

 

 

 

(10

)

Earnings

121

 

 

428

 

767

 

 

Adjusted earnings from Gas Pipelines, Processing and Energy Services were $123 million for the year ended December 31, 2010 compared with $116 million for the year ended December 31, 2009, primarily resulting from contributions from Aux Sable and the Company’s green energy investments.

 

Adjusted earnings from Gas Pipelines, Processing and Energy Services were $116 million for the year ended December 31, 2009 compared with $141 million for the year ended December 31, 2008. The decreased adjusted earnings were substantially due to the sale of the Company’s International investments, offset by higher volumes within Offshore and favourable foreign exchange rates.

 

 

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Gas Pipelines, Processing and Energy Services earnings were impacted by the following non-recurring or non-operating adjusting items:

 

 

·

Offshore earnings included insurance proceeds related to the replacement of damaged infrastructure as a result of a 2008 hurricane.

·

Earnings for the year ended December 31, 2008 were impacted by $2 million in proceeds received by Alliance Pipeline US from the settlement of a claim against a former shipper which repudiated its capacity commitment.

·

Aux Sable earnings for each period reflected unrealized fair value changes on derivative financial instruments related to the Company’s forward gas processing risk management position.

·

Earnings for the year ended December 31, 2009 from Aux Sable reflected a $7 million gain from a loan forgiveness related to a negotiated settlement with a counterparty in bankruptcy proceedings.

·

Energy Services earnings for each period reflected unrealized fair value gains and losses related to the revaluation of inventory and the revaluation of financial derivatives used to risk manage the profitability of forward transportation and storage transactions.

·

Energy Services earnings for the year ended December 31, 2008 included a $6 million write-off as a result of bankruptcies by SemGroup and Lehman Brothers. In 2009, $1 million was recovered from SemGroup and in 2010 the Company received a partial recovery of $1 million from the sale of its receivable from Lehman Brothers.

·

In March 2009, the Company sold its investment in OCENSA, a crude oil export pipeline in Colombia, for proceeds of $512 million, resulting in a gain of $329 million. In June 2008, the Company sold its investment in CLH for proceeds of $1,380 million, resulting in a gain of $556 million. A $5 million gain on sale of investment in Inuvik Gas was also reflected in earnings from Other in 2008.

·

Other earnings for 2009 reflected the impact of $4 million in favourable tax rate changes.

·

An impairment loss arising from the write-off of goodwill related to the Company’s Ontario Wind power assets was included in Other earnings in 2008.

 

ENBRIDGE OFFSHORE PIPELINE

Offshore is comprised of 13 natural gas gathering and FERC-regulated transmission pipelines and one oil pipeline in five major corridors in the Gulf of Mexico, extending to deepwater frontiers. These pipelines include almost 1,500 miles (2,400 kilometres) of underwater pipe and onshore facilities and transported approximately 2.2 bcf/d during 2010. Offshore currently moves approximately 50% of offshore deepwater gas production through its systems in the Gulf of Mexico.

 

Transportation Contracts

The primary shippers on the Offshore systems are producers who execute life-of-lease commitments in connection with transmission and gathering service contracts. In exchange, Offshore provides firm capacity for the contract term at an agreed upon rate. The firm capacity made available generally reflects the lease’s maximum sustainable production. The transportation contracts allow the shippers to define a maximum daily quantity (MDQ), which corresponds with the expected production life. The contracts typically have minimum throughput volumes which are subject to take-or-pay criteria, but also provide the shippers with flexibility, subject to advance notice criteria, to modify the projected MDQ schedule to match current deliverability expectations.

 

 

 

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The long-term transport rates established in the gathering and transmission service agreements are generally market-based but are established using a cost of service methodology, which includes operating cost, projected revenue generation directly tied to production deliverability and the appropriate cost of capital.

 

The business model utilized on a go forward basis and included in the WRGGS and Big Foot commercially secured projects differs from the historic model. These new projects have a base level return which is locked in by take or pay commitments. If volumes reach producer anticipated levels the return on these projects will increase. In addition, Enbridge has minimal capital cost risk on these projects and commercial agreements continue to contain life-of-lease commitments.

 

 

Results of Operations

Adjusted earnings from Offshore for the year ended December 31, 2010 were $23 million compared with $29 million for the year ended December 31, 2009. The Company experienced volume declines due to the slower regulatory permitting process. In July 2010, the Secretary of the Interior suspended deepwater drilling. Subsequently, in October 2010, the deepwater drilling suspension was lifted, allowing a return to deepwater drilling, but subject to increased regulation and approval. Other factors contributing to the adjusted earnings decrease were higher operating and administrative costs, including insurance and higher depreciation expense.

 

Offshore adjusted earnings for the year ended December 31, 2009 were $29 million compared with $7 million for the year ended December 31, 2008. This increase was due to higher volumes, including contributions from Shenzi, since its in-service date in April 2009, and Thunder Horse, since its in-service date of June 2008, as well as favourable foreign exchange rates. Offshore adjusted earnings for 2009 included $4 million in insurance proceeds collected during the second and fourth quarters, which were partial reimbursement for business interruption lost revenues and operating expenses associated with Hurricane Ike in 2008.

 

Earnings for 2010 and 2009 included insurance proceeds of $2 million and $4 million, respectively, related to the replacement of damaged infrastructure as a result of the 2008 hurricane.

 

Business Risks

The risks identified below are specific to Offshore. General risks that affect the Company as a whole are described under Risk Management and Financial Instruments.

 

Weather

Adverse weather, such as hurricanes, may impact Offshore financial performance directly or indirectly. Direct impacts may include damage to Offshore facilities resulting in lower throughput, and in inspection and repair costs. Indirect impacts include damage to third party production platforms, onshore processing plants and pipelines that may decrease throughput on Offshore systems.

 

Reflecting improved insurance market pricing terms, effective June 2010, Offshore’s insurance policy now again includes coverage related to named windstorms, such as hurricanes, for all systems except for the Stingray Pipeline system. As a result of the change in coverage, physical damage caused by hurricanes will not impact Offshore’s financial performance to the extent it otherwise would. On June 1, 2009, Offshore had chosen to eliminate this coverage due to significant increases in insurance premiums and deductibles

 

 

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as a result of the hurricanes that had taken place in the Gulf in previous years. As part of a 2009 FERC rate case settlement, the Stingray Pipeline system implemented an event surcharge mechanism to allow recovery from shippers for hurricane damage.

 

Competition

 

There is competition for new and existing business in the Gulf of Mexico. Offshore has been able to capture key opportunities, positioning it to more fully utilize existing capacity. Offshore serves a majority of the strategically located deepwater host platforms and its extensive presence in the deepwater Gulf of Mexico has Offshore well positioned to generate incremental revenues, with modest capital investment, by transporting production from sub-sea development of smaller fields tied back to existing host platforms. Offshore is also able to construct pipelines to transport crude oil, diversifying the risk of declining gas production, as demonstrated with the Neptune crude oil lateral and the recently announced Big Foot Oil Pipeline. Given rates of decline, offshore pipelines typically have available capacity, resulting in significant competition for new developments in the Gulf of Mexico.

 

Regulation

 

The transportation rates on many of Offshore’s transmission pipelines are generally based on a regulated cost of service methodology and are subject to regulation by the FERC. These rates are subject to challenge from time-to-time.

 

The Gulf of Mexico events of 2010 have altered the offshore regulatory environment. Although the moratorium on deepwater drilling was lifted, future deepwater drilling activity will be subject to heightened regulation and oversight. Increased regulation may impact the levels and timing of future exploration and drilling activity in the region and the resultant production volumes available to ship on the Company’s offshore system. The shifting business environment could result in increases in available capacity, resulting in heightened competition.

 

Other Risks

 

Other risks directly impacting financial performance include underperformance relative to expected reservoir production rates, delays in project start-up timing, changes in plans by shippers and capital expenditures in excess of those estimated. Capital risk is mitigated in some circumstances by having area producers as joint venture partners, through cost of service tolling arrangements and pre-arranged terms in commercial agreements. Start-up delays are mitigated by the right to collect stand-by fees.

 

ALLIANCE PIPELINE US

 

The Alliance System (Alliance), which includes both the Canadian and United States portions of the pipeline system, consists of an approximately 3,000-kilometre (1,875-mile) integrated, high-pressure natural gas transmission pipeline system and an approximately 730-kilometre (455-mile) lateral pipeline system and related infrastructure. Alliance transports liquids-rich natural gas from northeast British Columbia and northwest Alberta to Channahon, Illinois. Alliance Pipeline US and Alliance Pipeline Canada have firm service shipping contract capacity to deliver 1.365 bcf/d and 1.325 bcf/d, respectively. Enbridge owns 50% of Alliance Pipeline US, while EIF, described under Sponsored Investments, owns 50% of Alliance Pipeline Canada.

 

Alliance connects with Aux Sable, of which Enbridge owns 42.7%, a NGLs extraction and fractionation facility in Channahon, Illinois. The natural gas may then be transported to two local natural gas distribution systems in the Chicago area and five interstate natural gas pipelines, providing shippers with access to natural gas markets in the midwestern and northeastern United States and eastern Canada.

 

In September 2010, the Septimus Pipeline, a gathering pipeline owned by Aux Sable, was connected to a new receipt point on Alliance Pipeline Canada. This pipeline, with initial volumes of 20 million cubic feet per day (mmcf/d), sources liquids-rich gas from the Montney region. In 2009, Prairie Rose Pipeline, a gathering pipeline owned by a third party, was connected to a new gas receipt point on Alliance near Towner, North

 

 

 

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Dakota. This pipeline brings in associated rich gas from the Bakken formation on to Alliance. The new receipt point went into service in January 2010, with an initial firm transportation capacity of 40 mmcf/d, which will increase to 80 mmcf/d in 2011.

 

Transportation Contracts

 

Alliance Pipeline US has long-term, take-or-pay contracts to transport 1.345 bcf/d of natural gas or 98.5% of the total contracted capacity. Primary contract terms ending on December 1, 2015 are for 1.305 bcf/d, while contracts for 0.040 bcf/d have a contract term ending February 1, 2020. Alliance Pipeline US has an additional 20 mmcf/d of natural gas which is currently being contracted on a short term basis. These contracts permit Alliance to recover the cost of service, which includes operating and maintenance costs, the cost of financing, an allowance for income tax, an annual allowance for depreciation and an allowed ROE of 10.88%. Each long-term contract had the option of being renewed upon notice by November 30, 2010 for successive one-year terms beyond the original 15-year primary term. As noted below, shippers representing 8% of contracted capacity elected to extend their commitments. Alliance Pipeline US operations are regulated by the FERC.

 

Depreciation expense included in the cost of service is based on negotiated depreciation rates contained in the transportation contracts, while depreciation expense in the financial statements is recorded on a straight-line basis at 4% per annum. Negotiated depreciation expense is generally less than the financial statement amount at the beginning of the contract and higher than straight-line depreciation in the later years of the shipper transportation agreements. This difference results in recognition of a long-term receivable, referred to as deferred transportation revenue, that began being recovered from shippers, starting in 2009 for Alliance Pipeline US and 2012 for Alliance Pipeline Canada. As at December 31, 2010, $122 million (US$123 million) (2009 - $151 million (US$144 million)) was recorded as deferred transportation revenue for Alliance Pipeline US.

 

Alliance Pipeline Recontracting

 

In December 2010, shippers representing 8% of contracted capacity on the Alliance System elected to extend their existing contracts from December 1, 2015 to at least December 1, 2016. These shippers also retained the option of continuing to extend their capacity commitments on an annual basis. Remaining shippers, representing the balance of originally contracted capacity, have elected not to extend their commitments beyond 2015 under the terms of the original contracts. Alliance Pipeline US is entitled to additional compensation, in the form of accelerated depreciation recovered, from those shippers who have not elected to extend their contracts beyond 2015.

 

Currently, Alliance continues to be fully contracted on a firm service basis and is expected to run at or near full capacity for the foreseeable future given its geographic positioning and high pressure operating capability to move valuable liquids rich gas to market. Over the next five years, Alliance is expected to transition from a single-service, single toll export pipeline to a new multi-service business model, providing customers with a choice from an assortment of transportation services. Among other things, Alliance will seek to implement short-haul delivery and receipt services to complement its existing “bullet line” delivery service to Chicago and seek to provide greater shipper market liquidity through hub services. Also, Alliance is well placed to benefit from incremental unconventional volumes from shale gas plays in British Columbia, and is currently evaluating opportunities to expand its service offerings in this area. Rates for Alliance’s long haul service are expected to be favourable compared to other alternatives for reaching United States Midwest and eastern Canada markets.

 

 

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Results of Operations

 

Alliance Pipeline US adjusted earnings were $25 million for the year ended December 31, 2010, comparable with $27 million for the year ended December 31, 2009 and $25 million for the year ended December 31, 2008.

 

Earnings for the year ended December 31, 2008 included $2 million in proceeds received from the settlement of a claim against a former shipper which repudiated its capacity commitment.

 

VECTOR PIPELINE

 

The Company provides operating services to, and holds a 60% joint venture interest in, Vector Pipeline, which transports natural gas from Chicago, Illinois to Dawn, Ontario. Vector Pipeline has the capacity to deliver a nominal 1.3 bcf/d and is operating at or near capacity.

 

 

Vector Pipeline’s primary sources of supply are through interconnections with Alliance and the Northern Border Pipeline in Joliet, Illinois. The total long haul capacity of Vector is approximately 87% committed through 2015. Approximately 55% of the long haul capacity is committed through firm transportation contracts at rates negotiated with the shippers and approved by the FERC; with the remaining capacity sold at market rates. Transportation service is provided through a number of different forms of service agreements such as Firm Transportation Service and Interruptible Transportation Service. Vector Pipeline is an interstate natural gas pipeline with FERC and NEB approved tariffs establishing rates, terms and conditions governing its service to customers. On the United States portion of Vector, tariff rates are determined using a cost of service methodology and tariff changes may only be implemented upon approval by the FERC. For 2010, the FERC approved maximum tariff rates include an underlying weighted average after-tax ROE component of 11.18% (2009 - 11.07%; 2008 - 11.04%). On the Canadian portion, Vector Pipeline is required to file its negotiated tolls calculation with the NEB on an annual basis. Tolls are calculated on a levelized basis that include a rate of return incentive mechanism based on construction costs and are subject to a rate cap. In 2010, maximum tariff tolls include a ROE component of 10.48% after-tax.

 

Results of Operations

 

Vector Pipeline earnings were $15 million for the year ended December 31, 2010, comparable with $16 million for the year ended December 31, 2009 and $14 million for the year ended December 31, 2008.

 

Business Risks

 

The risks identified below are specific to both Alliance Pipeline US and Vector Pipeline. General risks that affect the entire Company are described under Risk Management and Financial Instruments.

 

 

 

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Supply and Demand

Currently, pipeline capacity out of the WCSB exceeds supply. Alliance Pipeline US and Vector Pipeline have been unaffected by this excess capacity environment mainly because of long-term capacity contracts extending primarily to 2015. Alliance Pipeline US is also well positioned to deliver incremental liquids-rich gas production from new developments in the Montney and Bakken regions. Vector Pipeline’s interruptible capacity could be negatively impacted by the basis (location) differential in the price of natural gas between Chicago and Dawn, Ontario relative to the transportation toll. Demand is supported by rising use of gas for power generation.

 

Exposure to Shippers

The failure of shippers to perform their contractual obligations could have an adverse effect on the cash flows and financial condition of Alliance Pipeline US and Vector Pipeline. To reduce this risk, Alliance Pipeline US and Vector Pipeline monitor the creditworthiness of each shipper and receive collateral for future shipping tolls should a shipper’s credit position not meet tariff requirements. These pipelines also have diverse groups of long-term transportation shippers, which include various gas and energy distribution companies, producers and marketing companies, further reducing the exposure.

 

 

Competition

 

Alliance Pipeline US faces competition for pipeline transportation services to the Chicago area from both existing and proposed pipeline projects. Competing pipelines provide natural gas transportation services from the WCSB to distribution systems in the Midwestern United States. In addition, there are several proposals to upgrade existing pipelines serving these markets. Any new or upgraded pipelines could either allow shippers greater access to natural gas markets or offer natural gas transportation services that are more desirable than those provided by Alliance. Shippers on Alliance Pipeline US have access to additional high compression delivery capacity at no additional cost, other than fuel requirements, serving to enhance the competitive position of Alliance Pipeline US.

 

Vector Pipeline faces competition for pipeline transportation services to its delivery points from new supply sources and traditional low cost pipelines, which could offer transportation that is more desirable to shippers because of cost, supply location, facilities or other factors. Vector Pipeline has mitigated this risk by entering into long-term firm transportation contracts, which expire starting in November 2015, for approximately 87% of its capacity. The remaining contracts expire at various times starting in April 2012. Certain long-term firm contracts (55% of capacity) provide for additional compensation to Vector Pipeline if shippers do not extend their contracts beyond the initial term ending November 2015. The effectiveness of these mitigating factors is evidenced by the increased utilization of the pipeline since its construction, despite the presence of transportation alternatives.

 

Regulation

 

Both the US portion of Vector Pipeline and Alliance Pipeline US operations are regulated by the FERC. On a yearly basis, following consultation with shippers, Alliance Pipeline US files its annual rates with the FERC for approval.

 

FERC has intensified its oversight of financial reporting, risk standards and affiliate rules and has issued new standards on managing gas pipeline integrity. The Company continues ongoing dialogue with regulatory agencies and participates in industry lobby groups to ensure it is informed of emerging issues in a timely manner.

 

 

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AUX SABLE

 

Enbridge owns 42.7% of Aux Sable, a NGLs extraction and fractionation business, which owns and operates a plant near Chicago, Illinois at the terminus of Alliance Pipeline. The plant extracts NGLs from the liquids-rich natural gas transported on Alliance, as necessary to meet gas quality specifications of downstream transmission and distribution companies and to take advantage of positive commodity price spreads.

 

Aux Sable sells its NGLs production to BP under a long-term contract. BP pays Aux Sable a fixed annual fee and a share of any net margin generated from the business in excess of specified natural gas processing margin thresholds (the upside sharing mechanism). In addition, BP compensates Aux Sable for all operating, maintenance and capital costs associated with the Aux Sable facilities subject to certain limits on capital costs. BP supplies, at its cost, all make-up gas and fuel gas requirements of the Aux Sable plant and is responsible for the capacity on the Alliance Pipeline, held by an Aux Sable affiliate, at market rates. The BP agreement is for an initial term of 20 years, expiring December 21, 2025 and may be extended by mutual agreement for 10-year terms.

 

Results of Operations

 

Aux Sable adjusted earnings increased from $26 million in 2009 to $37 million in 2010 primarily due to enhanced plant performance and stronger fractionation margins.

 

Adjusted earnings for the year ended December 31, 2009 were $26 million compared with earnings of $28 million for the year ended December 31, 2008. Aux Sable adjusted earnings decreased due to unexpected plant outages during the fourth quarter of 2009.

 

Aux Sable earnings reflected the following non-recurring or non-operating adjusting items:

 

·

Earnings for each period reflected unrealized fair value changes on derivative financial instruments related to the Company’s forward gas processing risk management position.

·

Earnings for 2009 included a $7 million gain from a loan forgiveness related to a negotiated settlement with a counterparty in bankruptcy proceedings.

 

ENERGY SERVICES

 

Energy Services includes the Company’s energy marketing businesses. Tidal Energy provides crude oil and NGLs marketing services for the Company and its customers. This business involves buying, selling, transporting and storing crude oil and condensate. Tidal Energy transacts at many North American market hubs and provides its customers with various services, including transportation, storage, supply management, flexible pricing, hedging programs and product exchanges. Tidal Energy is primarily a physical barrel marketing company and in the course of its market activities can create modest commodity exposures. Any residual open positions created from this physical business are closely monitored and must comply with the Company’s formal risk management policies.

 

Energy Services’ natural gas marketing services are provided by both Tidal Energy and Gas Services. Tidal Energy markets natural gas to optimize Enbridge’s commitments on the Alliance and Vector pipelines. Capacity commitments at December 31, 2010 and 2009 were 33 mmcf/d on Alliance (3% of capacity) and 156 mmcf/d on Vector Pipeline (12% of capacity). Earnings from these commitments are dependent upon the basis (location) differentials between Alberta and Chicago, for Alliance, and between Chicago and Dawn, for Vector Pipeline. To the extent transportation costs exceed the basis (location) differential, earnings will be negatively affected. Tidal Energy also provides fee-for-service arrangements for third parties, leveraging its natural gas marketing expertise and access to transportation capacity. Gas Services markets natural gas to commercial and industrial customers in the upper mid-west area of the United States.

 

 

 

MANAGEMENT’S DISCUSSION AND ANALYSIS

73

 

 



 

Results of Operations

Energy Services adjusted earnings decreased to $20 million for the year ended December 31, 2010 from $29 million in 2009 as a result of reduced volume and margin opportunities in liquids marketing.

 

Adjusted earnings from Energy Services increased from $17 million in 2008 to $29 million in 2009. The increase was due to higher volumes and the impact of realizing favourable storage and transportation margins.

 

Energy Services earnings were impacted by the following non-recurring or non-operating adjusting items:

 

·

Earnings for each period reflect unrealized fair value gains and losses related to the revaluation of inventory and the revaluation of financial derivatives used to risk manage the profitability of forward transportation and storage transactions.

·

Earnings in 2008 included a $6 million receivable write-off related to SemGroup and Lehman Brothers bankruptcies. In 2009, $1 million was recovered from SemGroup and, in 2010 the Company received a partial recovery of $1 million from the sale of its receivable from Lehman Brothers.

 

OTHER

Other includes operating results from the Company’s investments in green energy projects, including Ontario Wind and Sarnia Solar, net of business development expenses associated with international activities.

 

In 2009, the Company sold its 24.7% interest in OCENSA, a crude oil export pipeline in Colombia. In 2008, the Company sold its 25% equity interest in CLH, Spain’s largest refined products transportation and storage business. Both of these investments were sold at very attractive prices and proceeds were utilized in the funding of the North American expansion projects discussed earlier. There are currently minimal operations in International; however, Enbridge continues to actively monitor the international business environment to identify potential new investment opportunities.

 

Results of Operations

For the year ended December 31, 2010, Other adjusted earnings were $3 million compared with an adjusted loss of $11 million for the year ended December 31, 2009 primarily reflecting positive contributions from the Sarnia Solar Project and reduced business development costs.

 

Other adjusted earnings decreased from $50 million in 2008 to an adjusted loss of $11 million in 2009 primarily resulting from the sale of OCENSA and CLH and higher business development expenditures.

 

Other earnings were impacted by the following non-recurring or non-operating adjusting items:

 

·

In March 2009, the Company sold its investment in OCENSA for proceeds of $512 million, resulting in a gain of $329 million. In June 2008, the Company sold its investment in CLH for proceeds of $1,380 million, resulting in a gain of $556 million. A $5 million gain on the sale of investment in Inuvik Gas was also reflected in earnings in 2008.

·

Other earnings for 2009 reflected the impact of $4 million in favourable tax rate changes.

·

An impairment loss arising from the write-off of goodwill related to the Company’s Ontario Wind power assets was included in earnings in 2008.

 

 

74

 

ENBRIDGE INC. 2010 ANNUAL REPORT

 

 



 

Sponsored Investments

 

EARNINGS

 

 

2010

 

 

2009

 

2008

 

(millions of Canadian dollars)

 

 

 

 

 

 

 

 

Enbridge Energy Partners (EEP)

 

122

 

 

99

 

60

 

Enbridge Energy, L.P. – Alberta Clipper US (EELP)

 

42

 

 

7

 

 

Enbridge Income Fund (EIF)

 

45

 

 

45

 

41

 

Adjusted Earnings

 

209

 

 

151

 

101

 

EEP – leak remediation costs and lost revenue

 

(106

)

 

 

 

EEP – unrealized derivative fair value gains/(losses)

 

(1

)

 

(2

)

6

 

EEP – Lakehead System billing correction

 

1

 

 

4

 

 

EEP – dilution gain on Class A unit issuance

 

36

 

 

 

5

 

EEP – asset impairment loss

 

(2

)

 

(12

)

 

EEP – impact of 2008 hurricanes and project write-offs

 

 

 

 

(2

)

EIF – Alliance Canada shipper claim settlement

 

 

 

 

1

 

Earnings

 

137

 

 

141

 

111

 

 

Adjusted earnings from Sponsored Investments were $209 million for the year ended December 31, 2010 compared with $151 million in 2009 and $101 million in 2008. The increase in adjusted earnings resulted primarily from increased contributions from EEP as a result of positive operating factors, including growth projects, as well as the Company’s investment in EELP.

 

Sponsored Investments earnings were impacted by several non-recurring or non-operating adjusting items:

 

·      Earnings from EEP included a charge of $103 million (net to Enbridge) related to estimated costs, before insurance recoveries, associated with the Line 6B and Line 6A crude oil releases as well as an impact of $3 million (net to Enbridge) related to period lost revenue as a result of the leaks.

See EEP Lakehead System Line 6B and 6A Crude Oil Releases.

·      Earnings from EEP included a change in the unrealized fair value on derivative financial instruments in each year.

·      Earnings from EEP included Lakehead System billing corrections (net to Enbridge) related to services provided in prior periods.

·      EEP earnings were favourably impacted by a $36 million (2008 - $5 million) dilution gain (after-tax and non-controlling interest) because Enbridge did not participate in EEP’s Class A unit offerings.

·      EEP earnings for 2010 and 2009 included charges related to asset impairment losses.

·      2008 earnings from EEP included non-routine costs associated with Hurricanes Gustav and Ike, of which Enbridge’s share was $2 million, as well as the write-off of costs on certain projects cancelled due to market conditions.

·      Earnings from EIF for the year ended December 31, 2008 included proceeds of $1 million from the settlement of a claim against a former shipper on Alliance Canada which repudiated its capacity commitment.

 

 

 

MANAGEMENT’S DISCUSSION AND ANALYSIS

75

 

 



 

ENBRIDGE ENERGY PARTNERS

 

EEP owns and operates crude oil and liquid petroleum transportation and storage assets and natural gas gathering, treating, processing, transportation and marketing assets in the United States. Significant assets include the Lakehead System, which is the extension of the Enbridge System in the United States; the Mid-Continent crude oil system consisting of an interstate crude oil pipeline and storage facilities; a crude oil gathering system and interstate pipeline system in North Dakota; and natural gas assets located primarily in Texas.

 

In September 2010, EEP acquired the entities that comprise the Elk City Gathering and Processing System (Elk City System) from Atlas Pipeline Partners for US$700 million. The Elk City System extends from southwestern Oklahoma to Hemphill County in the Texas Panhandle. The Elk City System consists of approximately 1,290 kilometers (800 miles) of natural gas gathering and transportation pipelines, one carbon dioxide treating plant and three cryogenic processing plants with a total capacity of 370 mmcf/d and a combined natural gas liquids production capability of 20,000 bpd.

 

In March 2008, Enbridge did not participate in EEP’s issuance of Class A units, resulting in a $5 million dilution gain and a decrease in ownership interest from 15.1% to 14.6%. In late 2008, Enbridge purchased 16.3 million Class A common units of EEP, resulting in an ownership increase to 27.0%. The Company’s average ownership interest in EEP during 2008 was 15.7%. At December 31, 2009, Enbridge’s ownership interest in EEP remained at 27.0%. In June 2010, EEP entered into an Equity Distribution Agreement (EDA) for the issue and sale of its Class A units up to an amount of $150 million. During 2010, EEP issued 1.1 million Class A units under the EDA. Enbridge did not fully participate resulting in a dilution gain of $4 million. In November 2010, Enbridge did not participate in EEP’s issuance of 6 million Class A units, resulting in a $32 million dilution gain and decreasing the Company’s ownership to 25.5%. The Company’s average ownership interest in EEP during 2010 was 26.7%.

 

Distributions

 

EEP makes quarterly distributions of its available cash to its common unitholders. Under the Partnership Agreement, Enbridge Energy Company, Inc. (EECI), a wholly owned subsidiary of Enbridge, as general partner (GP), receives incremental incentive cash distributions, which represent incentive income, on the portion of cash distributions, on a per unit basis, that exceed certain target thresholds as follows:

 

 

 

Unitholders

 

 

 

 

 

including Enbridge

 

GP Interest

 

Quarterly Cash Distributions per Unit:

 

 

 

 

 

Up to $0.59 per unit

 

98%

 

2%

 

First target – $0.59 per unit up to $0.70 per unit

 

85%

 

15%

 

Second target – $0.70 per unit up to $0.99 per unit

 

75%

 

25%

 

Over second target – cash distributions greater than $0.99 per unit

 

50%

 

50%

 

 

 

76

 

ENBRIDGE INC. 2010 ANNUAL REPORT

 

 



 

In the first two quarters of 2008 EEP paid quarterly distributions of $0.95 per unit, and effective August 2008, EEP increased quarterly distributions to $0.99 per unit, which remained in effect through the first quarter of 2010. Effective April 2010, EEP increased the quarterly distributions to $1.0025 per unit. In July 2010, EEP further increased the quarterly distributions to $1.0275 per unit. Of the $122 million Enbridge recognized as adjusted earnings from EEP during 2010, 27% (2009 – 27%; 2008 – 37%) were GP incentive earnings while 73% (2009 – 73%; 2008 – 63%) were Enbridge’s limited partner share of EEP’s earnings.

 

In spite of the challenges posed by the crude oil releases on EEP’s Lakehead System, EEP believes it has sufficient liquidity to fund operating activities and environmental remediation obligations while maintaining its present distribution rate to EEP unitholders.

 

Results of Operations

After adjusting EEP earnings for non-recurring or non-operating items, including the impact of the Line 6B and Line 6A crude oil releases, EEP adjusted earnings increased to $122 million for the year ended December 31, 2010 compared with $99 million for the year ended December 31, 2009. The increase was largely attributable to strong results from the liquids business as well as higher incentive income. The liquids improvement was generated largely from higher delivered volumes and increased average transportation rates, partially offset by increased operating costs.

 

Adjusted earnings from EEP were $99 million for the year ended December 31, 2009 compared with $60 million for the year ended December 31, 2008. EEP adjusted earnings increased due to the Company’s higher ownership interest in EEP resulting from the December 2008 Class A unit subscription; an increased contribution due to additional assets placed in service and related tariff surcharges for recent expansions; higher incentive income; and a more favourable foreign exchange rate used to translate EEP’s earnings to Canadian dollars.

 

EEP earnings were impacted by several non-recurring or non-operating adjusting items:

 

·

Earnings from EEP included a charge of $103 million (net to Enbridge) related to estimated costs, before insurance recoveries, associated with the Line 6B and Line 6A crude oil releases as well as an impact of $3 million (net to Enbridge) related to period lost revenue as a result of the leaks. See EEP Lakehead System Line 6B and 6A Crude Oil Releases.

·

Earnings included a change in the unrealized fair value on derivative financial instruments in each year.

·

Earnings from EEP included Lakehead System billing corrections (net to Enbridge) related to services provided in prior periods.

·

EEP earnings were favourably impacted by a dilution gain because Enbridge did not participate in EEP’s Class A unit offerings.

·

EEP earnings for 2010 and 2009 included charges related to asset impairment losses.

·

2008 earnings from EEP included non-routine costs associated with Hurricanes Gustav and Ike, of which Enbridge’s share was $2 million, as well as the write-off of costs on certain projects cancelled due to market conditions.

 

EEP Lakehead System Line 6B and 6A Crude Oil Releases

Enbridge holds an approximate 25.5% combined direct and indirect ownership interest in EEP, which is accounted for as an equity investment. Subsidiaries of Enbridge provide services to EEP in connection with its operation of the Lakehead System.

 

 

 

MANAGEMENT’S DISCUSSION AND ANALYSIS

77

 

 



 

Line 6B Leak

 

On July 26, 2010, a crude oil release on Line 6B of EEP’s Lakehead System was reported near Marshall, Michigan. EEP currently estimates that approximately 20,000 barrels of crude oil were leaked at the site, a portion of which reached the Talmadge Creek, a waterway that feeds the Kalamazoo River. The pipelines in the vicinity were shut down, appropriate United States federal, state and local officials were notified, and emergency response crews were dispatched to oversee containment of the released crude oil and cleanup of the affected areas. Regulatory approval of the pipeline restart plan was obtained from the United States Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (PHMSA) and, on September 27, 2010, the pipeline was safely brought back into service. The cause of the release remains the subject of an investigation by the National Transportation Safety Board and other United States federal and state regulatory agencies.

 

EEP previously estimated that before insurance recoveries, and not including fines and penalties, costs of approximately US$430 million ($75 million after-tax net to Enbridge), excluding lost revenue of approximately US$13 million ($2 million after-tax net to Enbridge), will be incurred in connection with this incident. These costs include emergency response, environmental remediation and cleanup activities associated with the crude oil release. EEP subsequently revised its estimate from US$430 million to US$550 million ($96 million after-tax net to Enbridge) based on a review of costs and commitments incurred, as well as additional information concerning the requirements for environmental restoration and remediation. The assumptions made including the scope of remediation efforts, the duration that resources will be required to complete the work, weather conditions and other similar factors underlying EEP’s estimates are subject to further modification and could result in additional revisions to EEP’s estimates. Although EEP met the deadlines established by the Environmental Protection Agency (EPA) for clean up and remediation of areas affected by the crude oil release, it has the potential of incurring additional costs in connection with this incident, including fines and penalties.

 

Line 6A Leak

 

A crude oil release from Line 6A of EEP’s Lakehead System was reported in an industrial area of Romeoville, Illinois on September 9, 2010. The pipeline in the vicinity was immediately shut down and emergency response crews were dispatched to oversee containment, cleanup and replacement of the pipeline segment. EEP estimated approximately 9,000 barrels of crude oil were released, of which approximately 1,400 barrels were removed from the pipeline as part of the repair. Excavation and replacement of the pipeline segment were completed and the pipeline was returned to service on September 17, 2010. The cause of the crude oil release remains subject to investigation by United States federal and state environmental and pipeline safety regulators.

 

EEP currently estimates that before insurance recoveries, and not including fines and penalties, costs for emergency response, environmental remediation and cleanup activities associated with the Line 6A crude oil release will be approximately US$45 million ($7 million after-tax net to Enbridge), excluding lost revenue of approximately US$3 million ($1 million after-tax net to Enbridge). Actual costs incurred may differ from the estimate due to variations in assumptions or in any or all of the categories described above, including modified or revised requirements from regulatory agencies or other factors.

 

Insurance Recoveries

 

The Company maintains commercial liability insurance coverage that is consistent with coverage considered customary for its industry. The commercial liability insurance covers costs associated with environmental incidents such as those incurred for the leaks from Line 6B and 6A, excluding costs for fines and penalties. EEP is included in Enbridge’s comprehensive insurance program that has an aggregate limit of US$650 million of pollution liability through the policy renewal date of May 1, 2011. The remaining coverage under the Company’s existing insurance policies is approximately US$70 million. The Company does not maintain insurance coverage for interruption of operations except for water crossings; therefore, EEP will not recover approximately US$16 million of revenues lost while Line 6B and 6A were not in service.

 

 

78

 

ENBRIDGE INC. 2010 ANNUAL REPORT

 

 



 

Apart from the amounts for which EEP is not insured, it is anticipated that substantially all of the costs incurred from the leaks will ultimately be recoverable under the Company’s existing insurance policies. EEP expects to record a receivable for any amounts claimed for recovery pursuant to its insurance policies during the period that it deems realization of the claim for recovery is probable.

 

Pipeline Integrity Commitment

 

In connection with the restart of Line 6B, EEP committed to accelerate a process, initiated prior to the leak, to perform additional inspections, testing and refurbishment of Line 6B within and beyond the immediate area of the July 26, 2010 incident. Pursuant to this agreement, EEP is remediating on schedule those pipeline anomalies it previously identified between 2007 and 2009 that were scheduled for refurbishment, including anomalies identified for action in a July 2010 PHMSA notification. EEP has agreed to complete all required work within 180 days of the September 27, 2010 restart of Line 6B. In addition to the required integrity measures, EEP also agreed to replace a 3,600 foot section of the Line 6B pipeline that lies underneath the St. Clair River in Michigan within one year of the restart of Line 6B, subject to obtaining required permits. The total cost to EEP for these integrity measures and pipeline replacement are estimated to approximate US$110 million, the majority of which is expected to be capital in nature. Additional significant integrity expenditures may be required after this initial remediation program. EEP is currently discussing with its customers recovery of these costs through the tolls on its Lakehead System.

 

Legal and Regulatory Proceedings

 

A number of United States governmental agencies and regulators have initiated investigations into the Line 6B and Line 6A incidents. Currently, approximately 20 actions or claims have been filed against Enbridge, EEP or their affiliates in United States federal and state courts in connection with the Line 6B incident; however, currently no penalties or fines have been assessed against EEP in connection with this incident. Currently, one action or claim related to the Line 6A incident has been filed against Enbridge, EEP or their affiliates in a United States state court. The Company believes this action or claim has been resolved pursuant to an agreed interim order.

 

ENBRIDGE ENERGY, L.P. – ALBERTA CLIPPER US

 

In July 2009, the Company committed to fund 66.7% of the cost to construct the United States segment of the Alberta Clipper Project. The Company funded 66.7% of the project’s equity requirements through EELP, while 66.7% of the debt funding was made through EEP. EELP – Alberta Clipper US earnings are the Company’s earnings from its investment in EELP which undertook the project and represented AEDC recognized while the project was under construction. The Alberta Clipper Project was placed into service on April 1, 2010.

 

Results of Operations

 

Adjusted earnings from EELP – Alberta Clipper US were $42 million for the year ended December 31, 2010 compared with $7 million for the year ended December 31, 2009. These earnings represent the Company’s earnings from its 66.7% investment in a series of equity within EELP which owns the United States segment of Alberta Clipper. Earnings were attributable to AEDC recognized while the project was under construction as well as tolls since Alberta Clipper went into service on April 1, 2010.

 

Business Risks

 

The risks identified below are specific to EEP and EELP. General risks that affect the Company as a whole are described under Risk Management and Financial Instruments.

 

 

 

MANAGEMENT’S DISCUSSION AND ANALYSIS

79

 

 



 

Competition

 

EEP’s Lakehead System, the United States portion of the Enbridge System, is a major crude oil export route from the WCSB. Other existing competing carriers and pipeline proposals to ship western Canadian liquids hydrocarbons to markets in the United States represent competition for the Lakehead System. Further details on such competing projects are described within Business Risks under Liquids Pipelines. EEP’s Mid-Continent system and North Dakota system also face competition from existing competing pipelines, proposed future pipelines, and alternative gathering facilities available to producers or the ability of the producers to build such gathering facilities. Competition for EEP’s storage facilities include large integrated oil companies and other midstream energy partnerships.

 

Other interstate and intrastate natural gas pipelines or their affiliates and other midstream businesses that gather, treat, process and market natural gas or NGLs represent competition to EEP’s natural gas segment. The level of competition varies depending on the location of the gathering, treating and processing facilities. However, most natural gas producers and owners have alternate gathering, treating and processing facilities available to them, including competitors that are substantially larger than EEP.

 

Supply and Demand

 

The profitability of EEP depends to some extent on the volume of products transported on its pipeline systems. The volume of shipments on EEP’s Lakehead System depends primarily on the supply of western Canadian crude oil and the demand for crude oil in the Great Lakes and Midwest regions of the United States and eastern Canada.

 

EEP’s natural gas gathering assets are also subject to changes in supply and demand for natural gas, NGLs and related products. Commodity prices impact the willingness of natural gas producers to invest in additional infrastructure to produce natural gas. These assets are also subject to competitive pressures from third-party and producer-owned gathering systems.

 

Volume Risk

 

A decrease in volumes transported by EEP’s systems can directly and adversely affect revenues and results of operations. A decline in volumes transported can be influenced by factors beyond EEP’s control including: competition, regulatory action, weather, storage levels, alternative energy sources, decreased demand, fluctuations in commodity prices, economic conditions, supply disruptions, availability of supply connected to the systems and adequacy of infrastructure to move supply into and out of the systems.

 

Regulation

 

In the United States, the interstate oil pipelines owned and operated by EEP and certain activities of EEP’s intrastate natural gas pipelines are subject to regulation by the FERC or state regulators and its revenues could decrease if tariff rates were protested. While gas gathering pipelines are not currently subject to active rate regulation, proposals to more actively regulate intrastate gathering pipelines are currently being considered in certain of the states in which EEP operates. In addition, the FERC has also taken an interest in regulating gas gathering systems that connect into interstate pipelines.

 

Market Price Risk

 

EEP’s gas processing business is subject to commodity price risk for natural gas and NGLs. These risks have been managed by using physical and financial contracts, fixing the prices of natural gas and NGLs.  Certain of these financial contracts do not qualify for cash flow hedge accounting and EEP’s earnings are exposed to associated mark-to-market valuation changes.

 

 

80

 

ENBRIDGE INC. 2010 ANNUAL REPORT

 

 



 

ENBRIDGE INCOME FUND

 

EIF’s primary assets include a 50% interest in Alliance Pipeline Canada and the 100%-owned Saskatchewan System, both acquired from the Company in 2003. Alliance Pipeline Canada is the Canadian portion of Alliance previously described in the Gas Pipelines, Processing and Energy Services segment. The Saskatchewan System owns and operates crude oil and liquids pipelines systems in southern Saskatchewan and southwestern Manitoba, connecting primarily with Enbridge’s mainline pipeline to the United States. In December 2010, Phase II of the Saskatchewan System Capacity Expansion was completed, increasing capacity across the system by approximately 125,000 bpd.

 

 

EIF also owns interests in three wind power generation projects purchased from Enbridge in October 2006 and a business that operates waste-heat power generation projects at Alliance Pipeline Canada compressor stations.

 

Corporate Restructuring

 

On December 17, 2010, a plan of arrangement (the Plan) to restructure EIF took effect. Under the Plan all publicly held trust units and 5 million units held by Enbridge, were exchanged on a one-for-one basis for shares of a taxable Canadian corporation, EIFH. The business of EIFH is limited to investment in EIF.  In connection with this exchange, Enbridge as holder of Enbridge Commercial Trust (ECT) Preferred Units was granted a right of exchange whereby Enbridge may exchange such ECT Preferred Units for EIF Trust Units on a one-for-one basis. Concurrently, the liquidity right which provided Enbridge as the holder of ECT Preferred Units the option to request redemption was terminated.

 

The Company retained its overall 72% economic interest in EIF and is the primary beneficiary of EIF both before and after the Plan through a combined direct and indirect investment in EIF voting units and a non-voting preferred unit investment. As such, Enbridge consolidates EIF under variable interest entity accounting rules.

 

Incentive and Management Fees

 

Enbridge receives a base annual management fee for management services provided to EIF, plus incentive fees. Incentive fees paid to Enbridge prior to the December 17, 2010 restructuring of EIF were equal to 25% of annual cash distributions over $0.825 per unit. Following the restructuring of EIF, the incentive fee payable per the Management Agreement was modified to approximate the incentive fee calculation prior to the restructuring. In 2010, the Company received incentive fees of $8 million (2009 – $8 million; 2008 – $5 million) before income taxes.

 

Enbridge also provides management services to EIFH. No additional fee will be charged to EIFH for these services.

 

 

 

MANAGEMENT’S DISCUSSION AND ANALYSIS

81

 

 



 

Results of Operations

 

Adjusted earnings from EIF were $45 million for both the year ended December 31, 2010 and 2009. Adjusted earnings from EIF reflected growth attributable to Phase II of the Saskatchewan System Capacity Expansion, which was placed into service in December 2010, offset by a reduced contribution from the wind power assets and increased corporate costs related to the Corporate Restructuring completed in December 2010. EIF’s interest in Alliance Pipeline Canada continued to contribute stable adjusted earnings in both 2010 and 2009.

 

Adjusted earnings from EIF were $45 million for the year ended December 31, 2009 compared with adjusted earnings of $41 million for the year ended December 31, 2008. EIF adjusted earnings primarily reflected growth in Saskatchewan System earnings attributable to customer connections and expansions completed in 2008, partially offset by increased income taxes and corporate costs compared with 2008.

 

Earnings from EIF for 2008 included proceeds of $1 million from the settlement of a claim against a former shipper on Alliance Pipeline Canada which repudiated its capacity commitment.

 

Business Risks

 

Risks for Alliance Pipeline Canada are similar to those identified for Alliance Pipeline US in the Gas Pipelines, Processing and Energy Services segment. The following risks relate to the Saskatchewan System. General risks that affect the Company as a whole are described under Risk Management and Financial Instruments.

 

Competition

 

The Saskatchewan System faces competition in pipeline transportation from other pipelines as well as other forms of transportation, most notably trucking. These alternative transportation options could charge rates or provide service to locations that result in greater net profit for shippers and thereby potentially reduce shipping on the Saskatchewan System or result in possible toll reductions. The Saskatchewan System manages exposure to loss of shippers by ensuring the shipping rates are competitive and by providing a high level of service. Further, the Saskatchewan System’s right-of-way and expansion efforts have created a competitive advantage. The Saskatchewan System will continue to focus on increasing efficiencies through its expansion projects in order to meet its shippers’ growing demand.

 

Regulation

 

EIF’s 50% interest in Alliance Pipeline Canada and certain pipelines within the Saskatchewan System are subject to the actions of various regulators, including the NEB. Actions of the regulators related to tariffs, tolls and facilities impact earnings and the success of expansion projects. Delays in regulatory approvals could result in cost escalations and construction delays. Changes in regulation, including decisions by regulators on the applicable tariff structure or changes in interpretations of existing regulations by courts or regulators, could adversely affect the results of operations of EIF.

 

Demand for Services

 

Operations and tolls for the Saskatchewan Gathering and the Westspur Systems are, in general, based on volumes transported and are on terms similar to a common carrier basis with no specific on-going volume commitments. There is no assurance that shippers will continue to utilize these systems in the future or transport volumes on similar terms or at similar tolls.

 

 

82

 

ENBRIDGE INC. 2010 ANNUAL REPORT

 

 



 

Corporate

 

EARNINGS

 

 

2010

 

 

2009

 

2008

 

(millions of Canadian dollars)

 

 

 

 

 

 

 

 

Noverco

 

21

 

 

19

 

20

 

Corporate

 

(48

)

 

(39

)

(58

)

Adjusted Loss

 

(27

)

 

(20

)

(38

)

Noverco – impact of tax rate changes

 

 

 

6

 

 

Corporate – unrealized derivative fair value gains

 

25

 

 

207

 

26

 

Corporate – unrealized foreign exchange gains on translation of intercompany balances, net

 

40

 

 

133

 

 

Corporate – gain on sale of investment in NTP

 

 

 

25

 

 

Corporate – impact of tax rate changes

 

 

 

4

 

 

Corporate – gain on sale of corporate aircraft

 

 

 

 

5

 

Corporate – U.S. pipeline tax decision

 

 

 

 

(32

)

Corporate – asset impairment loss

 

 

 

 

(7

)

Earnings/(Loss)

 

38

 

 

355

 

(46

)

 

Total adjusted loss from Corporate was $27 million for the year ended December 31, 2010 compared with $20 million for the year ended December 31, 2009. The increase in adjusted loss was primarily due to the Company recording foreign exchange gains realized on hedge settlements and on residual United States dollar cash balances in 2009, whereas no similar gains occurred in 2010. Other factors contributing to the increased adjusted loss included higher administrative costs and higher interest costs, partially offset by an increased corporate income tax recovery.

 

Total adjusted loss from Corporate was $20 million for the year ended December 31, 2009 compared with $38 million for the year ended December 31, 2008. The improvement in Corporate adjusted loss is the result of foreign exchange gains realized on hedge settlements and on residual United States dollar cash balances as the result of a stronger United States dollar, partially offset by higher administrative costs, including compensation, and an increase in bank stand-by fees reflecting tighter credit markets.

 

Corporate earnings/(loss) was impacted by the following non-recurring or non-operating adjusting items:

 

·

Noverco earnings for 2009 included a $6 million benefit related to favourable tax rate changes.

·

Earnings for each year included the change in the unrealized fair value gains of derivative financial instruments related to forward foreign exchange risk management positions.

·

Earnings included net unrealized foreign exchange gains on the translation of foreign-denominated intercompany balances.

·

In May 2009, the Company sold its investment in NTP, an internet-based crude oil trading and clearing platform, for proceeds of $32 million, resulting in a gain of $25 million.

·

Earnings for the year ended December 31, 2009 included a $4 million benefit related to favourable tax rate changes.

·

A $5 million gain on the sale of a corporate aircraft is included in Corporate costs for the year ended December 31, 2008.

·

An unfavourable court decision related to the tax basis of previously owned United States pipeline assets resulted in the recognition of a $32 million income tax expense in the year ended December 31, 2008.

·

Earnings in 2008 included an asset impairment loss arising from the write-off of goodwill related to the Company’s investment in NSolv, a technology development venture.

 

 

 

MANAGEMENT’S DISCUSSION AND ANALYSIS

83

 

 



 

NOVERCO

 

Enbridge owns an equity interest in Noverco through ownership of 32.1% of the common shares and a cost investment in preferred shares. Noverco is a holding company that owns approximately 71.0% of Gaz Metro Limited Partnership (Gaz Metro), a natural gas distribution company operating in the province of Quebec with interests in subsidiary companies operating gas transmission, gas distribution and power distribution businesses in the province of Quebec and the states of New England. Gaz Metro became a privately held limited partnership as a result of a reorganization of its publicly held partnership units, which were exchanged on a one for one basis for common shares in Valener Inc., a new publicly listed corporation. The reorganization was effective September 30, 2010.

 

The Company announced on February 3, 2011 that it will invest $145 million to acquire an additional 6.8% interest in Noverco from Laurentides Investissements (SAS), a subsidiary of GDF SUEZ, bringing its total interest in Noverco to 38.9%.  Trencap, a partnership managed by the Caisse de Depot et Placement du Quebec, will acquire Laurentides Investissements’ remaining 10.8% interest in Noverco, following which Enbridge and Trencap will become the sole shareholders of Noverco.  The transaction is expected to close later in the year once all regulatory approvals have been received.

 

Weather variations do not affect Noverco’s earnings as Gaz Metro is not exposed to weather risk. A significant portion of the Company’s earnings from Noverco is in the form of dividends on its preferred share investment, which is based on the yield of 10-year Government of Canada bonds plus 4.34%.

 

Results of Operations

 

Noverco adjusted earnings were $21 million for the year ended December 31, 2010 comparable with $19 million for the year ended December 31, 2009 and $20 million for the year ended December 31, 2008. Noverco earnings for each year reflected stable contributions from the Company’s preferred share investment and Noverco’s underlying gas distribution investments.

 

CORPORATE

 

Corporate consists of the new business development activities, general corporate investments and financing costs not allocated to the business segments.

 

Results of Operations

 

Adjusted loss from Corporate was $48 million for the year ended December 31, 2010 compared with $39 million for the year ended December 31, 2009. The increase was primarily due to the Company recording foreign exchange gains realized on hedge settlements and on residual United States dollar cash balances in 2009, whereas no similar gains occurred in 2010. Other factors contributing to the increase included higher administrative costs and higher interest costs, partially offset by an increased income tax recovery.

 

Adjusted loss from Corporate was $39 million for the year ended December 31, 2009 compared with $58 million for the year ended December 31, 2008. The improvement in Corporate adjusted loss is a result of foreign exchange gains realized on hedge settlements and on residual United States dollar cash balances as the result of a stronger United States dollar, partially offset by higher administrative costs, including compensation, and an increase in bank stand-by fees reflecting tighter credit markets.

 

 

84

 

ENBRIDGE INC. 2010 ANNUAL REPORT

 

 



 

Liquidity and Capital Resources

 

The Company expects to utilize cash from operations and the issuance of replacement debt, commercial paper and/or credit facility draws to fund liabilities as they become due, finance capital expenditures, fund debt retirements and pay common share dividends. At December 31, 2010, excluding the Southern Lights project financing, the Company had $5,848 million of committed credit facilities of which $3,316 million was drawn or allocated to backstop commercial paper. Inclusive of unrestricted cash and cash equivalents of $182 million, the Company had net available liquidity at December 31, 2010 of $2,714 million. The net available liquidity is expected to be sufficient to finance all currently secured capital projects and to provide flexibility for new investment opportunities.

 

The Company actively manages its bank funding sources to ensure adequate liquidity and optimize pricing and other terms. The following table provides details of the Company’s credit facilities at December 31, 2010.

 

 

 

 

 

 

 

Credit Facility

 

 

 

 

 

Expiry Dates

2

Total Facilities

 

Draws

3

Available

 

(millions of Canadian dollars)

 

 

 

 

 

 

 

 

 

Liquids Pipelines

 

2012

 

200

 

26

 

174

 

Gas Distribution